# BART Analysis for

PSNH Merrimack Station Unit MK2

January 14, 2011BART Analysis – PSNH Unit MK2 January 14, 2011 Page 1



# BART Analysis for

PSNH Merrimack Station Unit MK2

1. INTRODUCTION

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

full time to meet baseload electric demand. Unit M K2 is a wet-bottom, cyclone-type boiler with a heat input rating of 3,473 MMBtu/hr and an e lectrical output of 320 MW. Installed in 1968, this generating unit is equipped with selecti ve catalytic reduction to remove oxides of nitrogen (NO X 

### ) formed during the combustion process. Two electr ostatic precipitators operate in series to capture particulate matter (PM ) in the flue gases. Also, construction is nearing completion on a limestone forced oxidation scrubber system that will reduce sulfur dioxide (SO 2 

### ) emissions. Retrofit options for this unit are li mited because the facility already has controls in place for these major pollu tants of concern. Only a few emission control technologies are compatible with the type o f boiler design employed, and space for new retrofits is very limited.

2. CURRENTLY AVAILABLE RETROFIT TECHNOLOGIES, POTE NTIAL COSTS, AND OTHER ENVIRONMENTAL AND ENERGY IMPACTS

2.1 Retrofit Technologies for NO X 

### Control

Because of the current boiler design, the only NO X 

### emission control technology options available and potentially applicable to Unit MK2 ar e selective non-catalytic reduction and selective catalytic reduction.

Selective Non-Catalytic Reduction (SNCR)

SNCR is a post-combustion technology that involves injecting ammonia or urea into specific temperature zones in the upper furnace or convectiv e pass. The ammonia or urea reacts with

NO X 

### in the flue gas to produce nitrogen and water. Th e effectiveness of SNCR depends on the temperature where reagents are injected, the mi xing of the reagent in the flue gas, the residence time of the reagent within the required t emperature window, the ratio of reagent to

NO X 

### , and the sulfur concentration in the flue gas. (S ulfur in the flue gas, originating from

the sulfur content of the fuel, can combine with am monia to form solid sulfur compounds such as ammonium bisulfate that may become deposite d in downstream equipment.) NO X 

### reductions of 35 to 60 percent have been achieved t hrough the use of SNCR on coal-fired boilers operating in the United States.

Selective Catalytic Reduction (SCR)

SCR is another post-combustion technology that invo lves injecting ammonia into the flue gas in the presence of a catalyst to reduce NO X 

### to nitrogen and water. The SCR reactor can be located at various positions in the process, inc luding 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 o f SCR is influenced by flue gas temperature, fuel sulfur content, ammonia-to-NO X 

### ratio, inlet NO X 

### concentration, spaceBART Analysis – PSNH Unit MK2 January 14, 2011 Page 2



### velocity, catalyst design, and catalyst condition. NO X 

### emission reductions of about 75 to 90 percent have been obtained with SCR on coal-fired b oilers operating in the U.S.

2.1.1 Potential Costs of NO X 

### Controls

The estimated costs of NO X 

### emission controls for SNCR and SCR at Merrimack St ation Unit MK2 are presented in Table 2-1. These estimates ar e based on assumptions used in EPA’s Integrated Planning Model for the EPA Base Case 200 6 (V.3.0), for retrofitting an electric generating unit (EGU) the size of Unit MK2. For SN CR, the total annual cost is estimated to be about $5,110,000, or $593/ton of NO X 

### removed. For an SCR system, the total annual cost is estimated to be $5,070,000, or $312/ton. S tated costs are for year-round operation.

Table 2-1. Estimated NO X 

### Control Costs

Control Technology Capital Cost

($/kW) $ 

### O&M Cost ($/yr) 

### Total Annual Cost

($/yr) 

### Average Cost

($/ton)



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

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

Estimates are derived from USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model , November 2006. Costs are scaled for boiler size. All costs are adjusted to 2008 dollars.

Total annual cost is for retrofit of a 320-MW unit with 80% capacity factor and 2,243 million kWh annu al generation. Total annual cost includes amortizatio n of capital cost over 15 years at 3.0% interest ra te. Average cost per ton is based on an estimated 8,613 tons of NO X removed for SNCR and an estimated

16,269 tons of NO X removed for SCR.



### Because Unit MK2 already has SCR controls in place, the listed costs serve for comparative purposes only. In 1998, PSNH estimated that its SC R costs would be about $400/ton for year-round operation and about $600/ton for operati on limited to the ozone season (May 1 through September 30). These costs are approximate ly equal to $530/ton and $790/ton, respectively, in 2008 dollars. PSNH currently oper ates Unit MK2 full time in order to meet

NO X 

### RACT requirements.

Year-round operation is EPA’s presumptive norm for BART (applicable to EGUs of 750 MW capacity or greater) for units that already have seasonally operated SCRs. Assuming that operating costs are proportional to operating time, the difference in cost between yearround and seasonal SCR operation for Unit MK2 is ab out $3,300,000, based on PSNH’s

1998 cost estimates. The cost differential could b e about half that amount, if based on the more recent generic estimates presented in Table 2- 1.

2.1.2 Other Environmental and Energy Impacts of NO X 

### Controls

SNCR and SCR both use urea or anhydrous ammonia. A mmonia 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 fl ue gases or as fugitive emissions from the handling and storage of urea or anhydrous ammonia. A facility must also maintain a risk management plan if the quantities of stored ammonia exceed the applicable regulatory

threshold.

Ammonia from SNCR that becomes entrained in the fly ash may affect the resale value or disposal cost of the ash. Ammonia in the flue gas may produce a more visible plume,BART Analysis – PSNH Unit MK2 January 14, 2011 Page 3



### depending on the ammonia concentration in the gas s tream. High ammonia concentrations

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

on the economizer, air heater, and other surfaces. Ammonium bisulfate can also plug filter bags in a baghouse. SNCR may generate nitrous oxid e emissions, a greenhouse gas.

With SCR, the formation of ammonium bisulfate may b e exacerbated by the ability of this catalyst-based technology to oxidize SO 2 

### to SO 3 

### , resulting in higher sulfate concentrations

than would otherwise exist. Ammonium bisulfate for mation can be reduced by controlling excess ammonia and using catalysts that minimize SO 2 

### oxidation. The air heater and other surfaces where the ammonia bisulfate may deposit mu st be acid washed periodically. Acid washing helps to maintain the efficiency of the air heater and prevents plugging to allow the free flow of flue gases through it. An SCR may als o require a fan upgrade to overcome additional pressure drop across the catalyst. The increase in fan capacity consumes a small amount of energy. (In the case of Unit MK2, the ex isting fan was sufficient to accommodate the additional pressure drop.)

NO X 

### emission reductions provide environmental and publ ic health benefits beyond visibility improvement – most notably, reductions in acid rain and ground-level ozone. NO X 

### is a chemical precursor to ozone formation and is one of the primary compounds contributing directly to acid rain formation. A decrease in aci d rain production improves water quality and the health of ecosystems sensitive to low pH.

2.2 Retrofit Technologies for PM Control

PM control technologies available and potentially a pplicable to Unit MK2 are electrostatic precipitators, fabric filters, mechanical collector s, and particle scrubbers.

Electrostatic Precipitators (ESPs)

Electrostatic precipitators capture particles throu gh the use of electrodes, which are electrical conductors used to make contact with non-metallic p arts of a circuit. An ESP consists of a small-diameter negatively charged electrode (usuall y a set of individual wires or a grid) and a grounded positively charged plate. In operation, a strong electric charge from the negatively charged electrode sets up a one-directio nal electric field. When particle-laden gases pass through this electric field, the particl es become charged and are then drawn to the positive collecting surface (the plate), where they are neutralized. The particles are then collected by washing or knocking the plate, causing the particles to fall into a collection hopper. Existing electrostatic precipitators are t ypically 40 to 60 percent efficient. New or

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

For older units, options for upgrading an ESP syste m include: replacement of existing control systems with modern electronic controllers; replace ment of old-style wire and plate systems inside the ESP with new, rigid electrode systems; a ddition of new ESP fields; or addition of entire new units (in series). The feasibility of a ny particular upgrade will be influenced by spatial limitations or design constraints on a case -by-case basis.

Fabric Filters

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

containment structure. These devices work on the s ame principal as a vacuum cleaner bag.BART Analysis – PSNH Unit MK2 January 14, 2011 Page 4



### The particle removal efficiency of the fabric filte r system depends on a variety of particle and operational parameters. The physical character istics of particle size distribution, particle cohesion, and particle electrical resistivity are i mportant variables. Operational parameters affecting collection efficiency include air-to-clot h ratio, operating pressure loss, cleaning sequence, interval between cleanings, and cleaning intensity. The structure of the fabric filter, filter composition, and bag properties also affect collection efficiency. Collection efficiencies of baghouses may exceed 99 percent.

Mechanical Collectors and Particle Scrubbers

Mechanical collectors, such as cyclones, are most e ffective at collecting coarse particulate matter (i.e., particles with a diameter of 10 micro meters or larger). Finer particles escape cyclones along with the flue gases. For this reaso n, mechanical collectors are generally most useful when used in conjunction with other pol lution control equipment. The typical collection efficiency of mechanical collectors is a bout 85 percent for larger particle sizes.

Scrubbing systems involve the injection of water an d/or chemicals into the flue gas to wash unwanted pollutants from the gas stream through phy sical or chemical absorption/adsorption. Scrubbing systems have been shown to reduce PM 10 

### emissions by 50 to 60 percent but are generally less effective for removal of fine partic les.

Because mechanical collectors and particle scrubber s are more costly and less efficient than other control options (i.e., ESPs, baghouses), thes e lower-performing technologies are rarely used today for removing particulate matter from pow er plant emissions. Consequently,

mechanical collectors and scrubbers are not conside red 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 dev eloped from NESCAUM’s Assessment of Control Technology Options for BART-Eligible Source s , March 2005. Approximate cost ranges are provided for two types of ESPs and two t ypes of fabric filters applicable to a retrofit installation the size of Unit MK2. Capita l and operating costs are based on flue gas flow rates in actual cubic feet per minute (acfm).

Table 2-2. Estimated PM Control Costs

Control Technology Capital Cost

($/kW) ($) 

### O&M Cost

($/yr) 

### Total

Annual Cost ($/yr) 

### Average

Cost ($/ton)



### Dry ESP 73-194 23.3-62.1 million 1.1-1.9 million 3. 0-7.1 million 100-240

Wet ESP 73-194 23.3-62.1 million 0.6-1.6 million 2. 6-6.8 million 90-230

Fabric filter – reverse air 82-194 26.4-62.1 millio n 1.6-2.4 million 3.8-7.6 million 130-260

Fabric filter – pulse jet 58-194 18.6-62.1 million 2.2-3.1 million 3.7-8.3 million 130-280

Reference: NESCAUM, Assessment of Control Technology Options for BART-E ligible Sources , March 2005. All costs are adjusted to 2008 dollars. Total annual cost is for retrofit of a 320-MW unit with 80% capacity fa ctor and flue gas

flow rate of 1.36 million acfm. Total annual cost includes amortization of capital cost over 15 years at 3.0% interest rate. Average cost per ton is based on 29,850 tons of PM removed for ESPs and 29,759 tons of PM removed for fabric filters.BART Analysis – PSNH Unit MK2 January 14, 2011 Page 5



### The costs for ESPs and fabric filters are of simila r magnitude, with total annual costs ranging from about $2.6 million to $8.3 million, or $90 to $280 per ton of PM removed. Because Unit MK2 already has two dry ESPs installed and ope rating, the tabulated costs are useful for comparative purposes only. For facilities with exi sting ESPs, typical equipment replacement costs to upgrade performance may be in the range of $10,000 to $30,000 per MW. (M. Sankey and R. Mastropietro, “Electrostatic Upgrade Strateg y: Get the Most From What You Have,” Hamon Research-Cottrell, Inc., April, 1997.)

2.2.2 Other Environmental and Energy Impacts of PM Controls

PM controls collect particulate matter, or fly ash, suspended in the flue gases. In some cases, the fly ash is injected back into the boiler , an arrangement that improves boiler efficiency by recapturing the residual heating valu e of the fly ash. If the fly ash is not reinjected, it must be either landfilled or reclaim ed, e.g., as a supplement in concrete production or as a component in other manufactured products.

2.3 Retrofit Technologies for SO 2 

### Control

SO 2 

### control technologies available and potentially app licable to Unit MK2 are scrubber systems for flue gas desulfurization, and use of lo w-sulfur coal.

Flue Gas Desulfurization

Scrubber systems use chemical reagents to “scrub” o r “wash” unwanted pollutants from a gas stream. Flue gas desulfurization (FGD) processes b ased 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 ot her air pollutants.

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

SO 2 

### in the flue gas. A PM control device is always lo cated upstream of a wet scrubber.

Lime/limestone scrubbers, sodium scrubbers, and dua l alkali scrubbers are among the commercially proven wet FGD systems. Wet regenerat ive (meaning the reagent material can be treated and reused) FGD processes are an att ractive option because they allow higher sulfur removal rates and produce minimal wastewater discharges.

For coal-fired power plants, the reagent is usually lime or limestone; and the reaction product is calcium sulfite or calcium sulfate. The solid compounds are collected and removed in downstream process equipment. Calcium s ulfate (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 land filled.

SO 2 

### removal efficiencies for existing wet limestone sc rubbers range from 31 to 97 percent with an average of 78 percent (NESCAUM, “Assessment of Control Technology Options for BART-Eligible Sources,” March 2005). For new F GD systems installed at large (>750 MW) coal-fired power plants, the presumptive norm i s 95 percent reduction of SO 2 

### emissions (USEPA, Appendix Y to Part 51 – Guidelines for BART Determinations under the Regional Haze Rule).BART Analysis – PSNH Unit MK2 January 14, 2011 Page 6



### Dry (or semi-dry) FGD processes are similar in conc ept to wet FGD processes but do not saturate the flue gas stream with moisture. Dry sc rubbers are of two general types: dry sorbent injection and spray dryers. With the former, an al kaline reagent such as hydrated lime or soda ash is injected directly into the flue gas str eam to neutralize the acid gases. In spray dryers, the flue gas stream is passed through an ab sorber tower in which the acid gases are absorbed by an atomized alkaline slurry. The SO 2 

### removal efficiencies range from 40 to 60 percent for existing dry injection systems and from 60 to 95 percent for existing lime spray dryer systems (NESCAUM, 2005). A PM control device (ESP or fabric filter) is always installed downstream of a dry or semi-dry scrubber to remove the sorbent from the flue gas.

Low-Sulfur Coal

Because SO 2 

### emissions are directly related to the sulfur conte nt of the fuel burned, reducing

the amount of sulfur in the fuel reduces SO 2 

### emissions. Usually, for operational reasons, a facility cannot make a complete switch from one fue l type to another. Instead, the facility may be able to blend different fuels to obtain a lo wer-sulfur mix that emits less SO 2 

### upon combustion – for example, blending low-sulfur bitum inous or subbituminous coal with a highsulfur bituminous coal. The feasibility of fuel sw itching or blending depends on the physical characteristics of the plant (including bo iler type), and significant modifications to systems and equipment may be necessary to accommoda te the change in fuels. Switching to a lower-sulfur coal can affect coal handling and pr eparation systems, ash handling systems, boiler performance, and the effectiveness of PM emi ssion controls. To meet federal acid rain requirements, many facilities have switched to lowe r-sulfur coals, resulting in SO 2 

### emission reductions of 50 to 80 percent.

2.3.1 Potential Costs of SO 2 

### Controls

PSNH Merrimack Station is required by New Hampshire law to install an FGD system to reduce mercury emissions (with SO 2 

### removal as a co-benefit) at both Unit MK1 (not a BART-eligible unit) and Unit MK2 (a BART-eligible u nit). A company estimate for the project placed the capital cost at $457 million, or $1,055/kW (both amounts in 2008$) to install a wet limestone FGD system. Using 2002 bas eline emissions of 30,657 tons of SO 2 

### from Units MK1 and MK2 combined, and a minimum capt ure efficiency of 90 percent for this pollutant, the annualized capital cost translates t o about $1,400 per ton of SO 2 

### removed.

The project cost is said to be in line with the cos ts 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 i n MACTEC Federal Programs, Inc., “Assessment of Reasonable Progress for Regional Haz e in MANE-VU Class I Areas,” Final, July 9, 2007 (see Reasonable Progress Report, Attac hment Y). The PSNH estimated cost is

also more than double the estimate of $300/kW to $5 00/kW as reported in a 2008 survey of FGD systems (George W. Sharp, “What’s That Scrubber Going to Cost?,” Power , March 1,

2009). The higher cost-per-kW for Unit MK2 may reflect industry-wide increases in raw material, manufacturing, and construction costs but may also reflect site-specific factors such as unit size, type, and difficulty of retrofit

.

The costs of switching to lower-sulfur coal at PSNH Merrimack Station would rest on the incremental cost of purchasing the lower-sulfur mat erial at prevailing market prices. Even if

a lower-sulfur coal is available at reasonable addi tional cost, operational considerationsBART Analysis – PSNH Unit MK2 January 14, 2011 Page 7



### related to the physical characteristics of Unit MK2 may dictate the choice of coal for this unit. (Only certain types of coal can be used in w et-bottom, cyclone boilers; and lower-sulfur coals have already been tested and adopted for regu lar use at this facility.) Commodity spot prices for coal vary considerably. For example, fr om late March to early May 2009, the price spread between Northern Appalachia coal (<3.0 SO 2 

### ) and Central Appalachia coal (1.2 SO 2 

### ) ranged from $10 to $25 per ton (source: Energy Info rmation Administration, http://www.eia.doe.gov/fuelcoal.html).

2.3.2 Other Environmental and Energy Impacts of SO 2 

### Controls

An FGD system typically operates with high pressure drops across the control equipment, requiring increased energy usage for blowers and ci rculation pumps. Some configurations of FGD systems also require flue gas reheating to p revent operational problems (including physical damage to equipment), resulting in higher fuel usage per unit of net electrical generation. Documentation for EPA’s Integrated Pla nning Model (IPM®) indicates that a wet FGD system reduces the generating capacity of t he unit by about 2 percent.

Flue gas desulfurization has impacts on the operati on of solid waste and wastewater management systems. In addition to removing SO 2 

### , the FGD process removes mercury and other metals and solids. Often, gypsum produced in a limestone FGD process is recycled or sold to cement manufacturers; otherwise, the sludge must be stabilized and placed in an approved landfill. Gypsum must be dewatered before it can be handled, resulting in a wastewater stream that requires treatment. This wa stewater stream increases the sulfates, metals, and solids loadings on the receiving wastew ater treatment plant. Sometimes an additional clarifier is required to remove wastewat er solids coming from the FGD system.

Wet FGDs increase the amount of water vapor entrain ed in the flue gas. The result is a lower stack exit temperature and a more visible plu me at the stack outlet.

3. DISCUSSION OF CURRENT POLLUTION CONTROL EQUIPMENT A ND EMISSIONS



### 3.1 Discussion of Current NO X 

### Emissions and Controls

In 1994, PSNH installed an SCR system on Unit MK2, the first such system to be used on a coal-fired, wet-bottom, cyclone boiler in the Unite d States. The SCR was designed to meet

NO X 

### Reasonably Available Control Technology (RACT) lim its. Specifically, Unit MK2 is subject to a NO X 

### RACT Order limit of 15.4 tons per calendar day and a second NO X 

### RACT Order limit of 29.1 tons per calendar day for combi ned emissions from Units MK1 and MK2. The facility must also meet a less stringent federal acid rain program limit of 0.86 lb

NO X 

### /MMBtu. PSNH has a monetary incentive to surpass t he NO X 

### RACT requirements

because further emission reductions allow the utili ty to accumulate DERs. Actual NO X 

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

Since January 2001, the SCR on Unit MK2 has reduced NO X 

### emissions to between 0.15 and 0.37 lb/MMBtu (calendar monthly average), with a fe w excursions outside this range. (Note that the existing NO X 

### RACT limit of 15.4 tons per calendar day is mathem atically equivalent to 0.37 lb/MMBtu.) Data available from the period of 1993 to early 1995, prior to operation of the SCR, provide a baseline for uncontrolled NO X 

### emissions in the range of 2.0 to 2.5BART Analysis – PSNH Unit MK2 January 14, 2011 Page 8



### lb/MMBtu. Taken together, this information indicat es that Unit MK2 achieves a control level that exceeds 85 percent most of the time and frequently surpasses 90 percent.

3.2 Discussion of Current PM Emissions and Controls

PSNH Merrimack Station Unit MK2 has two electrostat ic 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. Install ation of the ESPs has reduced PM emissions from this unit by about 99 percent, based on a revi ew of 2002 emissions data. The current air permit for the facility requires that Unit MK2 meet a total suspended particulate (filterable TSP) limit of 0.227 lb/MMBtu and a TSP emissions ca p of 3,458.6 tons/year. However, the 0.227 lb/MMBtu rate does not reflect the true capab ilities of the ESPs to control particulate emissions. Stack testing on three separate dates i n 1999 and 2000 found actual TSP

emissions to be 0.043, 0.041, and 0.021 lb/MMBtu af ter controls. The most recent test, in May 2009, produced an emission rate of 0.032 lb/MMB tu. Total TSP emissions from this

unit were 210 tons in 2002.

3.3 Discussion of Current SO 2 

### Emissions and Controls

New Hampshire law requires PSNH Merrimack Station t o install and operate a scrubber system for both Unit MK1 and Unit MK2 by July 1, 20 13. While the primary intent of this law is to reduce mercury emissions from the company ’s coal-fired power plants, a major cobenefit is SO 2 

### removal. Pursuant to this statutory obligation, N ew Hampshire issued a permit to PSNH on March 9, 2009, for the constructi on of a wet, limestone-based FGD system to control mercury and SO 2 

### emissions at Merrimack Station. The permit requir es an

SO 2 

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

states as follows:

Beginning on July 1, 2013,...SO 2 emissions shall be controlled to 10 percent of the uncontrolled

SO 2 emission rate (90 percent SO 2 removal)...The Owner shall submit a report no later than

December 31, 2014 that includes the calendar month average SO 2 emission rates at the inlet and outlet of the FGD and the corresponding calendar mo nth average emissions reductions during the preceding 12 months of operation,...DES will use this data to establish the maximum sustainable

rate of SO 2 emissions reductions for MK2. The maximum sustain able 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 SO 2 removal efficiency for MK2 be less than 90 percent.



### These permit conditions effectively require that ac tual SO 2 

### removal efficiencies exceed 90 percent on average for Unit MK2. This plant must a lso meet general regulations for coalburning devices that limit the sulfur content of th e coal to 2.0 pounds per million BTU gross heat content averaged over any consecutive 3-month period, and 2.8 pounds per million BTU gross heat content at any time. Since 2002, th e facility has operated well within these fuel limits. More specifically, PSNH has worked to control coal sulfur content to reduce

SO 2 

### emissions and minimize the purchase of SO 2 

### allowances. Because the particular boiler design does not permit the burning of straight low- sulfur coal, the company blends coals to bring average sulfur content to a level that is con sistent with sustainable boiler operations.

PSNH must also meet a fleet-wide SO 2 

### emissions cap of 55,150 tons/year effective for al l electrical generating units at its Merrimack, Newin gton, and Schiller Stations. In 2002,

actual SO 2 

### emissions from Unit MK2 were 20,902 tons.BART Analysis – PSNH Unit MK2 January 14, 2011 Page 9



### 4. REMAINING USEFUL LIFE OF UNIT

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

controlled in a manner consistent with BART and the expected useful life of the unit. Originally, electric generating units were estimate d 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 replace ment facilities and/or new transmission

lines. Merrimack Station Unit MK2 was built in 196 8. PSNH’s commitment to install new

emission controls on this unit demonstrates the com pany’s belief that this unit is capable of supplying electricity to the region for many years beyond the present.

5. DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FRO M BART

The New Hampshire Department of Environmental Servi ces (NHDES) conducted a CALPUFF modeling analysis to assess the anticipated visibil ity effects of BART controls at PSNH Merrimack Station Unit MK2. Visibility can be quan tified 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 se t of CALPUFF runs for Unit MK2

under controlled and uncontrolled conditions. Befo re considering the findings of this modeling work, it is useful to review the results o f the BART eligibility modeling performed by the Mid-Atlantic/Northeast Visibility Union (MAN E-VU).

In previous modeling, MANE-VU used CALPUFF to assis t in the identification of BARTeligible sources. This modeling assumed natural vi sibility conditions (about 7 dv) to produce the most conservative results possible, thereby min imizing the number of sources that would “model out” of BART requirements. Under these cond itions, uncontrolled emissions from Unit MK2 produce theoretical CALPUFF worst-case imp acts of 2.24 dv at Acadia National Park. EPA considers it acceptable to exempt source s when this form of conservative modeling indicates that a source produces less than 0.5 dv of impact. MANE-VU considers an exemption level of 0.2 to 0.3 dv to be more appr opriate but prefers, and has applied, an even more conservative exemption level of 0.1 dv. CALPUFF modeling results for baseline emissions from Unit MK2 exceed all of these exempti on levels.

The BART assessment modeling provides a comparison of visibility impacts from current allowable emissions with those from the post-contro l emission level (or levels) being assessed. Results are tabulated for the average of the 20% best visibility (about 11.7 to 12.4 dv) and 20% worst visibility (about 22.8 dv) modele d days at each nearby Class I area. For any pair of control levels evaluated, the differenc e in the level of impairment predicted is the degree of improvement in visibility expected.

Rather than use CALPOST to manipulate background de ciview calculations, NHDES normalized CALPUFF modeling results and then applie d predicted concentrations to a logarithmic best-fit equation to the actual observe d PM 2.5 

### -to-deciview relationship measured at Acadia NP, Great Gulf NWR, and Lye Brook NWR. T hus, 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 r esulting PM-extinction-to-deciview equation. In accordance with BART guidance, the na tural visibility condition (about 7 dv) was used for exemption purposes, and 20% best and 2 0% worst visibility were used forBART Analysis – PSNH Unit MK2 January 14, 2011 Page 10



### assessment of BART control effectiveness. The CALP UFF-predicted visibility benefits

from BART controls on 20% best and 20% worst visibi lity days are as follows:

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

Visibility Improvements from BART Controls

On the 20% Best Visibility Days (deciviews)

Pollutant Control Level Acadia Great Gulf Lye Brook

SO 2 

### 90% with FGD 1.07 0.83 0.17

NOx Additional 25% with SCR upgrade 0.21 0.18 0.10

PM 90% with upgraded controls 0.16 0.12 0.03

On the 20% Worst Visibility Days (deciviews)

Pollutant Control Level Acadia Great Gulf Lye Brook

SO 2 

### 90% with FGD 0.26 0.20 0.03

NOx Additional 25% with SCR upgrade 0.07 0.06 0.03

PM 90% with upgraded controls 0.07 0.05 <0.01*

* below sensitivity limit of model

Note: Values in boldface are considered as having greater validity in the mo deling estimation of maximum visibility benefits from BART controls.



### While Unit MK2 was predicted to have up to 2.24 dv impact at Acadia National Park under

natural conditions, the basis of the BART assessmen t evaluation changes to 20% worst visibility days. On those days, a 90% reduction in sulfur emissions at Unit MK2 results in only a 0.26 dv visibility improvement. At first th ese results may appear to be too low;

however, on further examination, it is found that C ALPUFF predicts the same amount of sulfate from Unit MK2 reaching Acadia under both be st and worst visibility conditions. The difference is that there is greater than an order o f magnitude more sulfate coming from other sources on the 20% worst visibility days, raising t he background concentrations to much higher levels. Because the deciview scale is logar ithmic, the same mass reduction of 0.259

μ g/m 3 

### of sulfate from this one source results in wide di fferences in deciview impacts for different background visibility conditions at oppos ite ends of the range.

NHDES also conducted a screening-level analysis of the anticipated visibility effects of

BART controls at PSNH Merrimack Station Unit MK2. Specifically, one modeling run using the CALGRID photochemical air quality model w as performed to assess the effects of installing an FGD system on Unit MK2. The simulati on covered the full summer modeling episode (from May 15 to September 15, 2002) and use d MANE-VU’s 2018 beyond-on-theway (BOTW) emissions inventory scenario as a baseli ne. The BOTW emissions scenario reflects controls from potential new regulations th at may be necessary to attain National Ambient Air Quality Standards and other regional ai r quality goals, beyond those regulations that are already “on the books” or “on the way.”

The CALGRID model outputs took the form of ambient concentration reductions for SO 2 

### , PM 2.5 

### , and other haze-related pollutants within the regi on. NHDES post-processed the

modeled concentration reductions to estimate the co rresponding visibility improvements at nearby Class I areas (i.e., concentration impacts w ere converted to visibility impacts).BART Analysis – PSNH Unit MK2 January 14, 2011 Page 11



### Based on the CALGRID modeling results, the installa tion of scrubber technology with 90% removal efficiency on Unit MK2 is expected to reduc e maximum predicted 24-hour average

SO 2 

### concentration impacts by up to 21 μ g/m 3 

### (8 ppb by volume; see Figure 5-1) and

maximum predicted 24-hour average PM 2.5 

### concentration impacts by up to 1 μ g/m 3 

### . The largest modeled pollutant concentration reductions occur within a 50-kilometer radius of the facility. For the affected Class I areas (located 100 to 500 kilometers away), reductions in the maximum predicted concentrations of SO 2 

### , PM 2.5 

### , and other haze-related pollutants, combined, are expected to yield a nominal improveme nt in visibility (about 0.1 deciview) on direct-impact hazy days.

Figure 5-1

NHDES’s use of CALGRID differs somewhat from EPA’s preferred methodology. CALPUFF is EPA’s preferred model for performing lon g-range visibility assessments of individual sources to distant Class I areas, in par t because it is considered to be a conservative model or one that is capable of estima ting worst-case impacts rather than expected impacts. This makes CALPUFF ideally suite d 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 contro lled.

CALGRID is a sister program to CALPUFF and shares m uch of the same chemistry; however, it works as a gridded model rather than a puff tracking model, and it has the advantage of easily tracking 20% worst visibility d ays and cumulative impacts by modeling

all source sectors. NHDES chose to use CALGRID for screening since it is much easier to track the dynamics of impacts from single sources t o multiple Class I areas on targeted days, rather than just applying the maximum impact condit ions that may or may not be associated with 20% worst days. While the CALPUFF model’s CAL POST post-processor has anBART Analysis – PSNH Unit MK2 January 14, 2011 Page 12



### option for application on 20% best visibility days, it does not in fact isolate those 20% best days for analysis. It simply changes the backgroun d 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 CALGRI D have aligned better in their predictions than might be expected. This result ma y be attributed to the similar chemistry used in both models and to the specific circumstanc es of this case in which the prevailing wind direction on the 20% worst visibility days car ries Unit MK2 emissions directly toward

Class I areas such as Acadia National Park. The bi g discrepancy occurs under best visibility days, when CALGRID (correctly) does not align the s ource to receptor, but CALPUFF (incorrectly) applies wind directions for worst vis ibility days to the best day calculations.

6. DETERMINATION OF BART

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

PSNH Merrimack Station Unit MK2, it is determined t hat the NO X 

### , PM, and SO 2 

### controls described below represent Best Available Retrofit T echnology for this unit.

6.1 Selecting a Pollution Control Plan for NO X



### PSNH currently operates an SCR system on Unit MK2. This system was installed in 1994 to meet the requirements of NO X 

### RACT and the ozone season NO X 

### budget program. SNCR is the only other control technology available for controlling NO X 

### emissions from this unit. SCR yields higher NO X 

### removal rates and is more cost-effective than SNCR . For units that already have seasonally operated SCRs, year-round o peration is EPA’s presumptive norm for BART. PSNH estimated, in 1998, that the existing S CR system could be operated yearround at a cost of $494 per ton of NO X 

### removed.

For an early-generation SCR that has received previ ous retrofits to improve its performance, further upgrades to this NO X 

### 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 locati on where physical space is already constrained. Capital costs would be comparable to installing a new SCR and would achieve only marginal additional reductions in NO X 

### emissions. Because Unit MK2 has an existing SCR system designed to meet other air program requi rements that could be operated yearround at reasonable cost, full-time operation of th e existing SCR is considered to be BART

for NO X 

### control on this unit.

EPA has provided presumptive BART emission rates th at are broadly applicable to power plants larger than 750 MW but are not necessarily r epresentative of smaller EGUs like Unit MK2. In the case of Unit MK2, the cyclone boiler h as a relatively high uncontrolled NO X 

### emission rate ( ≥ 2.0 lb/MMBtu); so it follows that the controlled em ission rate, even at 90 percent control efficiency, would be above the pres umptive norm of 0.10 lb/MMBtu applicable to larger EGUs of its type. The past de cade of emissions records for Unit MK2 shows monthly average NO X 

### emission rates normally ranging between 50 and 100 percent of the RACT limit. The existing NO X 

### RACT limit of 15.4 ton/day, equivalent to of 0.37BART Analysis – PSNH Unit MK2 January 14, 2011 Page 13



### lb/MMBtu * 

### , corresponds to a NO X 

### control rate of approximately 85 percent.

PSNH has described operational and infrastructural changes that would be needed in order to allow the company to guarantee a NO X 

### performance level lower than the current effective limit of 0.37 lb/MMBtu (see Supporting Documentatio n, attached). This could be accomplished by increasing the frequency of mainten ance cleanings and accelerating the rate of catalyst replacement to ensure a high level of NOx reduction capability at all times. The four major cost components would be:

1. The direct costs of extra inspections and maintenan ce cleanings for the air heater and SCR system,

2. The cost of purchased replacement power covering th e periods of additional scheduled maintenance outages,

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

4. The increased cost of purchased replacement power a ssociated with reduced flexibility to operate at partial load.

Calculations performed by PSNH assume a NOx emissio n rate of 0.8 lb/MMBtu during partial load operation. This relatively high emiss ion 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 wo uld otherwise occur under partial load operation). Replacement power at such times would represent an unavoidable cost.

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

the NO X 

### emission limit to 0.30 lb/MMBtu (an effective reduc tion of 0.07 lb/MMBtu) would have an incremental cost of approximately $800 per ton of NO X 

### removed and would result in

a potential incremental emission reduction of about 1,000 tons per year. The indicated cost per ton falls within the generally regarded cost-ef fective range. At the same time, PSNH has

estimated that further reduction of the NOx emissio n limit to 0.25-0.30 lb/MMBtu would yield diminishing returns, with the incremental cos t per ton approximately one order of magnitude higher. NHDES concurs that such addition al costs are not justifiable given the fact of negligible visibility benefit. When the hi storical performance of Unit MK2 is considered alongside the operational factors and es timated costs to achieve a higher performance level, NHDES finds that a NO X 

### 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 NO X 

### on a 30-day rolling average basis.

6.2 Selecting a Pollution Control Plan for PM

PSNH currently operates two ESPs in series on Unit MK2. Mechanical collectors (cyclones) are effective only for coarse particle removal and would be impractical as a retrofit for Unit MK2, where the more efficient ESPs already exist. Fabric filters have performance levels comparable to ESPs and are a suitable PM control te chnology for power plant emissions. However, fabric filters are also impractical as a r etrofit for Unit MK2 under present

_________________ * The 0.37 lb/MMBtu NO X emission rate for MK2 is calculated from its maxim um heat input rate of 3,473 MMBtu/hr and the applicable NO X RACT limit of 15.4 tons per day, as follows:

[(15.4 tons/day × 1 day/24 hr) × 2,000 lb/ton] ÷ 3,473 MMBtu/hr = 0.37 lb/MMBtuBART Analysis – PSNH Unit MK2 January 14, 2011 Page 14



### circumstances: ESPs already exist, physical space at the facility is limited, and the addition of an FGD system is now in progress.

The existing ESPs were previously upgraded to inclu de state-of-the-art electronic controls. Further upgrading would require either major equipm ent substitutions or the addition of a third ESP in series with the two existing units. A dding a third ESP might be physically impossible because of the aforementioned spatial li mitations following past improvements to emission control systems. To undertake either m ajor equipment replacement or installation

of a third ESP, if it could be done at all, would r equire 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 mag nitude are not easily justified when weighed against the visibility improvement (less th an 0.1 dv on the 20 percent worst visibility days) that would be realized.

The current PM emission limit for Unit MK2 is not r eflective of the performance capabilities of the existing ESPs. However, the volume of avail able 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 adminis trative rule that will hold TSP emissions to a maximum of 0.08 lb/MMBtu but will apply this l imitation more broadly than BART requires. The new PM emission limit will affect bo th of Merrimack Station’s coal-fired utility boilers – Unit MK1 (not a BART-eligible facility) a nd Unit MK2 – as explained below.

In the new rule, Units MK1 and MK2 are placed withi n a regulatory “bubble” for the purposes of TSP compliance. This arrangement serve s both necessity and convenience

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

calculate the maximum allowable emission rate for t he combined source:

1. For BART-eligible Unit MK2, the maximum heat input rating of 3,473 MMBtu/hr was multiplied by MANE-VU’s lowest presumptive cont rol level for TSP emissions,

0.02 lb/MMBtu, to obtain an emission rate of 69.46 lb/hr.

2. For non-BART Unit MK1, the maximum heat input ratin g 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 tot al maximum heat input rate, 4,711

MMBtu/hr, to obtain the new TSP emission limitation of 0.08 lb/MMBtu (rounded down from 0.086 lb/MMBtu).

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

units combined will be less than the allowable emis sions would be if the limit for Unit MK1 remained separate and unchanged, and the limit for Unit MK2 were reduced to 0.04 lb/MMBtu, its approximate performance capability fr om actual stack test data. †



### _________________ † For the bubble concept, the combined emission rate = 0.08 lb/MMBtu × 4,711MMBtu/hr = 377 lb/hr . For the

stand-alone alternative, the sum of the individual emission rates = (0.04 lb/MMBtu × 3,473 MMBtu/hr) + (0.27

lb/MMBtu × 1,238 MMBtu/hr) = 473 lb/hr

.BART Analysis – PSNH Unit MK2 January 14, 2011 Page 15



### It is concluded that the existing ESPs, operating i n conjunction with the FGD process, will provide the most cost-effective controls for partic ulate 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 SO 2



### PSNH Merrimack Station is installing a flue gas des ulfurization system to remove mercury emissions in compliance with New Hampshire law. As a co-benefit, the FGD system is expected to remove more than 90 percent of SO 2 

### emissions. Because this installation is already mandated and because it will attain SO 2 

### removal rates approaching the BART presumptive norm of 95 percent (generally applicabl e to facilities larger than Merrimack Station), the FGD system is considered to be BART f or SO 2 

### control on Unit MK2. (Note that, at an installed cost exceeding $1,000/kW, the FGD system being added to this facility is more expensive than the industry average and mig ht not be viewed as cost-effective if its only purpose were to satisfy BART requirements.)

7. SUMMARY AND CONCLUSIONS

Table 7-1 summarizes best available retrofit techno logy for PSNH Merrimack Station Unit MK2 for the pollutants NO X 

### , PM, and SO 2 

### . The summary includes existing controls that have been determined to meet or exceed BART require ments 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 f lue gas desulfurization system and is not requiring additional control technology for Merrima ck Station at this time in order to comply

with BART.

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

Pollutant Current Emission

Controls Additional Emission

Controls in Progress BART Controls BART

Emission Limit

NO X 

### SCR None SCR 0.30 lb/MMBtu, 30-day rolling average

PM Two ESPs in series None Two ESPs in series 0.08 lb/MMBt u total suspended particulate (TSP)

SO 2 

### Fuel sulfur limits set at

2.0 lb sulfur/MMBtu (averaged over 3 mos.)

and 2.8 lb sulfur/MMBtu at any time Flue gas desulfurization (FGD), with required

SO 2 

### percent reduction

set at maximum

sustainable rate, but not

less than 90% on a calendar monthly average basis Flue gas desulfurization (FGD), with required

SO 2 

### percent reduction

set at maximum

sustainable rate, but not

less than 90% on a calendar monthly average basis; existing

fuel sulfur limits to

remain in effect 10% of uncontrolled

SO 2 

### emissions, calendar monthly

averageBART Analysis – PSNH Unit MK2 January 14, 2011 Page16NEW HAMPSHIRE BART ANALYSIS: Merrimack Station Unit MK2 (320 MW)Estimated Cost of Emission Controls7UncontrolledEmissionsControlledEmissionsEmissionReductionsPollutantEmission ControlTechnologyControlLevelton/yr ton/yr ton/yrCapital$Capital$/kWO&M$/yrTotalAnnual$/yrAverage$/tonRef.SCR (existing) 85%19,14012,871216,26937,710,1861181,910,432 5,069,414 3128NOXSNCR 45%19,140110,5278,6133,876,771124,781,136 5,105,893 5938min.23,280,363731,086,417 2,571,006 862 ESPs (existing) 99+%30,0602210229,850max.62,080,9671941,940,030 7,140,553 2399min.18,624,290582,172,834 3,732,991 125PMFabric Filters 99%30,060230129,759max.62,080,9671943,104,048 8,304,571 2799Lower-S coal (existing) 40%3    SO2FGD 90%420,90252,09018,8126457,000,0001,055unknown unknown unknown101Estimated.22002 (baseline) emissions as taken from NHDES datasummary derived from facility's annual emissions statement.3Estimated average reduction in fuel sulfur contentwith use of lower-S coal, resulting in equivalent reduction in SO2emissions.4Additional control level on emissions after existing controls have been applied; overall control levelwith use of lower-S coal is estimated to be 40 + 90(1 - 0.40) = 94%52002 (baseline) emissions with use of lower-sulfurcoal at ~1.0 % S by weight.6Reductions from baseline emissions.7All cost estimates adjusted to 2008$.8USEPA,Documentation for EPA Base Case 2006 (V.3.0) Usingthe Integrated Planning Model, November 2006.9NESCAUM,Assessment of Control Technology Options for BART-Eligible Sources, March 2005.10FGD capital cost is PSNH's estimate (2008$) for Units MK1 (113 MW) and MK2 (320 MW) combined.BART Analysis – PSNH Unit MK2 January 14, 2011 Page17Merrimack Station Unit MK2: NOXControlsPlant type wet-bottom, cyclone, coal-fired boiler Historical operation:Generation capacity 320MW Year 2002 2003 2004 2005 2006 2007 2008Maximum heat Input3,473MMBtu/hr Operating hours 7,180 6,703 7,462 7,280 7,577 7,477 6,519Capacity factor 80% Total Heat Input* 22,013,51322,006,52424,024,38223,795,57525,328,21825,448,43718,282,000Annual hours 8,760hr/yr Capacity factor** 72.4% 72.3% 79.0% 78.2% 83.3% 83.6% 60.1%Annual production 2,242,560,000kWh/yr *MMBtu (from CEM data) **Based on ratio oftotal heat input to theoretical maximum heat inputCosts: 2004$CapitalScaledCapitalTotalCapitalTotalAnnualizedCapitalFixedO&MScaled FixedO&MVariableO&MScaled VariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh mills/kWh $/yr $/yr $/yr tons/yr $/tonSCR 111.48 103.46 33,108,1522,773,470 0.74 0.69 219,771 0.67 0.65 1,457,518 1,677,2894,450,75916,269 274SNCR 11.04 10.64 3,403,662 285,125 0.16 0.15 49,3281.46 1.85 4,148,332 4,197,6614,482,7868,613 520Costs: 2008$2004$→2008$1.139multiplierCapitalScaledCapitalTotalCapitalTotalAnnualizedCapitalFixedO&MScaled FixedO&MVariableO&MScaled VariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh mills/kWh $/yr $/yr $/yr tons/yr $/tonSCR 126.98 117.84 37,710,1863,158,982 0.84 0.78 250,319 0.76 0.74 1,660,113 1,910,4325,069,414 16,269 312SNCR 12.57 12.11 3,876,771 324,757 0.18 0.18 56,1851.66 2.11 4,724,951 4,781,1365,105,893 8,613 593Cost Reference: Annualized cost basis:Period, yrs15Interest, %3.0USEPA,Documentation for EPA BaseCase 2006 (V.3.0) Using the IntegratedPlanning Model, November 2006.CRF 0.08377BART Analysis – PSNH Unit MK2 January 14, 2011 Page18Merrimack Station Unit MK2: PM ControlsPlant type wet-bottom, cyclone, coal-fired boilerHistorical operation:Capacity 320MW Year 2002 2003 2004 2005 2006 2007 2008Maximum heat Input 3,473MMBtu/hr Operating hours 7,180 6,703 7,462 7,280 7,577 7,477 6,519Capacity factor 80% Total Heat Input* 22,013,51322,006,52424,024,38223,795,57525,328,21825,448,43718,282,000Annual hours 8,760hr/yr Capacity factor** 72.4% 72.3% 79.0% 78.2% 83.3% 83.6% 60.1%Annual production 2,242,560,000kWh/yr *MMBtu (from CEM data) **Based on ratio oftotal heat input to theoretical maximum heat inputFlue gas flow rate1,362,620acfmCosts: 2004$CapitalTotalCapitalTotalAnnualizedCapitalFixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr$/ton Cost Reference:min.15.0020,439,3001,712,2000.250.45953,8342,666,03429,85089Dry ESPmax.40.0054,504,8004,565,8670.650.601,703,2756,269,14229,850210min.15.0020,439,3001,712,2000.150.25545,0482,257,24829,85076NESCAUM,Assessment of ControlTechnology Options for BARTEligible Sources, March 2005.Wet ESPmax.40.0054,504,8004,565,8670.500.501,362,6205,928,48729,850199min.17.0023,164,5401,940,4940.350.701,430,7513,371,24529,759113Annualized cost basis:Fabric Filter -Reverse Airmax.40.0054,504,8004,565,8670.750.802,112,0616,677,92829,759224Period, yrs 15min.12.0016,351,4401,369,7600.500.901,907,6683,277,42829,759110Interest, % 3.0Fabric Filter -Pulse Jetmax.40.0054,504,8004,565,8670.901.102,725,2407,291,10729,759245CRF 0.08377Costs: 2008$2004$→2008$1.139multiplierCapitalTotal CapitalTotalAnnualizedCapitalFixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/acfm$ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr $/tonmin.17.0923,280,3631,950,1960.280.511,086,4173,036,61329,850102Dry ESPmax.45.5662,080,9675,200,5230.740.681,940,0307,140,55329,850239min.17.0923,280,3631,950,1960.170.28620,8102,571,00629,85086Wet ESPmax.45.5662,080,9675,200,5230.570.571,552,0246,752,54729,850226min.19.3626,384,4112,210,2220.400.801,629,6253,839,84829,759129Fabric Filter -Reverse Airmax.45.5662,080,9675,200,5230.850.912,405,6377,606,16029,759256min.13.6718,624,2901,560,1570.571.032,172,8343,732,99129,759125Fabric Filter -Pulse Jetmax.45.5662,080,9675,200,5231.031.253,104,0488,304,57129,759279This page is intentionally left blank

# BART Analysis for PSNH Newington Station Unit NT1

January 14, 2011BART Analysis – PSNH Unit NT1 January 14, 2011 Page 1



# BART Analysis 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 of peak electric demand. Power is derived from an oil- and/or natural-gas-fired steam-generating boil er with a heat input rating of 4,350 MMBtu/hr and an electrical output of 400 MW. Insta lled in 1968, the boiler is equipped with low-NOx burners, an overfire air system, and w ater injection to minimize the formation of oxides of nitrogen (NO X 

### ) during the combustion process. The facility also has an electrostatic precipitator (ESP) to capture particu late matter (PM) in the flue gases. Partial

control of SO 2 

### emissions is provided by sulfur content limits on the fuel oil.

2. CURRENTLY AVAILABLE RETROFIT TECHNOLOGIES, POTE NTIAL COSTS, AND OTHER ENVIRONMENTAL AND ENERGY IMPACTS

2.1 Retrofit Technologies for NO X 

### Control

NO X 

### emission control technology options available and potentially applicable to Unit NT1 are combustion controls, selective non-catalytic re duction, and selective catalytic reduction.

Combustion Controls

Controls on the combustion process can reduce NO X 

### formation by as much 75 percent. Combustion controls or firing practices include suc h measures as staged combustion, limiting excess air, providing overfire air, recirc ulating the flue gases, using low-NO X 

### burners, and injecting water or steam.

Operating with low excess air involves restricting the amount of combustion air to the lowest possible level while maintaining efficient a nd environmentally compatible boiler operation. Because less oxygen is introduced into the combustion zone, NO X 

### formation is inhibited. Adjustments to the air supply may affec t normal boiler operation and may reduce operational flexibility. The effectiveness of limi ting excess air varies from boiler to boiler, but typical NO X 

### reductions are 10 to 25 percent from uncontrolled levels.

Overfire air (OFA) is a method where some of the to tal combustion air is diverted from the burners and injected through ports above the top bu rner level. This staged combustion

reduces fuel-based NO X 

### formation in the oxygen-deficient primary combusti on zone and

limits thermal NO X 

### formation because of the lower peak flame temperat ure (i.e., combustion occurs over a larger portion of the furnace). For oil-fired boilers, OFA typically reduces

NO X 

### emissions 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 concent ration 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 Page 2



### mixture, resulting in less thermal NO X 

### formation. FGR reduces NO X 

### emissions by about 40 to 60 percent in oil-fired boilers.

Low-NO X 

### burners (LNB) are designed to control fuel/air mix ing and increase heat dissipation. These alternative burners can be inst alled on new boilers or retrofitted on older units. LNB technology integrates staged combustion in the burner. A typical LNB creates a fuel-rich primary combustion zone, thus lowering th e formation of fuel-based NO X 

### . At the

same time, limited combustion air reduces the flame temperature, minimizing the formation

of thermal NO X 

### . Combustion is completed in a lower-temperature, fuel-lean zone. LNB

retrofits have been shown to reduce NO X 

### formation by 30 to 55 percent.

Water or steam can be injected into the boiler comb ustion zone to reduce the peak flame temperature, with a corresponding reduction in ther mal NO X 

### formation. Water/steam injection can reduce NO X 

### emissions by as much as 75 percent in gas-fired bo ilers and slightly less in oil-fired boilers.

Selective Non-Catalytic Reduction (SNCR)

SNCR is a post-combustion technology that involves injecting ammonia or urea into specific temperature zones in the upper furnace or convectiv e pass. The ammonia or urea reacts with

NO X 

### in the flue gas to produce nitrogen and water. Th e effectiveness of SNCR depends on the temperature where reagents are injected, the mi xing of the reagent in the flue gas, the residence time of the reagent within the required t emperature window, the ratio of reagent to

NO X 

### , and the sulfur concentration in the flue gas. (S ulfur in the flue gas, originating from

the sulfur content of the fuel, can combine with am monia to form solid sulfur compounds such as ammonium bisulfate that may become deposite d in downstream equipment.) There is limited commercial experience with SNCR from whi ch to judge its effectiveness for oilfired boilers. NO X 

### reductions of 35 to 60 percent have been achieved through the use of SNCR on some oil-fired boilers operating in the Uni ted States.

Selective Catalytic Reduction (SCR)

SCR is another post-combustion technology that invo lves injecting ammonia into the flue gas in the presence of a catalyst to reduce NO X 

### to nitrogen and water. The SCR reactor can be located at various positions in the process, inc luding 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 o f SCR is influenced by flue gas temperature, fuel sulfur content, ammonia-to-NO X 

### ratio, inlet NO X 

### concentration, space velocity, catalyst design, and catalyst condition. NO X 

### emission reductions of about 75 to 90 percent have been obtained with SCR on coal-fired b oilers operating in the U.S. Although there is little experience with SCR systems on oil- fired boilers, SCR retrofits for oil-fired EGUs using the latest technology would be expected to achieve NO X 

### control efficiencies toward the upper end of this range.

2.1.1 Potential Costs of NO X 

### Controls

The estimated costs of NO X 

### emission controls at Newington Station Unit NT1 ar e presented in Table 2-1. These estimates are based on assumpt ions used in EPA’s Integrated Planning Model for the EPA Base Case 2006 (V.3.0), for retro fitting an electric generating unitBART Analysis – PSNH Unit NT1 January 14, 2011 Page 3



### (EGU) the size of Unit NT1. For low-NO X 

### burners, the total annual cost is estimated to be about $830,000, or $1,470 per ton of NO X 

### removed. With the addition of overfire air, this cost rises to $1,130,000, or $1,600 per ton. For S NCR, 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 p er ton of NO X 

### removed. Because Unit NT1 is primarily a peak-load generator, these estim ates are based on a 20-percent capacity

factor.

Table 2-1. Estimated NO X 

### Control Costs

Control Technology Capital Cost

($/kW) $ 

### O&M Cost ($/yr) 

### Total Annual Cost

($/yr) 

### Average Cost

($/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 from USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model , November 2006. Costs are scaled for boiler size. All costs are adjusted to 2008 dollars.

Total annual cost is for retrofit of a 400-MW unit with 20% capacity factor and 701million kWh annual generation. Total annual cost includes amortizatio n of capital cost over 15 years at 3.0% interest ra te. Average cost per ton is based on the following esti mates of NO X removed: 563 tons for LNB; 704 tons for

LNB+OFA; 704 tons for SNCR; and 1,196 tons for SCR.



### Low-NO X 

### burners have previously been reported to operate i n a cost range of $200 to $500 per ton of NO X 

### removed (NESCAUM, Assessment of Control Technology Options for BART-Eligible Sources , March 2005); however, this cost range is likely t o be more relevant to larger plants operating at higher capacity facto rs than Newington Station.

2.1.2 Other Environmental and Energy Impacts of NO X 

### Controls

SNCR and SCR both use urea or anhydrous ammonia. A mmonia 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 fl ue gases or as fugitive emissions from the handling and storage of urea or anhydrous ammonia. A facility must also maintain a risk management plan if the quantities of stored ammonia exceed the applicable regulatory

threshold.

Ammonia from SNCR that becomes entrained in the fly ash may affect the resale value or disposal cost of the ash. Ammonia in the flue gas may produce a more visible plume, depending on the ammonia concentration in the gas s tream. High ammonia concentrations

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

on the economizer, air heater, and other surfaces. Ammonium bisulfate can also plug filter bags in a baghouse. SNCR may generate nitrous oxid e emissions, a greenhouse gas.

With SCR, the formation of ammonium bisulfate may b e exacerbated by the ability of this catalyst-based technology to oxidize SO 2 

### to SO 3 

### , resulting in higher sulfate concentrations

than would otherwise exist. Ammonium bisulfate for mation can be reduced by controllingBART Analysis – PSNH Unit NT1 January 14, 2011 Page 4



### excess ammonia and using catalysts that minimize SO 2 

### oxidation. The air heater and other surfaces where the ammonia bisulfate may deposit mu st be acid washed periodically. Acid washing helps to maintain the efficiency of the air heater and prevents plugging to allow the free flow of flue gases through it. An SCR may als o require a fan upgrade to overcome extra pressure drop across the catalyst. The incre ase in fan capacity consumes a small amount of energy.

NO X 

### emission reductions provide environmental and publ ic health benefits beyond visibility improvement – most notably, reductions in acid rain and ground-level ozone. NO X 

### is a chemical precursor to ozone formation and is one of the primary compounds contributing directly to acid rain formation. A decrease in aci d rain production improves water quality and the health of ecosystems sensitive to low pH.

2.2 Retrofit Technologies for PM Control

PM control technologies available and potentially a pplicable to Unit NT1 are electrostatic precipitators, fabric filters, mechanical collector s, and particle scrubbers.

Electrostatic Precipitators (ESPs)

Electrostatic precipitators capture particles throu gh 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 ele ctrode (usually a set of individual wires or a grid) and a grounded positively charged plate. In operation, a strong electric charge from the negatively charged electrode sets up a one -directional electric field. When particleladen gases pass through this electric field, the p articles become charged and are then drawn to the positive collecting surface (the plate), whe re they are neutralized. The particles are then collected by washing or knocking the plate, ca using the particles to fall into a collection hopper. Existing electrostatic precipitators are t ypically 40 to 60 percent efficient. New or

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

For older units, options for upgrading an ESP syste m include: replacement of existing control systems with modern electronic controllers; replace ment of old-style wire and plate systems inside the ESP with new, rigid electrode systems; a ddition of new ESP fields; or addition of entire new units (in series). The feasibility of a ny particular upgrade will be influenced by spatial limitations or design constraints on a case -by-case basis.

Fabric Filters

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

containment structure. These devices work on the s ame principal as a vacuum cleaner bag. The particle removal efficiency of the fabric filte r system depends on a variety of particle and operational parameters. The physical character istics of particle size distribution, particle cohesion, and particle electrical resistivity are i mportant variables. Operational parameters affecting collection efficiency include air-to-clot h ratio, operating pressure loss, cleaning sequence, interval between cleanings, and cleaning intensity. The structure of the fabric filter, filter composition, and bag properties also affect collection efficiency. Collection efficiencies of baghouses may exceed 99 percent.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 5



### Mechanical Collectors and Particle Scrubbers

Mechanical collectors, such as cyclones, are most e ffective at collecting coarse particulate matter (i.e., particles with a diameter of 10 micro meters or larger). Finer particles escape cyclones along with the flue gases. For this reaso n, mechanical collectors are generally most useful when used in conjunction with other pol lution control equipment. The typical collection efficiency of mechanical collectors is a bout 85 percent for larger particle sizes.

Scrubbing systems involve the injection of water an d/or chemicals into the flue gas to wash unwanted pollutants from the gas stream through phy sical or chemical absorption/adsorption. Scrubbing systems have been shown to reduce PM 10 

### emissions by 50 to 60 percent but are generally less effective for removal of fine partic les.

Because mechanical collectors and particle scrubber s are more costly and less efficient than other control options (i.e., ESPs, baghouses), thes e lower-performing technologies are rarely used today for removing particulate matter from pow er plant emissions. Consequently,

mechanical collectors and scrubbers are not conside red 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 dev eloped from NESCAUM’s Assessment of Control Technology Options for BART-Eligible Source s , March 2005. Approximate cost ranges are provided for two types of ESPs and two t ypes of fabric filters applicable to a retrofit installation the size of Unit NT1. Capita l and operating costs are based on flue gas flow rates in actual cubic feet per minute (acfm).

Table 2-2

. PM Control Costs

Control Technology Capital Cost

($/kW) $ 

### O&M Cost

($/yr) 

### Total

Annual Cost ($/yr) 

### Average

Cost ($/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 millio n 2.0-3.0 million 4.8-9.6 million 14,000-29,000

Fabric filter – pulse jet 58-194 23.4-78.1 million 2.7-3.9 million 4.7-10.4 million 14,000-31,000

Reference: NESCAUM, Assessment of Control Technology Options for BART-E ligible Sources , March 2005. (Note that these costs were developed for coal-fired boilers.) All costs are adjusted to 2008 dollars. Total an nual cost is for retrofit of a 400-MW unit with 20% capacity factor and flue gas flow rate of 1.71 million acfm. Total annual c ost includes amortization of capital cost over 15 years at 3.0% interest rate. Average cost per ton is based on 14 2 tons of PM removed

for ESPs and 335 tons of PM removed for fabric filt ers.



### The costs for ESPs and fabric filters are of simila r magnitude, with total annual costs ranging from about $3.2 million to $10.4 million, or $14,00 0 to $63,000 per ton of PM removed. Because Unit NT1 already has an ESP installed and o perating, the tabulated costs are useful for comparative purposes only. For facilities with existing ESPs, typical equipment replacement costs to upgrade performance may be in the range of $10,000 to $30,000 per MW. (M. Sankey and R. Mastropietro, “Electrostatic Upgrade Strategy: Get the Most From What You Have,” Hamon Research-Cottrell, Inc., Apri l, 1997.)BART Analysis – PSNH Unit NT1 January 14, 2011 Page 6



### 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 valu e of the fly ash. If the fly ash is not reinjected, it must be either landfilled or reclaim ed, e.g., as a supplement in concrete production or as a component in other manufactured products.

2.3 Retrofit Technologies for SO 2 

### Control

SO 2 

### control technologies available and potentially app licable to Unit NT1 are scrubber systems for flue gas desulfurization, and use of lo w-sulfur coal.

Flue Gas Desulfurization

Scrubber systems use chemical reagents to “scrub” o r “wash” unwanted pollutants from a gas stream. Flue gas desulfurization (FGD) processes b ased 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 ot her air pollutants.

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

SO 2 

### in the flue gas. A PM control device is always lo cated upstream of a wet scrubber.

Lime/limestone scrubbers, sodium scrubbers, and dua l alkali scrubbers are among the commercially proven wet FGD systems. Wet regenerat ive (meaning the reagent material can be treated and reused) FGD processes are an att ractive option because they allow higher sulfur removal rates and produce minimal wastewater discharges.

For coal-fired power plants, the reagent is usually lime or limestone; and the reaction product is calcium sulfite or calcium sulfate. The solid compounds are collected and removed in downstream process equipment. Calcium s ulfate (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 land filled.

SO 2 

### removal efficiencies for existing wet limestone sc rubbers range from 31 to 97 percent with an average of 78 percent (NESCAUM, “Assessment of Control Technology Options for BART-Eligible Sources,” March 2005). For new F GD systems installed at large (>750 MW) coal-fired power plants, the presumptive norm i s 95 percent reduction of SO 2 

### emissions (USEPA, Appendix Y to Part 51

– Guidelines for BART Determinations under the Region al Haze Rule). While experience with FGD systems on s maller, oil-fired EGUs is generally lacking, it is anticipated that such installations would perform at a similar level, achieving

SO 2 

### removal efficiencies of 90 percent or greater.

Dry (or semi-dry) FGD processes are similar in conc ept to wet FGD processes but do not saturate the flue gas stream with moisture. Dry sc rubbers are of two general types: dry sorbent injection and spray dryers. With the former, an al kaline reagent such as hydrated lime or soda ash is injected directly into the flue gas str eam to neutralize the acid gases. In spray dryers, the flue gas stream is passed through an ab sorber tower in which the acid gases are absorbed by an atomized alkaline slurry. The SO 2 

### removal efficiencies range from 40 to 60 percent for existing dry injection systems and from 60 to 95 percent for existing lime sprayBART Analysis – PSNH Unit NT1 January 14, 2011 Page 7



### dryer systems (NESCAUM, 2005). A PM control device (ESP or fabric filter) is always installed downstream of a dry or semi-dry scrubber to remove the sorbent from the flue gas.

Low-Sulfur Fuels

Because SO 2 

### emissions are directly related to the sulfur conte nt of the fuel burned, reducing

the amount of sulfur in the fuel reduces SO 2 

### emissions. For facilities that burn fuel oil, switching to a lower-sulfur fuel may be a cost-effe ctive control option. Switching from high-sulfur residual fuel oil to low-sulfur residua l 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, increa sing the use of natural gas is another effective control strategy. Sulfur dioxide emissio ns from burning natural gas are negligible in comparison to those from burning fuel oil. When substituting natural gas for fuel oil, the resulting SO 2 

### emission reductions are roughly proportional to th e fraction of natural gas burned on a Btu-equivalent basis.

2.3.1 Potential Costs of SO 2 

### Controls

There is little or no experience with, or cost data on, flue gas desulfurization at oil-fired power plants. However, the technology is similar t o FGD for coal-fired plants. Therefore, the costs of an FGD system for PSNH Newington Stati on may be crudely approximated by extrapolating from the costs of FGD for PSNH Merrim ack Station.

The flue gas desulfurization system at Merrimack St ation is being installed to reduce mercury emissions (with SO 2 

### removal as a co-benefit) at its two coal-fired boi lers. These units have a combined generating capacity of 433 MW , or slightly greater than the capacity of Newington Station Unit NT1. The company’s capit al cost estimate for the wet limestone FGD system is $457 million, or $1,055/kW (both amou nts in 2008$), 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 FGD systems as reported in MACTEC Federal Progr ams, Inc., “Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I Areas ,” Final, July 9, 2007 (see Reasonable Progress Report, Attachment Y). The PSN H estimated cost is also more than double the estimate of $300/kW to $500/kW as report ed in a 2008 survey of FGD systems (George W. Sharp, “What’s That Scrubber Going to Co st?,” Power , March 1, 2009). The higher cost-per-kW for Unit MK2 may reflect industry-wide increases in raw material, manufacturing, and construction costs but may also reflect site-specific factors such as unit size, type, and difficulty of retrofit.

Using the latest Merrimack Station estimate of $1,0 55/kW for scaling purposes, the total capital cost of a wet limestone FGD system for Newi ngton 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 FGD on oil-fired b oilers previously has been estimated to be

about twice the cost of FGD on coal-fired boilers of comparabl e 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 pre vailing market prices. The long-term price differential between 1.0%-sulfur (low-S) resi dual fuel oil and 2.0%-sulfur residual fuel oil is estimated to be about 7.5 cents/gallon. The differential between 0.5%-sulfur (ultralow-S) residual fuel oil and 2.0%-sulfur residual f uel oil is estimated to be about twice thisBART Analysis – PSNH Unit NT1 January 14, 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.) Usi ng these unit prices, the total cost of switching to low-S residual fuel oil is approximate ly $3.3 million per year, or $1,900 per ton

of SO 2 

### emissions removed; and the cost of switching to ul tra-low-S residual fuel oil is approximately $6.6 million per year, or also $1,900 per ton of SO 2 

### emissions removed (both estimates based on 2002 actual fuel oil usage; note that fuel oil usage in 2006-2009 has been below 2002 levels). These results imply that the c osts of switching fuel oils may be relatively constant on a $/ton basis as long as supplies are a dequate.

Table 2-3 summarizes the approximate costs of flue gas desulfurization and fuel switching

as SO 2 

### control options for PSNH Newington Station Unit NT 1. The costs for switching

from 2.0%-S residual fuel oil to 1.0%-S or 0.5%-S r esidual 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. SO 2 

### Control Costs

Control Technology Capital Cost

($/kW) $ 

### O&M Cost

($/yr) 

### Total

Annual Cost ($/yr) 

### Average

Cost ($/ton)



### FGD 1,055 422,000,000 unknown unknown unknown

Switch to 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 FGD is based on reported cost per kilowatt-hour for FGD system at PSNH Merrimack Station. Actual costs for Newington Stat ion could be much higher. O&M costs for fuel switching are based on 2002 annual fuel usage of 44 ,140,000 gallons and estimated fuel price different ial

of 7.5 or 15 ¢ /gallon for substitution of 1.0%-S or 0.5%-S residu al fuel oil, respectively.



### In a similar analysis performed independently by PS NH (see attached letter), the company has estimated the costs of fuel 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 9/0 9.



### _________________ ‡ Platts, a division of The McGraw-Hill Companies, i s a provider of energy information services.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 9



### Using this historical fuel price record and PSNH’s calculated SO 2 

### emission reductions from fuel switching, the New Hampshire Department of Env ironmental Services (NHDES) has prepared alternate estimates of the increased costs of fuel switching from 2.0%-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. Th is 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-effectiv eness of switching to 0.5%-sulfur residual fuel oil appears reasonable as long as supplies rem ain stable. Switching to 0.3%-sulfur fuel oil could also prove reasonable in the future if pr ices were to stay within their recent historical range and future supplies could be assur ed.

Table 2-5. Costs of Fuel Switching Based on Histor ical Fuel Oil Prices

Increased Cost ($/barrel) Increased Cost

($/hour)** $/ton of

SO 2 

### Removed*** Fuel

Switch SO 2 

### Emission

Reduction* (lb/hr) low high low high low high

**** 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 12,9 57

2% to 0.7% 6,699.0 2 7 1,34 4,712 402 1,407

**** 2% 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, from PSNH letter dated December 4, 2009.

** $/barrel ÷ 42 gal/barrel ÷ 0.153846 MMBtu/gal × MMBtu/hr = $/hr

*** $/hr ÷ lb/hr × 2000 lb/ton = $/ton



### Besides switching residual fuel oils to reduce SO 2 

### 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 duri ng startup of Unit NT1, the boiler is not designed to operate routinely on this fuel; and ret rofitting the boiler for this purpose would involve major capital expenditure. Burner replacem ents to combust distillate fuel oil could exceed $20 to $30 million (approximately $1 to 2 mi llion per burner) in direct capital costs, not including the additional costs of engineering a nd any required auxiliary equipment.

The cost determinations associated with using natur al 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 tim e. 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 maximum heat inp ut, 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 maximum heat input from natural gas, with no corres ponding limitation on liquid fuel.) Firing Unit NT1 entirely with natural gas might be technically feasible but would require more than just burner replacements: it would require mod ifications to other major boiler components or replacement of the entire boiler. Su ch measures cannot be economically justified. However, using natural gas – to the ext ent that Unit NT1 can burn this fuel with existing equipment – remains a viable option as lon g as the cost of this fuel is competitive

with the cost of residual fuel oil and biofuel.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 10



### Volatile energy commodity prices in recent years an d the uncertainty of future fuel prices make it difficult to provide a useful estimate of t he cost of substituting natural gas for residual fuel oil. As seen in Figure 2-1, past prices of na tural gas and petroleum fuels, on a BTUequivalent basis, exhibit similar trends; but the p rice differentials show wide variation from year to year. Consequently, no cost estimate for t his fuel switching option is presented.

Figure 2-1. Comparison of Fossil Fuel Prices for E lectric Generation

in New England (1990-2008)

Data source: Energy Information Administration, For m EIA-923, "Power Plant Operations Report.”

http://www.eia.doe.gov/cneaf/electricity/st_profile s/e_profiles_sum.html



### 2.3.2 Other Environmental and Energy Impacts of SO 2 

### Controls

An FGD system typically operates with high pressure drops across the control equipment, requiring increased energy usage for blowers and ci rculation pumps. Some configurations of FGD systems also require flue gas reheating to p revent operational problems (including physical damage to equipment), resulting in higher fuel usage per unit of net electrical generation. Documentation for EPA’s Integrated Pla nning Model (IPM®) indicates that a wet FGD system reduces the generating capacity of t he unit by about 2 percent.

Flue gas desulfurization has impacts on the operati on of solid waste and wastewater management systems. In addition to removing SO 2 

### , the FGD process removes mercury and other metals and solids. Often, gypsum produced in a limestone FGD process is recycled or sold to cement manufacturers; otherwise, the sludge must be stabilized and placed in an approved landfill. Gypsum must be dewatered before it can be handled, resulting in a wastewater stream that requires treatment. This wa stewater stream increases the sulfates, metals, and solids loadings on the receiving wastew ater treatment plant. Sometimes an additional clarifier is required to remove wastewat er solids coming from the FGD system.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 11



### Wet FGDs increase the amount of water vapor entrain ed in the flue gas. The result is a lower stack exit temperature and a more visible plu me at the stack outlet. Switching to lower-sulfur fuel oil generally reduce s boiler maintenance requirements because less particulate matter is emitted. With f ewer material deposits occurring on

internal boiler surfaces, the intervals between cle anings/outages can be longer. Also,

because lower-sulfur oil reduces the formation of s ulfuric acid emissions, corrosion is reduced and equipment life is extended.

3. DISCUSSION OF CURRENT POLLUTION CONTROL EQUIPMENT A ND EMISSIONS



### 3.1 Discussion of Current NO X 

### Emissions and Controls

PSNH Newington Station Unit NT1 currently operates with low-NOx burners, an overfire air system, and water injection to minimize NO X 

### formation. For compliance with NO X 

### RACT requirements, the facility’s existing air perm it limits NO X 

### emissions from this unit to a daily average of 0.35 lb/MMBtu when burning oil a nd 0.25 lb/MMBtu when burning a combination of oil and gas. NHDES reviewed emissio ns data for Unit NT1 for the period from 2003 to 2005, when more than 99 percent of the gross heat input came from residual fuel oil. Monthly average NO X 

### emissions ranged between 0.21 and 0.30 lb/MMBtu. These values compare favorably with the facility’s NO X 

### RACT limits. Actual NO X 

### emissions from

this unit were 943 tons in 2002.

3.2 Discussion of Current PM Emissions and Controls

Unit NT1 has an electrostatic precipitator to captu re PM emissions. In an EPA inspection report on this unit from December 15, 1989, a table of design values for the ESP listed a particulate removal efficiency of 93 percent. It i s unknown whether the stated efficiency is representative of actual long-term performance. Th e facility’s air permit (TV-OP-054,

March 9, 2007; administrative amendment, December 1 7, 2007) sets an emission limit of 0.22 lb/MMBtu total suspended particulate matter (f ilterable TSP). The single available

stack test on Unit NT1 measured a controlled TSP em ission rate of 0.058 lb/MMBtu, which is well below the permit limit. The tested emission r ate lies within the expected range for a properly operating ESP at a plant like Newington an d may serve as a better measure of performance than any stated efficiency for this con trol device. Actual TSP emissions from

Unit NT1 were 198 tons in 2002.

3.3 Discussion of Current SO 2 

### Emissions and Controls

Sulfur dioxide emissions are partially controlled a t 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 NT1 does not have an

individual limitation on sulfur dioxide emissions b ut is subject to an annual cap of 55,150

tons of SO 2 

### for all electrical generating units at PSNH’s Merr imack, Newington, and

Schiller Stations combined. Actual SO 2 

### emissions from Unit 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 of values from the most recent decade. In 2009, the average was 1.0%.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 12



### 4. REMAINING USEFUL LIFE OF UNIT

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

controlled in a manner consistent with BART and the expected useful life of the unit. Originally, electric generating units were estimate d 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 replace ment facilities and/or new transmission lines. Newington Station Unit NT1 was built in 196 9. However, because this facility runs primarily on fuel oil, its remaining useful life ma y depend more on future commodity supplies/prices and other external factors than on the longevity of plant equipment.

5. DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FRO M BART

NHDES performed a set of CALPUFF model runs for the New Hampshire BART-eligible

sources under controlled and uncontrolled condition s. The same methodologies used for the CALPUFF modeling work for Merrimack Station Unit MK 2 were applied to the modeling for Newington Station Unit NT1.

In previous modeling, MANE-VU used CALPUFF to assis t in the identification of BARTeligible sources. This modeling assumed natural vi sibility conditions (about 7 dv) to produce the most conservative results possible, thereby min imizing the number of sources that would “model out” of BART requirements. Under these cond itions, uncontrolled emissions from Unit NT1 produce theoretical CALPUFF worst-case imp acts of 1.22 dv at Acadia National Park. EPA considers it acceptable to exempt source s when this form of conservative modeling indicates that a source produces less than 0.5 dv of impact. MANE-VU considers an exemption level of 0.2 to 0.3 dv to be more appr opriate but prefers, and has applied, an even more conservative exemption level of 0.1 dv. CALPUFF modeling results for baseline emissions from Unit NT1 exceed all of these exempti on levels. The CALPUFF-predicted visibility benefits from BART controls on 20% best and 20% worst visibility days are presented in Table 5-1.

As seen in the table, more benefit would result gen erally from SO 2 

### emission reductions than NOx emission reductions. This finding reinfor ces MANE-VU’s early determination

that SO 2 

### was the primary target pollutant for maximizing vi sibility improvements. NO X 

### , while also an important visibility impairing pollut ant, reacts with ammonia less preferentially than does SO 2 

### and is also less hydrophilic than SO 2 

### . As a result, NO X 

### has a lower rate of formation of haze-causing particles a nd impairs visibility less effectively than a

similar mass of SO 2



### .BART Analysis – PSNH Unit NT1 January 14, 2011 Page 13



### Table 5-1. CALPUFF Modeling Results for Newington Station Unit NT1:

Visibility Improvements from BART Controls

On the 20% Best Visibility Days (deciviews)

Pollutant Control Level Acadia Great Gulf Lye Brook

FGD (90% sulfur reduction*) 0.57 0.45 0.09

1.0%-S residual fuel oil (50% sulfur reduction*) 0.30 0.24 0.05

0.5%-S residual fuel oil (75% sulfur reduction*) 0.46 0.36 0.07

0.3%-S residual fuel oil (85% sulfur reduction*) 0.52 0.40 0.08

0.50 lb SO 2 /MMbtu (77% sulfur reduction*) 0.47 0.37 0.08 SO 2

Switch from 0.50 lb SO 2 /MMbtu emission limit to 0.3%S residual fuel oil <0.05 0.03 <0.01***

SNCR (25% NOx reduction**) 0.11 0.10 0.04 NOx

SCR

(78% NOx reduction**) 0.34 0.30 0.12

PM Baghouse

(85% PM reduction**) 0.05 0.04 0.01



### On the 20% Worst Visibility Days (deciviews)

Pollutant Control Level Acadia Great Gulf Lye Brook

FGD (90% sulfur reduction*) 0.13 0.10 <0.01***

1.0%-S residual fuel oil (50% sulfur reduction*) 0.07 0.06 <0.01***

0.5%-S residual fuel oil (75% sulfur reduction*) 0.11 0.09 0.01

0.3%-S residual fuel oil (85% sulfur reduction*) 0.13 0.10 0.01

0.50 lb SO 2 /MMbtu (77% sulfur reduction*) 0.11 0.09 0.01 SO 2

Switch from 0.50 lb SO 2 /MMbtu emission limit to 0.3%S residual fuel oil 0.01 0.01 <0.01***

SNCR (25% NOx reduction**) 0.04 0.03 0.01 NOx

SCR

(78% NOx reduction**) 0.11 0.10 0.03

PM Baghouse

(85% PM reduction**) 0.02 0.02 <0.01***

* from maximum permitted level

** from baseline level with existing controls *** below sensitivity limit of model

Note: Values in boldface are considered as having greater validity in the mo deling estimation of maximum visibility benefits from BART controls.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 14



### 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 CALGRID photochemical air quality model w as performed to assess the effects of switching to lower-sulfur fuel for this unit. The simulation covered the full summer modeling episode (from May 15 to September 15, 2002 ) with MANE-VU’s 2018 beyondon-the-way (BOTW) emissions inventory scenario as a baseline.

The CALGRID model outputs took the form of ambient concentration reductions for SO 2 

### , PM 2.5 

### , and other haze-related pollutants within the regi on. NHDES post-processed the

modeled concentration reductions to estimate the co rresponding visibility improvements at nearby Class I areas (i.e., concentration impacts w ere converted to visibility impacts).

Based on the modeling results, switching to lower-s ulfur fuel oil for Unit NT1 is expected to

reduce maximum predicted 24-hour average SO 2 

### concentration impacts by about 1.4 μ g/m 3



### . Reductions in the maximum predicted concentrations of SO 2 

### , PM 2.5 

### , and other haze-related pollutants, combined, would yield negligible visibi lity improvement at the affected Class I

areas.

6. DETERMINATION OF BART

Based on the completed review and evaluation of exi sting and potential control measures for PSNH Newington Station Unit NT1, it is determined t hat the NO X 

### , PM, and SO 2 

### controls described below represent Best Available Retrofit T echnology for this unit.

6.1 Selecting a Pollution Control Plan for NO X



### Use of low excess air reduces NO X 

### emissions but can often result in greater PM and/o r CO emissions. Many of the NO X 

### reduction benefits acquired through the implementa tion of low excess air are already being achieved at Unit NT1 t hrough the use of low-NOx burners, overfire air, and water injection; so the applicati on 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 r educing the oxygen content in the combustion zone, leading to further reductions in N O X 

### formation. Because Unit NT1 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 NO X 

### emission reductions being achieved at Unit NT1 thr ough the use of combustion control technologies are a substantial improvement over no controls. Retrofitting the facility

with SCR or SNCR would reduce NO X 

### emissions by an additional 300 to 700 tons per yea r. Despite the sizeable emission reductions that SCR o r SNCR would provide, with annualized costs of $0.7 to $1.3 million, neither technology o ption could be implemented costeffectively. Note that these dollar amounts do not include the significant additional costs of redesigning Newington Station’s layout to address s patial constraints. Also, the estimated costs are based on 2002 emission levels, when the p lant’s capacity factor was around 20 percent. With the capacity factor having fallen to less than 10 percent over the period 2006- 2009, it is difficult to justify additional technol ogy retrofits to reduce NO X 

### emissions at this facility today. This conclusion is reinforced by t he small improvement in visibility thatBART Analysis – PSNH Unit NT1 January 14, 2011 Page 15



### might be obtained with such retrofits on the few oc casions when meteorological conditions would indicate maximum impacts.

Another consideration with SCR or SNCR is flue gas and fugitive ammonia emissions. Based on past operation of Unit NT1 and on typical ammonia “slip” rates, it is estimated that fugitive ammonia emissions with either technology w ould be in the vicinity of 32 tons annually. Ammonia is a regulated toxic air toxic p ollutant 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 relative ly minor negative to be weighed in the

context of other factors.

Based on all of these considerations, NHDES finds t hat SCR and SNCR are not cost-effective as Best Available Retrofit Technology for NO X 

### control at this facility and will not be evaluated further. The existing NO X 

### controls, which include low-NOx burners, overfire air, and water injection, are determined to fulfill BART requireme nts for Newington Station Unit NT1.

Because additional retrofits are not proposed, comp letion of the BART assessment for Unit NT1 becomes a matter of ascertaining this facility’ s long-term performance capability with existing equipment. NHDES reviewed emissions data for Unit NT1 for the period from 2003 to 2005, when more than 99 percent of the gros s heat input came from residual fuel oil. Monthly average NO X 

### emissions ranged between 0.21 and 0.30 lb/MMBtu. These values compare favorably with the facility’s NO X 

### RACT limit of 0.25 lb/MMBtu, daily average, when burning natural gas and 0.35 lb/MMBtu, daily a verage, when burning fuel oil.

However, the extent of the data record is insuffici ent to demonstrate that the facility could sustainably meet more restrictive emission limits t han these. The current NO X 

### RACT

limitations for Unit NT1 are therefore considered t o represent BART control levels.

6.2 Selecting a Pollution Control Plan for PM

PSNH currently operates an electrostatic precipitat or on Unit NT1. ESPs perform with removal efficiency rates similar to those of fabric filters but operate at about half the cost for plants of this size. Although it may be technicall y feasible to improve performance of the existing ESP through some form of upgrade, it is di fficult to justify any major capital expense at this facility in light of its recent operating h istory. Since 2006, the plant’s capacity factor has been below 10 percent. In consideration of the facts that Unit NT1 already operates a fully functional ESP, that additional capital outla y for PM control cannot be economically justified at this time, and that any resulting bene fit to visibility would be negligible, it is determined that the existing ESP fulfills BART requ irements.

The single available stack test on this unit indica tes that the ESP yields controlled TSP emission rates in the vicinity of 0.06 lb/MMBtu ver sus a currently permitted rate of 0.22

lb/MMBtu. The extent of the data record is insuffi cient to support consideration of a BART performance level more restrictive than the existin g permit limit. The facility’s Title V operating permit requires that a compliance stack t est for PM emissions be performed on Unit NT1 before the permit expires on March 31, 201 2. NHDES will review the stack test results to ascertain the unit’s performance and inc orporate any new limit into a permit amendment by the permit expiration date, as appropr iate. The permit expiration date precedes the effective date of proposed BART contro l measures by fifteen months.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 16



### 6.3 Selecting a Pollution Control Plan for SO 2



### Flue gas desulfurization is a potential SO 2 

### control option for PSNH Newington Station Unit NT1. However, the cost per ton for FGD on oil-fire d boilers is estimated to be about twice the cost of this technology on coal-fired boilers a nd could well exceed $1,000/kW for Newington Station. Given the high costs of this op tion, it is apparent that FGD would be uneconomical as a retrofit for a peak-demand plant the size of Unit NT1.

Use of a lower-sulfur fuel is a practical option fo r controlling SO 2 

### emissions at Newington Station. When natural gas is available at reasonab le cost relative to residual fuel oil, natural gas is the preferred fuel because of its very low s ulfur content. Otherwise, use of low-sulfur residual fuel oil is a reasonable option. For rela tively minor increases in the cost of fuel, switching to 1.0%-sulfur or 0.5%-sulfur residual fu el oil would provide significant reductions in fuel sulfur content with proportional reductions in SO 2 

### emissions.

When not firing exclusively on natural gas, Newingt on Station Unit NT1 has traditionally burned No. 6 fuel residual fuel oil at 2.0 percent (nominal) sulfur content. From 2002 to 2009, the actual average annual sulfur content of t he fuel oil ranged between 1.03 and 1.54 percent by weight, with no significant trend (avera ge fuel sulfur content was 1.21 percent in 2002). For New Hampshire’s BART analysis of this p lant, the following fuel sulfur values

were assumed:

Nominal %S

(permit limitation) Assumed Actual %S (chemical assay)

2.0 1.2

1.0 0.8

0.5 0.4

Under these assumptions, switching from 2.0 %S (nom inal) to 1.0 %S (nominal) residual fuel oil would produce a one-third reduction in sul fur 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 w ithout 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 $2,000 per ton). At the 2002 production level of 7 00 million kilowatt-hours, estimated annual costs (long-term average, 2008$) for switchi ng 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 var y more or less in proportion to the fuel price differential and would not change significant ly 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 a s 0.5 percent. Residual fuel oil at 1.0% sulfur is already widely distributed within the reg ion; and there is greater assurance today of the availability 0.5%-sulfur residual fuel oil than in 2008, when New Hampshire began drafting its BART determinations. Maine, Massachus etts, New Jersey, and other states within MANE-VU are moving toward or already require the use of 0.5%-sulfur residual fuel oil, thus ensuring the presence of a regional marke t for this commodity.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 17



### NHDES considered the possible use of 0.3%-sulfur re sidual fuel oil for Unit NT1; but this fuel has had only very limited use within the northern N ew 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, which obtains its bulk oil sh ipments through different ports.

For Unit NT1, the possible use of low-sulfur residu al fuel oil is complicated by the plant’s low capacity factor and existing fuel stocks and st orage facilities. The plant now has a sizeable quantity of higher-sulfur residual fuel oi l in storage tanks on site. Because there is no practical way to offload and replace the existin g inventory with a lower-sulfur residual fuel oil, the existing stock of higher-sulfur fuel oil would 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 and capacity factor in the coming years (its capacity factor was less than 7 percent in 2009). Given this scenario, depletion of the existing stock of residual fuel oil could take more than a year, or substantially longer if the facility co-fires with natural gas to reduce sulfur dioxide emissions.

EPA has suggested greater use of natural gas and/or low-sulfur distillate fuel oil for Unit NT1 in place of residual fuel oil. The substitution of No. 2 distillate fuel oil for No. 6 residual fuel oil would not be practical for this facility f or two major reasons: the high cost of burner replacements needed to implement this option, and t he plant’s low utilization rate and capacity factor. Unit NT1 would produce relatively few kilowatt-hours of generation through which to recover capital costs.

Greater use of natural gas is a reasonable option w hen its price is competitive with that of residual fuel oil. Recent years have witnessed sud den and dramatic swings in the price of natural gas relative to fuel oil as supply/demand h as shifted. While the future price and availability of natural gas remain difficult to dis cern, the market for natural gas is expected to expand amid global concerns about carbon emissions and a visible renaissance in gas exploration and development.

Unit NT1 has considerable operational flexibility w ith 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 o f 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 n atural incentive for PSNH to operate Unit NT1 with natural gas as much as possible whenever t he price of this 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 s ulfur dioxide emission limitation of 0.50

lb/MMBtu § 

### applicable to any fuel type or mix. The recently adopted rule (Attachment GG) will allow the facility the flexibility to burn nat ural gas and/or fuel oil in any feasible ratio, depending on market conditions.

_________________ § This limit is calculated using USEPA’s published A P-42 emission factor for SO 2 of 150(S) lb SO 2 /1000 gallons. Assuming 0.5% fuel sulfur content by weig ht and a heating value of 150,000 Btu/gallon for No . 6 fuel

oil, the SO 2 emission rate would be 150 × 0.5 = 0.075 lb/gallon, and the SO 2 emission factor would be 0.075

lb/gallon ÷ 150,000 BTU/gallon × 10 6 = 0.5 lb/MMBtu.BART Analysis – PSNH Unit NT1 January 14, 2011 Page 18



### New Hampshire’s new rule will cause a substantial r eduction in SO 2 

### emissions from Unit NT1 regardless of fuel type while rendering unneces sary any need to speculate on the direction of relative fuel supplies and prices. Fo r the first regional haze progress report, due

no later than December 17, 2012, NHDES will review fuel usage, fuel supplies, fuel prices, and plant utilization/capacity factors to determine whether the fuel sulfur limitation described above is still appropriate as BART contro l for Unit NT1. Should the review

indicate a different BART control level, the facili ty’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 measure s. The use of low- or ultra-low-sulfur residual fuel oil will be reconsidered as part of t his 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 lev els to 0.25-0.5% for all residual fuel oils throughout the region by 2018 (refer to “State ment of the Mid-Atlantic/ Northeast Visibility Union (MANE-VU) Concerning a Course of A ction within MANE-VU toward Assuring Reasonable Progress,” June 20, 2007, inclu ded in Attachment E).

7. SUMMARY AND CONCLUSIONS

Table 7-1 summarizes Best Available Retrofit Techno logy for PSNH Newington Station Unit NT1 for the pollutants NO X 

### , PM, and SO 2 

### . The summary includes existing controls that have been determined to fulfill BART requireme nts as well as new operating conditions consistent with BART requirements. A more stringen t sulfur dioxide emission limitation, established by a rule change, will require the faci lity to reduce average fuel sulfur content through appropriate adjustments to its fuel mix.

Table 7-1. Summary of BART Determinations for Unit NT1

Pollutant Current Emission

Controls BART Controls BART

Emission Limit

NO X 

### Low-NOx burners,

overfire air, and water injection Low-NOx burners,

overfire air, and water injection 0.35 lb/MMBtu (oil) and 0.25 lb/MMBtu (oil/gas), daily avg. (= RACT limit)

PM ESP ESP 0.22 lb/MMBtu total suspended particulate

(TSP)

SO 2 

### 2.0% sulfur content limit

on residual fuel oil;

0.4% sulfur content limit

on distillate fuel oil SO 2 

### emission limitation of

0.50 lb/MMBtu, applicable to any fuel type

or mix 0.50 lb/MMBtu, 30-day rolling averageBART Analysis – PSNH Unit NT1 January 14, 2011 Page19NEW HAMPSHIRE BART ANALYSIS: Newington Station Unit NT1 (400 MW)Estimated Cost of Emission Controls6UncontrolledEmissionsControlledEmissionsEmissionReductionsPollutantEmission ControlTechnologyApprox.ControlLevelton/yr ton/yr ton/yrCapital$Capital$/kWO&M$/yrTotal Annual$/yrAverage$/tonRef./NoteCombustion Controls (existing)33%1,40719432464    LNB (typical) 40%1,40718445637,905,61720167,052829,3061,4737LNB+OFA (typical) 50%1,407170470410,732,57427228,2151,127,2831,6027SCR 85%1,40712111,19611,510,10037441,6851,405,8861,1757NOXSNCR 50%1,40717047043,298,47512451,026727,3391,0347ESP (existing) 42%33821962142    min.23,426,952592,733,1444,695,62014,033PMFabric Filters 99%33823335max.78,089,8401953,904,49210,446,07831,21882.0%-S oil (existing) 0%35,2262    Switch to 1.0%-S oil 33%45,22623,4841,742  3,310,8081,9019Switch to 0.5%-S oil 67%55,22621,7423,484  6,621,6151,90110SO2FGD 90%5,22625234,703422,000,0001,055unknown unknown unknown111Estimated.22002 (baseline) emissions reported in NHDES data summary as derived from facility's annual emissions statement.3Actual average fuel sulfur content was ~1.2% in 2002. Over period 2002-09, average annual values ranged from 1.03 to 1.54% S with no significant trend.4Based on an assumed average fuel sulfur content of0.8%.5Based on an assumed average fuel sulfur content of0.4%.6All cost estimates adjusted to 2008$.7USEPA,Documentation for EPA Base Case 2006 (V.3.0) Usingthe Integrated Planning Model, November 2006.8NESCAUM,Assessment of Control Technology Options for BART-Eligible Sources, March 2005.9Stated costs represent premium for purchasing 1.0%-S oil at estimated price differential of 7.5¢/gal.10Stated costs represent premium for purchasing 0.5%-S oil at estimated price differential of 15¢/gal.11Based on $/kW estimated capital cost for comparablecontrols at Merrimack Station.BART Analysis – PSNH Unit NT1 January 14, 2011 Page20Newington Station Unit NT1: NOXControlsPlant type oil- or natural-gas-fired boiler Historical operation:Capacity 400 MW Year 2002 2003 2004 2005 2006 2007 2008Maximum heat Input 4,350 MMBtu/hr Operating hours3,085 6,606 6,300 4,187 1,282 1,374 548Capacity factor 20 % Total Heat Input* 7,223,83226,414,481 22,477,521 16,060,698 3,600,581 4,303,867 1,231,841Annual hours 8,760 hr/yr Capacity factor** 19.0%69.3% 59.0% 42.1% 9.4% 11.3% 3.2%Annual production 700,800,000 kWh/yr *MMBtu (fromCEM data) **Based on ratio of total heat input to theoretical maximum heat inputCosts: 2004$CapitalScaledCapitalTotalCapitalTotalAnnualizedCapitalFixedO&MScaled FixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh $/yr $/yr $/yr tons/yr $/tonLNB 19.24 17.4 6,940,840 581,434 0.29 0.26 104,6180.06 42,048 146,666 728,100 563 1,293LNB+OFA 26.12 23.6 9,422,804 789,348 0.40 0.36 144,300 0.08 56,064 200,364 989,713 704 1,406SCR 32.20 25.26 10,105,443 846,533 0.99 0.78 310,695 0.11 77,088 387,783 1,234,316 1,196 1,032SNCR 10.80 7.24 2,895,939 242,593 0.17 0.11 45,5840.50 350,400 395,984 638,577 704 907Costs: 2008$2004$→2008$1.139 multiplierCapitalScaledCapitalTotalCapitalTotalAnnualizedCapitalFixedO&MScaled FixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh $/yr $/yr $/yr tons/yr $/tonLNB 21.91 19.76 7,905,617 662,254 0.33 0.30 119,1600.07 47,893 167,052 829,306 563 1,473LNB+OFA 29.75 26.83 10,732,574 899,068 0.46 0.41 164,358 0.09 63,857 228,215 1,127,283 704 1,602SCR 36.68 28.78 11,510,100 964,201 1.13 0.88 353,882 0.13 87,803 441,685 1,405,886 1,196 1,175SNCR 12.30 8.25 3,298,475 276,313 0.19 0.13 51,9200.57 399,106 451,026 727,339 704 1,034Cost Reference: Annualized cost basis:Period, yrs 15Interest, % 3.0USEPA,Documentation for EPA Base Case2006 (V.3.0) Using the Integrated PlanningModel, November 2006.Note: Cost estimates for LNB and LNB+OFA are basedonreferenced values for coal-fired plants; actual costs could begreater for oil- or gas-fired units.CRF 0.08377BART Analysis – PSNH Unit NT1 January 14, 2011 Page21Newington Station Unit NT1: PM ControlsPlant type oil- or natural-gas-fired boiler Historical operation:Capacity400MW Year 2002 2003 2004 2005 2006 2007 2008Maximum heat Input 4,350MMBtu/hr Operating hours 3,085 6,606 6,300 4,187 1,282 1,374 548Capacity factor 20% Total Heat Input* 7,223,832 26,414,48122,477,52116,060,6983,600,581 4,303,867 1,231,841Annual hours 8,760hr/yr Capacity factor** 19.0% 69.3% 59.0% 42.1% 9.4% 11.3% 3.2%Annual production 700,800,000kWh/yr *MMBtu (from CEM data) **Based on ratio oftotal heat input to theoretical maximum heat inputFlue gas flow rate1,714,000acfm2004$CapitalTotalCapitalTotalAnnualizedCapitalFixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr$/ton Cost Reference:min.15.0025,710,000 2,153,7270.250.451,199,8003,353,52714223,616Dry ESPmax.40.0068,560,000 5,743,2710.650.602,142,5007,885,77114255,534min.15.0025,710,000 2,153,7270.150.25685,6002,839,32714219,995NESCAUM,Assessment of ControlTechnology Options for BARTEligible Sources, March 2005.Wet ESPmax.40.0068,560,000 5,743,2710.500.501,714,0007,457,27114252,516min.17.0029,138,000 2,440,8900.350.701,799,7004,240,59033512,673Annualized cost basis:Fabric Filter -Reverse Airmax.40.0068,560,000 5,743,2710.750.802,656,7008,399,97133525,103Period, yrs 15min.12.0020,568,000 1,722,9810.500.902,399,6004,122,58133512,320Interest, % 3.0Fabric Filter -Pulse Jetmax.40.0068,560,000 5,743,2710.901.103,428,0009,171,27133527,408CRF0.08377Costs: 2008$2004$→2008$1.139multiplierCapitalTotalCapitalTotalAnnualizedCapitalFixedO&MVariableO&MTotal Fixed& VariableO&MTotalAnnualizedCostEmissionReductionsAverageCostControlTechnology$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr$/tonmin.17.0929,283,6902,453,0950.280.511,366,5723,819,66714226,899Dry ESPmax.45.5678,089,8406,541,5860.740.682,440,3088,981,89314263,253min.17.0929,283,6902,453,0950.170.28780,8983,233,99314222,775Wet ESPmax.45.5678,089,8406,541,5860.570.571,952,2468,493,83214259,816min.19.3633,188,1822,780,1740.400.802,049,8584,830,03233514,434Fabric Filter -Reverse Airmax.45.5678,089,8406,541,5860.850.913,025,9819,567,56733528,592min.13.6723,426,9521,962,4760.571.032,733,1444,695,62033514,033Fabric Filter -Pulse Jetmax.45.5678,089,8406,541,5861.031.253,904,49210,446,07833531,218BART Analysis – PSNH Unit NT1 January 14, 2011 Page22Newington Station Unit NT1: SO2ControlsSO2Control Cost Calculations for Switching from #6 Fuel Oil @ 2.0% S to Lower-Sulfur Fuel Oils @ 1.0 or0.5% S:Maximum(Nominal)Fuel Sulfur1ActualFuel SulfurAnnualFuel Usage4Annual SO2EmissionsSwitch toLower-S FuelAnnual SO2EmissionReductions7BlendedFuel Price Differential8SO2ControlCostFuel Type%S by wt %S by wt gal/yr ton/yr %S by wt ton/yr ¢/gal $/yr $/ton removed#6 Residual Oil 2.01.2244,144,100 5,2265   #6 ULS Residual Oil 1.00.8344,144,100 3,48462.0 to 1.0%1,7427.59$3,310,808$1,901#6 ULS Residual Oil 0.50.4344,144,100 1,74262.0 to 0.5% 3,484 15.010$6,621,615 $1,9011Maximum allowable sulfur content of specified fuel.2Actual average sulfur content of fuel burned in 2002. In the period 2002-09, average annual values ranged from 1.03 to 1.54% S with no significant trend.3Assumed average sulfur content of specified fuel asassayed.4Actual fuel usage in 2002.5Actual 2002 emissions from CEM data.6Estimated emissions based on stated fuel usage andestimated average sulfur content of specified fuel.7Estimated emission reductions after switch to specified lower-sulfur fuel.8Estimated price difference between residual oil @ >1.0%S and residual oil @≤1%S, based on EIA fuel price data for all U.S. locations, 1983-2008.9Estimated price difference between fuel @ 1.2%S (2002 actual) and fuel @ 0.8%S actual (1.0% nominal).10Estimated price difference between fuel @ 1.2%S (2002 actual) and fuel @ 0.4%S actual ( 0.5% nominal).SO2Control Cost Calculations for Flue Gas Desulfurization:As an approximation, assume that FGD capital cost for Newington Station would be comparable to that for Merrimack Station on a $/kW basis.Merrimack Station has an estimated capital cost of$1,055/kW, based on PSNH's 2008 estimate of $457 million for Unit MK1 (113 MW) and Unit MK2 (320 MW) combined.Newington Station Unit NT1 has a generating capacity of 400 MW (=400,000 kW).Estimated capital cost for FGD on Unit NT1 = 400,000 kW×$1,055/kW = $422,000,000.BART Analysis – PSNH Unit NT1 January 14, 2011 Page23Enclosure to Letter from PSNH to DES ARD, dated 12/4/09NOTE: This sheet is a re-creation of PSNH's tables, with formulas inserted andadditional calculations. All changes and additionsto the original are shown in blue.Assumptions Used to Calculate Incremental Cost Estimates*(A)AP-42** AP-42***(B) (C) (D) (E)% sulfurSO2 SO2SO2 Max Gross SO2 ReductionFuel Switchincreased cost/barrel increased cost/hr** ***$/tonlb/1000gal lb/mmbtulb/mmbtu Heat Input lb/hr in SO2 low high low highSO2 Reducedmmbtu/hr lb/hrlow high2.0314.0 2.0412.288 4,350 9,952.81.0157.0 1.0211.086 4,350 4,724.1 5,228.7 2% to 1%$0.00 $4.00 $0.00 $2,692.86$0$1,0300.7109.9 0.7140.748 4,350 3,253.8 1,470.3 1% to 0.7%$1.00 $3.30 $673.21 $2,221.61$414 $3,0220.578.5 0.5100.528 4,350 2,296.8 957.0 0.7% to 0.5%$1.00 $2.20 $673.21$1,481.07 $586 $3,0950.347.1 0.3060.313 4,350 1,361.6 935.3 0.5% to 0.3%$3.00 $9.00 $2,019.64 $6,058.93$2,967$12,9574,350 5,228.7 2% to 1%$0.00 $4.00 $0.00 $2,692.86 $0 $1,0304,350 6,699.0 2% to 0.7%$2.00 $7.00 $1,346.43 $4,712.50 $402 $1,4074,350 7,656.0 2% to 0.5%$3.00 $9.00 $2,019.64 $6,058.93 $528 $1,5834,350 8,591.3 2% to 0.3%$4.00 $17.00 $2,692.86 $11,444.65 $627 $2,664(A) % sulfur in the fuel oil(B) SO2 lb/mmBtu emission rate, calculated based on%S and 153,846 btu/gal** Source: USEPA, Compilation of Air Pollutant Emission Factors, AP-42, 5th Ed., Vol. 1. Section 1.3- Fuel Oil Combustion (9/98)(C) Maximum gross heat input rate from permit*** Based on fuel heating value of 153,846 BTU/gal(D) SO2 lb/hr emission rate, calculated = B * C**** From historical fuel cost table, approximate.(E) Lbs of SO2 reduced per hour*****$/barrel÷42 gal/barrel÷0.153846 mmBTU/gal×mmBTU/hr = $/hrActual Fuel Use Historical Fuel Cost#6 oil 2%S Oil 1%S Oil 0.7%S Oil 0.5%S Oil 0.3%SOil(barrels) ($/barrel) ($/barrel) ($/barrel) ($/barrel) ($/barrel)2002 1,051,050 $21.20 $22.45 $23.26 $23.80 $25.252003 3,425,217 $24.95 $27.48 $29.26 $30.45 $32.632004 3,099,258 $25.25 $27.92 $30.04 $31.46 $34.532005 2,027,172 $37.00 $41.00 $44.00 $46.00 $50.102006 392,922 $45.50 $46.30 $48.46 $49.90 $54.122007 529,092 $53.70 $53.45 $56.54 $58.60 $62.862008 201,172 $75.25 $77.80 $81.10 $83.30 $92.162009 118,246 $49.90 $50.75 $51.98 $52.80 $55.83Historical fuel cost data from Platts 2002-2009.2009 data includes costs through 9/09 only.*Estimates calculated illustrate cost increases based on assumptions relied upon.chm12/08/09

# Supporting Documentation for BART Analyses

• PSNH Correspondence, December 4, 2009

• PSNH Correspondence, July 9, 2010

• PSNH Correspondence, August 16, 2010

• PSNH Correspondence, December 15, 2010