BART Analysis for 

PSNH Merrimack Station Unit MK2 

January 14, 2011 
BART 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-generating boilers that operate nearly 

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

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

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

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

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

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

dioxide (SO2) emissions. Retrofit options for this unit are limited because the facility 

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

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

new retrofits is very limited. 

2. CURRENTLY AVAILABLE RETROFIT TECHNOLOGIES, POTENTIAL 

COSTS, AND OTHER ENVIRONMENTAL AND ENERGY IMPACTS 

2.1 Retrofit Technologies for NOX Control 

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

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

selective catalytic reduction. 

Selective Non-Catalytic Reduction (SNCR) 

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

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

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

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

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

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

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

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

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

boilers operating in the United States. 

Selective Catalytic Reduction (SCR) 

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

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

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

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

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

temperature, fuel sulfur content, ammonia-to-NOX ratio, inlet NOX concentration, space 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 2 

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

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

2.1.1 Potential Costs of NOX Controls 

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

MK2 are presented in Table 2-1. These estimates are based on assumptions used in EPA’s 

Integrated Planning Model for the EPA Base Case 2006 (V.3.0), for retrofitting an electric 

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

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

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

Table 2-1. Estimated NOX Control Costs 

Control 

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 annual 

generation. Total annual cost includes amortization of capital cost over 15 years at 3.0% interest rate. 

Average cost per ton is based on an estimated 8,613 tons of NOX removed for SNCR and an estimated 

16,269 tons of NOX removed for SCR.

Because Unit MK2 already has SCR controls in place, the listed costs serve for comparative 

purposes only. In 1998, PSNH estimated that its SCR costs would be about $400/ton for 

year-round operation and about $600/ton for operation limited to the ozone season (May 1 

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

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

NOX RACT requirements. 

Year-round operation is EPA’s presumptive norm for BART (applicable to EGUs of 750 

MW capacity or greater) for units that already have seasonally operated SCRs. Assuming 

that operating costs are proportional to operating time, the difference in cost between yearround and seasonal SCR operation for Unit MK2 is about $3,300,000, based on PSNH’s 

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

more recent generic estimates presented in Table 2-1. 

2.1.2 Other Environmental and Energy Impacts of NOX Controls 

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

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

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

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

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

threshold. 

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

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

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

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

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

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

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

catalyst-based technology to oxidize SO2 to SO3, resulting in higher sulfate concentrations 

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

excess ammonia and using catalysts that minimize SO2 oxidation. The air heater and other 

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

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

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

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

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

the additional pressure drop.) 

NOX emission reductions provide environmental and public health benefits beyond visibility 

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

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

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

and the health of ecosystems sensitive to low pH. 

 

2.2 Retrofit Technologies for PM Control 

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

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

Electrostatic Precipitators (ESPs) 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Fabric Filters 

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

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

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

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

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

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

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

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

efficiencies of baghouses may exceed 99 percent. 

Mechanical Collectors and Particle Scrubbers 

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

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

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

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

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

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

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

Scrubbing systems have been shown to reduce PM10 emissions by 50 to 60 percent but are 

generally less effective for removal of fine particles. 

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

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

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

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

of PM emissions. 

2.2.1 Potential Costs of PM Controls 

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

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

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

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

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

Table 2-2. Estimated PM Control Costs 

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 million 1.6-2.4 million 3.8-7.6 million 130-260 

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

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

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

flow rate of 1.36 million acfm. Total annual cost includes amortization of capital cost over 15 years at 3.0% interest rate. 

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

The costs for ESPs and fabric filters are of similar magnitude, with total annual costs ranging 

from about $2.6 million to $8.3 million, or $90 to $280 per ton of PM removed. Because 

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

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

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

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

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

2.2.2 Other Environmental and Energy Impacts of PM Controls 

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

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

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

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

production or as a component in other manufactured products. 

2.3 Retrofit Technologies for SO2 Control 

SO2 control technologies available and potentially applicable to Unit MK2 are scrubber 

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

Flue Gas Desulfurization 

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

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

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

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

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

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

SO2 in the flue gas. A PM control device is always located upstream of a wet scrubber. 

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

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

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

sulfur removal rates and produce minimal wastewater discharges. 

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

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

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

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

Sulfate products that are not recycled must be landfilled. 

SO2 removal efficiencies for existing wet limestone scrubbers range from 31 to 97 percent 

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

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

MW) coal-fired power plants, the presumptive norm is 95 percent reduction of SO2 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 concept to wet FGD processes but do not 

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

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

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

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

absorbed by an atomized alkaline slurry. The SO2 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 SO2 emissions are directly related to the sulfur content of the fuel burned, reducing 

the amount of sulfur in the fuel reduces SO2 emissions. Usually, for operational reasons, a 

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

may be able to blend different fuels to obtain a lower-sulfur mix that emits less SO2 upon 

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

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

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

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

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

requirements, many facilities have switched to lower-sulfur coals, resulting in SO2 emission 

reductions of 50 to 80 percent. 

2.3.1 Potential Costs of SO2 Controls 

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

reduce mercury emissions (with SO2 removal as a co-benefit) at both Unit MK1 (not a 

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

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

install a wet limestone FGD system. Using 2002 baseline emissions of 30,657 tons of SO2

from Units MK1 and MK2 combined, and a minimum capture efficiency of 90 percent for this 

pollutant, the annualized capital cost translates to about $1,400 per ton of SO2 removed. 

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

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

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

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

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

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

FGD systems (George W. Sharp, “What’s That Scrubber Going to Cost?,” Power, March 1, 

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

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

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

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

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

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

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

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

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

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

spread between Northern Appalachia coal (<3.0 SO2) and Central Appalachia coal (1.2 SO2) 

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

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

2.3.2 Other Environmental and Energy Impacts of SO2 Controls 

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

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

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

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

generation. Documentation for EPA’s Integrated Planning Model (IPM®) indicates that a 

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

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

management systems. In addition to removing SO2, the FGD process removes mercury and 

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

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

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

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

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

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

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

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

3. DISCUSSION OF CURRENT POLLUTION CONTROL EQUIPMENT AND EMISSIONS

3.1 Discussion of Current NOX Emissions and Controls 

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

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

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

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

Order limit of 29.1 tons per calendar day for combined emissions from Units MK1 and 

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

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

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

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

Since January 2001, the SCR on Unit MK2 has reduced NOX emissions to between 0.15 and 

0.37 lb/MMBtu (calendar monthly average), with a few excursions outside this range. (Note 

that the existing NOX RACT limit of 15.4 tons per calendar day is mathematically equivalent 

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

of the SCR, provide a baseline for uncontrolled NOX emissions in the range of 2.0 to 2.5 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 8 

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

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

3.2 Discussion of Current PM Emissions and Controls

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

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

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

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

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

TSP) limit of 0.227 lb/MMBtu and a TSP emissions cap of 3,458.6 tons/year. However, the 

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

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

emissions to be 0.043, 0.041, and 0.021 lb/MMBtu after controls. The most recent test, in 

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

unit were 210 tons in 2002. 

3.3 Discussion of Current SO2 Emissions and Controls 

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

system for both Unit MK1 and Unit MK2 by July 1, 2013. While the primary intent of this 

law is to reduce mercury emissions from the company’s coal-fired power plants, a major cobenefit is SO2 removal. Pursuant to this statutory obligation, New Hampshire issued a 

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

system to control mercury and SO2 emissions at Merrimack Station. The permit requires an 

SO2 control level of at least 90 percent for Unit MK2. The specific language of the permit 

states as follows: 

Beginning on July 1, 2013,...SO2 emissions shall be controlled to 10 percent of the uncontrolled 

SO2 emission rate (90 percent SO2 removal)...The Owner shall submit a report no later than 

December 31, 2014 that includes the calendar month average SO2 emission rates at the inlet and 

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

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

rate of SO2 emissions reductions for MK2. The maximum sustainable rate is the highest rate of 

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

incorporated as a permit condition for MK2. Under no circumstances shall the SO2 removal 

efficiency for MK2 be less than 90 percent. 

These permit conditions effectively require that actual SO2 removal efficiencies exceed 90 

percent on average for Unit MK2. This plant must also meet general regulations for coalburning devices that limit the sulfur content of the coal to 2.0 pounds per million BTU gross 

heat content averaged over any consecutive 3-month period, and 2.8 pounds per million 

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

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

SO2 emissions and minimize the purchase of SO2 allowances. Because the particular boiler 

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

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

PSNH must also meet a fleet-wide SO2 emissions cap of 55,150 tons/year effective for all 

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

actual SO2 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 estimated to have a life expectancy of 30 to 40 

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

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

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

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

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

5. DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FROM BART 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

even more conservative exemption level of 0.1 dv. CALPUFF modeling results for baseline 

emissions from Unit MK2 exceed all of these exemption levels. 

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

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

assessed. Results are tabulated for the average of the 20% best visibility (about 11.7 to 12.4 

dv) and 20% worst visibility (about 22.8 dv) modeled days at each nearby Class I area. For 

any pair of control levels evaluated, the difference in the level of impairment predicted is the 

degree of improvement in visibility expected. 

Rather than use CALPOST to manipulate background deciview calculations, NHDES 

normalized CALPUFF modeling results and then applied predicted concentrations to a 

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

at Acadia NP, Great Gulf NWR, and Lye Brook NWR. Thus, CALPUFF was applied in a 

relative way using real observed data as the basis. At this point, a number of background 

visibility scenarios could be calculated from the resulting PM-extinction-to-deciview 

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

was used for exemption purposes, and 20% best and 20% worst visibility were used for 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 10 

assessment of BART control effectiveness. The CALPUFF-predicted visibility benefits 

from BART controls on 20% best and 20% worst visibility 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

SO2 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

SO2 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 modeling 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 assessment 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 these results may appear to be too low; 

however, on further examination, it is found that CALPUFF predicts the same amount of 

sulfate from Unit MK2 reaching Acadia under both best and worst visibility conditions. The 

difference is that there is greater than an order of magnitude more sulfate coming from other 

sources on the 20% worst visibility days, raising the background concentrations to much 

higher levels. Because the deciview scale is logarithmic, the same mass reduction of 0.259 

μg/m3 of sulfate from this one source results in wide differences in deciview impacts for 

different background visibility conditions at opposite ends of the range. 

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

BART controls at PSNH Merrimack Station Unit MK2. Specifically, one modeling run 

using the CALGRID photochemical air quality model was performed to assess the effects of 

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

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

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

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

regulations that are already “on the books” or “on the way.”

The CALGRID model outputs took the form of ambient concentration reductions for SO2, 

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

modeled concentration reductions to estimate the corresponding visibility improvements at 

nearby Class I areas (i.e., concentration impacts were converted to visibility impacts). 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 11 

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

removal efficiency on Unit MK2 is expected to reduce maximum predicted 24-hour average 

SO2 concentration impacts by up to 21 μg/m3

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

maximum predicted 24-hour average PM2.5 concentration impacts by up to 1 μg/m3

. The 

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

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

the maximum predicted concentrations of SO2, PM2.5, and other haze-related pollutants, 

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

direct-impact hazy days. 

Figure 5-1 

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

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

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

conservative model or one that is capable of estimating worst-case impacts rather than 

expected impacts. This makes CALPUFF ideally suited to screening BART sources for 

exemption purposes because it is likely to identify virtually all sources that could provide 

visibility benefits when their emissions are controlled. 

CALGRID is a sister program to CALPUFF and shares much of the same chemistry; 

however, it works as a gridded model rather than a puff tracking model, and it has the 

advantage of easily tracking 20% worst visibility days and cumulative impacts by modeling 

all source sectors. NHDES chose to use CALGRID for screening since it is much easier to 

track the dynamics of impacts from single sources to multiple Class I areas on targeted days, 

rather than just applying the maximum impact conditions that may or may not be associated 

with 20% worst days. While the CALPUFF model’s CALPOST post-processor has an 
BART 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 background values the model uses to adjust what it 

estimates to be appropriate background levels. It does not account for wind directions that 

may be preferentially included or excluded on such days. 

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

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

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

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

Class I areas such as Acadia National Park. The big discrepancy occurs under best visibility 

days, when CALGRID (correctly) does not align the source to receptor, but CALPUFF 

(incorrectly) applies wind directions for worst visibility days to the best day calculations. 

6. DETERMINATION OF BART 

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

PSNH Merrimack Station Unit MK2, it is determined that the NOX, PM, and SO2 controls 

described below represent Best Available Retrofit Technology for this unit. 

6.1 Selecting a Pollution Control Plan for NOX 

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

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

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

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

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

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

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

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

negligible (generally less than 0.1 dv) improvement in visibility. Additional upgrades would 

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

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

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

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

for NOX control on this unit. 

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

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

MK2. In the case of Unit MK2, the cyclone boiler has a relatively high uncontrolled NOX

emission rate (≥2.0 lb/MMBtu); so it follows that the controlled emission rate, even at 90 

percent control efficiency, would be above the presumptive norm of 0.10 lb/MMBtu 

applicable to larger EGUs of its type. The past decade of emissions records for Unit MK2 

shows monthly average NOX emission rates normally ranging between 50 and 100 percent 

of the RACT limit. The existing NOX RACT limit of 15.4 ton/day, equivalent to of 0.37 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 13 

lb/MMBtu*, corresponds to a NOX control rate of approximately 85 percent. 

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

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

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

accomplished by increasing the frequency of maintenance cleanings and accelerating the 

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

The four major cost components would be: 

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

SCR system, 

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

scheduled maintenance outages, 

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

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

flexibility to operate at partial load. 

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

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

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

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

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

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

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

the NOX emission limit to 0.30 lb/MMBtu (an effective reduction of 0.07 lb/MMBtu) would 

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

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

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

estimated that further reduction of the NOx emission limit to 0.25-0.30 lb/MMBtu would 

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

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

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

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

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

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

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

6.2 Selecting a Pollution Control Plan for PM 

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

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

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

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

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

_________________ 

*

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

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

[(15.4 tons/day × 1 day/24 hr) × 2,000 lb/ton] ÷ 3,473 MMBtu/hr = 0.37 lb/MMBtu
BART 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 include state-of-the-art electronic controls. 

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

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

impossible because of the aforementioned spatial limitations following past improvements 

to emission control systems. To undertake either major equipment replacement or installation 

of a third ESP, if it could be done at all, would require a major capital expenditure. Typical 

equipment replacement costs for ESP upgrades may be in the range of $10,000 to $30,000 

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

weighed against the visibility improvement (less than 0.1 dv on the 20 percent worst visibility 

days) that would be realized. 

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

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

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

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

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

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

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

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

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

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

calculate the maximum allowable emission rate for the combined source: 

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

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

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

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

multiplied by the unit’s permitted TSP limit, 0.27 lb/MMBtu, to determine an 

emission rate of 334.26 lb/hr. 

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

of 403.72 lb/hr. This value was divided by the total maximum heat input rate, 4,711 

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

down from 0.086 lb/MMBtu). 

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

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

remained separate and unchanged, and the limit for Unit MK2 were reduced to 0.04 

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

_________________ 

†

 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 in conjunction with the FGD process, will 

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

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

above, represents BART for PM control on Unit MK2. 

6.3 Selecting a Pollution Control Plan for SO2

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

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

expected to remove more than 90 percent of SO2 emissions. Because this installation is 

already mandated and because it will attain SO2 removal rates approaching the BART 

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

Station), the FGD system is considered to be BART for SO2 control on Unit MK2. (Note 

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

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

only purpose were to satisfy BART requirements.)

7. SUMMARY AND CONCLUSIONS 

Table 7-1 summarizes best available retrofit technology for PSNH Merrimack Station Unit 

MK2 for the pollutants NOX, PM, and SO2. The summary includes existing controls that 

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

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

(construction permit) for the installation of the flue gas desulfurization system and is not 

requiring additional control technology for Merrimack Station at this time in order to comply 

with BART.

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

Pollutant Current Emission 

Controls 

Additional Emission 

Controls in Progress BART Controls BART Emission Limit 

NOX SCR None SCR 0.30 lb/MMBtu, 

30-day rolling average 

PM Two ESPs in series None Two ESPs in series 0.08 lb/MMBtu 

total suspended 

particulate (TSP) 

SO2 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 

SO2 percent reduction 

set at maximum 

sustainable rate, but not 

less than 90% on a 

calendar monthly 

average basis 

Flue gas desulfurization 

(FGD), with required 

SO2 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 

SO2 emissions, 

calendar monthly 

average 
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 16 

NEW HAMPSHIRE BART ANALYSIS: Merrimack Station Unit MK2 (320 MW) 

Estimated Cost of Emiss

Uncontrolled 

Emissions 

Controlled Emissions 

Emission 

Reductions Pollutant Emission Control Technology Control Level 

ton/yr ton/yr ton/yr 

Capital 

$ 

Capital

$/kW 

O&M 

$/yr 

SCR (existing) 85% 19,140 1 2,871 2 16,269 37,710,186 118 1,910,432 

NOX

SNCR 45% 19,140 1 10,527 8,613 3,876,771 12 4,781,136 

min. 23,280,363 73 1,086,417 

2 ESPs (existing) 99+% 30,060 2 210 2 29,850

max. 62,080,967 194 1,940,030 

min. 18,624,290 58 2,172,834 

PM 

Fabric Filters 99% 30,060 2 301 29,759

max. 62,080,967 194 3,104,048 

Lower-S coal (existing) 40% 3       

SO2

FGD 90% 4 20,902 5 2,090 18,812 6 457,000,000 1,055 unknown 

1 Estimated.2 2002 (baseline) emissions as taken from NHDES data summary derived from facility's annual emissions statement. 3 Estimated average reduction in fuel sulfur content with use of lower-S coal, resulting in equivalent reduction in SO2 emissions.

4 Additional control level on emissions after existing controls have been applied; overall control level with use of lower-S coal is estimated 

5 2002 (baseline) emissions with use of lower-sulfur coal at ~1.0 % S by weight.

6 Reductions from baseline emissions.

7 All cost estimates adjusted to 2008$.8 USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model, November 2006.

9 NESCAUM, Assessment of Control Technology Options for BART-Eligible Sources, March 2005.

10 FGD 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 Page 17 

Merrimack Station Unit MK2: NO

X Controls

Plant type wet-bottom, cyclone, coal-fired boiler Historical operation: Generation capacity 320 MW Year 2002 2003 2004 2005 2006 Maximum heat Input 3,473 MMBtu/hr Operating hours 7,180 6,703 7,462 7,280 7,577 Capacity factor 80 % Total Heat Input* 22,013,513 22,006,524 24,024,382 23,795,575 25,328,218 25Annual hours 8,760 hr/yr Capacity factor** 72.4% 72.3% 79.0% 78.2% 83.3% Annual production 2,242,560,000 kWh/yr *MMBtu (from CEM data) **Based on ratio of total heat input to t

Costs: 2004$ 

Capital Scaled Capital Total Capital Total Annualized Capital Fixed O&M Scaled Fixed O&M Variable O&M Scaled Variable O&M Total Fixed & Variable O&M 

A

Control Technology 

$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh mills/kWh $/yr $/yr 

SCR 111.48 103.46 33,108,152 2,773,470 0.74 0.69 219,771 0.67 0.65 1,457,518 1,677,289 4

SNCR 11.04 10.64 3,403,662 285,125 0.16 0.15 49,328 1.46 1.85 4,148,332 4,197,661 4

Costs: 2008$ 2004$ 

→ 2008$ 1.139 multiplier 

Capital Scaled Capital Total Capital Total Annualized Capital Fixed O&M Scaled Fixed O&M Variable O&M Scaled Variable O&M Total Fixed & Variable O&M 

A

Control Technology 

$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh mills/kWh $/yr $/yr 

SCR 126.98 117.84 37,710,186 3,158,982 0.84 0.78 250,319 0.76 0.74 1,660,113 1,910,432 5

SNCR 12.57 12.11 3,876,771 324,757 0.18 0.18 56,185 1.66 2.11 4,724,951 4,781,136 5

Cost Reference: Annualized cost basis: 

 Period, yrs 15 

 Interest, % 3.0 

USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model, November 2006. CRF 0.08377
BART Analysis – PSNH Unit MK2 January 14, 2011 Page 18 

Merrimack Station Unit MK2: PM ControlsPlant type wet-bottom, cyclone, coal-fired boiler Historical operation: Capacity 320 MW Year 2002 2003 2004 2005 Maximum heat Input 3,473 MMBtu/hr Operating hours 7,180 6,703 7,462 7,280 Capacity factor 80 % Total Heat Input* 22,013,513 22,006,524 24,024,382 23,795,575 25Annual hours 8,760 hr/yr Capacity factor** 72.4% 72.3% 79.0% 78.2% Annual production 2,242,560,000 kWh/yr *MMBtu (from CEM data) **Based on ratio of total heat input to theorFlue gas flow rate 1,362,620 acfm 

Costs: 2004$ 

Capital Total Capital Total Annualized Capital Fixed O&M Variable O&M Total Fixed & Variable O&M Total Annualized Cost Emission Reductions Average Cost Control Technology 

$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr $/ton C

min. 15.00 20,439,300 1,712,200 0.25 0.45 953,834 2,666,034 29,850 89 Dry ESP 

max. 40.00 54,504,800 4,565,867 0.65 0.60 1,703,275 6,269,142 29,850 210 

min. 15.00 20,439,300 1,712,200 0.15 0.25 545,048 2,257,248 29,850 76 

NTE

Wet ESP 

max. 40.00 54,504,800 4,565,867 0.50 0.50 1,362,620 5,928,487 29,850 199 

Fabric Filter - min. 17.00 23,164,540 1,940,494 0.35 0.70 1,430,751 3,371,245 29,759 113 A Reverse Air max. 40.00 54,504,800 4,565,867 0.75 0.80 2,112,061 6,677,928 29,759 224 PFabric Filter - min. 12.00 16,351,440 1,369,760 0.50 0.90 1,907,668 3,277,428 29,759 110 In Pulse Jet max. 40.00 54,504,800 4,565,867 0.90 1.10 2,725,240 7,291,107 29,759 245 CCosts: 2008$ 2004$ 

→ 2008$ 1.139 multiplier 

 Capital Total Capital 

Total 

Annualized 

Capital 

Fixed 

O&M 

Variable 

O&M 

Total Fixed 

& Variable 

O&M 

Total 

Annualized 

Cost 

Emission 

Reductions 

Average 

Cost Control Technology 

 $/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr $/ton 

min. 17.09 23,280,363 1,950,196 0.28 0.51 1,086,417 3,036,613 29,850 102 Dry ESP 

max. 45.56 62,080,967 5,200,523 0.74 0.68 1,940,030 7,140,553 29,850 239 

min. 17.09 23,280,363 1,950,196 0.17 0.28 620,810 2,571,006 29,850 86 Wet ESP 

max. 45.56 62,080,967 5,200,523 0.57 0.57 1,552,024 6,752,547 29,850 226 

Fabric Filter - min. 19.36 26,384,411 2,210,222 0.40 0.80 1,629,625 3,839,848 29,759 129  Reverse Air max. 45.56 62,080,967 5,200,523 0.85 0.91 2,405,637 7,606,160 29,759 256 Fabric Filter - min. 13.67 18,624,290 1,560,157 0.57 1.03 2,172,834 3,732,991 29,759 125  Pulse Jet max. 45.56 62,080,967 5,200,523 1.03 1.25 3,104,048 8,304,571 29,759 279 
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BART Analysis for 

PSNH Newington Station Unit NT1 

January 14, 2011 
BART 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 boiler with a heat input rating of 4,350 

MMBtu/hr and an electrical output of 400 MW. Installed in 1968, the boiler is equipped 

with low-NOx burners, an overfire air system, and water injection to minimize the formation 

of oxides of nitrogen (NOX) during the combustion process. The facility also has an 

electrostatic precipitator (ESP) to capture particulate matter (PM) in the flue gases. Partial 

control of SO2 emissions is provided by sulfur content limits on the fuel oil. 

2. CURRENTLY AVAILABLE RETROFIT TECHNOLOGIES, POTENTIAL 

COSTS, AND OTHER ENVIRONMENTAL AND ENERGY IMPACTS 

2.1 Retrofit Technologies for NOX Control 

NOX emission control technology options available and potentially applicable to Unit NT1 

are combustion controls, selective non-catalytic reduction, and selective catalytic reduction. 

Combustion Controls 

Controls on the combustion process can reduce NOX formation by as much 75 percent. 

Combustion controls or firing practices include such measures as staged combustion, 

limiting excess air, providing overfire air, recirculating the flue gases, using low-NOX burners, 

and injecting water or steam. 

Operating with low excess air involves restricting the amount of combustion air to the 

lowest possible level while maintaining efficient and environmentally compatible boiler 

operation. Because less oxygen is introduced into the combustion zone, NOX formation is 

inhibited. Adjustments to the air supply may affect normal boiler operation and may reduce 

operational flexibility. The effectiveness of limiting excess air varies from boiler to boiler, 

but typical NOX reductions are 10 to 25 percent from uncontrolled levels. 

Overfire air (OFA) is a method where some of the total combustion air is diverted from the 

burners and injected through ports above the top burner level. This staged combustion 

reduces fuel-based NOX formation in the oxygen-deficient primary combustion zone and 

limits thermal NOX formation because of the lower peak flame temperature (i.e., combustion 

occurs over a larger portion of the furnace). For oil-fired boilers, OFA typically reduces 

NOX 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 concentration in the combustion zone and 

depresses peak flame temperature by adding a large amount of cooled gas to the fuel-air 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 2 

mixture, resulting in less thermal NOX formation. FGR reduces NOX emissions by about 40 

to 60 percent in oil-fired boilers. 

Low-NOX burners (LNB) are designed to control fuel/air mixing and increase heat 

dissipation. These alternative burners can be installed on new boilers or retrofitted on older 

units. LNB technology integrates staged combustion in the burner. A typical LNB creates a 

fuel-rich primary combustion zone, thus lowering the formation of fuel-based NOX. At the 

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

of thermal NOX. Combustion is completed in a lower-temperature, fuel-lean zone. LNB 

retrofits have been shown to reduce NOX formation by 30 to 55 percent. 

Water or steam can be injected into the boiler combustion zone to reduce the peak flame 

temperature, with a corresponding reduction in thermal NOX formation. Water/steam 

injection can reduce NOX emissions by as much as 75 percent in gas-fired boilers and 

slightly less in oil-fired boilers. 

Selective Non-Catalytic Reduction (SNCR) 

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

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

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

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

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

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

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

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

is limited commercial experience with SNCR from which to judge its effectiveness for oilfired boilers. NOX reductions of 35 to 60 percent have been achieved through the use of 

SNCR on some oil-fired boilers operating in the United States. 

Selective Catalytic Reduction (SCR) 

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

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

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

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

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

temperature, fuel sulfur content, ammonia-to-NOX ratio, inlet NOX concentration, space 

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

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

toward the upper end of this range. 

2.1.1 Potential Costs of NOX Controls 

The estimated costs of NOX emission controls at Newington Station Unit NT1 are presented 

in Table 2-1. These estimates are based on assumptions used in EPA’s Integrated Planning 

Model for the EPA Base Case 2006 (V.3.0), for retrofitting an electric generating unit 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 3 

(EGU) the size of Unit NT1. For low-NOX burners, the total annual cost is estimated to be 

about $830,000, or $1,470 per ton of NOX removed. With the addition of overfire air, this 

cost rises to $1,130,000, or $1,600 per ton. For SNCR, the total annual cost is estimated to 

be $730,000, or $1,030 per ton. For SCR, the total annual cost doubles to $1,410,000; but 

the unit cost is only moderately higher at $1,180 per ton of NOX removed. Because Unit 

NT1 is primarily a peak-load generator, these estimates are based on a 20-percent capacity 

factor. 

Table 2-1. Estimated NOX 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 amortization of capital cost over 15 years at 3.0% interest rate. 

Average cost per ton is based on the following estimates of NOX removed: 563 tons for LNB; 704 tons for 

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

Low-NOX burners have previously been reported to operate in a cost range of $200 to $500 

per ton of NOX removed (NESCAUM, Assessment of Control Technology Options for 

BART-Eligible Sources, March 2005); however, this cost range is likely to be more relevant 

to larger plants operating at higher capacity factors than Newington Station. 

2.1.2 Other Environmental and Energy Impacts of NOX Controls 

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

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

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

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

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

threshold. 

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

disposal cost of the ash. Ammonia in the flue gas may produce a more visible plume, 

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

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

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

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

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

catalyst-based technology to oxidize SO2 to SO3, resulting in higher sulfate concentrations 

than would otherwise exist. Ammonium bisulfate formation can be reduced by controlling 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 4 

excess ammonia and using catalysts that minimize SO2 oxidation. The air heater and other 

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

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

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

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

amount of energy. 

NOX emission reductions provide environmental and public health benefits beyond visibility 

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

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

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

and the health of ecosystems sensitive to low pH.

2.2 Retrofit Technologies for PM Control 

PM control technologies available and potentially applicable to Unit NT1 are electrostatic 

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

Electrostatic Precipitators (ESPs) 

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

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

consists of a small-diameter negatively charged electrode (usually a set of individual wires 

or a grid) and a grounded positively charged plate. In operation, a strong electric charge 

from the negatively charged electrode sets up a one-directional electric field. When particleladen gases pass through this electric field, the particles become charged and are then drawn 

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

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

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

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

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

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

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

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

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

Fabric Filters 

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

containment structure. These devices work on the same principal as a vacuum cleaner bag. 

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

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

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

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

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

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

efficiencies of baghouses may exceed 99 percent. 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 5 

Mechanical Collectors and Particle Scrubbers 

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

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

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

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

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

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

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

Scrubbing systems have been shown to reduce PM10 emissions by 50 to 60 percent but are 

generally less effective for removal of fine particles. 

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

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

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

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

of PM emissions. 

2.2.1 Potential Costs of PM Controls 

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

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

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

retrofit installation the size of Unit NT1. Capital and operating costs are based on flue gas 

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

Table 2-2. PM Control Costs 

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 million 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-Eligible Sources, March 2005. (Note that 

these costs were developed for coal-fired boilers.) All costs are adjusted to 2008 dollars. Total annual 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 cost includes 

amortization of capital cost over 15 years at 3.0% interest rate. Average cost per ton is based on 142 tons of PM removed 

for ESPs and 335 tons of PM removed for fabric filters.

The costs for ESPs and fabric filters are of similar magnitude, with total annual costs ranging 

from about $3.2 million to $10.4 million, or $14,000 to $63,000 per ton of PM removed. 

Because Unit NT1 already has an ESP installed and operating, the tabulated costs are useful 

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

replacement costs to upgrade performance may be in the range of $10,000 to $30,000 per 

MW. (M. Sankey and R. Mastropietro, “Electrostatic Upgrade Strategy: Get the Most From 

What You Have,” Hamon Research-Cottrell, Inc., April, 1997.) 
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 value of the fly ash. If the fly ash is not 

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

production or as a component in other manufactured products.

2.3 Retrofit Technologies for SO2 Control 

SO2 control technologies available and potentially applicable to Unit NT1 are scrubber 

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

Flue Gas Desulfurization 

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

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

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

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

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

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

SO2 in the flue gas. A PM control device is always located upstream of a wet scrubber. 

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

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

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

sulfur removal rates and produce minimal wastewater discharges. 

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

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

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

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

Sulfate products that are not recycled must be landfilled. 

 

SO2 removal efficiencies for existing wet limestone scrubbers range from 31 to 97 percent 

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

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

MW) coal-fired power plants, the presumptive norm is 95 percent reduction of SO2 emissions 

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

Haze Rule). While experience with FGD systems on smaller, oil-fired EGUs is generally 

lacking, it is anticipated that such installations would perform at a similar level, achieving 

SO2 removal efficiencies of 90 percent or greater. 

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

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

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

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

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

absorbed by an atomized alkaline slurry. The SO2 removal efficiencies range from 40 to 60 

percent for existing dry injection systems and from 60 to 95 percent for existing lime spray 
BART 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 SO2 emissions are directly related to the sulfur content of the fuel burned, reducing 

the amount of sulfur in the fuel reduces SO2 emissions. For facilities that burn fuel oil, 

switching to a lower-sulfur fuel may be a cost-effective control option. Switching from 

high-sulfur residual fuel oil to low-sulfur residual fuel oil or low-sulfur distillate fuel oil is 

one possible control strategy. For facilities that have the option to replace fuel oil with 

natural gas or can co-fire with natural gas, increasing the use of natural gas is another 

effective control strategy. Sulfur dioxide emissions from burning natural gas are negligible 

in comparison to those from burning fuel oil. When substituting natural gas for fuel oil, the 

resulting SO2 emission reductions are roughly proportional to the fraction of natural gas 

burned on a Btu-equivalent basis. 

2.3.1 Potential Costs of SO2 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 to FGD for coal-fired plants. Therefore, 

the costs of an FGD system for PSNH Newington Station may be crudely approximated by 

extrapolating from the costs of FGD for PSNH Merrimack Station. 

The flue gas desulfurization system at Merrimack Station is being installed to reduce 

mercury emissions (with SO2 removal as a co-benefit) at its two coal-fired boilers. These 

units have a combined generating capacity of 433 MW, or slightly greater than the capacity 

of Newington Station Unit NT1. The company’s capital cost estimate for the wet limestone 

FGD system is $457 million, or $1,055/kW (both amounts in 2008$), which is said to be in 

line with project costs for multiple-unit scrubber installations occurring elsewhere in the 

United States. However, PSNH’s estimated cost per kilowatt is at least triple the cost range 

for FGD systems as reported in MACTEC Federal Programs, Inc., “Assessment of Reasonable 

Progress for Regional Haze in MANE-VU Class I Areas,” Final, July 9, 2007 (see 

Reasonable Progress Report, Attachment Y). The PSNH estimated cost is also more than 

double the estimate of $300/kW to $500/kW as reported in a 2008 survey of FGD systems 

(George W. Sharp, “What’s That Scrubber Going to Cost?,” Power, March 1, 2009). The 

higher cost-per-kW for Unit MK2 may reflect industry-wide increases in raw material, 

manufacturing, and construction costs but may also reflect site-specific factors such as unit 

size, type, and difficulty of retrofit. 

Using the latest Merrimack Station estimate of $1,055/kW for scaling purposes, the total 

capital cost of a wet limestone FGD system for Newington Station Unit NT1 would be 

roughly $422,000,000. Much caution is necessary in relating this number to the Newington 

facility: Note that the cost of FGD on oil-fired boilers previously has been estimated to be 

about twice the cost of FGD on coal-fired boilers of comparable size (NESCAUM, 2005). 

The costs of switching to a low-sulfur fuel oil at Unit NT1 would depend on the incremental 

costs of purchasing the lower-sulfur product at prevailing market prices. The long-term 

price differential between 1.0%-sulfur (low-S) residual fuel oil and 2.0%-sulfur residual fuel 

oil is estimated to be about 7.5 cents/gallon. The differential between 0.5%-sulfur (ultralow-S) residual fuel oil and 2.0%-sulfur residual fuel oil is estimated to be about twice this 
BART 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.) Using these unit prices, the total cost of 

switching to low-S residual fuel oil is approximately $3.3 million per year, or $1,900 per ton 

of SO2 emissions removed; and the cost of switching to ultra-low-S residual fuel oil is 

approximately $6.6 million per year, or also $1,900 per ton of SO2 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 costs of switching fuel oils may be relatively 

constant on a $/ton basis as long as supplies are adequate. 

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

as SO2 control options for PSNH Newington Station Unit NT1. The costs for switching 

from 2.0%-S residual fuel oil to 1.0%-S or 0.5%-S residual fuel oil are listed. At any given 

time, the actual cost of fuel switching would vary in proportion to the applicable fuel price 

differential. 

Table 2-3. SO2 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 Station 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 differential 

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

In a similar analysis performed independently by PSNH (see attached letter), the company 

has estimated the costs 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 9/09.

_________________ 

‡

 Platts, a division of The McGraw-Hill Companies, is 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 SO2 emission reductions from 

fuel switching, the New Hampshire Department of Environmental 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. This analysis produces somewhat less 

conservative (lower) estimates of the cost of fuel switching than the $1,900/ton estimate 

given above. In either analysis, the cost-effectiveness of switching to 0.5%-sulfur residual 

fuel oil appears reasonable as long as supplies remain stable. Switching to 0.3%-sulfur fuel 

oil could also prove reasonable in the future if prices were to stay within their recent 

historical range and future supplies could be assured. 

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

Increased Cost 

 ($/barrel) 

Increased Cost 

($/hour)** 

$/ton of 

SO2 Removed*** Fuel 

Switch 

SO2 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 12,957 

 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 SO2 emissions, other proposed options 

include replacing 2.0%-S residual fuel oil with low-sulfur distillate fuel oil or natural gas. 

Although distillate fuel oil is sometimes used during startup of Unit NT1, the boiler is not 

designed to operate routinely on this fuel; and retrofitting the boiler for this purpose would 

involve major capital expenditure. Burner replacements to combust distillate fuel oil could 

exceed $20 to $30 million (approximately $1 to 2 million per burner) in direct capital costs, 

not including the additional costs of engineering and any required auxiliary equipment. 

The cost determinations associated with using natural gas are more complicated. Unit NT1 

can be fired with either natural gas or liquid fuel (i.e., residual fuel oil or biofuel), or it can 

be co-fired with both types of fuel at the same time. However, because of physical 

limitations to the boiler’s design, the unit cannot operate at full capacity when fueled solely 

by natural gas. In order to reach maximum heat input, the boiler must either use liquid fuel 

or be co-fired with both fuel types. (Unit NT1 can operate at up to about 50 percent of 

maximum heat input from natural gas, with no corresponding 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 modifications to other major boiler 

components or replacement of the entire boiler. Such measures cannot be economically 

justified. However, using natural gas – to the extent that Unit NT1 can burn this fuel with 

existing equipment – remains a viable option as long as the cost 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 and the uncertainty of future fuel prices 

make it difficult to provide a useful estimate of the cost of substituting natural gas for residual 

fuel oil. As seen in Figure 2-1, past prices of natural gas and petroleum fuels, on a BTUequivalent basis, exhibit similar trends; but the price differentials show wide variation from 

year to year. Consequently, no cost estimate for this fuel switching option is presented. 

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

in New England (1990-2008) 

 

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

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

2.3.2 Other Environmental and Energy Impacts of SO2 Controls 

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

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

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

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

generation. Documentation for EPA’s Integrated Planning Model (IPM®) indicates that a 

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

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

management systems. In addition to removing SO2, the FGD process removes mercury and 

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

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

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

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

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

additional clarifier is required to remove wastewater solids coming from the FGD system. 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 11 

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

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

Switching to lower-sulfur fuel oil generally reduces boiler maintenance requirements 

because less particulate matter is emitted. With fewer material deposits occurring on 

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

because lower-sulfur oil reduces the formation of sulfuric acid emissions, corrosion is 

reduced and equipment life is extended. 

3. DISCUSSION OF CURRENT POLLUTION CONTROL EQUIPMENT AND EMISSIONS

3.1 Discussion of Current NOX Emissions and Controls 

PSNH Newington Station Unit NT1 currently operates with low-NOx burners, an overfire 

air system, and water injection to minimize NOX formation. For compliance with NOX

RACT requirements, the facility’s existing air permit limits NOX emissions from this unit to 

a daily average of 0.35 lb/MMBtu when burning oil and 0.25 lb/MMBtu when burning a 

combination of oil and gas. NHDES reviewed emissions data for Unit 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 NOX emissions ranged between 0.21 and 0.30 lb/MMBtu. These 

values compare favorably with the facility’s NOX RACT limits. Actual NOX emissions from 

this unit were 943 tons in 2002. 

3.2 Discussion of Current PM Emissions and Controls

Unit NT1 has an electrostatic precipitator to capture 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 is unknown whether the stated efficiency is 

representative of actual long-term performance. The facility’s air permit (TV-OP-054, 

March 9, 2007; administrative amendment, December 17, 2007) sets an emission limit of 

0.22 lb/MMBtu total suspended particulate matter (filterable TSP). The single available 

stack test on Unit NT1 measured a controlled TSP emission rate of 0.058 lb/MMBtu, which is 

well below the permit limit. The tested emission rate lies within the expected range for a 

properly operating ESP at a plant like Newington and may serve as a better measure of 

performance than any stated efficiency for this control device. Actual TSP emissions from 

Unit NT1 were 198 tons in 2002.

3.3 Discussion of Current SO2 Emissions and Controls 

Sulfur dioxide emissions are partially controlled at PSNH Newington Station by existing 

limits on fuel oil sulfur content. Permitted fuel sulfur limits are 2.0% sulfur by weight for 

No. 6 fuel oil and 0.4% sulfur by weight for No. 2 fuel oil. Unit NT1 does not have an 

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

tons of SO2 for all electrical generating units at PSNH’s Merrimack, Newington, and 

Schiller Stations combined. Actual SO2 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 estimated to have a life expectancy of 30 to 40 

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

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

lines. Newington Station Unit NT1 was built in 1969. However, because this facility runs 

primarily on fuel oil, its remaining useful life may depend more on future commodity 

supplies/prices and other external factors than on the longevity of plant equipment. 

5. DEGREE OF VISIBILITY IMPROVEMENT ANTICIPATED FROM BART 

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

sources under controlled and uncontrolled conditions. The same methodologies used for the 

CALPUFF modeling work for Merrimack Station Unit MK2 were applied to the modeling 

for Newington Station Unit NT1. 

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

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

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

Unit NT1 produce theoretical CALPUFF worst-case impacts of 1.22 dv at Acadia National 

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

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

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

even more conservative exemption level of 0.1 dv. CALPUFF modeling results for baseline 

emissions from Unit NT1 exceed all of these exemption 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 generally from SO2 emission reductions 

than NOx emission reductions. This finding reinforces MANE-VU’s early determination 

that SO2 was the primary target pollutant for maximizing visibility improvements. NOX, 

while also an important visibility impairing pollutant, reacts with ammonia less 

preferentially than does SO2 and is also less hydrophilic than SO2. As a result, NOX has a 

lower rate of formation of haze-causing particles and impairs visibility less effectively than a 

similar mass of SO2. 
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 SO2/MMbtu 

(77% sulfur reduction*) 0.47 0.37 0.08 

SO2 

Switch from 0.50 lb SO2/MMbtu emission 

limit to 0.3%S residual fuel oil <0.05 0.03 <0.01*** 

SNCR 

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

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 SO2/MMbtu 

(77% sulfur reduction*) 0.11 0.09 0.01 

SO2 

Switch from 0.50 lb SO2/MMbtu emission 

limit to 0.3%S residual fuel oil 0.01 0.01 <0.01*** 

SNCR 

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

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 modeling 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 was 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 SO2, 

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

modeled concentration reductions to estimate the corresponding visibility improvements at 

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

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

reduce maximum predicted 24-hour average SO2 concentration impacts by about 1.4 μg/m3. 

Reductions in the maximum predicted concentrations of SO2, PM2.5, and other haze-related 

pollutants, combined, would yield negligible visibility improvement at the affected Class I 

areas. 

6. DETERMINATION OF BART 

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

PSNH Newington Station Unit NT1, it is determined that the NOX, PM, and SO2 controls 

described below represent Best Available Retrofit Technology for this unit. 

6.1 Selecting a Pollution Control Plan for NOX 

Use of low excess air reduces NOX emissions but can often result in greater PM and/or CO 

emissions. Many of the NOX reduction benefits acquired through the implementation of low 

excess air are already being achieved at Unit NT1 through the use of low-NOx burners, 

overfire air, and water injection; so the application of low excess air would be redundant in 

this case. Flue gas recirculation reduces the peak flame temperature in much the same way 

as overfire air and has the additional benefit of reducing the oxygen content in the 

combustion zone, leading to further reductions in NOX formation. Because Unit 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 NOX emission reductions being achieved at Unit NT1 through the use of combustion 

control technologies are a substantial improvement over no controls. Retrofitting the facility 

with SCR or SNCR would reduce NOX emissions by an additional 300 to 700 tons per year. 

Despite the sizeable emission reductions that SCR or SNCR would provide, with annualized 

costs of $0.7 to $1.3 million, neither technology option could be implemented costeffectively. Note that these dollar amounts do not include the significant additional costs of 

redesigning Newington Station’s layout to address spatial constraints. Also, the estimated 

costs are based on 2002 emission levels, when the plant’s capacity factor was around 20 

percent. With the capacity factor having fallen to less than 10 percent over the period 2006-

2009, it is difficult to justify additional technology retrofits to reduce NOX emissions at this 

facility today. This conclusion is reinforced by the small improvement in visibility that 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 15 

might be obtained with such retrofits on the few occasions when meteorological conditions 

would indicate maximum impacts. 

Another consideration with SCR or SNCR is flue gas and fugitive ammonia emissions. 

Based on past operation of Unit NT1 and on typical ammonia “slip” rates, it is estimated that 

fugitive ammonia emissions with either technology would be in the vicinity of 32 tons 

annually. Ammonia is a regulated toxic air toxic pollutant in New Hampshire and is also a 

significant contributor to visibility impairment. However, the issue is not so much the 

magnitude of ammonia slip, toxicity, or visibility impairment as the fact that ammonia slip 

would occur at all. On balance, this is a relatively minor negative to be weighed in the 

context of other factors. 

Based on all of these considerations, NHDES finds that SCR and SNCR are not cost-effective 

as Best Available Retrofit Technology for NOX control at this facility and will not be evaluated

further. The existing NOX controls, which include low-NOx burners, overfire air, and water 

injection, are determined to fulfill BART requirements for Newington Station Unit NT1. 

Because additional retrofits are not proposed, completion of the BART assessment for Unit 

NT1 becomes a matter of ascertaining this facility’s long-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 gross heat input came from residual fuel oil. 

Monthly average NOX emissions ranged between 0.21 and 0.30 lb/MMBtu. These values 

compare favorably with the facility’s NOX RACT limit of 0.25 lb/MMBtu, daily average, 

when burning natural gas and 0.35 lb/MMBtu, daily average, when burning fuel oil. 

However, the extent of the data record is insufficient to demonstrate that the facility could 

sustainably meet more restrictive emission limits than these. The current NOX RACT 

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

6.2 Selecting a Pollution Control Plan for PM

PSNH currently operates an electrostatic precipitator on Unit 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 technically feasible to improve performance of the 

existing ESP through some form of upgrade, it is difficult to justify any major capital expense 

at this facility in light of its recent operating history. 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 outlay for PM control cannot be economically 

justified at this time, and that any resulting benefit to visibility would be negligible, it is 

determined that the existing ESP fulfills BART requirements. 

The single available stack test on this unit indicates that the ESP yields controlled TSP 

emission rates in the vicinity of 0.06 lb/MMBtu versus a currently permitted rate of 0.22 

lb/MMBtu. The extent of the data record is insufficient to support consideration of a BART 

performance level more restrictive than the existing permit limit. The facility’s Title V 

operating permit requires that a compliance stack test for PM emissions be performed on 

Unit NT1 before the permit expires on March 31, 2012. NHDES will review the stack test 

results to ascertain the unit’s performance and incorporate any new limit into a permit 

amendment by the permit expiration date, as appropriate. The permit expiration date 

precedes the effective date of proposed BART control measures by fifteen months.
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 16 

6.3 Selecting a Pollution Control Plan for SO2

Flue gas desulfurization is a potential SO2 control option for PSNH Newington Station Unit 

NT1. However, the cost per ton for FGD on oil-fired boilers is estimated to be about twice 

the cost of this technology on coal-fired boilers and could well exceed $1,000/kW for 

Newington Station. Given the high costs of this option, 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 for controlling SO2 emissions at Newington 

Station. When natural gas is available at reasonable cost relative to residual fuel oil, natural 

gas is the preferred fuel because of its very low sulfur content. Otherwise, use of low-sulfur 

residual fuel oil is a reasonable option. For relatively minor increases in the cost of fuel, 

switching to 1.0%-sulfur or 0.5%-sulfur residual fuel oil would provide significant reductions 

in fuel sulfur content with proportional reductions in SO2 emissions. 

When not firing exclusively on natural gas, Newington 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 the fuel oil ranged between 1.03 and 1.54 

percent by weight, with no significant trend (average fuel sulfur content was 1.21 percent in 

2002). For New Hampshire’s BART analysis of this plant, 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 (nominal) to 1.0 %S (nominal) residual 

fuel oil would produce a one-third reduction in sulfur dioxide emissions, and switching to 

0.5 %S (nominal) residual fuel oil would produce a two-thirds reduction in sulfur dioxide 

emissions at this facility. 

The proposed fuel switching could be accomplished without capital expense and would have 

predictable costs tied directly to fuel consumption and fuel price differentials. The cost per 

ton would be no more than about $1,900 (historical fuel prices suggest a range of $0 to 

$2,000 per ton). At the 2002 production level of 700 million kilowatt-hours, estimated 

annual costs (long-term average, 2008$) for switching to 1.0% or 0.5% residual fuel oil 

would be about $3.3 or $6.6 million (equivalent to $0.0047 or $0.0094 per kWh), 

respectively. The cost per kilowatt-hour would vary more or less in proportion to the fuel 

price differential and would not change significantly with increases or decreases in 

production level. 

While fuel availability is always a consideration, supplies should not be a significant factor 

in obtaining fuels whose sulfur content is as low as 0.5 percent. Residual fuel oil at 1.0% 

sulfur is already widely distributed within the region; 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, Massachusetts, 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 market for this commodity. 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 17 

NHDES considered the possible use of 0.3%-sulfur residual fuel oil for Unit NT1; but this fuel 

has had only very limited use within the northern New England region, and its future availability 

and price remain uncertain. More specifically, the fact that some plants in Connecticut are 

using 0.3%-sulfur residual fuel oil today does not guarantee the availability of this fuel in 

northern New England, which obtains its bulk oil shipments through different ports. 

For Unit NT1, the possible use of low-sulfur residual fuel oil is complicated by the plant’s 

low capacity factor and existing fuel stocks and storage facilities. The plant now has a 

sizeable quantity of higher-sulfur residual fuel oil in storage tanks on site. Because there is 

no practical way to offload and replace the existing inventory with a lower-sulfur residual 

fuel oil, the existing stock 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 for two major reasons: the high cost of burner 

replacements needed to implement this option, and the 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 when its price is competitive with that of 

residual fuel oil. Recent years have witnessed sudden and dramatic swings in the price of 

natural gas relative to fuel oil as supply/demand has shifted. While the future price and 

availability of natural gas remain difficult to discern, the market for natural gas is expected to 

expand amid global concerns about carbon emissions and a visible renaissance in gas 

exploration and development. 

Unit NT1 has considerable operational flexibility with respect to fuel selection. The boiler 

can be fired with either natural gas or liquid fuel as the only fuel, or it can be co-fired with 

both fuel types simultaneously. However, because of physical limitations to the boiler’s 

design, the unit can operate at no more than about 50 percent of maximum heat input when 

fueled solely by natural gas. There is already a natural incentive for PSNH to operate Unit 

NT1 with natural gas as much as possible whenever the 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 sulfur 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 natural gas and/or fuel oil in any feasible ratio, 

depending on market conditions. 

_________________ 

§

 This limit is calculated using USEPA’s published AP-42 emission factor for SO2 of 150(S) lb SO2/1000 

gallons. Assuming 0.5% fuel sulfur content by weight and a heating value of 150,000 Btu/gallon for No. 6 fuel 

oil, the SO2 emission rate would be 150 × 0.5 = 0.075 lb/gallon, and the SO2 emission factor would be 0.075 

lb/gallon ÷ 150,000 BTU/gallon × 106 = 0.5 lb/MMBtu. 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 18 

New Hampshire’s new rule will cause a substantial reduction in SO2 emissions from Unit 

NT1 regardless of fuel type while rendering unnecessary any need to speculate on the 

direction of relative fuel supplies and prices. For the first regional haze progress report, due 

no later than December 17, 2012, 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 control for Unit NT1. Should the review 

indicate a different BART control level, the facility’s Title V operating permit will be 

amended as necessary before its expiration date of March 31, 2012, fifteen months prior to 

the effective date of proposed BART control measures. The use of low- or ultra-low-sulfur 

residual fuel oil will be reconsidered as part of this review. Looking beyond 2012, a 

possible further reduction in the sulfur content of fuel oil burned at this facility would be 

consistent with MANE-VU’s plan to reduce sulfur levels to 0.25-0.5% for all residual fuel 

oils throughout the region by 2018 (refer to “Statement of the Mid-Atlantic/ Northeast 

Visibility Union (MANE-VU) Concerning a Course of Action within MANE-VU toward 

Assuring Reasonable Progress,” June 20, 2007, included in Attachment E).

 

7. SUMMARY AND CONCLUSIONS 

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

Unit NT1 for the pollutants NOX, PM, and SO2. The summary includes existing controls 

that have been determined to fulfill BART requirements as well as new operating conditions 

consistent with BART requirements. A more stringent sulfur dioxide emission limitation, 

established by a rule change, will require the facility 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 

NOX 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) 

SO2 2.0% sulfur content limit 

on residual fuel oil; 

0.4% sulfur content limit 

on distillate fuel oil 

SO2 emission limitation of 

0.50 lb/MMBtu, 

applicable to any fuel type 

or mix 

0.50 lb/MMBtu, 

30-day rolling average 

 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 19 

NEW HAMPSHIRE BART ANALYSIS: Newington Station Unit NT1 (400 MW) 

Estimated Cost of Em

Uncontrolled 

Emissions 

Controlled Emissions 

Emission 

Pollutant Emission Control Reductions Technology Approx. Control Level ton/yr ton/yr ton/yr Capital $ Capital $/kW O&M $/yr 

Combustion Controls (existing) 33% 1,407 1 943 2 464    LNB (typical) 40% 1,407 1 844 563 7,905,617 20 167,05LNB+OFA (typical) 50% 1,407 1 704 704 10,732,574 27 228,21SCR 85% 1,407 1 211 1,196 11,510,100 37 441,68

NOX

SNCR 50% 1,407 1 704 704 3,298,475 12 451,02

ESP (existing) 42% 338 2 196 2 142    

PM min. 23,426,952 59 2,733,14

Fabric Filters 99% 338 2 3 335

max. 78,089,840 195 3,904,49

2.0%-S oil (existing) 0% 3 5,226 2      Switch to 1.0%-S oil 33% 4 5,226 2 3,484 1,742    Switch to 0.5%-S oil 67% 5 5,226 2 1,742 3,484    

SO2

FGD 90% 5,226 2 523 4,703 422,000,000 1,055 unknown 

1 Estimated. 2 2002 (baseline) emissions reported in NHDES data summary as derived from facility's annual emissions statement. 3 Actual 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 4 Based on an assumed average fuel sulfur content of 0.8%. 5 Based on an assumed average fuel sulfur content of 0.4%. 6 All cost estimates adjusted to 2008$. 7 USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model, November 2006. 8 NESCAUM, Assessment of Control Technology Options for BART-Eligible Sources, March 2005. 9 Stated costs represent premium for purchasing 1.0%-S oil at estimated price differential of 7.5¢/gal. 

10 Stated costs represent premium for purchasing 0.5%-S oil at estimated price differential of 15¢/gal. 11 Based on $/kW estimated capital cost for comparable controls at Merrimack Station. 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 20 

Newington Station Unit NT1: NO

X Controls 

Plant type oil- or natural-gas-fired boiler Historical operation: Capacity 400 MW Year 2002 2003 2004 2005 Maximum heat Input 4,350 MMBtu/hr Operating hours 3,085 6,606 6,300 4,187 Capacity factor 20 % Total Heat Input* 7,223,832 26,414,481 22,477,521 16,060,698 Annual hours 8,760 hr/yr Capacity factor** 19.0% 69.3% 59.0% 42.1% Annual production 700,800,000 kWh/yr *MMBtu (from CEM data) **Based on ratio of total heat input to Costs: 2004$ 

Capital Scaled Capital Total Capital Total Annualized Capital Fixed O&M Scaled Fixed O&M Variable O&M Total Fixed & Variable O&M 

A

Control Technology 

$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh $/yr $/yr 

LNB 19.24 17.4 6,940,840 581,434 0.29 0.26 104,618 0.06 42,048 146,666 LNB+OFA 26.12 23.6 9,422,804 789,348 0.40 0.36 144,300 0.08 56,064 200,364 SCR 32.20 25.26 10,105,443 846,533 0.99 0.78 310,695 0.11 77,088 387,783 SNCR 10.80 7.24 2,895,939 242,593 0.17 0.11 45,584 0.50 350,400 395,984 Costs: 2008$ 2004$ 

→ 2008$ 1.139 multiplier 

Capital Scaled Capital Total Capital Total Annualized Capital Fixed O&M Scaled Fixed O&M Variable O&M Total Fixed & Variable O&M 

A

Control Technology 

$/kW $/kW $ $/yr $/kW/yr $/kW/yr $/yr mills/kWh $/yr $/yr 

LNB 21.91 19.76 7,905,617 662,254 0.33 0.30 119,160 0.07 47,893 167,052 LNB+OFA 29.75 26.83 10,732,574 899,068 0.46 0.41 164,358 0.09 63,857 228,215 SCR 36.68 28.78 11,510,100 964,201 1.13 0.88 353,882 0.13 87,803 441,685 SNCR 12.30 8.25 3,298,475 276,313 0.19 0.13 51,920 0.57 399,106 451,026 Cost Reference: Annualized cost basi

 Period, yrs 15  Interest, % 3.0 

USEPA, Documentation for EPA Base Case 2006 (V.3.0) Using the Integrated Planning Model, November 2006. 

Note: Cost estimates for LNB and LNB+OFA are based on referenced values for coal-fired plants; actual costs could be 

greater for oil- or gas-fired units. CRF 0.0837
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 21 

Newington Station Unit NT1: PM Controls Plant type oil- or natural-gas-fired boiler Historical operation: Capacity 400 MW Year 2002 2003 2004 2005 Maximum heat Input 4,350 MMBtu/hr Operating hours 3,085 6,606 6,300 4,187 Capacity factor 20 % Total Heat Input* 7,223,832 26,414,481 22,477,521 16,060,698 Annual hours 8,760 hr/yr Capacity factor** 19.0% 69.3% 59.0% 42.1% Annual production 700,800,000 kWh/yr *MMBtu (from CEM data) **Based on ratio of total heat input Flue gas flow rate 1,714,000 acfm 

2004$ 

Capital Total Capital Total Annualized Capital Fixed O&M Variable O&M Total Fixed & Variable O&M Total Annualized Cost Emission Reductions Average Cost Control Technology 

$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr $/ton 

min. 15.00 25,710,000 2,153,727 0.25 0.45 1,199,800 3,353,527 142 23,616 Dry ESP 

max. 40.00 68,560,000 5,743,271 0.65 0.60 2,142,500 7,885,771 142 55,534 

min. 15.00 25,710,000 2,153,727 0.15 0.25 685,600 2,839,327 142 19,995 

Wet ESP 

max. 40.00 68,560,000 5,743,271 0.50 0.50 1,714,000 7,457,271 142 52,516 

Fabric Filter - min. 17.00 29,138,000 2,440,890 0.35 0.70 1,799,700 4,240,590 335 12,673  Reverse Air max. 40.00 68,560,000 5,743,271 0.75 0.80 2,656,700 8,399,971 335 25,103 Fabric Filter - min. 12.00 20,568,000 1,722,981 0.50 0.90 2,399,600 4,122,581 335 12,320  Pulse Jet max. 40.00 68,560,000 5,743,271 0.90 1.10 3,428,000 9,171,271 335 27,408 Costs: 2008$ 2004$ 

→ 2008$ 1.139 multiplier 

Capital Total Capital Total Annualized Capital Fixed O&M Variable O&M Total Fixed & Variable O&M Total Annualized Cost Emission Reductions Average Cost Control Technology 

$/acfm $ $/yr $/yr-acfm $/yr-acfm $/yr $/yr tons/yr $/ton 

min. 17.09 29,283,690 2,453,095 0.28 0.51 1,366,572 3,819,667 142 26,899 Dry ESP 

max. 45.56 78,089,840 6,541,586 0.74 0.68 2,440,308 8,981,893 142 63,253 

min. 17.09 29,283,690 2,453,095 0.17 0.28 780,898 3,233,993 142 22,775 Wet ESP 

max. 45.56 78,089,840 6,541,586 0.57 0.57 1,952,246 8,493,832 142 59,816 

Fabric Filter - min. 19.36 33,188,182 2,780,174 0.40 0.80 2,049,858 4,830,032 335 14,434  Reverse Air max. 45.56 78,089,840 6,541,586 0.85 0.91 3,025,981 9,567,567 335 28,592 

min. 13.67 23,426,952 1,962,476 0.57 1.03 2,733,144 4,695,620 335 14,033 Fabric Filter - 

 Pulse Jet max. 45.56 78,089,840 6,541,586 1.03 1.25 3,904,492 10,446,078 335 31,218 
BART Analysis – PSNH Unit NT1 January 14, 2011 Page 22 

Newington Station Unit NT1: SO2 ControlsSO2 Control Cost Calculations for Switching from #6 Fuel Oil @ 2.0% S to Lower-Sulfur Fuel Oils @ 1.0 or 0.5% S: 

Maximum 

(Nominal) 

Fuel Sulfur

1

Actual 

Fuel Sulfur 

Annual 

Fuel Usage

4

Annual SO2

Emissions 

Switch to 

Lower-S Fuel

Annual SO2

Emission 

Reductions

7

Blende

Fuel Price Dif

Fuel Type 

%S by wt %S by wt gal/yr ton/yr %S by wt ton/yr ¢/gal 

#6 Residual Oil 2.0 1.2 2 44,144,100 5,226 5    #6 ULS Residual Oil 1.0 0.8 3 44,144,100 3,484 6 2.0 to 1.0% 1,742 7.5 9 $#6 ULS Residual Oil 0.5 0.4 3 44,144,100 1,742 6 2.0 to 0.5% 3,484 15.0 10 $

1 Maximum allowable sulfur content of specified fuel.2 Actual 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 3 Assumed average sulfur content of specified fuel as assayed. 4 Actual fuel usage in 2002. 5 Actual 2002 emissions from CEM data. 6 Estimated emissions based on stated fuel usage and estimated average sulfur content of specified fuel.7 Estimated emission reductions after switch to specified lower-sulfur fuel. 8 Estimated 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. 9 Estimated price difference between fuel @ 1.2%S (2002 actual) and fuel @ 0.8%S actual (1.0% nominal). 

10 Estimated price difference between fuel @ 1.2%S (2002 actual) and fuel @ 0.4%S actual ( 0.5% nominal).

SO2 Control 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 

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 Page 23 

Enclosure to Letter from PSNH to DES ARD, dated 12/4/09 NOTE: This sheet is a re-creation of PSNH's tables, with formulas 

additional calculations. All changes and additions to the original are 

Assumptions Used to Calculate Incremental Cost Estimates* 

(A) AP-42** AP-42*** (B) (C) (D) (E) 

% sulfur SO2 SO2 SO2 Max Gross SO2 Reduction Fuel Switch increased cost/barrel  increase

lb/1000gal lb/mmbtu lb/mmbtu Heat Input lb/hr in SO2 low high low 

 mmbtu/hr lb/hr 

2.0 314.0 2.041 2.288 4,350 9,952.8 1.0 157.0 1.021 1.086 4,350 4,724.1 5,228.7 2% to 1% $0.00 $4.00 $0.00 0.7 109.9 0.714 0.748 4,350 3,253.8 1,470.3 1% to 0.7% $1.00 $3.30 $673.21 0.5 78.5 0.510 0.528 4,350 2,296.8 957.0 0.7% to 0.5% $1.00 $2.20 $673.21 0.3 47.1 0.306 0.313 4,350 1,361.6 935.3 0.5% to 0.3% $3.00 $9.00 $2,019.64 

 4,350 5,228.7 2% to 1% $0.00 $4.00 $0.00  4,350 6,699.0 2% to 0.7% $2.00 $7.00 $1,346.43  4,350 7,656.0 2% to 0.5% $3.00 $9.00 $2,019.64  4,350 8,591.3 2% to 0.3% $4.00 $17.00 $2,692.86 

(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. (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 = $/hr  Actual Fuel Use Historical Fuel Cost  #6 oil 2%S Oil 1%S Oil 0.7%S Oil 0.5%S Oil 0.3%S Oil  (barrels) ($/barrel) ($/barrel) ($/barrel) ($/barrel) ($/barrel) 

2002 1,051,050 $21.20 $22.45 $23.26 $23.80 $25.25 2003 3,425,217 $24.95 $27.48 $29.26 $30.45 $32.63 2004 3,099,258 $25.25 $27.92 $30.04 $31.46 $34.53 2005 2,027,172 $37.00 $41.00 $44.00 $46.00 $50.10 2006 392,922 $45.50 $46.30 $48.46 $49.90 $54.12 2007 529,092 $53.70 $53.45 $56.54 $58.60 $62.86 2008 201,172 $75.25 $77.80 $81.10 $83.30 $92.16 2009 118,246 $49.90 $50.75 $51.98 $52.80 $55.83 

 Historical 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. 
 

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