BART Analysis for 

PSNH Newington Station Unit NT l 

January 14, 2011 

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

BART Analysis for 

PSNH Newington Station Unit NT 1 

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 S02 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 NT 1 January 14, 2011 ; amended August 26, 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 NT 1 January 14, 2011 ; amended August 26, 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 

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

factor. 

Table 2-1. Estimated NOx Control Costs 

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

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

LNB 21 .9 7,900,000 170,000 830,000 1,470 

LNB+OFA 29.8 10,700,000 230,000 1,130,000 1,600 

SNCR 12.3 3,300,000 450,000 730,000 1,030 

SCR 36.7 11,500,000 440,000 1,410,000 1,180 

Estimates are derived 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 S02 to S03, 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 ; amended August 26, 2011 Page 4 

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

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

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

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

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 NT I January 14, 2011 ; amended August 26, 2011 Page 5 

Mechanical Collectors and Particle Scrubbers 

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

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

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

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

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

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

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

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

generally less effective for removal of fine particles. . 

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

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

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

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

of PM emissions. 

2.2 .1 Potential Costs of PM Controls 

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

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

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

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

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

Table 2-2. PM Control Costs 

Capital Cost O&M Cost Total Average 

Control Technology Annual Cost Cost 

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

Dry ESP 73-194 29.3-78.1 million 1 .4-2.4 million 3 .8-9.0 million 27,000-63,000 

Wet ESP 73-194 29.3-78.1 million 0 .8-2 .0 million 3 .2-8.5 million 23,000-60,000 

Fabric filter-reverse air 82-194 33 .2-78.1 million 2 .0-3 .0 million 4.8-9.6 million 14,000-29,000 

Fabric filter-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 $14,060 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 NT 1 January 14, 2011 ; amended August 26, 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 SOz Control 

S02 control technologies available and potentially applicable to Unit NTl 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 

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

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

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

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

sulfur removal rates and produce minimal wastewater discharges . 

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

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

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

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

Sulfate products that are not recycled must be landfilled . 

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

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

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

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

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

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

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

S02 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 SOZ 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 ; amended August 26, 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 S02 emissions are directly related to the sulfur content of the fuel burned, reducing 

the amount of sulfur in the fuel reduces S02 emissions . For facilities that burn fuel oil, 

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

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

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

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

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

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

resulting S02 emission reductions are roughly proportional to the fraction of natural gas 

burned on a Btu-equivalent basis. 

2.3 .1 Potential Costs of S02 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 S02 removal as a co-benefit) at its two coal-fired boilers. These 

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

of Newington Station Unit NTl . The company's capital cost estimate for the wet limestone 

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 ; amended August 26, 2011 Page 8 

amount, or 15 cents/gallon (both estimates in 2008$ based on Energy Information Agency 

compiled price data for the period 1983-2008.) Using these unit prices, the total cost of 

switching to low-S residual fuel oil is approximately $3 .3 million per year, or $1,900 per ton 

of S02 emissions removed; and the cost of switching to ultra-low-S residual fuel oil is 

approximately $6.6 million per year, or also $1,900 per ton of SOZ emissions removed (both 

estimates 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 SOZ 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. SOZ Control Costs 

Control Capital Cost O&M Cost Total Average 

Technology Annual Cost Cost 

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

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

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 0/gallon for substitution of 1 .0%-S or 0.5%-S residual fuel oil, respectively . 

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

has estimated the costs 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 NT 1 January 14, 2011 ; amended August 26, 2011 Page 9 

Using this historical fuel price record and PSNH's calculated SOz emission reductions from 

fuel switching, the New Hampshire Department of Environmental Services (NHDES) has 

prepared alternate estimates of the increased costs of fuel switching 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 

Fuel SOZ Emission 

Reduction* 

Increased Cost 

($/barrel 

Increased Cost 

($/hour)** 

$/ton of 

SOZ Removed*** 

Switch (Ib/hr) low high low high low high 

4 2% to 1 % 5,228.7 0 4 0 2,692 0 1,030 

1% to 0.7% 1,470.3 1 3 .3 673 2,222 414 3,022 

0.7% to 0.5% 957.0 1 2 .2 673 1,482 586 3,095 

0.5% to 0.3% 935 .3 3 9 2,020 6,059 2,967 12,957 

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

4 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 x MMBtu/hr = $/hr 

* * * $/hr = lb/hr x 20001b/ton = $/ton 

Besides switching residual fuel oils to reduce S02 emissions, other proposed options 

include replacing 2 .0%-S residual fuel oil with low-sulfur distillate fuel oil or natural gas. 

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

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

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

exceed $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 NT 1 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 NT 1 January 14, 2011 ; amended August 26, 2011 Page 10 

Volatile energy commodity prices in recent years and the uncertainty of future fuel prices 

make it difficult to provide a useful estimate 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-l. Comparison of Fossil Fuel Prices for Electric Generation 

in New England (1990-2008) 

3 

m 

a`r 

a 

N 

d 

N 

a` 

d 

Q 

1,600 

1,600 

1 .400 

1,300 

1,200 

1,100 

1,000 

900 

800 

700 

1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 

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

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

0 

600 

500 

400 

300 

200 

100 

2.3 .2 Other Environmental and Energy Impacts of S02 Controls 

An 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(p) 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 S02, 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. 

---- -I-----~ 

i 

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BART Analysis - PSNH Unit NT l January 14, 2011 ; amended August 26, 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 NTI currently operates with low-NOx burners, an overfire 

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

RACT requirements, the facility's existing air permit limits NOx emissions 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 NTI 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 NTI 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 NTI were 198 tons in 2002. 

3.3 Discussion of Current S02 Emissions and Controls 

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

limits on fuel oil sulfur content. Permitted fuel sulfur limits are 2 .0% sulfur by weight for 

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

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

tons of S02 for all electrical generating units at PSNH's Merrimack, Newington, and 

Schiller Stations combined. Actual SOZ emissions 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 NT 1 January 14, 2011 ; amended August 26, 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 

5.1 CALPUFF Modeling Analysis 

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

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

CALPUFF modeling work for Merrimack Station Unit 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 NTl produce theoretical CALPUFF worst-case impacts of 1 .22 dv at Acadia National 

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

modeling indicates that a source produces less than 0 .5 dv 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% worst natural and 20% worst baseline visibility 

days are presented in Table 5-1 . 

As seen in the table, more benefit would result generally from S02 emission reductions 

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

that SOZ was the primary target pollutant for maximizing visibility improvements . NOx, 

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

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

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

similar mass of S02. 
BART Analysis - PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 13 

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

Visibility Improvements from BART Controls 

01u the 2(l% 

Pollutant 

SOZ 

NOx 

PM 

Control Level 

FGD 

(90% sulfur reduction*) 

1 .0%-S residual fuel oil 

(50% sulfur reduction*) 

0.5%-S residual fuel oil 

(75% sulfur reduction*) 

0.3%-S residual fuel oil 

(85% sulfur reduction*) 

0.50 lb SOZ/MMbtu 

(77% sulfur reduction*) 

atural Visibility Days (deciviews) 

Switch from 0.501b SOZ/MMbtu emission 

limit to 0.3%S residual fuel oil 

SNCR 

(25% NOx reduction**) 

SCR 

(78% NOx reduction") 

Baghouse 

(85% PM reduction 

On the 20% t Base 

Acadia 

0.57 

0.30 

0.46 

Great Gulf 

0.45 

Lye Brook 

0.09 

0.24 - 0.05 

0.36 0.07 

0.52 0.40 

0.47 C -_- -- 

<0.05 

L 

0.11 

0.34 

0.05 

0.08 

0.37 0.08 

0.03 

0.10 

0.30 

0.04 

tie V'isjbility Days (deciviews 

-

Pollutant ~ Control Level Acadia Great Gulf 

SOZ 

NOx 

FGD 

(90% sulfur reduction*) 

1.0%-S residual fuel oil 

(50% sulfur reduction*) 

0.5%-S residual fuel oil 

(75% sulfur reduction*) 

0.3%-S residual fuel oil 

(85% sulfur reduction*) 

0.50 lb SO2/MMbtu 

(77% sulfur reduction*) 

Switch from 0.50 lb SOz/MMbtu emission 

limit to 0.3%S residual fuel oil 

SNCR 

(25% NOx reduction**) 

SCR 

(78% NOx reduction**) 

PM Baghouse 

1 (85% PM reduction**) 

* from maximum permitted level 

** from baseline level with existing controls 

*** below sensitivity limit of model 

0.13 

0.07 

0.11 

0.13 

0.11 

0.01 

0.04 

0.11 

0.02 

0.10 

<0.01*** 

0.04 

0.12 

0.01 

Lye Brook 

<0.01*** 

0.06 <0.01*** 

0.09 

0.10 

0.09 

0.01 

0.03 

0.10 

0.02 

0.01 

0.01 

0.01 

<0.01*** 

0.01 

0.03 

<0.01*** 

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

visibility benefits from BART controls . 
BART Analysis - PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 14 

5.1 CALGRID Modeling Analysis 

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

BART controls at PSNH Newington Station Unit NT1 . Specifically, one modeling run 

using the 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 SOZ, 

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

modeled concentration reductions to estimate the corresponding visibility improvements at 

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

Based on the CALGRID modeling results, switching to lower-sulfur fuel oil for Unit NT l is 

expected to reduce near-stack maximum predicted 24-hour average SOZ concentration 

impacts by about 1 .4 ~tg/m3 . Reductions in the maximum predicted concentrations of S02, 

PM2.5, and other haze-related pollutants, combined, would yield negligible visibility 

improvement at the affected Class I areas . 

6. 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 SOZ 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 NT I 

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- 
BART Analysis - PSNH Unit NT 1 January 14, 2011 ; amended August 26, 2011 Page 15 

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 

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 NT 1 . 

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 NT 1 are therefore considered to represent BART control levels . 

6.2 Selecting a Pollution Control Plan for PM 

PSNH currently operates an electrostatic precipitator on Unit NTI. ESPs 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 
BART Analysis - PSNH Unit NT1 January 14, 2011 ; amended August 26, 2011 Page 16 

amendment by the permit expiration date, as appropriate . The permit expiration date 

precedes the effective date of proposed BART control measures by fifteen months. 

6.3 Selecting a Pollution Control Plan for S02 

Flue gas desulfurization is a potential SOZ control option for PSNH Newington Station Unit 

NTI. However, the cost per ton for 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 NT I . 

Use of a lower-sulfur fuel is a practical option for controlling S02 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 S02 emissions. 

When not firing exclusively on natural gas, Newington Station Unit NT I 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 Assumed Actual %S 

(permit limitation) (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 
BART Analysis - PSNH Unit NT 1 January 14, 2011 ; amended August 26, 2011 Page 17 

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. 

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 NT I 

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 NT 1 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) 

§ This limit is calculated using USEPA's published AP-42 emission factor for SO2 of 150(S) lb SOz/1000 

gallons. Assuming 0.5% fuel sulfur content by weight and a heating value of 150,000 Btu/gallon for No. 6 fuel 

oil, the SOZ emission rate would be 150 x 0 .5 = 0.075 lb/gallon, and the SOZ emission factor would be 0 .075 
BART Analysis - PSNH Unit NT 1 January 14, 2011 ; amended August 26, 2011 Page 18 

will allow the facility the flexibility to burn natural gas and/or fuel oil in any feasible ratio, 

depending on market conditions . 

New Hampshire's new rule will cause a substantial reduction in S02 emissions 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 S02. 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 BART Controls BART 

Controls Emission Limit 

NOx Low-NOx burners, Low-NOx burners, 0.35 lb/MMBtu (oil) and 

overfire air, and water overfire air, and water 0.25 lb/MMBtu (oil/gas), 

injection injection daily avg. (= RACT limit) 

PM ESP ESP 0.221b/MMBtu 

total suspended particulate 

(TSP) 

SOZ 2.0% sulfur content limit SOZ emission limitation of 0.50 lb/MMBtu, 

on residual fuel oil; 0.50 lb/MMBtu, 30-day rolling average 

0.4% sulfur content limit applicable to any fuel type 

on distillate fuel oil or mix 

lb/gallon = 150,000 BTU/gallon x 106 = 0.5 lb/MMBtu. 
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