because they may not reasonably be anticipated to cause or contribute to any visibility 

impairment in a Class I area. 

Based on the collective importance of BART sources, Maine has decided that no 

exemptions would be given for sources; a BART determination will be made for each 

BART-eligible source. 

10.6 MANE-VU BART Modeling 

MANE-VU conducted modeling analyses of BART-eligible sources using CALPUFF in 

order to provide a regionally-consistent foundation for assessing the degree of visibility 

improvement which could result from installation of BART controls (See Attachment L). 

While this modeling analysis differed slightly from the statutory language, it was 

intended to provide a first-order estimate of the maximum visibility benefit that could be 

achieved by eliminating all emissions from a BART source, and provides a useful metric 

for determining which sources are unlikely to warrant (additional) controls to satisfy 

BART. 

The MANE-VU modeling effort analyzed 136 BART-eligible sources in the MANE-VU 

region using the CALPUFF modeling platform and two meteorological data sets: 1) a 

wind field based on National Weather Service (NWS) observations; and 2) a wind field 

based on the MM5 meteorological model (MM5 2006). Modeling results from both the 

NWS and MM5 platforms include each BART eligible unit's maximum 24-hr, 8'h highest 

24-hr, and annual average impact at the Class I area. These visibility impacts were 

modeled relative to the 20 percent best, 20 percent worst, and average annual natural 

background conditions. In accordance with EPA guidance, which allows the use of either 

estimates of the 20 percent best or annual average natural background visibility 

conditions as the basis for calculating the deciview difference that individual sources 

would contribute for BART modeling purposes, MANE-VU opted to utilize the more 

conservative best conditions estimates approach because it is more protective of the 

region . 

The 2002 baseline modeling provides an estimate of the maximum improvement in 

visibility at Class I Areas in the region that could result from the installation of BART 

controls (the maximum improvement is equivalent to a "zero-out" of emissions) . In 

virtually all cases, the installation of BART controls would result in less visibility 

improvement than what is represented by a source's 2002 impact, but this approach does 

provide a consistent means of identifying those sources with the greatest contribution to 

visibility impairment. 

In addition to modeling the maximum potential improvement from BART, MANE-VU 

also determined that 98 percent of the cumulative visibility impact from all MANE-VU 

BART eligible sources corresponds to a maximum 24-hr impact of .22 dv from the NWSdriven data and 0.29 dv from the MM5 data. As a result, MANE-VU concluded that, on 

the average, a range of 0.2 to 0.3 dv would represent a significant impact at MANE-VU 

100 
Class I areas, and sources having less than 0.1 dv impact are unlikely to warrant 

additional controls under BART." 

Table 10-2 illustrates the modeled impacts (maximum) of Maine BART-Eligible sources 

on selected Class I areas in Maine and New Hampshire. For this table, S04, N03 and 

PMIO modeled impacts at these Class I areas were totaled to provide an estimate of the 

maximum 24-hr impact at these nearby Class I areas. It should be noted that a number of 

BART-eligible sources (highlighted) have less than a 0.1 deciview impact on Class I 

areas. 

10.7 The Maine BART Analysis Protocol 

40 CFR 51 .308(e)(1)(ii)(A) requires that, for each BART-eligible source within the state, 

any BART determination must be based on an analysis of the best system of continuous 

emission control technology available and the associated emission reductions achievable. 

In addition to considering available technologies, this analysis must evaluate five specific 

factors for each source : 

1 . The costs of compliance, 

2. The energy and non-air quality environmental impacts of compliance, 

3. Any existing pollution control technology in use at the source, 

4. The remaining useful life of the source, and 

5. The degree of visibility improvement which may reasonably be anticipated 

from the use of BART. 

Although Maine did not exempt any BART-eligible sources from a BART determination, 

it did utilize the MANE-VU zero-out modeling (described in the previous section) as a 

surrogate for estimating the visibility improvement reasonably expected from the 

application of controls . As previously highlighted in Table 10-2, there are ten BARTeligible sources with less than 0.1 deciview impact at any Class I area, with these impacts 

ranging from a low of 0.0018 deciviews to a higher (but still insignificant) 0.0822 

deciviews. Since zero-out modeling shows that the elimination of all emissions from 

these sources would provide only insignificant visibility benefits at nearby Class I areas, 

and recognizing that the majority of these units already have controls fully satisfying 

BART requirements, the Department used the "anticipated visibility improvement from 

BART" factor to determine the scope of the BART analysis and whether visibility impact 

modeling need be performed by specific sources . The Maine approach is consistent with 

that used by other MANE-VU states that are not allowing sources to utilize exemption 

modeling. With the Maine approach, all BART-eligible sources were required to 

undertake an engineering analysis of their existing and possible future controls. If an 

al As an additional demonstration that sources whose impacts were below the 0.1 dv level were too small to 

warrant BART controls, the entire MANE-VU population of these units was modeled together to examine 

their cumulative impacts at each Class I suite. The results of this modeling demonstrated that the 

maximum 24-hour impact at any Class I area of all modeled sources with individual impacts below 0.1 dv 

was only a 0.35 dv change relative to the estimated best days natural conditions at Acadia National Park. 

This value is well below the 0.5 dv impact recommended by EPA for exemption modeling and used by 

most other RPOs. 

101 
emissions unit was found to be well-controlled (in comparison with possible future 

controls), and the visibility impacts of the unit relatively sma1142 as determined by the 

MANE-VU zero-out modeling, BART was determined by existing controls, and 

additional visibility impact modeling was not necessary (for a more detailed look at 

Maine's BART process, see Attachment M-1). 

Table 10-2 

Modeled Impacts (Deciviews) of Maine BART-Eligible Sources at Selected MANEVU Class I Areas 

(Sources with < 0.1 deciview total impact highlighted) 

Facili ty Name Stack Name NWS CALPUFF MM5 CALPUFF 

Total S04 N03 PM10 Total S04 N03 PM10 

24-hr dv impact 24-hr d impact 

FPLE Wyman 

Station Boiler 4 0.1423 .1276 0.0334 0.0010 0.4749 0 0.107 0 .0005 FPLE Wyman 

Station Boiler 3 0.2212 ~ 1715 0 .0704 0.0004 0.3049 : 0 .0508 0 .0014 

Domtar Ind. #9 Power Boiler 1 .3630 0.2828 0.7988 1 .31 1 .6506 0.1815 0.7279 1 .3717 

Domtar Ind. Lime Kiln 0.5296 0 .0559 0.4309 0,120 0.4589 0.0427 0. 20 0.1048 

Dragon Products Kiln 2.0155 02434 1 .7614 0.0604 1 .8626 0.320$ 1 .72"34 0.0413 

Red Shield 

Acquisition, Old 

Town 

Acquisition, 

Town 

Red Shield 

Old 

#4 

Lime 

Recove

Kiln 

ry, Boiler 0

0

.2425 

.0851 

0

0

.0634 

.0171 

0

0

.11

.0433 

W,' 

;0

0 .0173 

.0278 

0.2631 0 .0424 0 .2070 0 .0391 

0.0138 0.0855 0.0463 

Verso, Bucks port Boiler #5 0.0543 0.0260 0.0267 0.0021 0.0817 0.0721 0.0098 

SAPPI Somerset Recove Boiler 0.2159 0.0151 ~ .1~7'1 0.0087 0.4421 0.0179 .4188 0 .0158 

SAPPI Somerset Smelt Tanks #1 and #2 0.0108 0.0034 0.0000 0.0095 0 .0000 0.0000 0 .0000 0 .0000 

SAPPI Somerset Lime Kiln 0.0380 0.0270 0.0105 0 .0012 0 .0651 0.0455 0 .0187 0 .0010 

Verso, 

Androsco in Power Boiler #1 0.6948 0 .5720 0.1235 0 .0094 1 .7631 1 .2176 0 .6867' 0.0290 

Verso, 

Androsco in Power Boiler #2 

- 

0.7223 0.5948 0.1287 0 .0095 1 .8289 1 .26" 0. 105 0.0293 

Verso, 

Androsco in 

Waste-Fuel-Incinerator 

Boiler 0 .4256 0.0036 0.3 01-, 0.0591 0.4956 0.0064 0 .4l144 0.0367 

Verso, 

Androsco in Recove Boiler #1 and #2 0.1101 0.0454 0.0598 0.0078 0.3856 0.0952 O:Z723 0.0215 

Verso, 

Androsco in Smelt Tank #1 0.0139 0.0002 0.0000 0.0137 0.0122 0.0002 0.0000 0.0120 

Verso, 

Androsco in Smelt Tank #2 0.0129 0.0004 0.0000 0.0125 0.0135 0.0006 0.0000 0 .0129 

Verso, 

Androsco in Lime Kiln A 0.0441 0.0001 0.0273 0 .0167 0 .0457 0.0004 0.0337 0 .0123 

Verso 

Andoco in Lime Kiln B 0.0296 0.0001 0.0197 0.0098 0.0293 0.0004 0.0228 0 .0062 

Verso, 

Androsco in Flash Dryer 0 .0222 0 .0044 0.0173 0 .0005 0 .0252 0 .0097 0 .0175 0 .0003 

Katahdin Paper 

Millinocket PB #4 0 .8293 0.6630 0.15 0.0210 0.4458 ,'0 . 3$,32 0,1164 0.0216 

Lincoln Paper and 

Tissue Recove Boiler #2 0.1151 0.0141 0.0806 0.0224 0.1200 0.0073 0.0882 0.0322 

Rumford Paper P13 #5 0.0369 0.0039 0.0327 0.0026 0.0108 0.0897 0.0020 

> 0.1 dv TOTAL and a pollutant 

42 Sources with less than 0.1 deciview impact on Class I areas are presumed to have a small impact. 

102 
10.8 Summary of Maine BART Determinations 

The following section details the BART determinations for all BART-eligible sources in 

Maine. All BART requirements are incorporated in a Title V air emissions license 

(operating permit) for each source ; Title V licensee are included in Attachment M. 

10.8 .1 Cap-Outs and Shutdowns 

EPA guidance allows BART-eligible sources to adopt a federally enforceable permit 

limit to permanently limit emissions of visibility impairing pollutants to less than 250 

tons per year, thereby "capping-out" of BART. Three Maine sources capped out of 

BART: 

1 . Katahdin Paper Company, LLC 

2. Rumford Paper Company 

3 . Verso Bucksport, LLC 

These sources have actual emissions of visibility impairing pollutants of fewer than 250 

tons per year, and are BART-eligible only because their potential emissions (PTE) 

exceed the statutory threshold of 250 tons per year. Pursuant to their requests, the Maine 

DEP has established federally enforceable permit conditions that limit the PTE of these 

units to less than the statutory threshold of 250 tons per year for all visibility impairing 

pollutants, which makes these units not subject to BART requirements. 

Federally enforceable terms and conditions were established for each source that limit the 

PTE for SOZ, PMIo and NOX to less than 250 TPY. Note that if, in the future, the source 

requests an increase in PTE greater than 250 tons per year per visibility impairing 

pollutant, then they shall be subject to the Best Available Retrofit Technology (BART) 

provisions of the Environmental Protection Agency's (EPA) Regional Haze Program 

Requirements (40 Code of Federal Regulations, Part 51, Section 308). 

10.8 .2 Maine BART Determinations 

In general, the following determinations summarize the controls and limits that are 

currently required under existing air emission licenses (as noted), or will be required 

specifically due to BART. 

1. Domtar Maine, LLC 

The Domtar Woodland Pulp facility is a pulp mill, which utilizes the Kraft Pulping 

process and produces market pulp. The Mill also operates support facilities including 

woodyards, wastewater treatment plant, sludge press, pulp production labs, 

environmental labs, finishing, shipping, and receiving operations, storage areas, a landfill, 

and a power boiler. There are two BART eligible units at the facility ; the #9 Power 

Boiler, and the Lime Kiln. 

103 
#9 Power Boiler is rated at 625 MMBtu/hr and was placed into operation in 1971 . #9 

Power Boiler is fueled primarily by biomass but is also licensed to burn #6 fuel oil, 

sludge, TDF, specification waste oil, HVLC, LVHC, mill yard waste, oily rags, stripper 

off-gas, and propane. Emissions are controlled using a variable-throat wet venturi 

scrubber and low-NO,, burners. The Lime Kiln is rated at 75 MMBtu/hr and was placed 

into operation in 1966. Emissions are controlled using a variable-throat wet venturi 

scrubber and a Ceilcote cross-flow scrubber. The Lime Kiln is fueled by #6 fuel oil. 

BART Analysis Summary 

#9 Power Boiler 

PM: Domtar evaluated the use of Fabric Filters, Wet Electrostatic Precipitator (WESP), 

Dry Electrostatic Precipitator (DESP), and Wet Scrubbers to control PM at the #9 Power 

Boiler . Fabric filters were found not technically feasible due to fire risk from 

combustible fly-ash, while WESP is not technically feasible due to operational 

difficulties with multi-fuel boilers. A DESP could not be installed post-scrubber due to 

excess moisture levels, but could be installed upstream. A DESP was evaluated and 

found to provide a 98-99% control efficiency for biomass a 90% efficiency for oil (for 

comparison, a wet scrubber provides an 85-98% control efficiency) . Domtar estimated 

the cost for DESP installation at $4,640 per ton of PM removed, and found that DESP is 

not a cost-effective option . 

SOZ: Power Boiler #9 is currently controlled through the use of a wet scrubber and low 

sulfur fuel (biomass). Domtar did not investigate other control technologies because the 

combination of low sulfur fuel and wet scrubber provides maximum emission reductions 

from this unit . 

NO,,: Domtar identified a number of potential NOX control strategies for use on Power 

Boiler #9, including : NO,, tempering, flue gas recirculation (FGR), selective non-catalytic 

reduction (SNCR), selective catalytic reduction (SCR), low NOX burners and good 

combustion practices. Several potential NOX controls were found to be technically 

infeasible, and did not warrant further investigation . NOX tempering is not technically 

feasible due to reduced thermal efficiency and increased fuel usage, SCR is not 

technically feasible due to the increased frequency of catalyst fouling from multi-fuel 

boilers, and FGR is not technically feasible based on previous failed FGR trials 

conducted on the #9 Power Boiler. SNCR, with a 30-40% control efficiency, and low 

NOX Burners, with 10% control efficiency, were identified as technically feasible control 

strategies. Domtar's analysis estimated the cost-effectiveness of SNCR at $7,360 per 

ton, and noted that SNCR has a reduced effectiveness on boilers with significant load 

swings (such as Power Boiler #9). Given the low cost-effectiveness of SNCR, Domtar 

identified the continued use of low NO,, burners as BART. 

Lime Kiln 

PM.- The Lime Kiln is subject to the MACT standard for PM found in 40 CFR, Part 63, 

Subpart MM. According to 40 CFR, Part 51, Appendix Y, According to 40 CFR Part 51, 

104 
Appendix Y, Section IV (C), an exemption is made that states "We believe that, in many 

cases, it will be unlikely that States will identify emission control standards more 

stringent than the Maximum Achievable Control Technology (MACT) standards without 

identifying control options that would cost many thousands of dollars per ton. Unless 

there are new technologies subsequent to the MACT standards which would lead to costeffective increases in the level of control, you may rely on the MACT standards for the 

purposes of BART." Since this current MACT requirement satisfies the requirements of 

BART, no further analysis was undertaken . 

SOZ: Domtar identified the use of a wet scrubber and in-process capture as feasible 

technologies for the control of SOZ from the lime kiln . Since both technologies are 

currently employed by Domtar (including two wet scrubbers), no further analysis was 

necessary. 

NQ,: A number of potential NO, control strategies were identified for the lime kiln, 

including: SNCR, SCR, non-selective catalytic reduction (NSCR), FGR, low NO, bumers 

and good combustion practices. The impracticality of installing chemical injection 

nozzles inside a rotating Kiln drum makes SNCR technically infeasible. SCR and NSCR 

are not feasible due to the known presence of catalyst fouling substances in the Lime 

Kiln. FGR is not feasible as it reduces the temperature in the flame zone, thus hindering 

the chemical reaction taking place in the Lime Kiln. Low NO, burners are a nondemonstrated technology and are not listed in the EPA BACT/RACT/LEAR 

Clearinghouse for Lime Kiln emissions control. Good combustion practices are the only 

feasible option, which is already employed at the Lime Kiln. No further analysis is 

necessary. 

Unit P M SOZ N O,, 

Control Emission Control Type Emission Control Emission 

Type Limit and Limit and Type Limit and 

Reference Reference Reference 

#9 Power 

Wet 0.15 Wet scrubber 0.3 Low-NO,, 0.4 

scrubber lb/MMBtu lbs/MMBtu burners lb/MMBtu 

Boiler (Existing on a 24- on a 24- 

Title V hour basis hour basis 

license) (BART (Existing 

order) Title V 

license 

Lime Wet Compliance Wet 8.3 lbs/hr . Good 120 ppmvd 

Kiln scubber with 40 scrubber/Process (Existing combustion @ 10% Oz 

CFR Part 63 control Title V practices (Existing 

Subpart license) Title V 

MM license 

2. Dragon Products Company 

Dragon operates a cement manufacturing facility in Thomaston. The facility, built in 

1971, was initially a wet process cement kiln that was converted to the more efficient dry 

Table 10-3 

BART Determination Summar for Domtar 

105 
cement manufacturing process beginning in 2003. The modernization project converted 

the existing wet process cement kiln to a dry process (preheater/precalciner type), 

converted the existing (wet) raw mill to a pregrinding finish cement mill, and improved 

other ancillary operations within the facility . The planned annual production rate of the 

new facility is approximately 766,500 tons of clinker. 

The BART eligible kiln system is a single dry process rotary kiln and inline raw mill 

equipped with a preheater/precalciner. Various allowable fuels, including petcoke, #2 

fuel oil, #4 fuel oil, specification waste oil, non-specification waste oil, whole tires, and 

tire chips provide thermal energy necessary to convert raw materials (limestone, silica, 

iron ore, fly ash, and/or other raw material additives) into calcium silicates or `clinker' . 

Hot flue gases from the kiln flow counter-current to the feed material up the length of the 

kiln . Heat is transferred to the fed material from the direct contact of the flue gases in the 

kiln and preheater/precaliner tower. 

BART Analys is Summarv 

Dragon submitted a 5-step BART analysis of the technical feasibility and cost of 

compliance, the energy and non-air quality impacts of compliance, any existing air 

pollution control technology in use at the source, the remaining useful life of the source, 

and the degree of visibility improvement anticipated from the use of BART (a CALPUFF 

version 5.8 analysis was performed by Dragon). 

PM: Emissions of PM from the kiln system are generated as a function of the clinker 

production process. The kiln system is subject to 40 CFR Part 63, Subpart LLL, National 

Emission Standards for Hazardous Air Pollutants from the Portland Cement 

Manufacturing Industry. Since the MACT is current and Dragon complies with the 

particulate matter limits in §63 .1343 and uses a fabric filter dust collector for PM,o 

control, no further BART analysis was performed. 

SO,: Emissions of S02 from cement kilns are generally related to the inherent SO2 

removal efficiency present in the kiln system operation itself, the pyritic sulfur 

concentration of the raw feed materials, the sulfur to alkali ratio of the raw feed materials, 

and whether the prevailing condition of the system is oxidizing or reducing . Dragon 

identified wet scrubbing, semi-dry scrubbing, dry scrubbing, fuel switching, and process 

alterations as possible retrofit control technologies for reducing S02 emissions. 

Wet caustic scrubbing, where one or more soluble components of an acid gas are 

dissolved in a liquid with a low volatility, semi-dry scrubbing, based on atomizing a 

reagent slurry stream containing lime and contacting the flue gases in a spray dryer type 

vessel, and dry scrubbing, consisting of injecting a dry reagent into the gas stream prior 

to the particulate matter control device, were considered technically feasible for the kiln 

system and were further evaluated 43 . The three scrubbing options were reviewed further, 

and the results are in the following table : 

43 A dry scrubbing system is currently installed on the kiln system but is not operated . 

106 
Expected Expected 

SO2 SOZ 

Emission Emissions Emissions 

Control Rate Performance Reductions 

Technology tons/ r Level tons/ r Cost of Compliance 

Wet 49.0 95% 46.6 Total Cap. Investment: $9,419,115 

Scrubbing Total Annualized Cost:$2,238,950 

Ave Cost Effectiveness : $48,098/ton 

Ave Cost Effectiveness per deciview: 

$12,508,101/dv 

Semi-Dry 49.0 90% 44.1 Total Cap. Investment: $2,359,464 

Scrubbing Total Annualized Cost: $675,978 

Ave Cost Effectiveness : $15,328/ton 

Ave Cost Effectiveness per deciview : 

$3,907,387/dv 

Dry 49.0 50% 24.5 Total Cap. Investment: $0 

Scrubbing Total Annualized Cost: $245,737 

Ave Cost Effectiveness : $10,030/ton 

Ave Cost Effectiveness per deciview: 

$2,254,468/dv 

Based on capital costs associated with the additional retrofit controls, the resultant SOZ 

control cost effectiveness values, and the predicted visibility at the nearest Class I area, it 

was determined that these are not viable BART options. 

Fuel switching and process alterations were also evaluated, but were not found to be 

viable control options. 

NOX: Emissions of NOX from cement kilns are generally related to thermal NOx, fuel 

NOx, and raw feed material NOx. Dragon identified fuel switching, process optimization, 

flue gas recirculation (FGR), indirect fuel firing, staged air combustion/mid-kiln firing, 

low NOX burners, selective Non-Catalytic Reduction (SNCR), and Selective Catalytic 

Reduction (SCR) as available NOX control retrofit technologies . 

Fuel switching was not considered technically feasible since the nitrogen content of the 

fuel used in the kiln burning zone has little or no effect on NOx generation in a portland 

cement kiln . Flue gas recirculation was not considered technically feasible since the 

effectiveness of FGR relies on cooling the flame and generating a reducing combustion 

atmosphere to reduce thermal NOx emissions, which is not compatible with the high 

flame temperature and an oxidizing combustion zone atmosphere in the kiln system 

required to produce quality clinker. SCR was not considered technically feasible since 

there are no full scale SCR systems (ammonia injection upstream of a catalyst bed) in 

operation at cement kilns in the United States due to various concerns including exhaust 

temperature and plugging. 

Process optimization is currently being used on the kiln system, with advanced computer 

controls and instrumentation to improve overall facility operation and fuel efficiency . 

SOZ Control Alternatives Analysis for Dragon Products 

107 
Indirect fuel firing is currently the kiln system's method of operation, whereby pulverized 

solid fuel from a solid fuel mill is captured in a cyclone or fabric filter and is stored 

before being conveyed to the kiln . This separates the mill conveyance air from the fuel 

and the fuel is introduced in a controlled manner from storage, reducing primary kiln 

combustion air to less than 10% of the total combustion air (in a direct-fired cement kiln, 

the primary combustion air can make up to 20% of the total combustion air) . Staged air 

combustion/mid-kiln firing is currently being used in the kiln system to reduce kiln 

stratification and improve combustion of the fuel, which aids in reducing emissions. Low 

NOx burners are currently being used on the kiln system. SNCR is currently being used 

on the kiln system, with ammonia injection at a location in the correct temperature range 

for proper reaction to reduce NOx emissions. 

Dragon initially proposed the use of the existing NOx controls as they are currently 

operated as BART. However, the Department requested additional information on the 

use of the SNCR technology at the facility relating to further NOx control. Dragon 

supplied possible operational changes to the existing SNCR control unit including : 

increasing the operating time of the SNCR control unit, relocating the reagent injection 

nozzles, changing the reagent used in the SNCR control unit, and increasing the injection 

rate of the SNCR control unit reagent. The unit is already operated whenever the kiln is 

in operation so changing the operating time is not feasible . Relocating the injection 

nozzles or changing the reagent (19% aqueous ammonia) is not feasible, since the SNCR 

unit operates at the optimum injection point and reagent type based on the original trial 

test . Increasing the injection rate is a feasible option . 

Records show that from April 2005 through December 2008, the SNCR operated at an 

average control efficiency of approximately 22%, and in 2008, the efficiency was slightly 

lower at 18%. Since the June 18, 2008 comments of the MACT standards for the 

Portland Cement amendments, EPA has stated that that `for an SNCR (control unit) with 

optimal injection configuration and reagent injection rate, a 50% NOx emission reduction 

represents a reasonable level of performance of SNCR over the long term,." The 

Department requested that Dragon assess the operation of the SNCR at 50% efficiency . 

Dragon performed an operational change impact analysis with the following results : 

Expected Expected 

NOx NOx 

Emission Emissions Emissions 

Control Rate Performance Reductions 

Technology tons/ r Level tons/ r Cost of Compliance 

SNCR 1130.6 927.1 565.3 Total Cap. Investment: $0 

operating at Total Annualized Cost:$1,483,877 

50% Ave Cost Effectiveness: $4101/ton 

Ave Cost Effectiveness per deciview: 

$7,419,385/dv 

Dragon proposed no increased reagent reaction rate due to additional cost, additional 

ammonia slip, and no perceptible change in visibility at the nearest class I area (Acadia 

NOx Control Alternatives Anal sis for Dragon Products 

108 
National Park) . However, the Department is setting a 45% removal efficiency 

requirement to further reduce NOX. 

BART Determination 

The Department determined BART for Dragon as follows: 

Table 10-4 

BART Determination Summary for Dragon Products Company 

Unit PM SOZ N O, 

Control Emission Control Emission Control Emission 

Type Limit and Type Limit and Type Limit and 

Reference Reference Reference 

baghouse 9.3 lb/hr and N/A 70.00 lb/hr. SNCR 350.0 lb/hr 

Kiln 0.3 lb/ton on a 90-day 45% control on a 90-day 

dry kiln feed rolling efficiency rolling 

(Existing average on a 24-hour average and 

Title V (Existing basis 1533 .0 tons 

license; 40 Title V (BART per year on 

CFR Part license) and order) a 12-month 

63) 200 rolling total 

tons/year on basis 

a 12-month (Existing 

rolling Title V 

average license) 

(BART 

order 

3. FPL Energy Wyman, LLC. 

FPLE Wyman is an 850-megawatt electric generating facility located on Cousins Island 

in Yarmouth, Maine. The plant consists of four generation units, all of which fire #6 

residual fuel oil. A fifth unit is a smaller oil-fired auxiliary boiler which provides building 

heat and auxiliary steam and a sixth unit is an emergency backup diesel generator that 

provides electricity for use on-site. There are two BART eligible units at the facilityUnit 3 and Unit 4 . 

Boiler #3 is a Combustion Engineering boiler, installed in 1963, with a maximum design 

heat input capacity of 1190 MMBtu/hr firing #6 fuel oil (2% sulfur) . The boiler is 

equipped with multiple centrifugal cyclones for control of particulate matter and 

optimization and combustion controls for NOX. Boiler #4 is a Foster Wheeler boiler, 

installed in 1975, with a maximum design heat input capacity of 6290 MMBtu/hr firing 

#2 or #6 fuel oil (0 .7 % sulfur) . The boiler is equipped with an electrostatic precipitator 

for control of particulate matter and optimization and combustion controls for NOX. 
BART Analysis Summary 

PM: Emissions of PM from oil fired boilers are a function of fuel firing .44 Both boilers 

#3 and #4 have high efficiency combustion systems in conjunction with PM control 

devices; boiler #3 having multiclones and boiler #4 having an ESP. The cost analysis of 

installing an ESP on boiler #3 resulted in pollutant removal cost effectiveness of 

$19,000/ton of PM removed and visibility improvement cost effectiveness of $143 

million per deciview of visibility improvement. This was determined to be excessive and 

not cost-effective . 

SO,. Emissions of SO2 from oil fired boilers are related to the sulfur in the fuel . FPLE 

Wyman identified the following available retrofit control technologies for reducing SOz 

emissions from the oil fired boilers: low sulfur #2 fuel oil, reduced sulfur #6 fuel oil, and 

wet or dry scrubbers . Low sulfur #2 fuel oil (0.05% down to 0.0015%) and the use of 

reduced sulfur #6 fuel oil (1% or less) were considered technically feasible options. Post 

combustion controls of wet or dry scrubbers on large boilers were researched and 

generally only typically applied to coal fired boilers. The use of scrubbing systems on oil 

fired boilers is considered cost prohibitive and was not considered as a BART option . 

FPLE Wyman performed a cost analysis on lowering the sulfur content in both boilers. 

Boiler #3 currently fires 2% sulfur oil and boiler #4 currently fires 0.7% sulfur oil. The 

annual costs were calculated to be the following (based on the differential fuel costs) : 

Boiler #3 Boil er #4 

% sulfur Annual Costs % sulfur Annual Costs 

1 .0 $0.68 million - - 

0.7 $0.80 million - - 

0.5 $3.2 million 0.5 $9 .2 million 

0.3 $5.7 million 0.3 $18.3 million 

The visibility cost effectiveness, incremental visibility improvement, and incremental 

visibility cost effectiveness from switching from 2% sulfur to reduced sulfur content fuel 

oil for boiler #3 was the following: 

S02 Control Costs Anal sis for W man #3 and #4 

44 It is estimated from the MANE-VU August 2006 document Contributions to Regional Haze in the 

Northeast and Mid-Atlantic United States, Tools and Techniques for Apportioning Fine Particle/Visibility 

Impairment in MANE-YU (pages 3-2, 4-7, 4-8) that course particulate matter has typically less than 4% of 

the contribution to visibility impairment at the MANE-VU Class I areas. 

110 
Sulfur 

Ranked 

Visibility 

Impact 

Visibility Cost 

Effectiveness 

$/deciview 

Incremental 

Visibility 

Improvement 

Incremental 

Visibility Cost 

Effectiveness 

$/deciview 

1 .0 1St $0.69 million - - 

0.7 1 S` $0.56 million 0.44 dv $0.27 million 

0.5 1 St $1 .82 million 0.35 dv $6.97 million 

0.3 1St $2.64 million 0.37 dv $6.59 million 

The visibility cost effectiveness, incremental visibility improvement, and incremental 

visibility cost effectiveness from switching from 0.7% sulfur to reduced sulfur content 

fuel oil for boiler #4 was the following: 

Incremental 

Ranked Visibility Cost Incremental Visibility Cost 

Visibility Effectiveness Visibility Effectiveness 

% Sulfur Impact $/deciview Imp rovement $/deciview 

0.5 Is` $22 .3 million - - 

0.3 1 St $19.5 million 0.53 dv $17.3 million 

Based on the sulfur contributions in the Northeast and the information above, FPLE 

Wyman proposed 0.7% sulfur fuel oil for boiler #3 beginning in 2013, and the current 

sulfur limit of 0.7% for boiler #4 as BART. 

NOX. Emissions of NOX from oil fired boilers are from thermal and fuel NOX. In order 

to minimize NOX emissions, FPLE Wyman installed combustion control technologies 

pursuant to 06-096 CMR 145, NOX Control Program Regulation. FPLE Wyman 

installed combustion control technology upgrades including low NOX fuel atomizers, 

improved swirler design, and overfire and interstage air ports. The bumers were 

optimized and fuel/air flows were balanced to the burners on each unit . The combustion 

control technology upgrades were completed in April 2003 and reductions of 29-35% 

have been documented with boiler #3 and reductions of 24-47% have been documented 

with boiler #4 depending on each unit's load. These reductions are equivalent to the use 

of SNCR (Selective Non-Catalytic Reduction) technology on the boilers. 

The cost analysis of installing additional NOX controls of regenerative selective catalytic 

reduction (RSCR) on the boilers in addition to the current combustion controls resulted in 

a pollutant removal cost effectiveness of $125,000/ton and $83,000/ton of NOX removed 

SOZ Control Visibility Analysis for W man #3 

S02 Control Visibility Analysis for W man #4 

111 
for boiler #3 and boiler #4, respectively . This was determined to be excessive and not 

cost effective. 

BART Determination 

The Department determined BART for FPLE Wyman as follows: 

Unit PM S OZ NO, 

Control Emission Control Emission Control Emission Limit 

Type Limit and Type Limit and Type and Reference 

Reference Reference 

multiclones 0.15lb/MMBtu Low- 0.7% Combustion 0.1751b/MMBtu 

Boiler (BART order) sulfur oil sulfur by engineering on a 90-day 

#3 weight oil rolling average* 

(BART (Existing Title V 

order) license; 06-096 

CMR Chapter 

145 

Boiler ESP O.llb/MMBtu Low- 0.7% Combustion 0.1701b/MMBtu 

#4 (Existing Title sulfur oil sulfur by engineering on a 90-day 

V license; 40 weight oil rolling 

CFR Part 60) (Existing average* (Existing 

Title V Title V license; 

license, 40 06-096 CMR 

CFR Part Chapter 145) 

60 

Alternatively, the NO., limit from boilers #3 and #4 averaged shall be limited to 0.165 lbs/MMBtu on a 90-

day operating rolling average 

4. Lincoln Paper and Tissue, LLC 

Lincoln Paper & Tissue (LPT) is an integrated kraft pulp and paper mill. Currently, LPT 

operates a hardwood digester and a softwood sawdust digester to produce pulp with 

approximately 50% recycled content. LPT uses one recovery boiler and a lime kiln in the 

recaust process for reclamation of the pulping chemicals. Also, LPT has three oil-fired 

boilers and one multi-fuel boiler to supply the mill with steam. The two paper machines 

produce specialty paper and the two tissue machines produce multi-ply dyed tissue . The 

pulp dryer machine produces bailed pulp which is either used by LPT or sold to other 

paper manufacturers . 

At LPT, the only BART-eligible source is the Recovery Boiler #2, which is used to 

recover chemicals and produce steam. Emissions exit through two identical 175 foot 

stacks. The recovery boiler is a straight fire unit burning black liquor, typically without 

combustion support from fossil fuel. Normally, oil is used only during start-ups, 

shutdowns and to stabilize operation of the boiler. 

The Recovery Boiler is exhausted to a wet bottom electrostatic precipitator (ESP) to 

control particulate emissions. This unit also serves to re-introduce salt cake into the 

Table 10-5 

BART Determination Summary for FPLE W man 

112 
black liquor which further concentrates the solids content. 

BART Analysis Summary 

The LPT BART analysis evaluated the best system of continuous emissions control 

technology available for each of the visibility-impairing pollutants (S02, PM, and NO,,). 

LPT's BART analysis submittal demonstrated that additional emission controls are 

neither feasible nor necessary for Recovery Boiler #2. PM emissions are controlled with 

the ESP to levels meeting compliance with MACT standards and therefore meet BART. 

S02 emissions are controlled by proper operation of the recovery boiler, including a 

three-level staged combustion air control system, and limitations on fuel oil use and 

sulfur content. NO, emissions are minimized through staged combustion (having 

independently operating primary, secondary, and tertiary air dampers) and by the low 

nitrogen content of black liquor solids along with proper operation of the Recovery 

Boiler. Existing SOZ and NOx controls on the #2 Recovery Boiler were determined by 

the Department and EPA to meet BACT in the PSD/NSR licensing of the facility. As no 

new control technologies are available for further control of these pollutants from a 

recovery boiler the BACT determination constitutes BART compliance. Maine did not 

require additional visibility impact modeling because of the limited visibility impacts 

from this source .45 

BART Determination 

The Department determined BART for Lincoln Paper and Tissue as follows: 

Table 10-6 

BART Determination Summary for Lincoln Paper and Tissue 

Unit PM S02 N O,, 

Control Emission Control Emission Control Emission 

Type Limit and Type Limit and Type Limit and 

Reference Reference Reference 

ESP 0.044 grains Low-sulfur 141 ppmv Combustion 233 ppmv 

Recovery per dry oil (dry basis) engineering (dry basis) 

Boiler standard @8% OZ on @ 8% OZ on 

cubic foot a 24-hour a 24-hour 

(0 .044 block block 

gr/dscf) average average 

(Existing basis basis 

Title V (Existing (Existing 

license; 40 Title V Title V 

CFR Part license) license) 

63 

4s Modeled visibility impacts attributable to Recovery Boiler #2 as 0.0073 deciviews (dv) for S02, 0.0882 

dv for NOx, 0.0322 dv for PM, and 0.12 dv total impacts. 

113 
5. SD Warren Company, Somerset 

SD Warren Company (SDW) is an integrated kraft pulp and paper mill. Whole logs, 

chips, and biomass, are delivered to the mill by truck and/or train. The logs are sawn, 

debarked, chipped and stored in the mill's woodyard. The biomass is stored in piles and 

then conveyed to the boilers . The chips are stored in piles and then conveyed to the chip 

bin, chip steaming vessel, and then the digester. SDW operates one Kamyr continuous 

digester to produce pulp (hardwood, softwood, or any combination thereof), one recovery 

boiler and one lime kiln in the recaust process for reclamation of the pulping chemicals . 

There are two multi-fuel boilers and an oil fired package boiler to supply the mill with 

steam. SDW has three paper machines which produce paper. There are also two pulp 

machines. One pulp machine has a steam operated dryer and both machines produce 

bailed pulp. The mill also operates support facilities, including the wood yard, 

wastewater treatment plant, sludge presses, pulp and paper production labs, 

environmental labs, roll wrapping, shipping and receiving operations, and a landfill . 

There are four emissions units that were determined to be BART eligible at this facility; 

the Recovery Boiler, Smelt Tanks #1 and #2, and the Lime Kiln. The Recovery Boiler 

was installed in 1975-1976. It is used to recover chemicals from spent pulping liquors 

and to produce steam for mill operations. The Recovery Boiler is licensed to fire black 

liquor (spent pulping liquor), residual (#6) fuel oil, distillate (#2) fuel oil, and used oil. 

The Recovery Boiler is also licensed to combust low volume-high concentration (LVHC) 

and high volume-low concentration (HVLC) gases produced at various points in the 

pulping process . The current black liquor firing rate is 5.1 million pounds per day of 

black liquor solids (BLS). The licensed maximum black liquor firing rate will become 

5 .5 million pounds per day of BLS after the boiler upgrade project is completed 

(scheduled for October 2010). The Recovery Boiler is subject to MACT standards for 

Chemical Recovery Combustion Sources at Kraft Soda, Sulfite, and Stand-Alone 

Semichemical Pulp Mills (40 CFR 63, Subpart MM). 

SDW operates two smelt tanks which were installed in 1975-1976. The Smelt Tanks 

operate in conjunction with the Recovery Boiler. Recovered sodium-based pulping 

chemicals, in the form of molten salts, are discharged from the bottom of the Recovery 

Boiler into the Smelt Tanks, where they are mixed with a water/caustic solution to form 

green liquor. The Smelt Tanks are subject to MACT standards for Chemical Recovery 

Combustion Sources at Kraft Soda, Sulfite, and Stand-Alone Semichemical Pulp Mills 

(40 CFR 63, Subpart MM). 

The Lime Kiln was installed in 1975-1976. It is used to convert lime mud (principally 

calcium carbonate) to lime (calcium oxide) . Fuel is fired in the Lime Kiln to generate the 

heat that is needed to convert lime mud to lime. The Lime Kiln is licensed to fire 

residual (#6) fuel oil, distillate (#2) fuel oil, used oil, and propane. The Lime Kiln is also 

licensed to combust LVHC gases and foul condensate streams. 
BART Analysis Summary 

Recovery Boiler 

PM.- SDW currently operates a three-chamber electrostatic precipitator (ESP) on the 

Recovery Boiler . SDW identified the following available retrofit technologies for control 

of PM from Kraft mill recovery boilers : electrostatic precipitators, wet scrubbers, and 

fabric filters . Wet scrubbers were eliminated as a feasible control strategy because the 

ESP currently installed is capable of a greater degree of emissions control at a lower 

operating cost. Fabric filters are generally considered to be equivalent to ESPs in regards 

to pollution control . However, fabric filters have not been applied to recovery boilers at 

Kraft mills and have been eliminated as a feasible control alternative . Since the controls 

already in place are considered the most stringent available, and these controls are 

already required by a federally enforceable condition, SDW was not required to perform 

the remaining steps of the control analysis . 

SO2: SDW's Recovery Boiler is currently equipped with a three-level staged combustion 

air control system and, after the upgrade project, will be equipped with a four-level 

staged combustion air system. SDW identified staged combustion systems and wet 

scrubbers as available retrofit technologies for control of SOZ from Kraft mill recovery 

boilers. SOZ emissions from recovery boilers occur due to the volatilization and 

subsequent oxidation of sulfur compounds that are present in the black liquor . Proper 

operation of the recovery boiler maximizes the conversion of sulfur compounds in the 

liquor to the principal constituents of the pulping chemicals. This occurs through capture 

of these sulfur compounds in the combustion zone of the boiler by sodium fume released 

from the smelt bed. Consequently, proper combustion control achieved through the use 

of staged combustion air systems results in effective control of S02 emissions . The only 

available alternative for SOZ emission control is a wet scrubber . However, recovery 

boilers with a properly operated staged air combustion system operate at much lower 

concentrations of SOZ in the flue gas than emission units to which wet scrubbers are 

routinely applied. Since the controls already in place are considered the most stringent 

available, and these controls are already required by a federally enforceable condition, 

SDW was not required to perform the remaining steps of the control analysis. 

NQ,: SDW's Recovery Boiler is currently equipped with a three-level staged combustion 

air control system and is in the process of upgrading with a four-level staged combustion 

air system. SDW identified the following available retrofit technologies for control of 

NO,, from Kraft mill recovery boilers : staged combustion systems, Selective NonCatalytic Reduction (SNCR), Selective Catalytic Reduction (SCR), Low NO, Burners, 

Flue Gas Recirculation, and Low-Temperature Oxidation. Emission controls which have 

been demonstrated on conventional steam boilers, including SNCR, SCR, flue gas 

recirculation, and low NOX burners, cannot be applied to, or have not been demonstrated 

to be feasible on, Kraft mill recovery boilers . There has been some small-scale work 

done on "low-temperature oxidation" where pure oxygen is injected into the evaporation 

process to drive ammonia from the black liquor. However, the company currently 

looking into this technology has advised SDW that they are not aware of any commercial 

size case where this technology has been used. Therefore, this technology is not 

115 
considered technically-feasible . There are no technically-feasible alternatives for control 

of NO,, emissions from recovery boilers other than proper operation of the boiler and the 

staged combustion control system. Since the controls already in place are considered the 

most stringent available, and these controls are already required by a federally 

enforceable condition, SDW was not required to perform the remaining steps of the 

control analysis. 

Smelt Tanks 

PM: SDW currently operates a wetted fan scrubber on each of the smelt tanks for control 

of particulate emissions. The scrubbing media for the scrubbers is either water or weak 

wash from the white liquor clarification system. SDW identified the following available 

retrofit technologies for control of PM from smelt tanks : electrostatic precipitators, wet 

scrubbers, fabric filters, and mist eliminators. The most common PM emission control 

system employed on smelt tanks is wet scrubbers. The use of wet scrubbers also provides 

a secondary environmental benefit by controlling reduced sulfur compound emissions. 

The high moisture content of the smelt tank exhaust gases makes dry PM control 

systems, including fabric filters and dry ESPs, technically infeasible on this type of 

emission unit . The only remaining control technology, mist eliminators, provide a lower 

degree of PM emission control than the use of wet scrubbers. Since the controls already 

in place are considered the most stringent available, and these controls are already 

required by a federally enforceable condition, SDW was not required to perform the 

remaining steps of the control analysis. 

S02: Since no combustion takes place within smelt tanks, SOZ is not generated within the 

emission unit. SDW has found that (SOZ) emissions from the smelt tanks are dependent 

on how much sulfur carries over from the respective recovery boilers with the smelt. SOZ 

emissions from both smelt dissolving tanks combined are very low at approximately 10.5 

tons per year, primarily because the wet scrubber PM control (see previous paragraph) 

also reduces SOZ emissions. SDW proposes that BART for SOZ emissions from smelt 

tanks # 1 and #2 is no additional control based on the following : (1) SOZ emissions from 

the smelt dissolving tanks during the BART baseline period were and are expected to 

continue to be extremely low (-10.5 TPY, combined) ; (2) the smelt dissolving tanks and 

associated scrubbers are designed and operated to minimize SOZ emissions; (3) SOZ 

emissions from the smelt dissolving tanks have a minimal impact on visibility (<0.004 

deciviews); and (4) additional control of SOZ emissions from the smelt dissolving tanks 

would have a minimal impact on overall visibility. 

NO,: Since no combustion takes place within smelt tanks, NO, is not generated within 

the emission unit. SDW was not able to identify any retrofit control technologies 

applicable to the control of NO,, emissions from smelt tanks. 

Lime Kiln 

PM: Particulate emissions from the Lime Kiln are currently controlled by a variable 

throat venturi scrubber system followed by a cyclone separator. SDW identified the 

116 
following available retrofit technologies for control of PM from lime kilns: electrostatic 

precipitators, wet scrubbers, and fabric filters. Fabric filters have never been applied to 

kraft pulp mill lime kilns. They are generally deemed to be technically infeasible on lime 

kilns. ESPs provide a greater degree of particulate matter control than venturi scrubbers. 

However, the possible annual reduction in emissions to be gained by replacing the 

existing scrubber with an ESP is relatively small (estimated at under 40 ton/year). 

Additionally, the scrubber also helps control emissions of S02 and reduced sulfur 

compounds. This beneficial removal of other pollutants is not available to lime kilns 

equipped with ESPs. Consequently, replacement of the existing scrubber with an ESP 

would be expected to result in higher TRS and SOZ emissions from the Lime Kiln. With 

respect to any possible improvement in visibility impacts associated with retrofitting an 

ESP on the Lime Kiln, the modeling result for current PM emissions from the Lime Kiln 

was 0.0463 dv; well below the State's de minimis level of 0.1 dv. Therefore, any 

additional emission reductions that might be achieved by retrofitting the Lime Kiln with 

an ESP could only result in visibility impacts that would similarly be de minimis . 

S02: SOZ forms in the Lime Kiln from either the combustion of sulfur in the fuel or 

combustion of TRS compounds in the LVHC gases. Currently emissions of S02 are 

controlled by using a combination of the inherent sulfur removal provided by operation 

of the kiln itself (i .e . extensive contact between burner exhaust gases and the calcium 

compounds in the kiln) enhanced through the use of a venturi wet scrubber (postcombustion). SDW also uses a caustic scrubber (pre-combustion) on the LVHC gases 

fired in the boiler . Firing of LVHC gases in the Lime Kiln without pre-treatment with the 

caustic scrubber causes formation of rings within the Lime Kiln leading to excessive 

down-time of the equipment. Emissions of SOZ from the Lime Kiln can vary 

significantly based on the amount of LVHC gases being fired and whether or not the 

caustic scrubber is in operation. SDW identified the following available retrofit 

technologies for control of SOz from lime kilns: lime kiln operation and wet scrubbers . 

Since the controls already in place are considered the most stringent available, and these 

controls are already required by a federally enforceable condition, SDW was not required 

to perform the remaining steps of the control analysis . 

NQ,: NO,, emissions from the Lime Kiln are currently controlled by good combustion 

controls and operation of the unit's combustion air system . SDW identified the following 

available retrofit technologies for control of NO, from lime kilns: Combustion Air 

Systems controls, SNCR, SCR, Low NO,, Burners, Flue Gas Recirculation. There are no 

technically feasible alternatives for control of NO,, from lime kilns beyond the measures 

currently employed. Low NOx burner systems, which seek to reduce thermal NOx 

formation through either combustion air or fuel staging, are not possible on the lime kilns 

because such systems negatively impact the efficiency, energy use, and calcining 

capacity of a lime kiln . Post combustion controls, such as SCR and SNCR, are not 

feasible for lime kilns. The temperature window necessary for the SNCR process (1500 

- 2000 °F) is unavailable in a Kraft lime kiln . The high PM load at the exit of the kiln 

precludes the placement of the catalyst grid needed for the SCR process upstream of the 

PM control device, and the requisite temperature window required for this process (550 -

750 °F) is not available downstream of the PM control system . Since the controls already 

in place are considered the most stringent available, and these controls are already 

117 
required by a federally enforceable condition, SDW was not required to perform the 

remaining steps of the control analysis . 

BART Determination 

Table 10-7 

BART Determination Summarv for SD Warren 

Unit 

Recovery 

Boiler 

Smelt 

Tanks # 1 

and #2 

Lime Kiln 

PM 

Control Emission 

Type I Limit and 

Reference 

ESP 

Wet scrubber 

Wet scrubber 

0 .030 gr/dry 

standard 

cubic foot 

(dscf) when 

all three ESP 

chambers are 

online and 

0.038 gr/dscf 

when less 

than three 

chambers are 

online ; 207 

lb/hr (NSR 

License #A19-77-2-A, 

40 CFR Part 

63, subpart 

MM)-- - 

261b/hr; 0.2 

lbs/ton BLS 

40 CFR Part 

63, subpart 

MM 

(Existing 

Title V 

license) 

0.10 gr/dscf 

@10% OZ; 

581b/hr 

(Existing 

Title V 

license; 40 

CFR Part 63) 

6. Verso Androscoggin 

S02 NOx 

Control Type I Emission Limit I Control Type I Emission 

and Reference Limit and 

Reference 

Low-sulfur 

oil 

N/A 

Wet scrubber 

100 ppmv (dry 

basis) @8% OZ 

on a 24-hour 

block average 

basis (BART 

order) 

19751bs/hr 

(NSR License 

#A-19-77-2-A) 

261b/hr 

(Existing Title 

V license) 

1 .92 

lb/MMBtu ; 100 

tons/year limit 

on a 12-month 

rolling average 

(Existing Title 

V license) 

Combustion 

engineering 

N/A 

Staged 

Combustion 

120 ppmv 

(dry basis) 

@ 8% OZ on 

a 24-hour 

block 

average 

basis; 750 

lb/hr (NSR 

License #A19-77-2-A) 

N/A 

120 ppmvw 

@ @10% OZ 

(Existing 

Title V 

license) 

The Verso Androscoggin pulp mill produces bleached Kraft pulp and groundwood pulp. 

The bleached pulp is produced in two separate process lines, designated "A" and "B". 

Groundwood pulp is produced in another separate process line. Logs and wood chips are 

received in the Woodyard area, where they are stored and processed for eventual use in 

118 
the Pulp Mill or Groundwood Mill. The Pulp Mill consists of two separate, parallel 

Kraft chemical pulping process lines. Pulp produced at the Verso Jay Mill is either used 

in the paper mill area or dried in the Flash Dryer for storage and/or sale . 

The Paper Mill consists of all the equipment and operations used to convert pulp to paper, 

including stock preparation, additive preparation, coating preparation, starch handling, 

finishing, storage and paper machines. Non-condensable gases (NCGs) collected 

throughout the process from certain units in the Pulp Mill are sent to the Lime Kilns for 

combustion. The high-volume, low-concentration (HVLC) emission streams from certain 

other units are collected and sent to the Regenerative Thermal Oxidizer where they are 

incinerated . The Mill produces steam and electric power for mill operations with Power 

Boilers #1 and #2 and the Waste Fuel Incinerator (WFI). 

There are ten BART-eligible units at Verso Jay: (1) Power Boiler #1 ; (2) Power Boiler 

#2; (3) Waste Fuel Incinerator; (4) Recovery Boilers # 1 ; (5) Recovery Boiler #2; (6) 

Smelt Tank #1 ; (7) Smelt Tank #2; (8) Lime Kiln A; (9) Lime Kiln B; and (10) Flash 

Dryer. Power Boilers #1 and #2 are each rated at 680 MMBtu/hr and began operation in 

1965 and 1967, respectively . Power Boilers #1 and #2 are licensed to fire #6 fuel oil, #2 

fuel oil, and used oil . The license currently limits the sulfur content of the fuel oil to no 

more than 1 .8%, by weight. In addition, each boiler is equipped with low NO,, burners . 

The operation of the two boilers is related to whether or not and how the cogeneration 

plant (three natural gas fired turbines) at the Mill is operating . Typically when the 

cogeneration plant is operating, Power Boilers #1 and #2 do not operate. When the 

cogeneration plant is not operating, both boilers are operated, however, one boiler will 

typically carry the bulk of the load and the other boiler is idled or run at low load. There 

are occasions when both boilers operate at high load, but this is not a routine operating 

mode. 

The Waste Fuel Incinerator (WFI) is rated at 480 MMBtu/hr on biomass and 240 

MMBtu/hr on oil and began operation in 1976. While the WFI primarily fires biomass, 

fuel oils (#6 and #2 fuel oils, waste oil, and oily rags) can also be fired in the boiler. 

Sulfur dioxide and particulate matter emissions are controlled using a variable throat 

venturi scrubber and demister arrangement. When #6 fuel oil is fired in significant 

amounts, caustic is used in the wet scrubber to meet the applicable SOz emission limit. In 

addition, the WFI is equipped with a combustion system designed to ensure the optimal 

balance between control of NOX and limitation of CO and VOC. 

Recovery Boilers #1 and #2 generate steam while regenerating chemicals used in the 

wood pulping process, and began operation in 1965 and 1976, respectively . Recovery 

Boilers (#1 and #2) have rated processing capacities of 2.50 and 3 .44 million pounds per 

day of dry black liquor solids (MMIb/day of BLS), respectively . Inorganic material 

(smelt) from the bottoms of the recovery boilers is used to produce green liquor, which is 

a solution of sodium sulfide and sodium carbonate salts, when it is dissolved in water or 

weak wash in the Smelt Dissolving Tanks (#1 and #2) . Although the recovery boilers 

primarily fire black liquor, they also fire small quantities of #2 and #6 fuel oils during 

startup, shutdown, and load stabilization conditions . The license currently limits the 

sulfur content of the fuel oils to no more than 0.5%, by weight . Particulate matter 

119 
emissions from both recovery boilers are currently controlled using an electrostatic 

precipitator (ESP). 

Smelt Dissolving Tank #1 is rated at 2.50 MMlb/day of dry BLS and began operation in 

1965. Smelt Dissolving Tank #2 is rated at 3.44 MMlb/day of dry BLS and began 

operation in 1975 . Inorganic materials from the recovery boiler floors drain into Smelt 

Dissolving Tanks #1 and #2 as molten smelt. In the smelt dissolving tanks, the smelt is 

mixed with weak wash to form green liquor which is pumped to the causticizing area. 

Sulfur dioxide (SOZ) and particulate matter (PMIO) emissions from Smelt Dissolving 

Tank # 1 are controlled with a dual-nozzle wet cyclonic scrubber which utilizes an 

alkaline scrubbing solution and was installed in 1983 . Sulfur dioxide (S02) and 

particulate matter (PMIo) emissions from Smelt Dissolving Tank #2 are controlled with a 

triple-nozzle wet cyclonic scrubber which utilizes an alkaline scrubbing solution and was 

installed in 1976. 

The "A" and "B" Lime Kilns process lime mud (calcium carbonate) from the causticizing 

area to regenerate calcium oxide (CaO). Inside the lime kilns, the lime mud is dried and 

heated to a high temperature where the lime mud is converted to lime (calcium oxide or 

CaO). "A" and "B" Lime Kilns are each rated at an operating rate of 248 tons of calcium 

oxide (CaO) per day and a heat input of 72 MMBtu/hr and began operation in 1965 and 

1975, respectively . The lime kilns are licensed to fire #6 fuel oil, #2 fuel oil, propane, 

and used/waste oil. The license currently limits the sulfur content of the fuel oil to no 

more than 1 .8%, by weight. The A and B Lime Kilns also serve as an incineration device 

(control device) for select sources of low volume high concentration (LVHC) noncondensable gases (NCG) from pulping operations at the mill . Particulate matter (PMIo) 

emissions are controlled from the "A" and "B" Lime Kilns using a fixed throat venturi 

scrubber. 

The Flash Dryer is used to dry pulp for resale or for storage and future use on one of 

Verso Androscoggin's paper machines. The Flash Dryer has a rated heat input capacity 

of 84 MMBtu/hr and began operation in 1964 . The flash dryer is licensed to fire #2 fuel 

oil, which contains a maximum sulfur content of 0.5% as defined by ASTM D396 

standards. Particulate matter emissions are controlled using a wet shower system and 

S02 emissions are limited through the firing of #2 fuel oil. 

BART_Analvsis_Summarv 

Power Boilers #1 and #2 : 

PM: Verso did not identify or evaluate potential control technologies for the reduction of 

PMIO emissions from Power Boilers #1 and #2 because these units are subject to MACT 

Standards under section 112 of the CAA. In addition, Verso stated in their application 

that PMIO emissions are low based on the firing of fuel oil and that PMIO emissions from 

Power Boilers #1 and #2 have a minimal impact on visibility and a reduction in these 

emissions would have no impact on the contribution of either boiler to overall visibility 

impacts. Verso Androscoggin proposed that the final "Boiler MACT" standards (40 CFR 

120 
Part 63, Subpart DDDDD) that the boilers are subject to will also represent BART for 

Power Boilers #1 and #2. 

S02; Verso Androscoggin identified and evaluated low sulfur fuels, wet scrubbing, dry 

scrubbing, and semi-dry scrubbing as potential control technologies in the reduction of 

SOZ emissions from Power Boilers #1 and #2 . Low sulfur fuels and wet scrubbing 

control technologies were found to be technically feasible by Verso Androscoggin and so 

were evaluated further. 

46 A summary of Verso Androscoggin's evaluation of the 

remaining viable SOZ control technologies (low sulfur fuels and wet scrubbing) is 

provided in the table below. 

SOZ Control Alternatives Analysis for the Verso Power Boilers #1 and #2 

Control Control Cost Energy and Greatest Visibility 

Technology Effectiveness Effectiveness Other Impacts Improvement 

($/ton removed 

Natural 99% $3,334 Negligible 1 .5 

Gas 

#2 Fuel Oil 97% $3,341 Negligible 1 .5 

0.7% 60% $631 Negligible 0.9 

Sulfur #6 

Fuel Oil 

Wet 99% $2,278 Disposal 1 .5 

Scrubbing Impacts 

The cost effectiveness numbers in the table above are based on controlling SOZ emissions 

from Power Boilers #1 and #2 at the control effectiveness rates indicated in the table 

from the highest estimated two year average annual emissions between 2002 and 2008 . 

In recent years (2008 and 2009) these boilers have been operating close to only 20% of 

the time, which for example, would result in an actual cost effectiveness of between 

$4,920 and $7,133 per ton of SOZ removed with the installation of a wet scrubber. The 

use of low sulfur fuels or a wet scrubber has the potential to reduce visibility impacts 

from Power Boilers #1 and #2 by a perceptible amount; however there are significant cost 

differences among the three low sulfur containing fuels evaluated by Verso 

Androscoggin and the wet scrubber. Based on Verso Androscoggin's identification and 

evaluation of control technology options, they propose that the use of 0.7% sulfur #6 fuel 

oil is a feasible and justifiable cost at $631 per ton of SOZ reduced, but that the other low 

sulfur fuel options and the wet scrubbing option are not economically justifiable and do 

not represent BART. Therefore, Verso Androscoggin proposes that the use of lower 

sulfur (0.7%) #6 fuel oil in place of the higher sulfur (1 .8%) #6 fuel oil currently fired, 

represents BART for control of SOZ emissions from Power Boilers #1 and #2 . 

ab Dry and semi-dry scrubbing control technologies were evaluated, however Verso Androscoggin found 

that control effectiveness levels would be low (<25%), downstream particulate matter control devices such 

as an ESP and/or fabric filter would need to be installed to collect and re-circulate the scrubbing material, 

and no applications of these technologies on fuel oil fired boilers like Power Boilers #1 and #2 were 

identified during Verso Androscoggin's research of potential control technologies. 

121 
NQ,: Verso Androscoggin identified and evaluated selective catalytic reduction (SCR), 

low NO,, burners (LNBs), selective non-catalytic reduction (SNCR), and combustion 

control methods (including an overfire air (OFA) system and a flue gas recirculation 

(FGR) system) as potential control technologies in the reduction of NO. emissions from 

Power Boilers #1 and #2. SCR and SNCR control technologies were found to be 

technically feasible and so were evaluated further. LNBs are currently installed and used 

on Power Boilers #1 and #2, and are estimated to provide a 15% reduction in NO,, 

emissions, so were not evaluated further. Combustion control methods were evaluated, 

however none were found to be viable control options for Power Boilers #1 and #2. 

Verso Androscoggin found that the size and design of Power Boilers #1 and #2 would 

provide little room for the installation of an overfire air system and that the application of 

a flue gas recirculation system would result in minimal reductions (7% to 15%) in NO,, 

emissions. A summary of Verso Androscoggin's evaluation of the remaining viable NO,, 

control technologies (SCR and SNCR) is provided in the table below. 

Control Control Cost Energy and Greatest 

Technology Effectiveness Effectiveness Other Impacts Visibility 

$/ton removed Improvement 

SCR 90% $5,271 Minor Impacts 1 .7 

SNCR 35% $5,973 Minor Impacts 1 .4 

The cost effectiveness numbers in the table above are based on controlling NO, 

emissions from Power Boilers #1 and #2 at the control effectiveness rates indicated in the 

table from the highest estimated two year average annual emissions between 2002 and 

2008 . In recent years (2008 and 2009) these boilers have been operating close to only 

20% of the time, which for example, would result in an actual cost effectiveness of 

$16,313 per ton of NOX removed with the installation of SCR. Although the use of SCR 

or SNCR has the potential to reduce visibility impacts by a perceptible amount, Verso 

Androscoggin proposes that the cost effectiveness levels are not economically justifiable 

based on the limited use of Power Boilers #1 and #2 . Based on Verso Androscoggin's 

identification and evaluation of control technology options, they propose that the current 

use of LNBs represents BART for control of NOX emissions from Power Boilers #1 and 

#2 and that no additional level of control is justifiable as BART. 

Waste Fuel Incinerator Boiler : 

PM: Verso Androscoggin did not identify or evaluate potential control technologies for 

the reduction of PMIO emissions from the Waste Fuel Incinerator Boiler (WFI) because 

this unit is subject to MACT Standards under section 112 of the CAA. Verso 

Androscoggin proposed that the final "Boiler MACT" standards (40 CFR Part 63, 

Subpart DDDDD) that the WFI is subject to will also represent BART for the WFI. 

NOx Control Alternatives Analysis for the Verso Power Boilers #1 and #2 

SO2 : Verso Androscoggin identified and evaluated low sulfur fuels, wet scrubbing, dry 

scrubbing, and semi-dry scrubbing as potential control technologies in the reduction of 

SOz emissions from the WFI. While using low sulfur fuels is technically feasible, Verso 

122 
Androscoggin believes that it is not a practically feasible option for the WFI based on the 

limited amount of fuel oil typically used in the boiler (less than 10% of the annual fuel oil 

heat input capacity). The WFI currently uses a water based wet scrubbing system for PM 

control with the addition of caustic to meet S02 emission limits when firing #6 fuel oil in 

significant amounts. Dry and semi-dry scrubbing control technologies were not 

considered by Verso Androscoggin to be either practical or technically feasible for the 

WFI due to the fact that they could not find any applications of these technologies on any 

other biomass-fired grate type boilers like the WFI. Verso Androscoggin also believes 

that the cost of removing the existing wet scrubber and replacing it with a dry or semi-dry 

scrubbing system and a new ESP and/or fabric filter would be costly . A summary of 

Verso Androscoggin's evaluation of the only remaining viable SOZ control technology 

(adding caustic to the existing wet scrubbing system) is provided in the table below. 

Control Control Cost Energy and Other Greatest 

Technology Effectiveness Effectiveness Impacts Visibility 

($/ton removed Improvement 

Addition of 50% $21,800 Disposal Impacts <0.1 

Caustic to 

Existing Wet 

Scrubber 

The WFI has very low baseline SOZ emissions (-50 tons per year) due to the inherent low 

sulfur content and alkalinity of the primary fuel (biomass) and the small amount of fuel 

oil used in the WFI. In addition, during the limited amount of time that #6 fuel oil is used 

to provide a significant portion of the heat input to the WFI, caustic is added to the wet 

scrubber to control SOZ emissions. Based on Verso Androscoggin's identification and 

evaluation of control technology options, they propose that additional control of SOZ 

emissions from the WFI cannot be justified as BART due to the imperceptible effect it 

would have on visibility . 

NO,,: Verso Androscoggin identified and evaluated selective catalytic reduction (SCR), 

low NO,, burners (LNB), selective non-catalytic reduction (SNCR), and combustion 

control methods (including an overfire air system and a flue gas recirculation system) as 

potential control technologies in the reduction of NO,{ emissions from the WFI. SCR and 

SNCR control technologies were found to be technically feasible and so were evaluated 

further. Since the WFI primarily fires biomass on the grate, LNBs would not be effective 

for the majority of the time that the WFI operates, thus Verso Androscoggin felt LNBs 

did not warrant further evaluation . Combustion control methods were evaluated, 

however none were found to be viable control options for the WFI due to the limited NO,{ 

removal potential (<15%), potential impacts to other pollutants and boiler equipment, and 

the limited amount of room available for the installation of control equipment. A 

summary of Verso Androscoggin's evaluation of technically feasible NO,, control 

technologies (SCR, SNCR, and FGR) is provided in the table below. 

SOZ Control Alternatives Analysis for the Verso Waste Fuel Incinerator 

123 
Control Control Cost Energy and Greatest 

Technology Effectiveness Effectiveness Other Impacts Visibility 

($/ton removed Improvement 

SCR 90% $4,676 Minor Impacts 0.3 

SNCR 30% $5,944 Minor Impacts 0.1 

FGR 15% $17,010 Minor Energy <0.1 

Impacts 

Although the use of SCR has the potential to reduce visibility impacts by a perceptible 

amount, Verso Androscoggin proposes that the cost effectiveness levels are not 

economically justifiable for any of the control technologies evaluated, including SCR. 

Based on Verso Androscoggin's identification and evaluation of control technology 

options, they propose that additional control of NO,, emissions from the WFI cannot be 

justified as BART due to the capital costs ($3 million to more than $7.6 million) and cost 

effectiveness levels ($4,700 to more than $17,000 per ton of NO,, removed). 

Recovery Boilers #1 and #2 

PM: Particulate matter (PM) emissions from Recovery Boilers #1 and #2 are currently 

controlled by an existing shared/common electrostatic precipitator (ESP). Verso 

Androscoggin did not identify or evaluate potential control technologies for the reduction 

of PMIO emissions from Recovery Boilers #1 and #2 because these units are subject to 

MACT Standards under section 112 of the CAA. Recovery Boilers #1 and #2 are 

subject to MACT standards pursuant to 40 CFR Part 63, Subpart MM (MACT II) . Verso 

Androscoggin reviewed the RACT/BACT/LAER Clearinghouse (RBLC) and believes 

that the current control configuration is the most current control technology in use on 

recovery boilers and that there are no new technologies subsequent to the MACT 

standard that should be considered. Based on this information, Verso Androscoggin 

proposed in its BART analysis that it was not necessary to expand the BART analysis for 

PMIO and therefore did not identify or evaluate potential control technologies for the 

additional reduction of PMIO emissions from Recovery Boilers #1 and #2. Verso 

Androscoggin proposes that "MACT II" standards (40 CFR Part 63, Subpart MM) that 

the boilers are currently subject to represent BART for PMIO emissions from Recovery 

Boilers #1 and #2. 

S02: Verso Androscoggin has found that sulfur dioxide (SOz) emissions from Recovery 

Boilers #1 and #2 are variable due to several factors including black liquor properties 

(e.g ., sulfidity, sulfur to sodium ratio, heat value, and solids content), combustion air, 

liquor firing patterns, furnace design features, and type of startup fuel used. Both 

recovery boilers are low-odor design. Although each recovery boiler has the ability to 

utilize #2 fuel oil, #6 fuel oil, and used/waste oil for startup, shutdown, and load 

stabilizing conditions, fuel oil firing is not a typical operating scenario for the recovery 

boilers . SOZ emission levels during fuel oil firing conditions are directly related to the 

sulfur content of the fuel oils. Black liquor solids (BLS) firing produces sodium fume, 

which effectively scrubs SOZ emissions. Verso Androscoggin identified and evaluated 

124 

NO,, Control Alternatives Analysis for the Verso Waste Fuel Incinerator 
wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in 

the reduction of SOZ emissions from Recovery Boilers #1 and #2, however none of these 

technologies were found to have been applied to recovery boilers and Verso 

Androscoggin believes that operation of these technologies could negatively affect the 

operation of Recovery Boilers #1 and #2 . Based on Verso Androscoggin's identification 

and evaluation of control technology options, they propose that each of the control 

technologies evaluated are not technically feasible and therefore were not evaluated 

further. Verso Androscoggin proposes that existing combustion controls represent BART 

for the control of SOZ emissions from Recovery Boilers #1 and #2. 

NO,: Kraft recovery boilers are a unique type of combustion source that inherently 

produce low levels of NOX emissions . Most of the NOX emissions produced by recovery 

boilers can be attributed to fuel based NOX resulting from the partial oxidation of the 

nitrogen contained in the black liquor. Both Recovery Boilers (#1 and #2) operate with a 

reducing zone in the lower part of the boiler and an oxidizing zone in the region of the 

liquor spray guns designed to provide secondary and tertiary staged combustion zones to 

complete combustion of the black liquor and minimize NOX emissions . 

Verso Androscoggin identified and evaluated selective catalytic reduction (SCR), low 

NOX burners (LNB), selective non-catalytic reduction (SNCR), and combustion control 

methods (including the addition of a fourth level or quaternary air system and a flue gas 

recirculation system) as potential control technologies in the reduction of NOX emissions 

from Recovery Boilers #1 and #2. SCR has not been applied or demonstrated 

successfully on any recovery boilers according to Verso Androscoggin and they do not 

know how the unique characteristics of recovery boiler exhaust gas constituents would 

react with a SCR catalyst, so they did not further evaluate this control technology. Verso 

Androscoggin's evaluation of LNB technology is that it is not feasible to use this 

technology in the firing of black liquor given its tar-like qualities and the method by 

which it is injected into the boiler and that it would have minimal results in the firing of 

fuel oils given the small amounts of fuel oils that are fired in the recovery boilers . Verso 

Androscoggin's evaluation of SNCR control technologies resulted in a finding that there 

have been no applications of this technology on recovery boilers in the United States for 

a variety of reasons, including safety concerns associated with the risk of a smelt/water 

explosion should boiler tube walls corrode and leak near urea injection points and risks 

associated with an ammonia handling system for the SNCR. Operational concerns 

associated with SNCR were found to include the potential formation of acidic sulfates 

that could result in corrosion and a catastrophic boiler tube failure . As a result of Verso 

Androscoggin's initial evaluation of SNCR, no further evaluation was conducted. 

Recovery Boilers #1 and #2 are currently designed and operated using low excess air 

combined with three levels of staged combustion to minimize NOX emissions. Additional 

combustion control methods were evaluated by Verso Androscoggin, however none were 

found to be viable control options for Recovery Boilers #1 and #2 due to the limited 

amount of space in the boilers to install a fourth or quaternary air system and due to the 

technical challenges re-circulating recovery boiler exhaust gases in a FGR system due to 

the unique characteristics of the exhaust gases. Based on Verso Androscoggin's 

identification and evaluation of control technology options, they proposed that the 

existing combustion control methods represent BART and that additional control of NOX 

125 
emissions from Recovery Boilers #1 and #2 are not technically feasible and warrant no 

further evaluation . 

Smelt Tanks #1 and #2 

PM: Particulate matter (PM) emissions from Smelt Dissolving Tanks # 1 and #2 are 

currently controlled by existing wet cyclonic scrubbers . Verso Androscoggin did not 

identify or evaluate other potential control technologies for the reduction of PMIO 

emissions from Smelt Dissolving Tanks #1 and #2 because these units are subject to 

MACT Standards under section 112 of the CAA. Smelt Dissolving Tanks #1 and #2 are 

subject to MACT standards under 40 CFR Part 63, Subpart MM (MACT II) . Verso 

Androscoggin reviewed the RACT/BACT/LAER Clearinghouse (RBLC) and believes 

that the current control configuration is the most current control technology in use on 

smelt dissolving tanks and that there are no new technologies subsequent to the MACT 

standard that should be considered. Verso Androscoggin proposes that "MACT II" 

standards (40 CFR Part 63, Subpart MM) that the smelt dissolving tanks are currently 

subject to represent BART for PMIO emissions from Smelt Dissolving Tanks #1 and #2. 

SO2: Verso Androscoggin has found that sulfur dioxide (SOZ) emissions from Smelt 

Dissolving Tanks #1 and #2 are dependent on how much sulfur carries over from the 

respective recovery boilers with the smelt. Controlled smelt-water explosions in the 

smelt dissolving tanks can create SOZ as a result of the oxidation of the sulfur in the 

smelt. SOZ emissions from both smelt dissolving tanks combined are very low at 

approximately 5 tons per year. Verso Androscoggin proposes that BART for SOZ 

emissions from Smelt Dissolving Tanks #1 and #2 is no additional control based on the 

following: (1) SOZ emissions from the smelt dissolving tanks during the BART baseline 

period were and are expected to continue to be extremely low (-5 TPY, combined) ; (2) 

the smelt dissolving tanks and associated scrubbers are designed and operated to 

minimize SOZ emissions; (3) SOZ emissions from the smelt dissolving tanks have a 

minimal impact on visibility (<0.1 deciviews); and (4)additional control of S02 emissions 

from the smelt dissolving tanks would have a minimal impact on overall visibility. 

NQ,: Smelt Tanks #1 and #2 do not emit NO.. 

Lime Kilns A and B 

PM: Particulate matter (PMIO) emissions from the "A" and "B" Lime Kilns consist 

primarily of dust entrained from the combustion section of the kilns. This dust consists 

of sodium salts, calcium carbonate, and calcium oxide. PMIO emissions are currently 

controlled by existing venturi scrubbers . These units are also subject to MACT Standards 

under section 112 of the CAA, and 40 CFR Part 63, Subpart MM (MACT II) . Verso 

Androscoggin reviewed the RACT/BACT/LAER Clearinghouse (RBLC) and believes 

that there are two control technologies that represent the most stringent PM control (ESPs 

and venturi scrubbers). Both ESPs and venturi scrubbers have been used to control PM 

emissions from lime kilns and both are capable of a high level of control . Verso 

Androscoggin proposes that use of the existing venturi scrubbers to control PMIO 

emissions from the "A" and "B" represents BART for the following reasons: (1) the 

126 
existing venturi scrubbers maintain compliance with the MACT lI PM emission limits ; 

(2) the replacement of the existing venturi scrubbers with dry ESPs could increase SOZ 

emissions from the lime kilns when compared to use of the venturi scrubbers; (3) the 

replacement of the existing venturi scrubbers with wet ESPs would result in high capital 

costs ($1 .5 million per kiln); and (4)visibility impacts from the lime kilns are minimal 

and installation of additional control would result in inconsequential improvement in 

visibility . 

SOZ: Verso Androscoggin has found that a significant portion of the sulfur dioxide (SOZ) 

formed during the combustion process in the lime kilns is removed as the regenerated 

quicklime in the kilns functions as a scrubbing agent. In addition, the NCG collection 

system is equipped with a scrubber that uses white liquor (sodium hydroxide or NaOH) 

and thus the sulfur loading from the NCGs is minimized. S02 emissions from both lime 

kilns combined are very low at less than 4 tons per year primarily due to the alkalinity of 

the lime. Verso Androscoggin proposes that BART for S02 emissions from the "A" and 

"B" Lime Kilns is no additional control based on the following: (1) SOZ emissions from 

the lime kilns during the BART baseline period were and are expected to continue to be 

extremely low (<4 TPY, combined); (2) there are no control technologies available for 

lime kilns that are more cost effective than the inherent scrubbing that occurs for SOZ due 

to the alkalinity of the lime in the process; (3) S02 emissions from the smelt dissolving 

tanks have a minimal impact on visibility (<0 .1 deciviews); and (4)additional control of 

S02 emissions from the lime kilns would have a minimal impact on overall visibility . 

NOx: Verso Androscoggin identified and evaluated selective catalytic reduction (SCR), 

low NO,, burners (LNB), and selective non-catalytic reduction (SNCR) as potential NOx 

control technologies . Verso Androscoggin's evaluation of SCR and SNCR as potential 

NOX control technologies revealed that they have not been installed on any lime kilns in 

the pulp and paper industry, and were also found to be technically infeasible, so were not 

evaluated further . Verso Androscoggin's research with respect to lime kilns and LNB 

technology revealed that the technology is actually a combination of passive combustion 

control measures used to minimize NOX formation primarily from thermal NOX and to a 

lesser extent fuel NO,,. These combustion control measures include careful design of the 

fuel feed system in order to ensure proper mixing of the fuel with air and burner "tuning" 

or optimization which impacts fuel burning efficiency and overall flame length . Verso 

Androscoggin already incorporates burner "tuning" in the operation and maintenance of 

the "A" and "B" Lime Kilns to optimize the relationship between NOX emissions and 

operating efficiency. Based on Verso Androscoggin's identification and evaluation of 

control technology options, they propose that the current use of LNB (referred to as 

combustion control measures on lime kilns) represents BART for control of NOX 

emissions from "A" and "B" Lime Kilns and that no additional level of control is 

technically feasible . Verso Androscoggin also notes in their BART analysis that existing 

NOX emissions from the "A" and "B" Lime Kilns have a minimal impact on visibility 

(<0.1 deciviews) and that additional control of NO, emissions would have a minimal 

impact on the overall improvement to visibility. 

127 
Flash Dryer 

PM: Particulate matter (PMIo) emissions from the Flash Dryer are currently controlled 

by the use of a wet shower system. Verso Androscoggin proposes that the application of 

add-on controls and the use of cleaner fuels are not practical considerations for 

controlling PM emissions from the Flash Dryers and that with potential visibility impacts 

from the Flash Dryer being extremely low, any emission reductions would have an 

inconsequential impact on visibility improvement . 

SO2: The Flash Dryer is limited to firing #2 fuel oil with a maximum sulfur content of 

0 .5%, by weight and so has relatively low SOz emissions. Although Verso Androscoggin 

could replace the use of #2 fuel oil with lower sulfur containing fuels such as low sulfur 

(0.05%) diesel fuel or natural gas, the Flash Dryer is predicted to have peak visibility 

impacts of 0.1 deciviews or less. Based on Verso Androscoggin's identification and 

evaluation of SOZ control technology options for the Flash Dryer, they propose that no 

additional level of control is representative of BART. 

NQ,: The Flash Dryer is not equipped with any NOx control equipment. NOX emissions 

from the Flash Dryer are primarily generated from the nitrogen component in the fuel oil. 

Verso Androscoggin currently uses good maintenance practices to minimize NOX 

emissions from the Flash Dryer. Verso Androscoggin's investigation of conventional 

NO,, combustion controls (e.g ., LNB, OFA, and FGR) lead to findings that they are either 

unavailable for installation on the Flash Dryer or are not feasible for a combustion source 

as small as the Flash Dryer. 

BART Determinations : 

Unit P M SOZ NO,, 

Control Emission Control Type Emission Limit Control Type Emission 

Type Limit and and Reference Limit and 

Reference Reference 

Low sulfur Compliance Low sulfur Low sulfur fuel Low NO,, 0.447 

Power oil/ with 40 CFR fuel oil containing burners lbs/MMBtu 

Boilers #1 combustion Part 63 no more than on a 24-hour 

and #2 control Subpart 0.7 % sulfur, by block 

DDDD weight. (BART average basis 

order) (Existing 

Title V 

license 

Waste Combustion Compliance Wet scrubber 0.8 lbs/MMBtu Combustion 0.41bs/ 

Fuel controls, wet with 40 CFR on a 3-hour controls MMBtu on a 

Incinerator 

scrubber Part 63 average 24-hour 

Subpart (Existing Title block 

DDDD V license) average basis 

(Existing 

Title V 

license 

Table 10-8 

BART Determination Summa for VERSO Androsco in 

128 
Recovery ESP Compliance Staged air 120 ppmdv Combustion 150 ppmdv, 

Boiler #1 with 40 CFR combustion @8% OZon a controls when 

Part 63 30-day rolling (NSR) corrected to 

Subpart MM average basis 8% % OZ on 

when operating a 24-hour 

at a black liquor block 

recover rate of average basis 

50% or higher . (BART 

S02 emissions order) 

shall not exceed 

140 ppmdv 

@8% OZ on a 

30-day rolling 

average basis 

when operating 

at a black liquor 

recover rate of 

less than 50% 

BART order 

Recovery ESP Compliance Staged air 120 ppmdv Combustion 206 ppm 

Boiler #2 with 40 CFR combustion @8% Oz on a controls corrected to 

Part 63 30-day rolling (RACT) 8% % OZ on 

Subpart MM average basis a 24-hour 

(Existing (Existing Title block 

Title V V license) average basis 

license) (Existing 

Title V 

license 

Smelt Wet cyclonic Compliance Wet cyclonic Smelt Tank #1- N/A N/A 

Tanks #1 scrubber with 40 CFR scrubber 2.7 lbs/hr 

and #2 

Part 63 

Subpart MM Smelt Tank #2- 

(Existing 3.91bs/hr 

Title V (Existing Title 

license V license 

Lime Venturi Compliance Venturi 6.7 Lbs/hr, 74 .6 Combustion 120 ppm @ 

Kilns A scubber with 40 CFR scubber tpy controls 10%02 

and B 

Part 63 (Existing Title (RACT) (stack test) 

Subpart MM V license) (Existing 

Title V 

license 

Flash Wet shower 5 lbs/hr Low sulfur Low sulfur fuel Good 11 .8 lbs/hr 

Dryer (Existing fuel (#2 oil) oil containing combustion 

Title V no more than practices 

license) 0.5 % sulfur, by (Existing 

weight Title V 

(Existing Title license) 

V license 

129 
7. Red Shield Environmental, LLC.4' 

Red Shield operates a pulp mill in Old Town, Maine. Pulp production at the facility 

begins with wood chips entering the facility, where they are conveyed to, and "cooked" 

in an impregnation vessel followed by a digester. In the digester, white liquor is used to 

dissolve the lignin from around the wood fibers . The pulp from the digester is then 

washed in the brownstock washer system to remove residual spent cooking liquor. After 

bleaching the pulp to the desired brightness, it is the dried. There are two BART eligible 

units at the facility ; the #4 Recovery Boiler, and the Lime Kiln. 

48 

BART Analvsis Summary 

Recovery Boiler 

The #4 Recovery Boiler, manufactured by Babcock & Wilcox was originally installed in 

1971, however, in June of 1987, a smelt bed explosion damaged the boiler. The #4 

Recovery Boiler was repaired and returned to operation by December of 1987. The #4 

Recovery Boiler has the capability of firing black liquor, either alone or in combination 

with #6 fuel oil and is limited to firing 2.57 MMlbs of black liquor solids per day. The 

total heat input capacity of firing #6 fuel alone in the boiler is 375 MMBtu/hr (2500 

gal/hr) . A dry bottom electrostatic precipitator (ESP) controls particulate matter from the 

unit . This unit is subject to 40 CFR Part 63, Subpart MM, NESHAPS from Chemical 

recovery Combustion Sources at Kraft, Soda, sulfite and Stand-alone Semichemical Pulp 

Mills. 

PM: The #4 Recovery Boiler is equipped with an ESP for particulate matter, and a limit 

of 0 .044 gr/dscf has been established pursuant to 40 CFR Subpart MM. 

SO2: SOZ emissions from the recovery boiler are limited through the use of low sulfur 

(0.5% fuel sulfur content limit) as established by air emission license amendment A-180-

71-Z-A and required by the Part 70 air emission license (A-180-70-A-I) . 

NO,: 06-096 CMR 138 contains the applicable NO,, ppm limit (150 ppm). The unit is 

also subject to a best practical treatment (BPT) NO,, limit of 154.41b/hr when firing black 

liquor, and a 188.21b/hr limit when firing oil. 

47 Formerly Red Shield Acquisition, LLC. 

48 Although Red Shield indicated an intention to "cap-out" of BART (see Section 10 .8 .1), the facility 

subsequently chose to undergo a BART analysis . While the BART analysis for this facility is limited in 

scope, the Department feels that the subject units and processes at this facility are similar enough to those at 

the SD Warren and Verso Androscoggin facilities that these more extensive analyses may be referred to in 

an effort to provide at least a qualitative comparison of potential BART controls . 

130 
Lime Kiln 

The Lime Kiln, lime mud clarifier, storage tanks, precoat filter, and scrubber are all part 

of the Lime Kiln System. Lime Mud (CaC03) from the recausticizing slaker system is 

processed back into lime (CaO) through the Lime Kiln System. The Lime Kiln was 

installed in 1974 and is controlled with a venturi scrubber system. The Lime Kiln burner 

has a rating of 64 MMBtu/hr and fires primarily #6 fuel oil with a 2% sulfur content. 

Propane is used only for the pilot flame. Low volume high concentration (LVHC) gases 

are also fired in the Lime Kiln. 

PM.- The Lime Kiln is equipped with a venture scrubber system for particulate matter, 

and is subject to 40 CFR Part 63, Subpart MM, which contains an applicable PM gr/dscf 

emission limit of 0.064 gr/dscf. However, 40 CFR Part 63, Subpart MM also allows Red 

Shield to propose an alternative PM limit (0.13 gr/dscf), which takes into account facility 

emissions from the #4 recovery Boiler and #4 Smelt Tank. The Department has 

established an applicable lb/hr emission limit of 32 .9 lb/hr under BPT. 

SO2: The Lime Kiln is subject to BPT with an applicable limit of 7.1 lb/hr. 

NQ, : 06-096 CMR 138 contains the applicable NO,, ppm limit (170 ppm on a dry basis) . 

The applicable NO,, lb/hr emission limit is 36.0 lb/hr. 

Unit 

~ 

P M S02 N O,, 

Control Emission Control Type Emission Limit Control Type Emission 

] 

Type Limit and and Reference Limit and 

Reference Reference 

ESP Compliance Low sulfur Low sulfur fuel Good 150 ppm on 

Recovery with 40 CFR fuel oil containing combustion a dry basis 

Boiler #4 Part 63 no more than practices corrected to 

Subpart MM- 0.5 % sulfur, by 8%02 

0.028 gr/dscf weight . (Existing 

corrected to (Existing Title Title V 

8%02 V license) license) 

(Existing 

Title V 

license 

Lime Kiln Venturi Compliance Process 7.1 lb/hr Good 170 ppm on 

Scrubber with 40 CFR (lime mud is (Existing Title combustion a dry basis 

Part 63 an effective V license) practices corrected to 

Subpart SO2 10%02 

MM- 0.13 scrubber) (Existing 

gr/dscf Title V 

corrected to license) 

10% 

OZ(Existing 

Title V 

license 

Table 10-9 

BART Determination Summary for Red Shield Environmental, LLC 

131 
10.9 Emission Reductions Attributable to BART in Maine 

The following table (Table 10-10) illustrates the estimated emission reductions 

attributable to the application of BART in Maine. Since a number of BART-eligible 

sources in Maine have demonstrated that their existing controls met all requirements for 

BART, only those sources required to implement additional emissions controls are 

included. Table 10-10 

Estimated Emissions from the Application of BART in Maine 

Source and Unit LI~ ?oil utant T 2002 Baseline . BART Level Emissions ' Emissions 

Emission of Control % After Reductions 

(tons per year) Controls Tans Per 

Tons Per Year 

Year 

Dragon Products 230130002 NOX 1727 45% (SNCR) 1218 996 

Kiln 8 

-005 

FPLE Wyman Station 230050013 SOZ 616 0.7% Sulfur 216 400 

Boiler #3 5 Fuel Oil 

-004 

Verso Androscoggin 230070002 2964 0.7% Sulfur 1152 1812 

Power Boiler #1 -001 SOZ 3086 Fuel Oil 1200 1886 

Power Boiler #2 -002 

10.10 Schedule for BART Implementation 

As provided in 40 CFR Section 51 .308(e)(1)(iv) BART must be in operation for each 

applicable source no later than five years after SIP/TIP approval . Pursuant to 38 

M.R.S .A. §603-A, sub-§8 (b), the State of Maine is requiring that each source subject to 

BART shall install and operate BART as expeditiously as practicable but in no event later 

than January 1, 2013 . 

As provided in 40 CFR Section 51 .308(e)(1)(v) the Title V operating permits for BART 

sources must include a requirement that each source maintain the control equipment and 

establish procedures to ensure such equipment is properly operated and maintained. This 

requirement is included in the air emissions license amendment for each source subject to 

BART. The BART requirements for Maine BART eligible sources will be federally 

enforceable through the Title V operating permit program and through incorporation in 

the Maine Regional Haze SIP. 

Copies of the BART orders for each source are included in Attachment M 

132 
11 . Reasonable Progress Goals 

The Regional Haze Rule (40 CFR Section 51 .308 (d)(1)) requires each state with Class I 

areas to establish reasonable progress goals providing for reasonable progress towards 

achieving natural visibility in each Class I area. In addition, EPA released guidance on 

June 7, 2007 to use in setting reasonable progress goals. The goals must provide 

improvement in visibility for the most impaired days, and ensure no degradation in 

visibility for the least impaired days over the State Implementation Plan (SIP) period . The 

State of Maine must also provide an assessment of the number of years it would take to 

attain natural visibility conditions if improvement continues at the rate represented by the 

reasonable progress goal. 

Under 40 CFR Section 51 .308 (d)(1)(iv), consultation is required in developing 

reasonable progress goals. The rule states : 

In developing each reasonable progress goal, the State must consult with those 

States which may reasonably be anticipated to cause or contribute to visibility 

impairment in the mandatory Class I Federal area. In any situation in which the 

State cannot agree with another such State or group of States that a goal provides 

for reasonable progress, the State must describe in its submittal the actions taken 

to resolve the disagreement. In reviewing the State's implementation plan 

submittal, the Administrator will take this information into account in determining 

whether the State's goal for visibility improvement provides for reasonable 

progress towards natural visibility conditions. 

As discussed in Section 3, Maine consulted with states that contribute to visibility 

impairment at its Class I areas and with states that requested consultation with Maine 

regarding their Class I areas (New Hampshire, Vermont and New Jersey) . Maine worked 

closely with these states during the consultation process and agrees with the reasonable 

progress goals established by New Hampshire, Vermont and New Jersey . 

In developing the reasonable progress goals the Class I state must also consider four 

factors (cost, time needed, energy & non-air quality environmental impacts, and 

remaining useful life). The state also must show that it considered the uniform rate of 

improvement and the emission reduction measures needed to achieve it for the period 

covered by the implementation plan, and if the state proposes a rate of progress slower 

than the uniform rate of progress, assess the number of years it would take to attain 

natural conditions if visibility improvement continues at the rate proposed. 

11.1 Calculation of Uniform Rate of Progress 

As a benchmark to aid in developing reasonable progress goals, MANE-VU compared 

the baseline visibility conditions to natural visibility condition at each Class I area. The 

difference between baseline and natural visibility conditions at each MANE-VU Class I 

area was used to determine the uniform rate of progress that would be needed during each 

implementation period in order to attain natural visibility . Table 11-1 presents baseline 

133 
visibility, natural visibility and required uniform rate of progress for each MANE-VU 

Class I area. Visibility values are expressed in deciviews (dv) where a single-unit 

decrease would represent a barely perceptible improvement in visibility . 

Table 11-1 

Uniform Rate of Progress Calculation 

(all values in deciviews) 

(2000-2004) Natural 

Baseline Visibility Total 

Visibility Conditions Deciview Deciview Uniform Rate 

(deciviews) (20% Improvement Improvement of 

(20°/. Worst Worst Needed by ,Needed by Improvement 

Class I Area Days) Days) 2018 2064 Annually 

Acadia National Park 22.9 12.4 2.4 10.5 0.174 

Roosevelt/Campobello 

International Park 21.7 12.0 2.3 9.7 0.162 

Moosehorn Wilderness 

Area 21 .7 12.0 2.3 9 .7 0.162 

Presidential Range/Dry 

River Wilderness Area 22.8 12.0 2.5 10.8 0.180 

Great Gulf Wilderness 

Area 22.8 12.0 2 .5 10.8 0.180 

Lye Brook Wilderness 24.5 11 .7 3 .0 12.8 _0.212 

Brigantine Wilderness 29.0 12.2 3 .9 16.8 0.280 

Note: Both natural conditions and baseline visibility for the 5 year period from 2000 through 2004 were 

calculated in conformance with an alternative method recommended by the IMPROVE Steering 

Committee . 

49 

The reasonable progress goals established for the Maine Class I areas are expected to 

provide greater visibility improvements than the uniform rate of progress shown in Table 

11-1, above. 

11.2 Reasonable Progress Goals for Class I Areas in Maine 

In accordance with the requirements of 40 CFR Section 51 .308 (d)(1), this Regional Haze 

SIP establishes reasonable progress goals (RPG) for each Class I area in Maine for the 

period of the implementation plan. 

40 CFR Section 51 .308(d)(1)(vi) requires that reasonable progress goals represent at least 

the visibility improvement expected from implementation of other Clean Air Act 

programs during the applicable planning period. As documented in Section 8 Emissions 

Inventory, and Section 12 Long-Term Strategy, the modeling that formed the basis for 

reasonable progress goals in MANE-VU Class I areas included estimation of the effects 

a9"Baseline and Natural Visibility Conditions, Considerations and Proposed Approach to the Calculation of 

Baseline and Natural Visibility Conditions at MANE-VU Class I Areas," NESCAUM, December 2006. 

134 
of all other programs required by the Clean Air Act. Further information may be found 

in those sections of this SIP and in the documentation for the MANE-VU modeling. 

Both natural conditions and baseline visibility for the 5-year period from 2000 through 

2004 were calculated in conformance with an alternative method recommended by the 

IMPROVE Steering Committee. Progress toward the 2018 target will be calculated 

based on 5-year averages calculated in a nationally consistent manner consistent with 

EPA's "Guidance for Tracking Progress Under the Regional Haze Rule" (EPA-454/B-03-

004, September 2003) as updated by the alternative method for calculating regional haze 

recommended by the IMPROVE Steering Committee . 

To determine the RPG in deciviews, MANE-VU conducted modeling with certain control 

measure assumptions. The control measures reflected in these reasonable progress goals 

are summarized below. In establishing its reasonable progress goals for 2018, Maine 

recognizes that contributing states have the flexibility to submit SIP revisions between 

now and 2018 as they are able to adopt control measures to implement these goals. This 

long-term strategy to reduce and prevent regional haze will allow each state up to 10 

years to pursue adoption and implementation of reasonable and cost-effective SO2, NOX 

and PM control measures. 

Tables 11-2 and 11-3 below, provide a summary of the Reasonable Progress Goals for 

Maine Class I areas. 

Table 11-2 

Reasonable Progress Goals-20% Worst Days 

(all values in deciviews) 

Baseline Reasonable 

Visibility Progress Goals, Deciview 

(decivlews) 20°lo Worst Improvement Natural Visibility 

Class I Area (20e/8 Days (expected Expected by, . Conditions (20% 

Worst Days deciview level 2018 Worst Days) 

2E100-2004) by 2018) 

Acadia National Park 22.9 19.4 3.5 12.4 

Moosehorn 21 .7 19.0 2 .7 12.0 

Wilderness Area/ 

Roosevelt Campobello 

International Park 
Table 11-3 

Reasonable Progress Goals-20% Best Days 

(all values in deciviews) 

Reasonable 

Baseline Progress Goals, 

Visibility 20®/a Best Days Peciview Natural Visibility 

Class I Area (deciviews) (expected Improvement (20°lu Best Days) 

(20% Best deciview level Expected by 2018 (dedvlews) 

Days) by 2018) 

Acadia National Park 8 .8 8 .3 0.5 4.7 

Moosehorn 9.2 8 .6 0.6 5 .0 

Wilderness Area/ 

Roosevelt Campobello 

International Park 

11.3 Identification of Additional Reasonable Controls 

Maine and the other MANE-VU states have identified specific emission control 

measures- beyond those which individual states or RPOs have already made 

commitments to implement- that would be reasonable to undertake as part of a concerted 

strategy to mitigate regional haze. The proposed additional control measures were 

incorporated into the regional strategy adopted by MANE-VU on June 20, 2007, to meet 

the reasonable progress goals established in this SIP. The basic elements of this strategy 

are described in the MANE-VU "Ask" (see Subsection 3.4). States targeted for 

coordinated actions toward achieving these goals include all of the MANE-VU states plus 

Georgia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, South Carolina, 

Tennessee, Virginia and West Virginiaso . 

In addition to proposed emission controls in the U.S., the MANE-VU Class I states 

determined that it was reasonable to include anticipated emission reductions in Canada in 

the modeling used to set reasonable progress goals. This determination was based on 

evaluations conducted before and during the consultation process (see description of 

relevant consultations in Subsection 3.3). Specifically, the modeling accounts for six 

coal-burning EGUs in Canada having a combined output of 6,500 MW that are scheduled 

to be shut down and replaced by nine natural gas turbine units with selective catalytic 

reduction (SCR) by 2018. 

The process of identifying reasonable progress measures and setting reasonable progress 

goals is described in the subsections which follow . Further elaboration on the reasonable 

progress measures which make up the Maine/MANE-VU long-term strategy is provided 

so In addition, the State of Vermont identified at least one source in the State of Wisconsin as a significant 

contributor to visibility impairment at the Lye Brook Wilderness Class I Area. 

136 
in Section 12 of this SIP. "Under this plan, the affected states will have until July 31, 

2018 to implement reasonable and cost-effective control measures to reduce primarily 

SOz and NO, emissions." For a description of how proposed emission control measures 

were modeled to estimate resulting visibility improvements, see Subsection 11 .5, 

Visibility Effects of Additional Control Measures. 

11 .4 The Foundations for Determining Reasonable Controls 

40 CFR Section (d)(1)(i)(A) of EPA's Clean Air Visibility Rule requires that, in 

establishing reasonable progress goals for each Class I area, the State must consider the 

costs of compliance, the time necessary for compliance, the energy and non-air quality 

environmental impacts of compliance, and the remaining useful life of any potentially 

affected sources . The SIP must include a demonstration showing how these factors were 

taken into consideration in setting the reasonable progress goals . These factors are 

sometimes termed the "four statutory factors," since their consideration is required by the 

Clean Air Act. 

Focus on SOZ: MANE-VU conducted a Contribution Assessment (Attachment A) and 

developed a conceptual model that indicated particulate sulfate formed from emissions of 

SOZ was the dominant contributor to visibility impairment at all sites and during all 

seasons in the base year. While other pollutants, including organic carbon and NO,{, will 

need to be addressed in order to achieve the national visibility goals, MANE-VU's 

contribution assessment suggested that an early emphasis on SOZ will yield the greatest 

near-term benefit. Therefore, it is reasonable to conclude that the additional measures 

considered in establishing reasonable progress goals require reductions in S02 emissions. 

Contributing Sources: The MANE-VU Contribution Assessment indicates that 

emissions in 2002 from within the MANE-VU region were responsible for about 25 to 30 

percent of the sulfate at MANE-VU Class I areas. Sources in the Midwest and Southeast 

regions were responsible for about 15 to 25 percent each, respectively . Point sources 

dominated the inventory of SOZ emissions. Therefore, the MANE-VU's long-term 

strategy, includes additional measures to control sources of SOZ both within the MANEVU region and in other states that were determined to contribute to regional haze at 

MANE-VU Class I areas. 

The Contribution Assessment documented the source categories most responsible for 

visibility degradation at MANE-VU Class I areas. As described in the Section 12, Long 

Term Strategy, there was a collaborative effort between the Ozone Transport 

Commission and MANE-VU to evaluate a large number of potential control measures. 

Several measures that would reduce SOZ emissions were identified for further study. 

These efforts led MANE-VU to prepare the report entitled, "Assessment of Reasonable 

Progress for Regional Haze in MANE-VU Class I Areas" MACTEC, July 9, 2007 

otherwise known as the Reasonable Progress Report (Attachment T), which documented 

an analysis of the four statutory factors for five major source categories. Table 11-4 

summarizes the results of MANE-VU's Reasonable Progress Report, which considered 

EGUs, ICI boilers, cement kilns, heating oil and residential wood combustion. 

137 
Table 11-4 

Summary of Results from the Four Factor Analysis 

* Integrated Planning Model® CAIR versus CAIR plus analysis conducted for MARAMA/MANE-VU by ICF. 

Average 

Cost in 2006 Energy and 

dollars Non-Air Quality Primary 

n 

Control Measure(s) (per ton of Environmental R a lft Source Regio al pollutant Compliance _ Impacts em h 8 

Category Haze Timeframe Useful 

Pollutant reduction) Life 

Electric S02 Switch to a low sulfur coal IPM®* v.2 .1 .9 2-3 years Fuel supply issues, 50 years or 

Generating (generally <1% sulfur), predicts $775- following SIP potential permitting more 

Units switch to natural gas $1,690 submittal issues, reduction in 

(virtually 0% sulfur), coal electricity production 

cleaning, Flue Gas $170-$5,700 based capacity, wastewater 

Desulfurization (FGD)-Wet, 

on available issues 

-Spray Dry, or -Dry . 

literature 

industrial, S02 Switch to a low sulfur coal $130-$11,000 2-3 years Fuel supply issues, 10-30 years 

Commercial, (generally <1% sulfur), based on available following SIP potential permitting 

Institutional switch to natural gas literature . Depends submittal issues, control device 

Boilers 

(virtually 0% sulfur), switch 

on size . 

energy requirements, 

to a lower sulfur oil, coal wastewater issues 

cleaning, combustion 

control, Flue Gas 

Desulfurization (FGD) - 

Wet, -Spray Dry , or -Dry . 

Cement and S02 Fuel switching, Dry Flue $1,900-$73,000 2-3 years Control device energy 10-30 years 

Lime Kilns Gas Desulfurization-Spray based on available following SIP requirements, 

Dryer Absorption (FGD), literature . Depends submittal wastewater issues 

Wet Flue Gas on size . 

Desulfurization (FGD), 

Advanced Flue Gas 

Desulfurization FGD . 

Heating Oil SOz Lower the sulfur content in $550-$750 based Currently feasible . Increases in 18-25 years 

the fuel . Depends on the on available Capacity issues fumace/boiler 

state. literature . There is may influence efficiency, Decreased 

a high uncertainty timeframe for fumace/boiler 

associated with implementation of maintenance 

this cost estimate. new fuel standards re quirements 

Residential PM State implementation of $0-$10,000 based Several years - Reduce greenhouse gas 10-15 years 

Wood NSPS, Ban on resale of on available dependent on emissions, increase 

Combustion uncertified devices, installer literature mechanism for efficiency of combustion 

training certification or emission reduction device 

inspection program, pellet 

stoves, EPA Phase 11 

certified RWC devices, 

retrofit requirement, 

accelerated changeover 

requirement, and accelerated 

changeover inducement. 

138 
The MANE-VU states reviewed the four-factor analysis presented in the Reasonable 

Progress Report, consulted with each other about the measures, and concluded by 

adopting the statements known as the MANE-VU Ask on June 20, 2007. These 

statements identify the control measures that would be pursued toward improving 

visibility in the region . The following discussion focuses on the four basic control 

strategies chosen by MANE-VU and included in the modeling used to establish 

reasonable progress goals: BART, emissions reductions from specific EGUs, low sulfur 

fuel oil requirements, and additional measures determined to be reasonable. 

11 .4 .1 Best Available Retrofit Technology (BART) Controls 

The MANE-VU states have identified approximately 100 BART-eligible sources in the 

region . Most of these facilities are already controlling emissions in response to other 

federal or state air programs, or are likely to install emission controls under new 

programs. Previously, EPA determined that CAIR fulfilled the BART requirement for all 

EGUs in CAIR-affected states . Although CAIR has been remanded to EPA, the 

determination that CAIR is equivalent to BART is still in place. Maine anticipates that 

those same units will be covered by successor legislation or new rulemaking undertaken 

in response to the CAIR remand. A complete compilation of BART-eligible sources in 

the MANE-VU region is available in Attachment A of MANE-VU's "Assessment of 

Control Technology Options for BART-Eligible Sources," March 2005 (Attachment R). 

To assess the benefits of implementing BART in the MANE-VU region, NESCAUM 

estimated reductions for twelve BART-eligible units in the MANE-VU states that would 

probably be controlled as a result of BART requirements alone. These sources include 

one EGU and eleven non-EGUs. The affected units were identified by staff members in 

each MANE-VU state, who then furnished data on potential control technologies and 

expected emission levels for these units under BART implementation . The twelve 

sources are listed in Table 11-5, along with their 2002 baseline and 2018 projected 

emissions. Information on these units was incorporated into the 2018 emissions 

inventory projections that were used to establish reasonable progress goals. 

Best Available Retrofit Technology is Reasonable: BART controls are part of the 

strategy for improving visibility at MANE-VU Class I areas. MANE-VU prepared 

reports to provide states with information about available control technologies (e .g ., 

MANE-VU's "Assessment of Control Technology Options for BART-Eligible Sources," 

March 2005), estimated cost ranges and other factors associated with those controls . The 

reasonable progress goals established in this Regional Haze SIP assume that states whose 

emissions affect MANE-VU Class I areas will make determinations demonstrating the 

reasonableness of BART controls for sources in their states. 
Table 11-5 

Estimated Emissions from BART-Eligible Facilities MANE-VU States 

2002 2018 

State so, S02 

Facility Name Unit SCC Plant ID * Point Facility Type Fuel Emis Emissions 

Name Code ID * sions (tons) 

tons 

EASTALCO Metal 

MD ALUMINUM 28 30300101 021-0005 28 Production 1506 1356 

EASTALCO Metal 

MD ALUMINUM 29 30300101 021-0005 29 Production 1506 1356 

LEHIGH 

PORTLAND 

MD CEMENT 39 30500606 013-0012 39 Portland Cement 9 8 

LEHIGH 

PORTLAND 

MD CEMENT 16 30500915 021-0003 16 Portland Cement 1321 1,189 

LEHIGH 

PORTLAND 

MD CEMENT 17 30500915 021-0003 17 Portland Cement 976 878 

WESTVACO 

MD FINE PAPERS 2 10200212 001-0011 2 Paper and Pulp 8923 1338 

ME W an Station Boiler 3 10100401 2300500135 004 EGU Oil 616 308 

Power Oil/Wood 

Boiler Bark/Process 

ME SAPPI Somerset #1 10200799 2302500027 001 Paper and Pulp Gas 2884 1442** 

Power 

Boiler 

ME IP Jay #2 10200401 2300700021 002 Paper and Pulp Oil 3086+ 1543 

Power 

Boiler 

ME IP Jay #1 10200401 2300700021 001 Paper and Pulp Oil 2964+ 1482 

KODAK PARK Chemical 

NY DIVISION U00015 10200203 8261400205 U00015 Manufacturer 23798 14216 

LAFARGE 

BUILDING 

MATERIALS 

NY INC 41000 30500706 4012400001 041000 Portland Cement 14800 4440 

*(from the MANE-VU Inventory) 

+1999 emissions 

** The SAPPI Power Boiler #1 was subsequently determined to be exempt from BART. These emissions 

reductions however, will still take place as a result of other programs. 
11 .4 .2 The MANE-VU Low Sulfur Fuel Strategy 

The MANE-VU region, especially the northeast, is heavily reliant on distillate oil for 

home space heating, with more than with more than 4 million gallons used, according to 

2006 estimates from the Energy Information Administrations' . Likewise, the heavier 

residual oils are widely used by non-EGU sources, and to a lesser extent the EGU sector . 

The sulfur content of distillate fuels currently averages above 2000 ppm (0.2percent) . 

Although the sulfur content of residual oils varies by source and across the region, it can 

exceed 2.0 percent. In 2002, combustion of distillate and residual fuel in the MANE-VU 

region resulted in SOZ emissions totaling approximately 380,000 tons. 

As the second component of MANE-VU's long term strategy, the member states agreed 

to pursue measures that would require the sale and use of fuel oils having reduced sulfur 

content. This strategy would be implemented in two phases : 

1 . Phase 1 would require reducing the sulfur content in distillate (#1 and #2) fuel oils 

from current levels of 2,000 to 2,3000 ppm (0.20 to .23 percent) to a maximum of 

500 ppm (0.05 percent) by weight. It would also restrict the sale of heavier 

blends of residual (#4 and # 5 and #6) fuel oils that have a sulfur content greater 

than 2,500 ppm (0.25 percent) and 5, ppm (0.5 percent) by weight, respectively . 

2 . Phase 2 would require further reducing the sulfur content of the distillate fraction 

from 500 ppm (0.05 percent) to 15 ppm (0.0015 percent) while keeping the sulfur 

limits on residual oils at first-phase levels . 

The two phases are to be introduced in sequence with slightly different timing for an 

inner zone of the MANE-VU states 52 and the remainder of the MANE-VU states . While 

all MANE-VU states have agreed to pursue implementation of both phases to full effect 

by the end of 2018, it is possible that not every state can make a firm commitment to 

these measures today. States are expected to review the situation by the time of the first 

five-year regional haze progress report. 

Reductions in sulfur dioxide emissions will occur as a direct consequence of the lowsulfur fuel strategy. For both phases combined, it is estimated that SOZ emissions in the 

MANE-VU region will decline from 2002 levels by 168,222 tons per year for combustion 

of light distillates, and by 42,875 tons per year for combustion of the heavier fuels . 

Together, these reductions represent a 35 percent decrease in the projected 2018 SOZ 

emissions inventory for non-EGU sources in the region . 

NESCAUM analyzed both steps of the program separately, but it is the combined benefit 

of implementing the program that is relevant to the question of visibility improvement by 

2018 . To estimate the total 2018 emissions reductions from this strategy, MANE-VU 

applied the expected sulfur dioxide emission reductions to all non-EGU sources burning 

#l, #2, #4, #5, or #6 fuel oil. These emission reductions would result directly from the 

sl U.S . Department of Energy, EIA, Table F3a, at http ://www.eia .doe .gov/emeu/states/sep fuel/html/fuel_use_df.html . 

52 The inner zone includes Delaware, Maryland, New Jersey, New York, and possibly portions of eastern 

Pennsylvania. 

141 
lowering of fuel sulfur content from original levels to 0.0015 percent for #1 and #2 oil, to 

0.25 percent for #4 oil and to 0.5 percent for #5 and #6 oil. 

The reduction in SOZ emissions by 2018 will yield corresponding reductions in sulfate 

aerosol, the main culprit in fine particle pollution and regional haze. The full benefits of 

MANE-VU's low-sulfur fuel strategy is represented in Figure 11-1, which displays the 

estimated average change in 24-hr average PM2.5 for the combined first and second 

phases of the low-sulfur fuel strategy as calculated by the CMAQ model. 

Figure 11-1 

Average Change in 24-hr PM2,5 Due to Low Sulfur Fuel Strategies Relative to 

OTB/OTW 

(Flg/m3) 

Average Change In 24hr 

PM2.S 

0 

0.01 - 0.07 

: 0.07-0.79 

~ 0.15-0.78 

~ 0.18 - 0.25 

~ 0.25 - 0.36 

M 0.78 - 0.81 

Low Sulfur Fuel Oil Requirements are Reasonable: The MANE-VU Contribution 

Assessment documented source apportionment analyses that linked visibility impairment 

in MANE-VU Class I areas with SOZ emissions from sources burning fuel oil. The 

reasonable assumption underlying the low-sulfur fuel oil strategy is that refiners can, by 

2018, produce home heating and fuel oils that contain 50 percent less sulfur for the 

heavier grades (#4 and #6 residual oil), and a minimum of 75 percent and maximum of 

99 .25 percent less sulfur in #2 fuel oil (also known as home heating oil, distillate, or 

diesel fuel) at an acceptably small increase in price to the consumer. 
Four-Factor Analysis- Low sulfur Fuel Oil Stratezy 

The MANE-VU Reasonable Progress Report discussed the four factors as they apply to 

low sulfur fuel use for industrial, commercial, and institutional boilers and residential 

heating systems . MANE-VU's Reasonable Progress Report identified switching to lower 

sulfur oil as an available SOZ control option that would achieve 50 to 90 percent 

reductions in SOZ emissions from ICI Boilers. The report also noted that home heating 

oil use generates an estimated 100,000 tons of S02 emissions in the Northeast each year, 

and that SOZ emissions would decline in proportion to reductions in fuel sulfur content. 

The following discussion summarizes information concerning the four factors for the 

low-sulfur fuel strategy. 

Costs of Compliance 

The MANE-VU Reasonable Progress Report noted that because of requirements for 

motor vehicle fuels, refineries have already performed the capital investments required 

for the production of low sulfur diesel (LSD) and ultra-low sulfur diesel (ULSD). The 

report estimated a cost per ton of SOZ removed by switching to lower sulfur fuel would 

range from $554 to $734 per ton (Converted from 2001 to 2006 dollars using a 

conversion factor of 1 .1383) . In some seasons and some locations, low sulfur diesel is 

actually cheaper than regular diesel fuel. (See Chapter 8 of the Reasonable Progress 

Report .) 

The sulfur content of #4 and #6 fuels can also be cost-effectively reduced. Residual oil is 

essentially a by-product of the refining process, and is produced in several grades that can 

be blended to meet a specified fuel sulfur content limit. New York Harbor residual fuel 

prices for the week ended March 21, 2008 ranged from a low of $71 .38 a barrel for 2.00 

and 2.2 percent sulfur fuel ; to a high of $91 .38 per barrel for 0.3 percent sulfur fuel . Low 

pour" fuel oil with 0.5 percent sulfur sold for $80.83 per barrel in this same period5a. 

While the costs for achieving the projected emissions reductions with the low-sulfur fuel 

strategy are somewhat dependent on market conditions, they are believed to be 

reasonable in comparison to costs of controlling other sectors. Some MANE-VU states 

are proceeding with low-sulfur oil requirements much sooner than 2018; however, all of 

the MANE-VU states concur that a low-sulfur oil strategy is both reasonable and 

achievable by 2018 . MANE-VU has concluded that the cost of requiring lower sulfur 

fuel is reasonable. 

Time Necessary for Compliance 

MANE-VU's Reasonable Progress Report indicated that furnaces and boilers would not 

have to be retrofit and would not require expensive control technology to burn ULSD 

distillate fuel oil. Therefore, the time necessary for compliance would be determined by 

the availability of the fuel. 

13 Low pour refers to a low-temperature pour point (or reduced viscosity at low temperature) for the fuel . 

sa During this same period, residual oil with a fuel sulfur content limit of 0.7 percent and 1 .0 percent traded 

at $75 .13 and $72.63, respectively . 

143 
The MANE-VU Reasonable Progress Report notes that, on a national scale, more ULSD 

is produced than both LSD and high sulfur fuel, and concludes that there is sufficient 

domestic infrastructure to produce adequate stocks of LSD and ULSD. The NESCAUM 

Low Sulfur Heating Oil Reportss also observes that the federal rules for heavy-duty 

highway diesel fuel are flexible, so that if there is a shortage of 15 ppm fuel, the 15 to 

500 ppm fuel could be used to relieve the shortage. With this flexibility, the report 

concludes that the likelihood of a fuel shortage in the short term due to use of ULSD for 

heating oil is diminished. The volatile nature of heating supply and demand presents 

unique challenges to the fuel oil industry . The success of a low sulfur fuel oil program is 

predicated on meeting these challenges. The Northeast states are assessing a variety of 

business strategies and regulatory approaches that could be used to minimize any 

potential adverse supply and price impacts that could result from a regional 500 ppm 

sulfur standard for heating oil. Suppliers can increase pre-season reserves and look to 

increase imports from offshore refiners producing low sulfur product. Blending 

domestically produced biodiesel into heating oil offers opportunity to reduce imports, 

stabilize supplies and minimize supply-related price spikes. 

Potential supply disruptions and price spikes for residual fuels were a particular concern 

for several northern MANE-VU states . While the potential for disruptions in the supply 

of residual fuels is greater than that for distillate oil, these disruptions would affect only a 

limited number of states during extreme weather events . 

MANE-VU has identified several mechanisms that could be implemented to address 

disruptions, including seasonal averaging and emergency waivers. A seasonal averaging 

approach would reduce potential supply constraints by allowing the use of higher sulfur 

fuel during periods of peak demand (and limited supply), and then requiring the increased 

sulfur content of these fuels to be offset through the use of a lower sulfur fuel at other 

times. This approach would provide regulatory certainty and greater flexibility during 

the winter months when fuel supplies may be subject to weather-related disruptions, but 

at a cost of increased recordkeeping and compliance monitoring. Since many states 

already have statutory authority to waive fuel sulfur limits for an emergency waiver, 

states could also utilize their discretionary powers to address short-term supply 

disruptions . 

The strategy adopted by Maine and the other MANE-VU states proposes to phase in the 

required use of lower-sulfur fuels over the next 8 years, providing adequate time for full 

implementation . 

Energy and Non-Air Quality Environmental Impacts of Compliance 

According to MANE-VU's Reasonable Progress Report, reducing the sulfur content of 

fuel oil would have a variety of beneficial consequences for boilers and furnaces using 

this fuel. Low-sulfur distillate fuel is cleaner burning and emits less particulate matter, 

thereby substantially reducing the rate of fouling of heating units and allowing longer 

time intervals between cleanings . The MANE-VU report cites a study by the New York 

55 "Low Sulfur Heating Oil in the Northeast States : An Overview of Benefits, Costs and Implementation 

Issues", December 31, 2005 by NESCAUM. 

144 
State Energy Research and Development Authority (NYSERDA) showing that boiler 

deposits are reduced by a factor of two by lowering the fuel sulfur content from 1,400 

ppm to 500 ppm. The use low-sulfur oil could extend the useful life of a source by 

reducing the maintenance required because low-sulfur oil is less damaging to the 

combustion equipment. The report also notes that decreasing sulfur levels in fuel would 

enable manufacturers to develop more efficient furnaces and boilers by using more 

advanced condensing equipment that recovers energy normally lost to the heating of 

water vapor in the exhaust gases. 

Furthermore, SOZ controls would also have beneficial environmental impacts by reducing 

acid deposition and helping to decrease concentrations of PM2.5 . Reductions in PM2.5 

would potentially help nonattainment areas meet health-based National Ambient Air 

Quality Standards . 

Remaining Useful Life of Any Potentially Affected Sources 

Residential furnaces and boilers have finite life spans, but they do not need to be replaced 

to burn low- or ultra-low-sulfur fuel . The Energy Research Center estimates that the 

average life expectancy of a residential heating oil boiler is 20-25 years . As noted above, 

use of low-sulfur fuel is less damaging to equipment and could therefore extend the 

useful life of an oil-fired residential furnace or boiler . 

Available information on the remaining useful life of ICI boilers indicates a wide range 

of life expectancies, depending on unit size, capacity factorsb, and level of maintenance 

performed. The typical life expectancy of an ICI boiler ranges from 10 years to more 

than 30 years. As in the case of residential units, use of lower-sulfur fuels could extend 

the lifespan of an ICI boiler. 

11 .4 .3 Targeted Strategy for Reducing SO2Emissions from EGU Stacks 

EGUs are the single largest sector contributing to visibility impairment at MANE-VU 

Class I areas. S02 emissions from power plants continue to dominate the emissions 

inventory . Sulfate formed through atmospheric processes from S02 emissions are 

responsible for over half the mass and approximately 70-80 percent of the extinction on 

the days of worst visibility (NESCAUM's Contribution Assessment and Conceptual 

Model, Attachment A). 

To ensure that EGU controls are targeted at those EGUs with the greatest impact on 

visibility at MANE-VU Class I areas, a modeling analysis was conducted to identify the 

individual sources responsible for the greatest contributions to visibility impairment. 

Accordingly, MANE-VU developed a list of the 100 EGUs having the greatest impacts at 

each MANE-VU Class I area during 2002 The combined list for all seven MANE-VU 

Class I areas identified a total of 167 distinct emission points, with these stacks located 

throughout the Northeast, Midwest and Southeast (Figure 11-2) 

sb Capacity factor is defined as the actual amount of energy a boiler generates in one year divided by the 

total amount it could generate if it ran full time at full capacity. 

145 
Figure 11-2 

Location of 167 EGU Stacks Contributing the Most to Visibility Impairment at 

MANE-VU Class I Areas 

After consultations with its member states and other RPOs MANE-VU requested a 90-

percent reduction in SOZ emissions from the top 167 stacks no later than 2018 (See the 

MANE-VU "Ask," described in Section 3 .4 of this SIP). NESCAUM's preliminary 

modeling for MANE-VU showed that reducing SOZ emissions from the targeted facilities 

by 90 percent would also produce measurable improvements in ambient 24-hour PM2.5 

concentrations . Assuming a control level equal to 10 percent of the 2002 baseline 

emissions (i .e ., 90 percent emission reduction), NESCAUM used CMAQ to model 

sulfate concentrations in 2018 after implementation of controls. The modeled sulfate 

values were then converted to estimates of PMZ.5 concentrations . 

Figure 11-3 illustrates the reduction in fine particle pollution in the Eastern U.S. that 

would result from implementing the targeted EGU SOZ strategy. Improvements in PM2.5 

146 
concentrations would occur throughout the MANE-VU region as well as for portions of 

the VISTAS and Midwest RPO regions, especially the Ohio River Valley. 

Figure 11-3 

Preliminary Estimate of Average Change in 24-hr PM2,5 Due to 90 Percent 

Reduction in SOZ Emissions from 167 EGU Stacks Affecting MANE-VU 

Average Change In 24hr 

1310.5 due to 167 ECU 

-0.3-0 

0 - 0.15 

0.15 - 0.25 

~ 0.25 - 0.35 

~ 0.35 - 0.47 

~ OA7 - 0.63 

~ 0.63 - 0.94 

~ 0.94 -1 .83 

Although the reductions are potentially large, MANE-VU determined, after consultation 

with affected states, that it was unreasonable to expect that the full 90-percent reduction 

in SOZ emissions would be achieved by 2018. Therefore, additional modeling was 

conducted to assess the more realistic scenario in which emissions would be controlled 

by the individual facilities and/or states to levels already projected to take place by that 

date. At some facilities, the actual emission reductions are anticipated to be greater or 

less than the 90 percent benchmark. For a detailed description of this analysis, see 

Alpine Geophysics' report for MARAMA entitled "Documentation of 2018 Emissions 

from Electric Generating Units in the Eastern United States for MANE-VU's Regional 

Haze Modeling, Revised Final Draft, April 21, 2008 (Attachment S). 

Targeted EGUSOZ Emissions Reductions are Reasonable: MANE-VU identified 

specific EGU stacks that were significant contributors to visibility degradation at MANEVU Class I areas in 2002 based on CALPUFF modeling analyses documented in the 

Contribution Assessment. MANE-VU obtained information about existing and planned 

controls on emissions from those stacks . These analyses and the information on proposed 

147 
EGU controls are presented in the MANE-VU Reasonable Progress Report, and the 

Contribution Assessment (specifically Attachment D),as well as in Section 8 .0 

(Emissions Inventory), and Section 12 .0 (Long Term Strategy) of this SIP . 

Based on information gathered from the states and RPOs, MANE-VU anticipates that 

emissions from many of the specific EGU stacks will be controlled as a result of EPA's 

Clean Air Interstate Rule (CAIR). Since CAIR is a cap and trade program, it is not 

possible to predict with certainty which of the 167 stacks will in fact be controlled under 

CAIR in 2018 . 

Four-Factor Analvsis - Tarmeted EGU SO 

Costs of Compliance 

Technologies to control the precursors of regional haze are commercially available.s7 

Because EGUs are the most significant stationary source of SOZ, NO, and PM, they have 

been subject to extensive federal and state regulations to control all three pollutants . The 

technical feasibility of control technologies has been successfully proven for a large 

number of small (@100MW) to very large boilers (over 1,000 MW) using different types 

of coal used. Over the last few years, the cost data clearly indicate that many technologies 

provide substantial and cost-effective reductions. 

Both wet and dry flue gas desulfurization ("scrubbers") are in wide commercial use in the 

U.S. for controlling SOZ emissions from coal-fired power plants. The capital costs for 

new or retrofit wet or dry scrubbers are higher than the capital costs for NOX and PM 

controls . Capital costs ranged from $180/kW for large units (larger than 600 MW) to as 

high as $350/kW for small units (200 to 300 MW). (See pages 2-22 of the NESCAUM 

report "Assessment of Control Technologies for BART Eligible Sources," March 2005, 

Attachment R). However, the last few years have seen a general trend of declining 

capital costs due to vendor competition and technology maturation. Also, the costeffectiveness (in dollars per ton of emissions removed) is very attractive because the high 

sulfur content of the coal burned by these units results in a very large amount of SOZ 

removed by the control devices . The typical cost-effectiveness is in the range of 200 to 

500 dollars per ton of SOZ removed, although the cost rises steeply for small units 

burning low-sulfur coals and operating at low capacity factors . For any unit, the overall 

cost effectiveness is determined mostly by the baseline pre-controlled SOZ emission rate 

(or fuel sulfur content), size and capacity factor of the unit, as well as the capital cost of 

flue gas desulfurization (generally ranges from $150 to $200/Kw). 

The MANE-VU Reasonable Progress Report reviewed options for controlling coal-fired 

EGU boilers, including switching to lower-sulfur coal, switching to natural gas, coal 

cleaning, and flue gas desulfurization (FGD). The most effective control option (but not 

necessarily appropriate for all installations) is FGD, which can achieve up to a 95 percent 

reduction in S02 emissions. The cost varies considerably among units and was estimated 

57 The information in this and the next paragraph comes from the "Assessment of Control Technology 

Options for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper 

and Pulp Facilities," March 2005, prepared by NESCAUM, in partnership with MANE-VU. 

148 
to range from as low as $170/ton to as high as $5,700/ton. Table 11-6 summarizes the 

estimated SOZ control costs on a dollar per ton of SOZ removed basis. 

Table 11-6 

Estimated Cost Ranges for SOZ Control Options for Coal-Fired EGU Boilers 

(2006 dollars per ton of SOZ removed) 

Cost Range 

Technology Description Performance (2006 dollars/ton of 

SO2 Reduced) 

Switch to a Low Sulfur Replace high-sulfur 50-80% reduction in SO. Potential reduction in coal 

Coal (generally <1% sulfiu) bituminous coal combustion emissions by switching to a costs, bat possibly offset by 

with lower-sulfur coal lower-sulfur coal expensive retrofits and loss 

of boiler efficiency 

Switch to natural gas Replace coal combustion Virtually ehminau SOZ Unknown - cost of switch is 

(Mrtually 0°fa sulfur) with natural gas emissions by switching to currently uneconomical due 

natural gas to price of natural gas 

Coal Cleaning Coal is washed to remove 20-2 5% reduction in SO` 2-15% increase in fuel costs 

some of the sulfur and ash emissions based on current prices of 

prior to combustion coal 

Flue Gas Desulfittization SOZ is removed from flue 30-95'%-+- reduction in SOZ $570-55,700 for EGUs 

(FGD) - Wet gas by dissolving it in a emissions <:1 .200 MM' 

lime or limestone slurry. $330-S570 for EGUs 

(Other alkaline chemicals ==1,200 NM' 

are sometinies used) 

Flue Gas Destdlftuization A fine mist containing lime 60-95%-+- reduction in SO; $570-S4,550 for EGUs 

(FGD) - Spray Dry or other stutable sorbent is etnissions --600 MW 

injected directly into flue $170-S340 for EGUs 

gas >dpp MW 

Flue Gas Desulfinzation Powdered lime or other 40-60''o reduction in S02 S250-S850 for EGUs 

(FGD) -Dry suitable sarbent is injected emissions -300 MW 

directly into flue gas 

Table refererues : 

1 . EIA website accessed on 2/20l07: huoJlwww.eia.doe.gov/cneaflcoaUpagelcoalnewslcoalmar .html 

2. EIA website accessed on 2/20/07: bttaJlwww.eia.doe.govlcneaflcoallRageJacr/table3l_html 

3. STAPPA ALAPCO. Controlling Ftne Particulate Matter Under the Clean Air Act: .4 Menu of Options; March 

2006. 

To predict future emissions and further evaluate the costs of emission controls for electric 

generating units, MANE-VU and other RPOs have followed the example of EPA in using 

the Integrated Planning Model (IPM©), an integrated economic and emissions model for 

EGUs. This model projects electricity supplies based on various assumptions while at the 

same time developing least-cost solutions to electrical generating needs within the 

specified emissions targets. IPM also provides estimates of the costs of complying with 

various policy requirements . 

EPA developed IPM version 2.1 .9 and used this model to evaluate the impacts of CAIR 

and the Clean Air Mercury Rule (CAMR)58. Recently, EPA updated their input data and 

58 CAMR was also vacated by the federal courts and is no longer in effect . 

149 
developed IPM v3 .0 . However, because of time constraints, all MANE-VU modeling 

runs were based on EPA IPM v2.1 .9 with changes made to the input assumptions . As 

stated previously, CAIR has recently been remanded to EPA and it is unknown at this 

time when EPA will propose a revised or new rule in accordance with the court's July 11, 

2008 decision. 

The RPOs collaborated with each other to update EPA Base Case v.2 .1 .9 using more 

current data about EGUs with more realistic fuel prices, creating an IPM run called 

VISTAS PC _lf. The VISTAS IPM run is the basis for regional air quality modeling for 

regional haze SIPs in MANE-VU. 

MANE-VU, through MARAMA, contracted with the consulting firm ICF International to 

prepare two new IPM runs59. The first modeling run, known as the MARAMA CAIR 

Base Case run, was based on the VISTAS PC _1 f run and underlying EPA IPM v.2 .1 .9 

with some updated information on fuel prices, control constraints, etc . This run also goes 

by the name MARAMA_5c . The second run, called the MARAMA CAIR Plus run (also 

known as MARAMA_4c), was similarly based on VISTAS PC _1 f run and the underlying 

EPA IPM v.2.1 .9, and included updated information used in the VISTAS run, but 

assumed lower NOX emission caps and higher SOZ retirement ratios . 

Based on modeling results, MANE-VU estimates that the marginal cost of SOZ 

reductions (the cost of reducing an additional ton of emissions) ranges from $640/ton in 

2008 to $1,392 ton in 2018 .60 

Costs will vary for individual plants to reduce emissions by 90 percent, as recommended 

in the MANE-VU Ask. However, this strategy provides states with the flexibility to 

pursue controls on specific sources as appropriate and to control emissions from 

alternative sources, if necessary, to meet the 90 percent target established in the Ask. 

Given the significance of SOZ emissions from specific EGU's to visibility impairment in 

MANE-VU Class I areas, the MANE-VU Commissioners, after weighing all factors- the 

availability of technology to reduce emissions, the estimated cost of controls, the costs of 

alternative measures, the flexibility to achieve alternative reductions if necessary, etc. -

concluded that the costs of reducing emissions from the identified key stacks was 

reasonable. Maine agrees with this conclusion for base-load coal-fired units, but 

recognizes add-on controls may not be cost-effective for oil-fired peaking units. 

Time Necessary for Compliance 

MANE-VU's Reasonable Progress Report indicates that, generally, sources are given a 2-

to 4-year phase-in period to comply with new rules. Under Phase I of the NOX SIP call, 

EPA provided a compliance date of about 3 .5 years from the SIP submittal date. Most 

MACT standards allow a 3-year compliance period. Under Phase 11 of the NOX SIP Call, 

EPA provided a 2-year compliance period from the SIP submittal date. The MANE-VU 

s9 See the report, Comparison of CAIR and CAIR+ Proposal using the Integrated Planning Model (IPM®), 

ICF Resources LLC, May 2007, Attachment U. 

bo See Table 6, "Allowance Prices (Marginal Costs) of Emissions Reductions . . ." p. 9, ICF, May 2007, 

Attachment U. 

150 
states concluded that there is more than sufficient time between 2008 and 2018 for 

affected states to adopt requirements and for affected sources to install necessary 

controls. Maine agrees with this conclusion 

Energy and Non-Air Quality Environmental Impacts of Compliance 

The MANE-VU Reasonable Progress Report identified several energy and non-air 

quality impacts as a result of additional EGU controls. These included potential adverse 

impacts on fuel supplies if there were large-scale fuel switching, the triggering of NSR 

requirements, and the generation of wastewater and sludge from flue gas desulfurization 

systems . Conversely, additional controls for SO2, NO,, and ammonia would have 

beneficial environmental impacts by reducing mercury emissions, acid deposition and 

nitrogen deposition to water bodies and natural landscapes. Reductions would also result 

in decreases in ambient levels of PM2,5 with corresponding health benefits . The MANEVU states concluded that the energy and non-air quality impacts of additional EGU 

controls are reasonable. Maine agrees with this conclusion 

Remainin Useful Life of Anv Potentiall 

As noted in the MANE-VU Reasonable Progress Report, remaining useful life estimates 

of EGU boilers indicate a wide range of operating lifetimes, depending on unit size, 

capacity factor, and level of maintenance performed. Typical life expectancies range to 

50 years or more. Additionally, implementation of air pollution regulations over the 

years has necessitated emission control retrofits that have increased the expected life 

spans of many EGUs. The lifetime of an EGU may be extended through repair, repowering, or other strategies if the unit is more economical to run than to replace with 

power from other sources. Extending facility lifetime may be particularly likely for a 

unit serving an area with limited transmission to bring in other power. The remaining 

useful life of a unit should not be confused with the economic decision of whether or not 

to continue operating a unit or to re-power or replace it . The cost of environmental 

compliance is only one of many factors involved in such a decision. 

11 .4 .4 Non-EGU S02 Emissions Reduction Strategy Outside the MANE-VU Region 

In addition to the measures described above, (i .e ., BART, low sulfur fuel within MANEVU, and targeted controls on specific EGUs), MANE-VU asked states in neighboring 

regional planning organizations to consider further non-EGU emissions reductions 

comparable to those achieved by states located within the MANE-VU region through the 

application of MANE-VU's low sulfur fuel strategy. Previous modeling indicated that 

the MANE-VU low sulfur fuel strategy would achieve a greater than 28 percent reduction 

in non-EGU SOZ emissions by 2018 . After consultation with other states and 

consideration of comments received, the MANE-VU Class I States decided to include, in 

the latest modeling for the VISTAS and MRPO regions, implementation of measures 

capable of achieving SOZ emission reductions equivalent to MANE-VU's 28 percent 

reduction in non-EGU SOZ emissions in 2018 . 

To model the impact of this strategy on visibility at MANE-VU Class I areas, MANEVU had to make reasonable assumptions about where the requested emissions reductions 

would occur in the VISTAS and MRPO states without knowing precisely how those 

151 
reductions would be realized. As a means to approximate a 28 percent reduction in nonEGU SOZ emissions, the following reductions were modeled: 

" For control measures in VISTAS and MRPO states: 

" Coal-Fired ICI Boilers: SOZ emissions were reduced by 60 percent 

" Oil-Fired ICI boilers: S02 emissions were reduced by 75 percent 

" ICI Boilers lacking fuel specification : SOZ emissions were reduced 

by 50 percent 

" For additional controls only in the VISTAS states : SOZ emissions from 

other area oil-combustion sources were reduced by 75 percent (based on 

the same SCCs identified in MANE-VU's oil strategies list) 

This modeling scenario represents just one example of realistic strategies that states 

outside of MANE-VU could employ to meet the non-EGU SOZ emissions reductions 

requested by MANE-VU. 

A number of non-MANE-VU states have not included, or may not include, the requested 

28 percent reduction in non-EGU SOZ emissions in their initial SIPs. The MANE-VU 

states encourage EPA to hold these states responsible for satisfying the MANE-VU Ask 

in the course of preparing their first five-year progress reports in order to meet the CAA 

national goal of remedying any existing visibility impairment in Class I areas. 

Non EGUSOZ Emission Reductfons Measures Outside the MANE- VURegion are 

Reasonable: After EGUs, ICI boilers and heaters are the next largest class of SOZ 

emitters . ICI boilers are thus a logical choice among non-EGU sources for consideration 

of additional SOZ control measures. 

ICI Boiler Control Options 

Air pollution reduction and control technologies for ICI boilers have advanced 

substantially over the past 25 years. However, according to the 1998 survey of industrial 

boilers by EPA (2004), only 2 percent of gas-fired boilers and 3 percent of oil-fired 

boilers had installed any kind of air pollution control device . A larger percentage of coalfired boilers had installed air pollution control devices: specifically, 47 percent had 

installed some type of control device, mainly to control particulate matter (PM). Postcombustion SOZ controls were used by less than one percent of industrial boilers in 1998, 

with the exception of boilers firing petroleum coke (2 percent of boilers firing petroleum 

coke had acid scrubbers) . A small percentage of industrial boilers had combustion 

controls in place in 1998, although since 1998, additional low-NOX firing systems may 

have been installed since that date . 

Almost all SOZ emission control technologies fall in the category of reducing SOZ after its 

formation, as opposed to minimizing its formation during combustion. The method of 

SOZ control appropriate for any individual ICI boiler is dependent upon the type of boiler, 

type of fuel, capacity utilization, and the types and staging of other air pollution control 

devices. However, cost-effective emissions reduction technologies for SOZ are available 

and are effective in reducing emissions from the exhaust gas stream of ICI boilers . Post152 
combustion SOZ control is accomplished by reacting the SOZ in the gas with a reagent 

(usually calcium- or sodium-based) and removing the resulting product (a sulfate/sulfite) 

for disposal or commercial use, depending on the technology used. S02 reduction 

technologies are commonly referred to as Flue Gas Desulfurization (FGD) and are 

usually described in terms of the process conditions (wet versus dry), byproduct 

utilization (throwaway versus saleable) and reagent utilization (once-through versus 

regenerable) . 

The exceptions to the nearly universal use of post-combustion controls are found in fuel 

switching, coal cleaning, and fluidized bed boilers, in which limestone is added to the 

fuel in the combustion chamber. SOz control options for ICI boilers are outlined in Table 

11-7. Further descriptions of these SOZ control technology options are available in 

Chapter 4 of the MANE-VU Reasonable Progress Report (Attachment T). 

The SOZ removal efficiency of these controls varies from 20 to 99+ percent, depending 

upon the fuel type and control strategy . For coal-fired boilers, options include switching 

to low-sulfur coal, coal cleaning, wet FGD, dry FGD, and spray dryers . The overall SOZ 

reductions vary from a low of 20 to 25 percent for switching to low-sulfur fuel(s) to a 

high of 60 to 95 percent for wet FGD and spray dry FGD. The majority of control 

strategies, however, are capable of achieving a 60 percent or greater reduction. Thus, 

assuming that coal-fired ICI boilers adopt varying levels of controls, with most choosing 

a 50 to 70 percent reduction strategy and fewer choosing either the 20 percent or the 90 

percent reduction strategy, the region-wide average is likely to be in the range of a 60 

percent reduction in SOZ emissions. This assumption is validated by the data which 

documents that wet FGD systems represent 85 percent of the FGD systems in use in the 

United States and that FGD systems have an average S02 removal efficiency of 78 

percent. MANE-VU's modeling of a 60 percent reduction in SOZ emission from coalfired ICI boilers is therefore reasonable. 

For oil-fired boilers, options include switching to a lower sulfur fuel (e.g ., oil or natural 

gas), dry FGD, and spray dryers . The overall SOZ reductions vary from a low of 40 to 60 

percent for dry FGD, to a high of 60 to 95 percent for spray dry FGD. For comparison, 

the MANE-VU low sulfur fuel strategy assumes a 50 to 90 percent reduction in SOZ 

emissions from oil-fired ICI boilers. Assuming a typical distribution of control strategies 

chosen by the sources, MANE-VU's modeling of an average 75 percent reduction in SOZ 

emission from oil-fired ICI boilers is reasonable. 

For ICI boilers in which a fuel was not specified, a 50 percent reduction in SOZ emissions 

was assumed. ICI boilers in this category include those outside the MANE-VU region 

for which the current inventory did not specify the type of fuel burned. Because a 

response was not received from the MRPO, this assumption also encompasses some of 

the uncertainty regarding the implementation of MANE-VU's non-EGU Ask. Given the 

paucity of data, a lower reduction in SOZ emissions (50 percent) was assumed in this 

category than for coal- or oil-fired ICI boilers . Implementation of one or more of the 

suggested S02 control options capable of achieving an average 50 percent SOZ reduction 

at these sources is a reasonable assumption. 

153 
Table 11-7 

Available S02 Control Options for ICI Boilers 

Technology Description Applicability Performance 

Switch to a Low Sulfur Coal Replace high-sulfur Potential control measure 50-80% reduction in SOZ 

(generally <1 % sulfur) bituminous coal combustion for all coal-fired Us emissions by switching to a 

with lower-sulfur coal currently using coal with lower-sulfur coal 

high sulfur content 

Switch to Natural Gas Replace coal combustion Potential control measure Virtually eliminate SOZ 

(virtually 0% sulfur) with natural gas for all coal-fired ICIs emissions by switching to 

natural gas 

Switch to a Lower Sulfur Oil Replace higher-sulfur Potential control measure 50-80% reduction in S02 

residual oil with lower-sulfur for all oil-fired ICIs emissions by switching to a 

distillate oil . Alternatively, currently using higher lower-sulfur oil 

replace medium sulfur sulfur content residual or 

distillate oil with ultra-low distillate oils 

sulfur distillate oil 

Coal Cleaning Coal is washed to remove Potential control measure 20-25% reduction in SOZ 

some of the sulfur and ash for all coal-fired ICI boilers emissions 

prior to combustion 

Combustion Control A reactive material, such as Applicable to pulverized 40%-85% reductions in SOZ 

limestone or bi-carbonate, is coal-fired boilers and emissions 

introduced into the circulating fluidized bed 

combustion chamber along boilers 

with the fuel 

Flue Gas Desulfurization SOZ is removed from flue Applicable to all coal-fired 30-95%a+ reduction in SOZ 

(FGD) -Wet gas by dissolving it in a lime ICI boilers emissions 

or limestone slurry . (Other 

alkaline chemical are 

sometimes used) 

Flue Gas Desulfurization A fine mist containing lime or Applicable primarily for 60-95%+ reduction in SOZ 

(FGD) -Spray Dry other suitable sorbent is boilers currently firing low emissions 

injected directly into flue gas to medium sulfur fuels 

Flue Gas Desulfurization Powdered lime or other Applicable primarily for 40-60% reduction in SO2 

(FGD)-Dry suitable sorbent is injected boilers currently firing low emissions 

directly into flue gas to medium sulfur fuels 

For emissions from other area oil-combustion sources in the VISTAS region, an SOZ 

reduction of 75 percent was assumed. This is equivalent to the MANE-VU low sulfur 

fuel strategy . The four factor analysis of this strategy was presented in Section 11 .3 .2 . 

Four-Factor Analysis - Non-EGU SO_ 2Emission Reduction Measures Outside 

MANE-VU 

Based on the survey of available technologies outlined above and the four-factor analysis 

summarized below, MANE-VU concludes that each of the strategies assumed for 

modeling purposes to meet the MANE-VU Ask of a 28 percent reduction in non-EGU 

SOZ emissions is reasonable. States should have no difficulty in meeting this benchmark 

in light of the control efficiencies that are attainable at reasonable costs with retrofit 

technologies that are available for ICI boilers today. 

154 
Costs of Compliance 

Industrial boilers have a wider range of sizes than EGUs and often operate over a wider 

range of capacities . Thus, cost estimates for the same technologies will generally span a 

relatively larger range, and costs for individual boilers will depend on the capacity of the 

boiler and typical operating conditions. In general, cost-effectiveness increases as boiler 

size and capacity factor (a measure of boiler utilization) increases. 

MANE-VU's Reasonable Progress Report (Attachment T) provides emission control cost 

estimates for ICI boilers in the range of $130 per ton to $11,000 per ton, a very wide 

range due to the variability of sources and control options in this category. bl All costs 

presented below for emission controls on ICI boilers are borrowed from this report. 

Dollar amounts originated from EPA publications cited in the report and have been 

converted to 2006 dollars using a conversion factor from www.inflationdata.com. 

o Cost of Fuel Switching: 

Although fuel switching can be a very effective means of reducing S02 emissions 

(reductions of 50 to 99.9 percent are possible), burning low-sulfur fuel may not be a 

technically feasible or economically practical SOZ control alternative for every ICI coalfired boiler. Factors impacting applicability include the characteristics of the plant and 

the particular type of fuel change being considered . Additionally, switching to a lower 

sulfur coal can affect fuel handling systems, boiler performance, PM control 

effectiveness, and ash handling systems. Oil-fired boilers switching to a lower sulfur fuel 

of the same grade (e .g ., switching from #6 fuel oil at 2.0%S to #6 fuel oil at 0.5% S) do 

not typically encounter these issues ; please see Section 11 .4 .2 for a discussion of the 

costs and issues associated with switching to low sulfur fuel oil. 

The costs of coal fuel switching, including substitution or blending with a low-sulfur 

coal, can be attributed to two main reasons : the cost of low-sulfur coal compared to 

higher sulfur coal (including coal's heating value), and the cost of any necessary boiler or 

coal handling equipment modifications. Many plants will be able to switch from highsulfur to low-sulfur bituminous coal without serious difficulty, but switching from 

bituminous to sub-bituminous coal may require potentially significant investments and 

modifications to an existing plant. Even if a lower sulfur fuel is available, it may not be 

cost competitive if it must be transported long distances from the supplier or supplied in 

small quantities. It also may be more cost-effective to burn a higher sulfur fuel supplied 

by nearby suppliers and to use a post-combustion control device . 

Switching from coal combustion to natural gas combustion virtually eliminates SOZ 

emissions. It is technically feasible to switch from coal to natural gas, but the wide 

variation in natural gas process means that it may be uneconomical to consider this option 

for large ICIs due to the fuel quantity necessary and the price of natural gas. Natural gas 

is currently about twice times the price of coal in terms of heating value, but has been as 

high as seven times the price of coal in recent years . 

6'MANE-VU's Reasonable Progress Report is entitled "Assessment of Reasonable Progress for Regional 

Haze in MANE-VU Class I Areas" prepared by MACTEC for MARAMA, dated July 9, 2007. 

155 
o Cost of Coal Cleaning 

The World Bank, an organization which assists with economic and technological needs in 

developing countries, reports that the cost of physically cleaning coal varies from $1 to 

$10 per ton of coal cleaned, depending on the coal quality, the cleaning process used, and 

the degree of cleaning desired. In most cases the costs were found to be between $1 and 

$5 per ton of coal cleaned. The effectiveness of coal cleaning is typically a 20 to 25 

percent reduction in SOZ emissions. Coal cleaning also increases the heating value of the 

fuel by a small amount. 

o Cost of Combustion Controls 

Dry sorbent injection (DSI) systems have lower capital and operation costs than postcombustion FGD systems because of the simplicity of the DSI design, lower water use 

requirements, and smaller land area requirements. Table 11-8 presents the estimated 

costs of adding DSI-based SOZ controls to ICI boilers based for different boiler sizes, fuel 

types, and capacity factors . 

o Cost of FGD 

Installation of post-combustion SOZ controls in the form of FGD has several impacts on 

facility operations, maintenance, and waste handling procedures . FGD systems generally 

require substantial land area for construction of the absorber towers, sorbent tanks, and 

waste handling equipment. The facility costs therefore depend on the cost and 

availability of space for construction of the FGD system . Solid waste handling is another 

factor that influences the cost of FGD control systems. Significant waste material may be 

generated that requires disposal. These costs may be mitigated, however, by utilization 

of a forced oxidation FGD process that produces commercial-grade gypsum, which may 

be sold as a raw material for other commercial processes. 

Table 11-8 

Estimated Dry Sorbent Injection (DSI) Costs for ICI Boilers 

(2006 dollars) 

SOZ Capacity 

Cost Effectiveness ($/Ton of SOZ ) 

Fuel Reduction 

N 

Factor (%) 100 

MMBTUIhr i 

250 

MMBTUIhr 

1,000 

MMBTUIhr 

2%-sulfur coal 40 14 4,686 3,793 2,979 

50 1,312 1,062 834 

83 772 624 490 

3.43%-sulfur 40 14 2,732 2,212 1,737 

coal 50 765 619 486 

83 450 364 286 

2%-sulfur coal 85 14 2,205 1,786 1,402 

50 617 500 392 

83 363 294 231 

3.43%-sulfur 85 14 1,286 1,040 818 

coal 50 360 291 229 

83 212 171 134 

156 
Table l l-9 presents the total estimated cost effectiveness of adding FGD-based SOZ 

controls for different boiler sizes, fuel types, and capacity factors. There is no indication 

that these cost data include revenue from gypsum sales, which would partially offset the 

costs of FGD controls. 

Carbon dioxide is also emitted as a by-product of FGD, therefore impacts of increased 

carbon emissions would need to be considered. COZ emissions will become more of an 

issue in the future if they are limited under climate change mitigation strategies . Given 

the uncertainty of such future strategies, costs related to increased carbon emissions from 

FGD cannot yet be assessed . 

MANE-VU's request for a 28 percent reduction in non-EGU SOZ emissions allows states 

flexibility in determining which sources to control, so that the most cost-effective control 

measures can be adopted and implemented over the next 10 years. Given the wide range 

of control options and costs available for this purpose, MANE-VU has concluded that its 

request for a 28 percent reduction in non-EGU SOZ emissions is reasonable. Maine 

concurs with this conclusion . 

Time Necessary for Compliance 

For pre- and post-combustion SOZ emission controls, engineering and construction lead 

times will vary between 2 and 5 years, depending on the size of the facility and specific 

control technology selected. Generally, sources are given a 2-4 year phase-in period to 

comply with new rules, as previously described, and states generally have a 2-year period 

for compliance with RACT rules. 

Table 11-9 

Estimated FGD Costs For ICI Boilers 

(2006 dollars) 

SOZ Capacity Cost Effectiveness ($/Ton of SOZ ) 

Fuel Technology Reduction 

(%) 

Factor (°/a) 100 

MMBT hr 

250 

MM BT hr 

1,000 

MMBT hr 

High-sulfur FGD (Dry) 40 14 3,781 2,637 1,817 

coal 50 1,379 1,059 828 

83 1,006 814 676 

Lower- FGD (Dry) 40 14 4,571 3,150 2,119 

sulfur coal 50 1,605 1,207 928 

83 1,147 906 744 

Coal FGD (Spray 85 14 4,183 2,786 1,601 

dry) 50 1,290 899 567 

83 843 607 407 

High-sulfur FGD (Spray 85 14 3,642 2,890 1,909 

coal dry) 50 1,116 875 601 

83 709 563 398 

Lower- FGD (Wet) 40 14 4,797 3 693 2, 426 

sulfur coal 50 1,415 1 , 106 751 

83 892 705 492 

Oil FGD (Wet) 40 14 10,843 8,325 5,424 

50 2,269 1,765 1,184 

1513 1_,371 1,079 

_ 

740 
For the purposes of this review, it is assumed that a 2-year period after SIP submittal is 

adequate for the installation of pre-combustion controls (fuel switching or cleaning) and a 

3-year period for the installation of post-combustion controls . MANE-VU has therefore 

concluded that there is sufficient time between 2008 and 2018 for the affected states to 

adopt emission control requirements and for affected sources to install controls necessary 

to meet MANE-VU's requested SOZ emission reductions from non-EGU sources. Maine 

concurs with this conclusion. 

Energy and Non-Air Quality Environmental Impacts of Compliance 

The primary energy impact of pre- or post-combustion control alternatives is a potential 

increase in electricity usage. Fuel switching and cleaning do not significantly affect the 

efficiency of the boiler itself, but require additional energy to clean or blend coal. FGD 

systems typically operate with high-pressure drops across the control equipment, and 

therefore consume significant amounts of electricity to operate blowers and circulation 

pumps. In addition, some combinations of FGD technology and plant configuration may 

require flue gas reheating to prevent physical damage to equipment, resulting in higher 

fuel usage . 

The primary non-air environmental impacts of fuel switching derive from transportation 

of the fuel . Secondary environmental impacts derive from waste disposal and material 

handling operations (e.g. fugitive dust). For FGD systems, the generation of wastewater 

and sludge from the SOZ removal process is a consideration . Wastewater from the FGD 

systems will increase sulfate, metals, and solids loading at the receiving wastewater 

treatment facility, resulting in potential impacts to operating cost, energy requirements, 

and effluent water quality. Processing of the wastewater sludge can require energy for 

stabilization and/or dewatering, and transporting the sludge to the landfill has additional 

environmental impacts. 

Fuel switching to a low-sulfur distillate fuel oil has a variety of beneficial consequences 

for ICI boilers . Low-sulfur distillate fuel is cleaner burning and emits less particulate 

matter, which reduces the rate of fouling of heating units substantially and permits longer 

time intervals between cleanings. According to a study conducted by the New York State 

Energy Research and Development Authority, (NYSERDA)6z, lowering the fuel sulfur 

content from 1,400 ppm to 500 ppm will reduce boiler deposits by a factor of two. These 

reductions in buildup of deposits result in longer service intervals between cleanings . 

Reducing SOZ emissions from ICI boilers would have positive environmental and health 

impacts. SOZ controls would reduce acid deposition, helping to preserve aquatic life, 

forests, crops, and buildings and sculptures made of acid-sensitive materials. These 

emission reductions would also help to decrease ambient concentrations of PM2.5, a 

significant contributor to premature morbidity and illness in individuals with heart or 

lung conditions . 

62 Reference 10 in Attachment T. 

158 
MANE-VU has concluded that the energy and non-air environmental impacts of 

controlling SOZ emissions from ICI boilers are justified in light of the beneficial impacts 

on regional haze, fine particulate air pollution, acid rain, and equipment operation, as 

described above. Maine concurs with this conclusion. 

Remaining Useful Life of Any Potentially Affected Sources 

Available information for remaining useful life estimates of ICI boilers indicates a wide 

range of operating time, depending on size of the unit, capacity factor, and level of 

maintenance performed. Typical life spans range from about 10 years up to over 30 

years. However, the remaining useful life of a source is highly variable; and older units 

are not likely to be retrofitted with expensive emission controls . Given the typical range 

of life expectancies of ICI boilers, the technical options available, and the flexibility that 

non-MANE-VU states would have to meet the Ask, MANE-VU has concluded that its 

request for a 28 percent reduction in non-EGU SOz emissions is reasonable. Maine 

concurs with this conclusion. 

11 .5 Visibility Impacts of Additional Reasonable Controls 

MANE-VU's evaluations included modeling to estimate the visibility effects of various 

elements of the Maine/MANE-VU Ask. This modeling is described in NESCAUM's 

report entitled "MANE-VU Modeling for Reasonable Progress Goals," February 2008, 

(Attachment P). NESCAUM also conducted more recent, revised modeling to assess the 

effects of all haze reduction strategies combined. The latter modeling is described in 

NESCAUM's report entitled "2018 Visibility Projections," March 2008, (Attachment Q). 

The following information about the effects of specific strategies is taken from these 

reports . 

The NESCAUM modeling demonstrates that significant visibility benefits will accrue 

from implementation of the additional reasonable control measures described in 

Subsection 11 .4, above. Figures 11 .4 and 11 .5 describe the results of this modeling. In 

the first of the two figures, the light yellow bars represent expected visibility at MANEVU Class I areas in 2018. Comparison of these values with the 2018 "glide slope" 

values (the plum-colored second bars from the left) shows that all areas are expected to 

experience visibility improvements that meet or exceed the uniform rate of progress 

calculated for each area. The second figure shows that, for the 20 percent of days having 

the best visibility, expected visibility in 2018 will be better than it is today at all 

locations. 

In conclusion, the reasonable progress goals for Class I areas proposed by the MANE-VU 

states are found to be consistent with the stated national goals of preventing further 

visibility degradation while making timely progress toward achieving natural visibility 

conditions in Class I areas by 2064. 
Figure 11-4 

Demonstration of Required and Reasonable Visibility Progress for 20% Worst 

Visibility Days 

Visibility Progress for 20% Worst Days 

(Visibility Improvements Must be Made at Reasonable Rate) 

35 

30 a 

3 25 -- 

> 

Z 20 

. 

~,. 

~ 15 

y 10 

> 

5 

0 

Acadia Brigantine Great Gulf Lye Brook Moosehorn 

~ " 2002 Baseline 0 2018 Glideslope ~ 2018 Projected Progress © Natural 

Figure 11-5 

Demonstration of Required and Visibility Maintenance for 20% Best Visibility Days 

Visibility Progress For 20% Best Days 

(Baseline Visibility Must be Maintained or Improved) 

16 

14 

: . w 

y 

3 

12 

T 

> 10 

8 

6 

H :a 

> 4- 

2 

0 

Acadia Brigantine Great Gulf Lye Brook Moosehom ' 

" 2002 Baseline " 2018 Projected Progress 
12. Long Term Strategy 

40 CFR Section 51 .308(d)(3) requires the State of Maine to submit a long-term strategy 

that addresses regional haze visibility impairment for each mandatory Class I Federal 

area within and outside the State which may be affected by emissions from within Maine. 

These Class I areas include: Acadia National Park; Great Gulf Wilderness Area; 

Presidential Range-Dry River Wilderness ; Moosehorn Wilderness and Roosevelt 

Campobello International Park. The long-term strategy must include enforceable 

emissions limitations, compliance schedules, and other measures necessary to achieve the 

reasonable progress goals established by States/Tribes where the Class I areas are 

located. As described in Section 3 .0, Regional Planning and Consultation, Maine 

consulted with states and tribes both within and outside MANE-VU when developing the 

emission management strategies in this SIP. The following describes how Maine meets 

the long-term strategy requirements of the Regional Haze Rule. 

Maine's long term strategy includes enforceable emissions limitations, compliance 

schedules, and other measures necessary to achieve the reasonable progress goals 

established in Section 11 . Additional measures may be reasonable to adopt at a later date 

after further consideration and review . In developing this long-term strategy, Maine also 

considered the requirements of the Clean Air Act, Section 110(a)(2)9D)(i)(ii), pertaining 

to interstate and international transport of pollutants . Maine has previously addressed 

this issue in its "Transport SIP Revision," submitted to EPA on April 24, 2008. As that 

document observed, states must include provisions in their implementation plans to 

prohibit any source or activity from emitting air pollutants in amounts that would 

interfere with another state's ability to prevent significant deterioration of air quality and 

visibility . The long-term strategy presented herein is designed to protect visibility in 

Maine as well as in areas outside of Maine that are affected by Maine emissions. 

12.1 Overview of the Long Term Strategy Development Process 

The regional strategy development process identified reasonable measures that would 

reduce emissions contributing to visibility impairment at MANE-VU Class I areas by 

2018 or earlier. The process for identifying potential emission reduction measures and 

the technical basis for the long term strategy is discussed in the following sections . 

As a MANE-VU member and participant, Maine supported a number of technical 

analyses that were developed to assist the MANE-VU states in deciding which regional 

haze control measures to pursue. These analyses are documented in the following 

reports : 

. "Contributions to Regional Haze in the Northeast and Mid-Atlantic United 

States" (also known as the Contribution Assessment), August 3, 2006, 

NESCAUM (Attachment A). 

161 
" "Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning 

Model®" (also known as the CAIR+ Report), May 30. 2007, ICF/MARAMA 

(Attachment U). 

" "Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I 

Areas" (also known as the Reasonable Progress Report), July 9, 2007, 

MACTEC/MARAMA (Attachment T). 

. "Five-Factor Analysis of BART-Eligible Sources: Survey of Options for 

Conducting BART Determinations," June 1, 2007, NESCAUM (Attachment 

N). 

" "Assessment of Control Technology Options for BART-Eligible Sources: 

Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp 

Facilities," March 7, 2005, NESCAUM (Attachment R). 

12.2 The Regional Process for Identifying Potential Strategies 

MANE-VU reviewed a wide range of potential control measures to reduce regional haze 

at the affected Class I areas by the 2018 milestone. The process of choosing a set of 

proposed regional haze control measures started in late 2005 . The Ozone Transport 

Commission (OTC) selected a contracting firm to assist with the analysis of ozone and 

regional haze control measure options, and provided the contractor with a "master list" of 

some 900 potential control measures, based on experience and previous state 

implementation plan work. With the help of an internal OTC control measure workgroup, 

the contractor narrowed the list of available regional haze control measures for further 

consideration by MANE-VU. 

MANE-VU then developed an interim list of control measures for regional haze. The 

identified control measures can be divided into five general categories : 

" Beyond-CAIR sulfate reductions from electricity generating units (EGUs) and 

related control measures targeted at specific EGUs in the eastern United States ; 

" Low-sulfur heating oil (residential and commercial); 

" Controls on ICI boilers (both coal and oil-fired) ; 

" Controls on lime and cement kilns; and 

" Controls on residential wood combustion, and outdoor burning (including outdoor 

wood boilers) . 

The next step was to further refine this list, with the aid of several of the reports named 

above. The CAIR Plus Report (Attachment U) documents MANE-VU's assessment of 

the costs of CAIR and provides a cost analysis for additional SOZ and NOX controls at 

EGUs in the eastern United States. The Reasonable Progress Report documents the 

assessment of control measures for EGUs and the other source categories selected for 

analysis . Further analysis is provided in the NESCAUM document entitled, "Assessment 

of Control Technology Options for BART-Eligible Sources : Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and Pulp Facilities." 

The beyond-CAIR EGU strategy quickly became central to the MANE-VU long term 

strategy planning efforts, since EGU sulfate emissions are the largest contributor to 

162 
visibility impairment at MANE-VU Class I areas. Similarly, a low-sulfur oil strategy 

gained traction after a NESCAUM-initiated conference with refiners and fuel-oil 

suppliers concluded that such a strategy could fully implemented by 2018 . Thus the lowsulfur heating oil and the oil-fired ICI boiler sector control measures merged into an 

overall strategy requiring the use of low-sulfur oil. Under this strategy, low-sulfur oil 

would be required for all residential and commercial heating units and all ICI boilers 

burning #2, #4, or #6 fuel oils . 

During MANE-VU's internal consultation meeting in March 2007, member states 

reviewed the interim list of control measures to make additional refinements. States 

determined, for example, that there may be too few coal-fired ICI boilers in the MANEVU states for that to be considered as a "regional" strategy, but those sources could be 

controlled on a state-by-state basis. The MANE-VU members also decided that lime and 

cement kilns, of which there are few in the MANE-VU region, would best be handled via 

the BART determination process. Residential wood burning and outdoor wood boilers 

remained on the list for those states where localized visibility impacts are a consideration, 

even though emissions from these sources are primarily organic carbon and direct 

particulate mater. Finally, the MANE-VU membership decided that the issue of outdoor 

wood burning should be examined further by individual states, because of concerns 

related to enforcement and penetration of existing state regulations" . 

12. 3 The Technical Basis for Strategy Development 

40 CFR Section 51 .308(d)(3)(iii) requires Maine to document the technical basis for the 

State's apportionment of emission reductions necessary to meet reasonable progress goals 

in each Class I area affected by its emissions . Maine relied on the technical analyses 

developed by MANE-VU to demonstrate that the Maine emission reductions, when 

coordinated with those of other States and Tribes, are sufficient to achieve reasonable 

progress goals in Class I areas affected by emissions originating in Maine. 

The emission reductions necessary to meet reasonable progress goals in the Class I areas 

affected by Maine are described in the following documents: 

"Baseline and Natural Background Visibility Conditions-Considerations and 

Proposed Approach to the Calculation of Baseline and Natural Background 

Visibility Conditions at MANE-VU Class I Areas," December 31, 2006, 

NESCAUM (Attachment G). 

"The Nature of the Fine Particle and Regional Haze Air Quality Problems in 

the MANE-VU Region: A Conceptual Description," November 2, 2006, 

NESCAUM (Attachment V). 

63 Maine regulates outdoor burning activities through statute at 12 MRSA §9321 et seq. and through its 06-

096 CMR Chapter 102 Open Burning and 06-096 CMR Chapter 150 Control of Emissions From Outdoor 

Wood Boilers rule . 

163 
"Contributions to Regional Haze in the Northeast and Mid-Atlantic United 

States (also known as the Contribution Assessment)," August 31, 2006, 

NESCAUM (Attachment A). 

"Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning 

Model© (also known as the CAIR+ Report) May 30, 2007, ICF/MARAMA 

(Attachment U). 

"Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I 

Areas" (called the Reasonable Progress Report), July 9, 2007, 

MACTEC/MARAMA) (Attachment T). 

"Five-Factor Analysis of BART-Eligible Sources : Survey of Options for 

Conducting BART Determinations," June 1, 2007, NESCAUM (Attachment 

N). 

"Assessment of Control Technology Options for BART-Eligible Sources: 

Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp 

Facilities," March 7, 2005, NESCAUM (Attachment R) . 

"MANE-VU Modeling for Reasonable Progress Goals: Model Performance 

Evaluation, Pollution Apportionment, and Control Measure Benefits," 

February 7, 2008, NESCAUM (Attachment P). 

"2018 Visibility Projections," March 31, 2008, NESCAUM (Attachment Q). 

In addition, Maine relied on analyses conducted by neighboring RPOs, including the 

following documents, which are available upon request but are not incorporated into this 

SIP: 

VISTAS Reasonable Progress Analysis Plan by VISTAS, dated September 

18, 2006. 

. Reasonable Progress for Class I Areas in the Northern Midwest-Factor 

Analysis, by EC/R, dated July 18 . 2007 . . 

As described in Subsection 12.2, above, Maine worked with the other members of 

MANE-VU and with the Ozone Transport Commission to evaluate a large number of 

potential emission reduction strategies covering a wide range of sources of S02 and other 

pollutants contributing to regional haze. 40 CFR 51 .308(d)(3)(v) requires states to 

consider several factors in developing their long-term strategies . Operating within this 

framework and using the available information about emissions and potential impacts, the 

MANE-VU Reasonable Progress Workgroup selected the following source categories for 

detailed analysis : 

. 

Coal and oil-fired electric generating units, (EGUs); 

Point and area source industrial, commercial and institutional (ICI) boilers; 

Cement and lime kilns; 

Sources capable of using low-sulfur heating oil; and 

Residential wood combustion and open burning. 

164 
These efforts led to the selection of the emission reductions strategies presented in this 

SIP. 

12.4 Emission Reductions Due to Ongoing Air Pollution Reduction Programs 

40 CFR Section 51 .308(d)(3)(v)(A) requires Maine to consider emission reductions from 

ongoing pollution control programs. In developing its Long Term Strategy, Maine 

considered emission control programs being implemented between the 2002 baseline 

period and 2018 . The emission reduction programs described in Subsection 12.4.1, 

12.4.2 and 12.4 .3 below represent commitments already made by Maine and other states 

to implement air pollution control measures for EGU point sources, non-EGU point 

sources, and area sources, respectively . These control measures are the very same 

measures that were included in the 2018 emissions inventory and used in the modeling. 

While these control measures were not designed expressly for the purpose of improving 

visibility, the pollutants they control include those that contribute to visibility impairment 

in MANE-VU Class I Areas. 

MANE-VU's 2018 "beyond on the way" (BOTW) emissions inventory accounts for 

emission controls already in place as well as emission controls that are not yet finalized 

but are likely to achieve additional reductions by 2018. The BOTW inventory was 

developed based on the MANE-VU 2002 Version 3 .0 inventory and the MANE-VU 2018 

on the books/on the way (OTB/OTW) inventory . Inventories used for other RPOs reflect 

anticipated emissions controls that will be in place by 2018. The inventory is termed 

"beyond on the way" because it includes control measures that were developed for ozone 

SIPs that were not yet on the books in some states . For some states it also included 

controls that were under consideration for Regional Haze SIPs that have not yet been 

adopted . More information may be found in the following documents : 

" "Development of Emissions Projections for 2009, 2012, and 2018 for NonEGU Point, Area, and Non-road Sources in the MANE-VU Region," February 

2007, MACTEC/MARAMA (Attachment J) 

" "Documentation of 2018 Emissions from Electric Generating Units in Eastern 

U.S . for MANE-VU Regional Haze Modeling," April 28, 2008, Alpine 

Geophysics/MARAMA (Attachment S) 

" "MANE-VU Modeling for Reasonable Progress Goals: Model Performance 

Evaluation, Pollution Apportionment, and Control Measure Benefits," February 

7, 2008, NESCAUM (Attachment P) 

" "2018 Visibility Projections," March 31, 2008, NESCAUM (Attachment Q) 

12 .4 .1 EGU Emissions Controls Expected by 2018 

The following EGU emission reduction programs were included in the modeling used to 

develop the reasonable progress goals. These programs represent the greatest 

opportunities for reducing SOZ emissions at Class I areas in the MANE-VU region and 

serve as the starting point for MANE-VU's long-term strategy to mitigate regional haze. 

165 
Clean Air Interstate Rule (CAIR). This major federal rule has been remanded to EPA to 

correct deficiencies . The original CAIR imposed permanent caps on sulfur dioxide (SOZ) 

and nitrogen oxides (NOX) in the eastern United States by 2015. When fully effective, 

this program was expected to reduce S02 emissions in the CAIR region by up to 70 

percent. The first phase of CAIR was implemented on an interim basis in 2009, and EPA 

is expected to issue a revised CAIR rule in response to the remand in 2010 or 2011 . To 

predict future emissions from EGUs after implementation of CAIR, MANE-VU used the 

Integrated Planning Model (IPM).64 Adjustments to the IPM output were made to 

provide a more accurate representation of anticipated controls at specific EGU sources as 

documented in the Alpine Geophysics report listed above. In making these adjustments, 

emission controls originating from the following states and regional programs were 

considered. 

Connecticut EGU Regulations: Connecticut adopted the following regulations governing 

EGU emissions : 

" Regulations of Connecticut State Agencies (RCSA) section 22a-174- 19a, limiting 

the S02 emission rate to 0.33 lb SOZ/MMBtu for fossil fuel-fired EGUs greater 

than 15 MW that are also Title IV sources. (Implementation status - 2007). 

" RCSA section 22a-174-22, limiting the non-ozone seasonal NOx emission rate to 

0 .15 lb NOx/MMBtu for fossil fuel-fired EGUs greater than 15 MW. 

(Implementation status - 2007). 

Connecticut General Statutes section 22a-199, limiting the mercury (Hg) 

emission rate to 0.00000061b HglMMBtu for all coal-fired EGUs or alternatively 

coal-fired EGUs can meet a 90% Hg emission reduction. (Implementation status 

-2008). 

Delaware EGU Regulations: Delaware adopted the following regulations governing 

EGU emissions: 

1 . Reg. 1144, Control of Stationary Generator Emissions, SOz, PM, VOC and NO,, 

emission control, state-wide, effective January 2006. 

2. Reg. 1146, EGUs, Electric Generating Unit (EGU) Multi-Pollutant Regulation, 

SOZ and NO,, emission control, state-wide, effective December 2007. SOZ 

reductions will be more than regulation specifies . 

64 The IPM model runs also anticipated the implementation of EPA's Clean Air Mercury Rule (CAMR), 

which was recently vacated by the courts . However, MANE-VU believes that the adjustments made to the 

predicted SOZ emissions from EGUs will have a larger effect on the air quality modeling analysis 

conducted for this SIP than will the vacatur of the CAMR rule . The emission adjustments were based on 

state's comments on the actual levels of SOZ controls expected to be installed in response to state-specific 

regulations and EPA's CAIR rule . MANE-VU believes these adjustments improve the reliability of both 

the emission inventory and modeling results. 

166 
3. Regulation No. 1148, Control of Stationary Combustion Turbine Electric 

Generating Unit Emissions, requiring SO2, NO,, and PM2,5 emission controls, 

state-wide, effective January 2007. 

Delaware estimates that these regulations will result in the following emission reductions 

for affected units : S02 emissions of 32,630 tons in 2002 will decline to 8,137 tons in 

2018 (a 75 percent reduction) ; NO,, emissions of 8,735 tons in 2002 will decline to 3,740 

tons in 2018 (a 57 percent reduction) . 

Also, Delaware anticipates the following reductions resulting from the consent decree 

with the Valero Refinery Delaware City, DE (formerly Motiva, Valero Enterprises) . 2002 

SOZ levels of 29,747 tons will drop to 608 tons in 2018 (a 98 percent reduction) . NO,, 

2002 levels of 1,022 tons will fall to 102 tons in 2018 (a 90 percent reduction) . 

Maine EGU Regulations: Chapter 145 NOX Control Program, limits the NOx emission 

rate to 0.221b NOX /MMBtu for fossil fuel-fired units greater than 25 MW built before 

1995 with a heat input capacity between 250 and 750 MMBtu/hr, and which also limits 

the NOX emission rate to 0.171b NOx /MMBtu for fossil fuel-fired units greater than 25 

MW built before 1995 with a heat input capacity greater than 750 MMBtu/hr. (effective 

2007) 

Massachusetts EGU Regulations : Based on the Massachusetts Department of 

Environmental Protection's 310 CMR 7.29, Emissions Standards for Power Plants, 

adopted in 2001, six of the largest fossil fuel-fired power plants in Massachusetts must 

comply with emissions limitations for NO, SO2, mercury, and C02. These regulations 

will achieve an approximately 50 percent reduction in NOX emissions and a 50 - 75 

percent reduction in SOZ emissions compared to previous emissions. Depending upon 

the compliance path selected by the affected facilities, the facilities will comply with the 

output-based NOX and SOZ standards between 2004 and 2008 . This regulation also limits 

the six grandfathered EGUs to a C02 emission rate of 1,8001b/MWh. 

New Hampshire EGU Regulations: New Hampshire adopted the following regulations 

governing EGU emissions: 

" Chapter Env-A 2900 capping NOX emissions at 3,644 tons NOX per year, SOz 

emissions at 7,289 tons S02 per year, and C02 emissions at 5,425,866 tons COZ per 

year for all existing fossil steam units by December 31, 2006. 

" Chapter Env A 3200 NOz Budget Trading Program limiting ozone season NO,, 

emissions on all fossil fuel-fired EGUs greater than 15 MW to 0.15 lb/MMBtu, 

effective November 2, 2007. 

New Jersey New Source Review Settlement Agreements: The New Jersey settlement 

agreement with PSEG required the following actions for specific EGUs: 

" Bergen Unit #2: Repower to combined cycle by December 31, 2002. 

" Hudson Unit #2: install Dry FGD or approved alternative technology by Dec. 31, 

167 
2006 to control SOZ emissions, and operate the control technology at all times the 

unit operates to limit SOZ emissions to 0.15 lb SOZ/MMBtu; install SCR or 

approved alternative technology by May 1, 2007 to control NOx emissions and 

operate the control technology year-round to limit NOx emissions to 0.1 lb 

NOX/MMBtu; and install a baghouse or approved alternative technology by May 1, 

2007 to control PM emissions and limit PM emissions to 0.015 lb PM/MMBtu. 

. Mercer Unit #1 : install Dry FGD or approved alternative technology by Dec. 31, 

2010 to control SOZ emissions and operate the control technology at all times the 

unit operates to limit SOZ emissions to 0.15 lb SOZ/MMBtu, and install SCR or 

approved alternative technology by 2005 to control NOx emissions, and operate the 

control technology ozone season only in 2005 and year-round by May l, 2006 to 

limit NOX emissions to 0.13 lb NOx/MMBtu. 

. For Mercer Unit #2: install Dry FGD or approved alternative technology by Dec. 

31, 2012 to control SOZ emissions, and operate the control technology at all times 

the unit operates to limit SOZ emissions to 0 .15 lb SOz/MMBtu, and install SCR or 

approved alternative technology by 2004 to control NOx emissions, and operate the 

control technology ozone season only in 2004 and year-round by May 1, 2006 to 

limit NOX emissions to 0.13 lb NOX /MMBtu. 

The New Jersey settlement also requires coal with monthly average sulfur content no 

greater than 2% at units operating an FGD. 

New York EGU Regulations: New York adopted the following regulations governing 

EGUs: 

Title 6 NYCRR Parts 237, Acid Deposition Reduction NO, Budget Trading Program, 

limits NOx emissions on all fossil fuel-fired EGUs greater than 25 MW to a non-ozone 

season cap of 39,908 tons in 2007. 

Title 6 NYCRR Parts 238, Acid Deposition Reduction S02 Budget Trading Program 

limits annual SOZ emissions from all fossil fuel-fired EGUs greater than 25 MW to an 

annual SOZ cap of 197,046 tons S02/year, starting in 2007 and an annual SOZ cap of 

131,364 tons S02/year starting in 2008. 

North Carolina Clean Smokestacks Act: Enacted in 2002, this legislation requires that 

coal-fired EGUs achieve a 77 percent cut in nitrogen oxide (NOX) emissions by 2009 and 

a 73 percent cut in sulfur dioxide (SOZ) emissions by 2013. This legislation also 

establishes annual caps on both SOZ and NOX emissions for the two primary utility 

companies in North Carolina, Duke Energy and Progress Energy. These reductions must 

be made in North Carolina, and allowances are not saleable . 

Consent Agreements in the VISTAS region : The effects of the following consent 

agreements in the VISTAS states were reflected in the emissions inventories used for 

those states : 

" Santee Cooper: A 2004 consent agreement calls for Santee Cooper in South 

Carolina to install and commence operation of continuous emission control 

168 
equipment for PM/S02/NO,, emissions; comply with system-wide annual 

PM/S02/NO,, emissions limits ; agree not to buy, sell or trade SO2/NO,, 

allowances allocated to Santee Cooper System as a result of said agreement; 

and to comply with emission unit limits of said agreement. 

TECO: Under a settlement agreement, by 2008, Tampa Electric in Florida will 

install permanent emissions-control equipment to meet stringent pollution 

limits ; implement a series of interim pollution reduction measures to reduce 

emissions while the permanent controls are designed and installed; and retire 

pollution emission allowances that Tampa Electric or others could use, or sell 

to others, to emit additional NO,, SOZ and PM. 

VEPCO: Virginia Electric and Power Co . agreed to spend $1 .2 billion 

between by 2013 to eliminate 237,000 tons of S02 and NO,, emissions each 

year from eight coal-fired electricity generating plants in Virginia and West 

Virginia. 

Gulf Power 7: A 2002 agreement calls for Gulf Power to upgrade its operation 

to cut NO,, emission rates by 61 percent at its Crist 7 generating plant by 2007 

with major reductions beginning in early 2005. The Crist plant is a significant 

source of nitrogen oxide emissions in the Pensacola Florida, area. 

12 .4 .2 Non-EGU Point Point Source Controls Expected by 2018 

For non-EGU sources within MANE-VU, Maine relied on MANE-VU's Version 3 .0 

Emission Inventory for 2002 . MACTEC conducted an analysis of various control 

measures as documented in "Development of Emission Projections for 2009, 2012, and 

2018 for Non-EGU, Area, and Nonroad sources in the MANE-VU Region" (Attachment 

I) . Control factors were applied to the 2018 MANE-VU inventory for non-EGUs to 

represent the following national, regional, or state control measures: 

. NOX SIP Call Phase I (NOX Budget Trading Program) (except ME, NH and 

VT) 

. NOX SIP Call Phase II (except ME, NH and VT ) 

" NOX RACT in 1-hour Ozone SIPs (already included in the 2002 inventory) 

" NOX OTC 2001 Model Rule for ICI Boilers 

. 2-, 4-, 7-, and 10-year MACT Standards 

" Combustion Turbine and RICE MACT (NO, co-benefits not includedassumed to be minimal) 

. Industrial Boiler/Process Heater MACT6s 

0 EPA's Refinery Enforcement Initiative (Fluid catalytic cracking units and 

fluid coking units; process heaters and boilers ; flare gas recovery; leak 

detection and repair; and benzene (wastewater)) 

bs The inventory was prepared before the MACT for Industrial Boilers and Process Heaters was vacated. 

Control efficiency was assumed to be at 4 percent for SOZ and 40 percent for PM. 

169 
In addition, states provided specific control measure information about specific non-EGU 

sources or regulatory programs in their state. For example, several states developed 

additional control measures in the course of their planning efforts to reduce ozone within 

the Ozone Transport Region (OTR). These control measures were included by MANEVU in their inventories used for regional haze modeling. (The affected states may or may 

not have committed to adopting these measures in their ozone SIPs). For specific states, 

the ozone reduction strategies included in the modeling would reduce NOX emissions 

from the following non-EGU point sources: 

" Asphalt production plants in Connecticut, New Jersey, New York, and the District 

of Columbia; 

Cement kilns in Maine, Maryland, New York, and Pennsylvania ; and 

" Glass and fiberglass furnaces in Maryland, Massachusetts, New Jersey, New York 

and Pennsylvania . 

For other regions, MANE-VU used emission inventory data developed by the RPOs for 

those regions, including VISTAS Base G2, MRPO's Base K, and CenRAP's emissions 

inventory . Non-EGU source controls incorporated into the modeling include the 

following consent agreements reflected in the VISTAS inventory: 

Dupont: A 2007 agreement calls for E. I. Dupont Nemours & Company's 

James River plant to install dual absorption pollution control equipment by 

September 1, 2009, resulting in emission reductions of approximately 1,000 

tons SOZ annually . The James River plant is a non-EGU located in the state of 

Virginia . 

Stone Container: A 2004 agreement calls for the West Point Paper Mill in 

Virginia owned by Smurfit/Stone Container to control with a wet scrubber the 

SOZ emissions of the #8 Power Boiler . This control device should result in 

reductions of over 3,500 tons of SOz in 2018. 

12.4.3 Area Source Controls Expected by 2018 

For area sources within MANE-VU, Maine utilized MANE-VU's Version 3 .0 Emissions 

Inventory for the 2002 base year. In general, MANE-VU developed the 2018 inventory 

for area sources by applying growth and control factors to the 2002 Version 3 .0 

inventory. Area source control factors were developed and incorporated in the modeling 

for the following national or regional control measures: 

" OTC VOC Model Rules (Consumer Products, Architectural and Industrial 

Maintenance Coatings, Portable Fuel Containers, Mobile Equipment Repair 

and Refinishing and Solvent Cleaning); 

" Residential Woodstove NSPS; and 

" State-specific control strategies implemented since 2002. 

170 
The following additional control measures were included in the 2018 analysis to reduce 

VOC and NO,, emissions for the following area source categories for some states (as 

identified below) : 

. VOC control measures for adhesives and sealants (controls added in all 

MANE-VU states except VT); 

" VOC control measures for emulsified and cutback asphalt paving (controls 

added in all MANE-VU states except ME, and VT) ; 

" VOC control measures for consumer products (controls added in all MANEVU states except VT); 

" VOC control measures for portable fuel containers (controls added in all 

MANE-VU states except VT); and; 

. NOX control measures for the combustion of natural gas, no. 2, 4 and 6 fuel 

oil, and coal (CT, NJ, NY). 

As noted above, inventory data for other regions were obtained from those Region's 

RPOs. Some of the area source control measures listed above may have been developed 

by states for the primary purpose of reducing ozone within the Ozone Transport Region 

(OTR)- see Subsection 12 .4 .2 for information on other measures included in state's ozone 

SIPS. 

12.4 .4 Mobile Sources Controls Expected by 2018 

For the on-road mobile source emission inventory, Maine relied on MANE-VU's version 

3 .0 emission inventory, which included the following post-2002 emission control 

measures: 

On-Board Refueling Vapor Recovery (OR VR) Rule: The 1990 Clean Air Act (CAA) 

Amendments contain provisions that require passenger cars to capture refueling 

emissions . In 1994, EPA published the ORVR rule establishing standards for refueling 

emissions controls for passenger cars and light trucks. The onboard controls were 

required to be phased in for all new car production by 2000 and for all light trucks by 

2006. The rule established a refueling emission standard of 0.20 grams per gallon of 

dispensed fuel, which was expected to yield a 95 percent reduction of VOC emissions 

over uncontrolled levels . The CAA authorizes EPA to allow state and local agencies to 

phase out Stage II programs, even in the worst nonattainment areas, once EPA has 

determined that onboard systems are in "widespread use". 

Heavy Duty Diesel (2007) Engine Emission Standards for Trucks and Buses: EPA set 

a PM emissions standard for new heavy-duty engines of 0.01 grams per brakehorsepower-hour (g/bhp-hr), to take full effect for diesel engines in the 2007 model year. 

This rule also includes standards for NO, and non-methane hydrocarbons (NMHC) of 

0.20 g/bhp-hr and 0.14 g/bhp-hr, respectively . These NO,, and NMHC standards will be 

171 
phased-in together between 2007 and 2010 for diesel engines. Sulfur in diesel fuel must 

be lowered to enable modern pollution-control technology to be effective on these trucks 

and buses. EPA began requiring the use of 500 ppm low sulfur diesel fuel in 1993. In 

2006, the highway diesel sulfur content was lowered to l5ppm (ultra low sulfur diesel) . 

Tier 2 Motor Vehicle Standards: Tier 2 is a fleet averaging program, modeled after the 

California LEV II standards . Manufacturers can produce vehicles with emissions ranging 

from relatively dirty to zero, but the mix of vehicles a manufacturer sells each year must 

have average NOX emissions below a specified value. Tier 2 standards became effective 

in the 2005 model year and are included in the assumptions used for calculating mobile 

source emissions inventories used for 2018. 

12.4 .5 Controls on Non-Road Sources Expected by 2018 

For non-road emission sources, Maine used Version 3 .0 of the MANE-VU 2002 

Emissions Inventory. Because the NONROAD Model used to develop the nonroad 

source emissions did not include aircraft, commercial marine, and locomotives, MANEVU's contractor, MACTEC, developed the inventory for these source categories. 

Nonroad mobile source emissions for the 2018 emission inventory were calculated with 

EPA's NONROAD2005 emissions model as incorporated in the NMIM2005 (National 

Mobile Inventory Model) database. The NONROAD model accounts for the emissions 

benefits associated with Federal non-road equipment emissions control measures such as 

the following : 

" "Control of Air Pollution; Determination of Significance for Nonroad Sources 

and Emissions Standards for New Nonroad Compression Ignition Engines At or 

Above 37 Kilowatts," 59 FR 31306, June 17, 1994. 

" "Control of Emissions of Air Pollution From Nonroad Diesel Engines," 63 FR 

56967, October 23, 1998. 

" "Control of Emissions From Nonroad Large Spark-Ignition Engines and 

Recreational Engines (Marine and Land-Based); Final Rule," 67 FR 68241, 

November 8, 2002 . 

" "Control of Emissions of Air Pollution From Nonroad Diesel Engines and Fuel; 

Final Rule," 69 FR 38958, June 29, 2004. 

As noted above, the inventory information used for other regions was obtained from 

those region's RPOs. 
12.5 Additional Reasonable Strategies 

As required under 40 CFR Section 51 .308(d)(3)(v), Maine and the other MANE-VU 

states applied a four-factor analysis to potential control measures for the purpose of 

establishing reasonable progress goals (See Subsection 11 .4 for a detailed description) . 

Reasonable measures include those that the affected states have already committed 

themselves to implementing, as described in Subsection 12.4, above. In addition, the 

MANE-VU states have identified other control measures that were found to be 

reasonable and were included in the modeling that was used to set reasonable progress 

goals. (These additional measures surpass the "beyond-on-the-way" emission controls 

and inventories) . All of the control measures- those embodied in the states' 

commitments to existing or planned programs and the additional reasonable control 

measures described below- comprise the long-term strategy for improving visibility at 

MANE-VU Class I Areas. 

Specifically, the MANE-VU long-term strategy includes the following additional 

measures to reduce pollutants that cause regional haze: 

Timely implementation of BART requirements ; 

" A low sulfur fuel oil strategy in the inner zone states (New Jersey, New York, 

Delaware, and Pennsylvania, or portions thereof) to reduce the sulfur content of: 

o Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 

2012, 

o #4 residual oil to 0 .25 percent sulfur by weight by no later than 2012, 

o #6 residual oil to 0 .3 - 0 .5 percent sulfur by weight by no later than 2012, 

and 

o Further reduce the sulfur content of distillate oil to 15 ppm by 2016; 

" A low sulfur fuel oil strategy in the outer zone states (the remainder of the 

MANE-VU region) to reduce the sulfur content of- 

* Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 

2014, 

o #4 residual oil to 0.25 percent-0 .50 percent sulfur by weight by no later 

than 2018, 

o #6 residual oil to no greater than 0.5 percent sulfur by weight by no later 

than 2018, and 

o Further reduce the sulfur content of distillate oil to 15 ppm by 2018 

depending on supply and availability ; 

" A 90 percent or greater reduction in sulfur dioxide (SOZ) emissions from each of 

the electric generating unit (EGU) stacks identified by MANE-VU (Attachment 

W) comprising a total of 167 stacks, dated June 20, 2007) as reasonably 

anticipated to cause or contribute to impairment of visibility in each mandatory 

Class I Federal area in the MANE-VU region . If it is infeasible to achieve that 

173 
level of reduction from a unit, alternative measures will be pursued in such State; 

and 

" Continued evaluation of other control measures including energy efficiency, 

alternative clean fuels, and other measures to reduce SOZ and nitrogen oxide 

(NOX) emissions from all coal-burning facilities by 2018 and new source 

performance standards for wood combustion. 

This suite of additional control measures are those that the MANE-VU states have agreed 

to pursue for the purpose of mitigating regional haze . The corollary is that the MANEVU Class I states (Maine, New Hampshire, Vermont, and New Jersey) are asking states 

outside the MANE-VU region that contribute to visibility impairment inside the region to 

pursue similar measures. The control measures that non-MANE-VU states choose to 

pursue may be directed toward the same emission source sectors identified by MANEVU for its own emission reductions, or they may be equivalent measures targeting other 

source sectors. Under the MANE-VU long-term strategy, states will be allowed until 

2018 to pursue adoption and implementation of proposed control measures. 

12.5 .1 BART 

Implementation of the BART provisions of the Regional Haze Rule (40 CFR 51 .308(e)) 

is one of the reasonable strategies included in this SIP66. BART controls in Maine are 

identified in Section 10 of this SIP. 

To assess the benefits of implementing the BART provisions of the Regional Haze Rule 

for non-EGU facilities, NESCAUM included estimated reductions anticipated for BARTeligible facilities in the MANE-VU region in the final 2018 CMAQ modeling analysis, as 

described previously in Subsection 11 .5 of this SIP. The modeling assumed that 12 units 

at seven BART-eligible sources in MANE-VU would be controlled as a result of BART 

requirements alone. (see Table 12.1) 

Note that additional emission reductions will occur at many other BART-eligible 

facilities within MANE-VU as a result of controls achieved by either programs that serve 

as BART but are not specifically identified as such (e.g ., RACT). While not specifically 

identified as being attributable to BART, these additional emission reductions were 

accounted for in the 2018 CMAQ modeling. 

Additional visibility benefits are likely to result from the installation of new emissions 

controls at BART-eligible facilities that are located in neighboring RPOs. However, the 

MANE-VU modeling did not account for BART controls in other RPOs, and 

consequently, did not include the visibility improvements at MANE-VU Class I Areas 

that would likely result from such measures. 

12.5 .2 Low-Sulfur Oil Strategy 

66 For EGU's , EPA determined that CAIR would fulfill the BART requirement for this sector . 

174 
The important assumption underlying MANE-VU's low-sulfur fuel oil strategy is based 

on the production and use of home heating and fuel oils that contain 50% less sulfur for 

the heavier grades (#4 and #6 residual), and a minimum of 75% and maximum of 99.25% 

less sulfur in #2 fuel oil (also known as home heating oil, distillate, or diesel fuel) at an 

acceptably small increase in price to the end user. As much as three-fourths of the total 

sulfur reductions achieved by this strategy come from using the low-sulfur #2 distillate 

for space heating in the residential and commercial sectors. The costs of these emission 

reductions are estimated at $550 to $750 per ton, as documented in the MANE-VU 

Reasonable Progress Report . While the costs of the low-sulfur fuel oil strategy vary 

depending on market conditions, they appear to be reasonable when measured against the 

costs of controlling other sectors. 

Maine has already adopted a low sulfur fuel strategy. The 124th Second Regular Session 

of the Maine Legislature (2010) adopted LD 1662, "An Act To Improve Maine's Air 

Quality and Reduce Regional Haze at Acadia National Park and Other Federally 

Designated Class I Areas," which implements the MANE-VU low sulfur fuel strategy in 

Maine. This legislation establishes a statewide sulfur limit for distillate fuels of 50 ppm 

in 2016, and 15 ppm in 2018. For residual (#6) fuel oil, the statewide sulfur limit will be 

reduced to 0.5% in 2018. The legislation also directs the Department to undertake 

rulemaking (to be completed by 2014) to adopt rules that provide an opportunity for a 

licensed air contamination source that holds a license on the effective date of the statute 

to apply for an equivalent alternative sulfur reduction strategy to the residual fuel oil and 

distillate fuel requirements. The rules must provide for the achievement of equivalent 

sulfur emission reductions through other means, including, but not limited to, reductions 

in consumption of residual fuel oil and distillate fuel, early sulfur emission reductions 

from a baseline emissions inventory year of 2002, and conversions. LD 1662, as adopted 

by the Maine Legislature and signed by Governor Baldacci on April 5, 2010, is attached 

in Attachment Z. 

12.5 .3 Targeted EGU Strategy 

MANE-VU has identified emissions from the top 167 EGU emission points that 

contribute most to visibility impairment at MANE-VU Class I Areas (see Figure 12-1) . 

Controlling emissions from these contributing facilities is crucial to mitigating haze 

pollution in wilderness areas and national parks of the northeast states . 

MANE-VU's agreed regional approach for the EGU source sector is to pursue a 90 

percent control level on SOZ emissions from the 167 identified stacks by 2018. MANEVU has concluded that pursuing this level of sulfur reduction is both reasonable and costeffective . Even though current wet scrubber technology can achieve sulfur reductions 

greater than 95 percent, and overall 90-percent sulfur reduction level would include the 

effects of lower average reduction rates from dry scrubbing technology, consistent with 

historic experience. The Costs of S02 reductions will vary by unit. The MANE-VU 

Reasonable Progress Report (Attachment T) summarizes the various control methods and 

costs, which range from $170 to $5,700 per ton, depending on site-specific factors such 

as the size and type of unit, combustion technology, and type of fuel used. Maine has one 

EGU identified in the MANE-VU analysis, Wyman Station Unit #4, which is located in 

175 
located in Yarmouth, Maine. As a signatory to the MANE-VU statement of principles 

(Attachment D), Maine is committed to pursue additional emission reductions at this 

facility through its low sulfur fuel oil program. Maine DEP believes that the use of lowsulfur fuel at this facility (in lieu of add-on controls) will provide the most cost-effective 

sulfur reductions, and that additional controls at this unit should be subsumed under the 

low-sulfur fuel strategy. For more detail on Maine's implementation of the Targeted 

EGU Strategy, see Section 12.9, below. 

Several states have implemented state-specific EGU emission reduction programs. These 

commitments, identified below, are included in the long-term strategy as reasonable 

measures to meet MANE-VU's reasonable progress goals. 

Maryland Healthy Air Act: Maryland adopted the following requirements governing 

EGUs: 

" For NO,: 

Phase 1 (2009) sets unit specific annual caps (totaling 20,216 tons) and 

ozone season caps (totaling 8,900 tons). 

Phase II (2012) sets unit specific annual caps (totaling 16,667 tons) and 

ozone season caps (totaling 7,337 tons). 

For SO2 : 

- Phase 1(2010) sets unit specific annual caps (totaling 48,818 tons). 

- Phase II (2013) sets unit specific annual caps (totaling 37,235 tons). 

" For mercury : 

Phase 1 (2010) requires a 12-month rolling average of a minimum of 80% 

removal efficiency. 

Phase 11 (2013) requires a: 12-month rolling average of a minimum of 

90% removal efficiency. 

The specific EGUs included are: Brandon Shores (Units 1 and 2), C.P.Crane (Units 1 and 

2), Chalk Point (Units 1, and 2), Dickerson (Units 1, 2, and 3), H.A. Wagner (Units 2 and 

3) Morgantown (Units 1 and 2) and R. Paul Smith (Units 3 and 4). No out-of-state 

trading of emission allowances, no inter-company trading and no banking from year-toyear were included in this analysis 
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Figure 12-1 

167 EGU Stacks Affecting MANE-VU Class I area(s) 

Massachusetts EGURegulations: Based on the Massachusetts Department of 

Environmental Protection's 310 CMR 7.29, Emissions Standards for Power Plants, 

adopted in 2001, six of the largest fossil fuel-fired power plants in Massachusetts must 

comply with emissions limitations . For mercury (Hg), 6 facilities must comply with: 

85% Hg reduction or 0.0075 lbs Hg/GWh in 2008 and 90% Hg reduction or 0.0025 Ibs 

Hg/GWh in 2012. The specific EGUs included are: Brayton Point (Units 1, 2, 3, 4, IC 1, 

IC2, IC3, and IC4), Mystic (Units 4, 5, 6, 7, 307, 308, 309 and 310), NRG Somerset 

(Units 8, J1, and J2), Mount Tom (Unit 1), Canal (Units 1 and 2), and Salem Harbor 

(Units 1, 2, 3 and 4). 

New Hampshire EGULaws and Regulations : New Hampshire amended the following 

laws and regulations governing EGU emissions: 

" RSA 125-0 requires the installation of scrubbers on Merrimack Station (Units 1 

and 2) by July 1, 2013 to control S02 and mercury emissions. This law allows 

State-level SOZ credits for over- or early- compliance. 

178 
" Env-A 2900 sets limits for NO, S02, and COZ emissions by December 31, 2006 for 

all existing fossil EGUs. 

New Jersey Hg MA CT Rule: Under this rule, all coal-fired EGUs will have a mercury 

removal efficiency of 90%. (Some SOZ reductions may occur as a result of this mercury 

rule .) 

Consent Agreements in the VISTAS Region: The following consent agreements in the 

VISTAS states were reflected in the emissions inventories used for those states : 

East Kentucky Power Cooperative: A July 2, 2007 consent agreement between 

the EPA and East Kentucky Power Cooperative requires the utility to reduce its 

emissions of SOz by 54,000 tons per year and its emissions of NO,, by 8,000 tons 

per year, by installing and operating selective catalytic reduction (SCR) 

technology; low-NO,, burners, and PM and mercury Continuous Emissions 

Monitors at the utility's Spurlock, Dale and Cooper Plants. According to the 

EPA, total emissions from the plants will decrease between 50 and 75 percent 

from 2005 levels . As with all federal consent decrees, EKPC is precluded from 

using reductions required under other programs, such as CAIR, to meet the 

reduction requirements of the consent decree. EKPC is expected to spend $654 

million to install pollution controls . 

American Electric Power: Under this agreement, American Electric Power will 

spend $4 .6 billion dollars for emission controls at sixteen plants located in 

Indiana, Kentucky, Ohio, Virginia and West Virginia. These control measures 

will eliminate 72,000 tons of NO, emissions each year by 2016 and 174,000 tons 

of S02 emissions each year by 2018 . 

12.6 Source Retirement and Replacement Schedules 

40 CFR Section 51 .308(d)(3)(v)(D) requires Maine to consider source retirement and 

replacement schedules in developing reasonable progress goals. Source retirement and 

replacement were considered in developing the 2018 emission inventory described 

previously in Subsection 11 .2, Reasonable Progress Goals for Class I Areas in Maine. 

See also Table b-5 in the Emission Projections Report (Attachment N). 

12.7 Additional Measures Considered 

12 .7 .1 Measures to Mitigate the Impacts of Construction Activities 

40 CFR Section 51 .308(d)(3)(v)(B) requires Maine to consider measures to mitigate the 

impacts of construction activities on regional haze. MANE-VU's consideration of 

measures to mitigate the impacts of construction activities is documented in "Technical 

Support Document on Measures to Mitigate the Visibility Impacts of Construction 

Activities in the MANE-VU Region," Draft, October 20, 2006, MARAMA (Attachment 

X). 

179 
The construction industry is already subject to requirements for controlling pollutants that 

contribute to visibility impairment . For example, EPA's off-road engine standards and 

low sulfur fuel requirements result in reductions of PM and precursor emissions (S02 and 

NOX) from construction vehicles. 

At the state level, Maine currently regulates emissions of fugitive dust through its 06-096 

CMR Chapter 101, Visible Emissions rules, which establishes opacity limits for 

emissions from several categories of air contaminant sources, including fugitive 

emissions from construction activities . Maine also regulates emissions from both on-road 

vehicles and construction activities through its 06-096 CMR Chapter 127 New Motor 

Vehicle Emission Standards rules (new motor vehicle emission standards), the 06-096 

CMR Chapter 147 Diesel-Powered Motor Vehicle Emission Standards rules (opacity 

standards), and the 06-096 CMR General Permit Regulations for Nonmetallic Mineral 

Processing Plants rules. Non-road vehicles are subject to federal regulations. 

MANE-VU's Contribution Assessment (Attachment B) found that, from a regional haze 

perspective, crustal material generally does not play a major role at MANE-VU Class I 

Areas. On the 20 percent best visibility days during the 2000-2004 baseline period, 

crustal material accounted for 6 to 11 percent of the particle-related light extinction at 

MANE-VU Class I Areas. On the 20 percent worst visibility days, however, the ratio 

was reduced to between 2 and 3 percent. Furthermore, the crustal fraction is largely 

made up of pollutants of natural origin (e .g ., soil or sea salt) that are not targeted under 

the Regional Haze Rule. Nevertheless, the crustal fraction at any given location can be 

heavily influenced by the proximity of construction activities ; and construction activities 

occurring in the immediate vicinity of MANE-VU Class I Areas could have a noticeable 

effect on visibility. The need for additional control measures for construction activities 

and their possible implementation will be evaluated in the first regional haze progress 

report . 

12.7 .2 Agricultural and Forestry Smoke Mana gement 

40 CFR Section 51 .308(d)(3)(v)(E) requires Maine to consider smoke management 

techniques related to agricultural and forestry management in developing its long-term 

strategy . MANE-VU's analysis of smoke management in the context of regional haze 

SIPs is documented in "Technical Support Document on Agricultural and Forestry 

Smoke Management in the MANE-VU Region," September l, 2006, MARAMA 

(Attachment Y). 

As noted in this report, fires used for resource management are of far less significance to 

the total inventory of fine-particle pollutant emissions than other sources of wood smoke 

in the region . The largest wood smoke source categories, with respect to PM2.5 

emissions, are residential wood combustion (73 percent); open burning (15 percent); and 

industrial, commercial and institutional wood combustion (9 percent). Unwanted fires 

involving buildings and wild lands make up only a minor fraction of wood burning 

emissions and cannot be reasonably addressed in this SIP. Fires that are covered under 

180 
smoke management plans, including agricultural and prescribed forest burning, constitute 

less than one percent of total wood smoke emissions in MANE-VU6'. 

Moreover, smoke emissions from all sources represent only a minor fraction of fineparticle mass that is the cause of regional haze. MANE-VU's Contribution Assessment 

(Attachment A) found that elemental carbon, the main ingredient of smoke, contributed 

only 3 to 4 percent of fine particle mass on days of worst and best visibility . 

Additionally, elemental carbon absorbs light more readily than it scatters light. It is 

therefore reasonable to conclude that smoke emissions from controlled agricultural and 

forestry burning contribute, on average, only a small fraction of one percent of total light 

extinction on days of both good and poor visibility . Maine has no information to indicate 

that this situation would change significantly over the next decade . 

12 .7 .3 Control of Residential and Commercial Wood Combustion Emissions 

As noted in Section 8, residential wood combustion is responsible for 25 percent of 

primary fine particulate emissions in the MANE-VU region, and is a significant 

contributor to regional haze. Maine has adopted regulations to address emissions from 

outdoor wood and pellet boilers, an outdoor wood boiler replacement and buy-back 

program, and a woodstove replacement buy-back program. 

The Chapter 150 Control of Emissions from Outdoor Wood Boilers Rule 

In June 2007, the Maine Legislature adopted the EPA Phase I particulate emission limit 

of 0.601bs/MMBtu/hr heat input as the standard for new outdoor wood-fired hydronic 

heaters (OWHH), also known as outdoor wood boilers, sold in Maine beginning April 1, 

2008 . Beginning April 1, 2010 new OWHH sold in Maine are required to meet a more 

stringent particulate emission standard of 0.32 lbs/MMBTU heat output (Phase II) . 

06-096 CMR Chapter 150 Control of Emissions from Outdoor Wood Boilers, which 

incorporated the OWHH particulate emission standards adopted by the Legislature, 

became effective November 1, 2007, and also established setback, stack height, 

particulate emission limits, and fuel requirements for outdoor wood boilers (See 

Attachment BB). Chapter 150 was subsequently amended 61 to control the sale, 

installation, use, and siting of outdoor wood boilers that combust biomass pellets as fuel . 

Maine is submitting this rule to EPA for incorporation into the Regional Haze SIP. 

The Chapter 160, Outdoor Wood Boiler Replacement and Buy Back Program: 

In April 2008, the Maine Legislature also enacted Public Law, Chapter 680, An Act 

Establishing an Outdoor Wood Boiler Fund. This Public Law established a nonlapsing 

fund administered by commissioner to be used by the Department to upgrade, purchase 

and replace outdoor wood boilers that create a nuisance condition as defined in the 

6' For example, PM2.5 and PM 10 emissions from agricultural burning and forestry management activities 

account for only 0.139% and 0.157% of total wood smoke emissions (Source: 2002 MANE-VU Modeling 

Inventory Version 3 .0). 

181 
Department's rules or threat to public health or safety, and directed the Department to 

develop a rule that includes, but not limited to, criteria for determining whether an 

outdoor wood boiler constitutes a nuisance condition or threat to public health or safety 

and is eligible for use of the fund, compensation criteria and amounts and procedures for 

certification and verification of removal and possible replacement of eligible outdoor 

wood boilers. 

Pursuant to this legislation, the Department adopted the 06-096 CMR Chapter 160, 

Outdoor Wood Boiler Replacement and Buy Back Program rules, which establish a 

replacement and buy back program to remove nuisance outdoor wood boilers that were 

installed prior to February 1, 2008 and replace them with approved heating appliances. 

The Department will maintain a list of nuisance outdoor wood boilers and prioritize them 

for the program based on the threat to public health and safety and proximity to neighbors 

and sensitive populations. To receive compensation, the owner of the outdoor wood 

boiler must have explored all possible remedies, including increasing the stack height and 

setback distances to neighbors and potential retrofits to eliminate the nuisance conditions . 

Compensation may include the cost of installation and disposal and shall not exceed 

$15,000. 

The Residential Wood Stove Replacement Fund 

On April 8, 2010, the Maine Legislature enacted 38 MRSA §610-D, which established a 

residential woodstove replacement program in the Maine Department of Environmental 

Protection . Under this program, eligible participants will be able to receive funding 

toward the purchase of new cleaner-burning residential heating appliances to replace 

older wood stoves that are not certified by the EPA lower emitting residential heating 

appliances, such as EPA certified wood, pellet or vented gas stoves . The Department 

will be establishing eligibility criteria for program participation, benefits, and approved 

methods for replacement and disposal of non-certified wood stoves . 

12.8 Estimated Effects of the Long-Term Strategy on Visibility 

40 CFR 51 .308(d)(3)(v)(G) requires Maine to consider, in developing its long-term 

strategy, the anticipated net effect on visibility due to projected changes in point, area and 

mobile source emissions over the period addressed by the long-term strategy. 

NESCAUM conducted modeling to evaluate the expected improvements to visibility at 

affected Class I Areas by 2018 as a consequence of implementing MANE-VU's longterm strategy . Those visibility improvements will result, in part, from the efforts 

identified in this SIP to reduce emissions that originate in Maine. 

All Class I states affected by emissions originating in Maine have (or will have) 

established reasonable progress goals for 2018 for each of their Class I Areas. The 

control measures included in this SIP represent the reasonable efforts of Maine, in 

conjunction with the efforts of other MANE-VU states, toward achieving the reasonable 

progress goals established by the affected states . 

182 
Based on the most recent MANE-VU modeling, the proposed control measures will 

reduce sulfate levels at affected Class I Areas by about one-third on the worst visibility 

days and by 6 to 31 percent on the best visibility days by 2018. Nitrate and elemental 

carbon levels will also show substantial reductions across all areas for both bets and 

worst days, while smaller reductions in organic carbon will occur. Small increases are 

predicted for the fine soil component of regional haze. There is the possibility that the 

predicted increases in this component are not real but, rather, related to structural 

differences in the data sets used in the modeling for the baseline and future years 69- No 

changes were predicted for sea salt because the model does not track this component. 

The 2000-2004 visibility readings at affected Class I areas provide the baseline against 

which future visibility readings will be measured to assess progress deriving from 

implementation of Maine's Regional Haze SIP and those of the other MANE-VU states . 

To determine baseline visibility for affected Class I areas, the 2000-2004 IMPROVE 

monitoring data was used to calculate the average deciview values for the 20 percent best 

visibility days and the 20 percent worst visibility days over that period. Thus, the 20 

percent best day and 20 percent worst day values represent average visibility conditions 

for the top and bottom quintiles . 

To create the series of visibility graphs which follow, 2018 visibility estimates were made 

in accordance with EPA modeling guidance. First, 2002 daily average baseline 

concentrations were multiplied by their corresponding relative reduction factors to obtain 

2018 projected concentrations for each day. The 2018 projected concentrations were 

then used to derive daily visibility in deciviews. As a final step, the deciview values for 

the 20 percent of days having best visibility were averaged, and the process repeated for 

the 20 percent of days having worst visibility. The resulting averages represent the 

projected upper and lower quintiles of visibility in 2018. 

The following is provided to assist with interpretation of the line graphs in Figures 12 .2 

through 12.7 . Note that lower deciview values indicate better visibility . 

" The irregular blue line (^') represents the 20 percent best visibility average value 

as determined from monitoring data for each year of the period 2001-2005 . 

The irregular red line (^') represents the 20 percent worst visibility average value 

as determined from monitoring data for each year of the period 2001-2005 . 

" The straight orange line (-) represents the 20 percent best visibility average value 

as determined from monitoring data for the 5-year period of 2000-2004. (This 

line represents the 20 percent best visibility baseline condition.) 

" The straight blue line (-) represents the 20 percent worst visibility average value 

as determined from monitoring data for the 5-year period of 2000-2004 . (This 

line represents the 20 percent worst visibility baseline condition.) 

69 Specifically, the fire emissions inventory used in VISTAS for the base year relied on an earlier version of 

fire emissions data than the one used for the 2018 inventory. 

183 
" The straight broken line ( . . . . ) is a continuation of the 20 percent best visibility 

baseline, representing the 20 percent best visibility condition as it would be with 

no further degradation or improvement. 

The straight green line (-) represents the 20 percent worst visibility values that 

establish the uniform rate of progress for the period 2004-2064. (This line is 

sometimes referred to as the uniform progress line, or "glide slope. " It was 

created by linear interpolation between the 20 percent worst visibility baseline 

value in 2004 and the 20 percent worst visibility value under natural conditions in 

2064. If visibility improvements match this rate of progress, actual visibility will 

return to natural conditions in 2064). 

" The light-green dash ( ) shown at 2064 represents the theoretical 20 percent best 

visibility value under natural conditions (i .e ., no anthropogenic emissions). 

" The purple star (*) represents the 20 percent best visibility value in 2018 after 

implementation of MANE-VU's long-term strategy, as predicted by the CMAQ 

model. (This value is a reasonable progress goal.) 

" The blue star (*) represents the 20 percent worst visibility value in 2018 after 

implementation of MANE-VU's long-term strategy, as predicted by the CMAQ 

model . (This value is a reasonable progress goal.) 

Figures 12-2 through 12-4 are line graphs showing anticipated visibility improvements 

for the MANE-VU Class I Areas affected by emissions originating in Maine. Figures 12-

2 and 12-3 illustrate the predicted visibility improvement at Acadia National Park and 

Moosehorn National Wildlife Refuge/Roosevelt Campobello International Park by 2018 

resulting from the implementation of the long-term strategy (See the blue cross mark). 

This improvement is compared to the Uniform Rate of Progress for affected Class I areas 

(see green sloping line) . Note that the blue cross mark is below the green line as it passes 

over the 2018 date marked at the bottom of the chart. This indicates that the control 

measures identified in this SIP provide visibility improvements exceeding the uniform 

rate of progress for reaching natural visibility in 2064. The lower number of deciviews 

means better visibility .) Figure 12-4 demonstrates that Great Gulf Wilderness Class I 

area in New Hampshire, which is significantly affected by Maine emissions, is also 

projected to meet or exceed the uniform rate of progress goal for 2018. All Class I areas 

affected by Maine emissions are also projected to have no degradation from current 

baseline best visibility . 

12.9 Implementation of the Regional Haze Strategies in Maine 

40 CFR Section 51 .308(d)(3)(ii) of the Regional Haze Rule requires Maine to 

demonstrate that its implementation plan includes all measures necessary to obtain the 

emission reductions needed to meet the reasonable progress goals. The modeling 

analysis referenced in Subsection 12.8 (Figures 12-2 through 12-4) above, which 

demonstrates that Maine's long-term strategy is sufficient to meet reasonable progress 

184 
goals, is predicated on Maine (and other MANE-VU) states reducing their SOZ emissions 

as a result of a number of emission control programs. 

Figure 12-2 

Projected Visibility Improvement at Acadia National Park Based On 2018 Best and 

Final Projections 

-'+'-20% Worst Observed 

---20% Best Observed 

-20% Worst Basellne 

-20% Best Bas efine 

-Uniform P rogress 

- - -NoDegradation 

X C MAO 20% Worst 

x CMQQ 20% Best 

20% Best'Natural 

N N N N N N N N N N N N N N 

((D~ f~Dp O Op O O O~7 OOO~ Op Op OOO p~O p~

O U S 01 O U O U O VI O [T O OI O U 

Year 

Figure 12-3 

Projected Improvement in Visibility at Moosehorn National Wildlife Refuge and 

Roosevelt Campobello International Park based on 2018 Best and Final Projections 

~-20% Worst Observed 

~-20% Best Observed 

25 -20% WOrstBaseine 

-20% Best Baeline 

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Figure 12-4 

Projected Visibility Improvement at Great Gulf Wilderness 

Based on Most Recent Projections for 2018 

~-20% Worst Observed 

-~20% Best Observed 

~2D% Worst Baseline 

-20% Best Baseline 

- U rifo rm Progress 

25 - - No Degradation 

x CMAO20%Worst 

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z0 - 23% Best'Natural 

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As previously noted, Maine has adopted, and will implement, the following measures as 

part of its long-term strategy to meet the reasonable progress goals: 

l . A low sulfur fuel oil strategy in accordance with the MANE-VU statement providing 

SOZ reductions for Wyman Station, ICI boilers, and residential heating units ; 

2. Timely implementation of BART requirements at Maine sources subject to BART; 

3. A program to reduce S02 emissions at the Wyman Station #4 boiler by at least 84 

percent from uncontrolled levels ; and 

4. A comprehensive program to reduce wood smoke emissions from outdoor wood 

and pellet boilers, woodstoves and other wood-burning devices. 

12.9 .1 The Maine Low Sulfur Oil Program 

The Maine Low Sulfur Oil Program, as established in statute at 38 M.R.S .A. §603-A, 

sub-§2, (See Attachment Z), instituted the following restrictions on fuel sulfur content for 

residual (#4, #5, and #6) and distillate oil: 

(1) Beginning January 1, 2018; a person may not use residual oil with a sulfur content 

greater than 0.5% by weight; 

(2) Beginning January 1, 2016, a person may not use distillate oil with a sulfur 

content greater than 0.005 % by weight; and 

(3) Beginning January 1, 2018, a person may not use distillate oil with a sulfur 

content greater than 0.0015 % by weight . 

186 
In addition to the low sulfur requirements for distillate and residual oil, the program 

contains two elements not included in the MANE-VU Low Sulfur Oil Strategy. These 

elements include: 

1) An exemption from the low sulfur content limits for sources using distillate fuel 

for manufacturing purposes; and 

2) Equivalent alternative sulfur reduction application . The Department of 

Environmental Protection is required to adopt major substantive rules7° that 

provide an opportunity for a licensed air contamination source that holds a license 

on the effective date of this subsection to apply for an equivalent alternative sulfur 

reduction strategy to the residual fuel oil and distillate fuel requirements. The 

rules must provide for the achievement of equivalent sulfur emission reductions 

through other means, including, but not limited to, reductions in consumption of 

residual fuel oil and distillate fuel, early sulfur emission reductions from a 

baseline emissions inventory year of 2002 and conversions to alternative fuels. 

Approved alternate sulfur reduction strategies must be in effect by January 1, 

2018 . 

The Distillate Fuel Exemption 

The Department does not believe that the low sulfur content limit exemption for 

manufacturing purposes will have a significant impact on the emission reductions 

afforded by this strategy for 2018 and beyond. While the exemption allows the continued 

use of high-sulfur 7 l distillate oil at several manufacturing facilities, there are structural 

impediments to the actual use of these fuels. First, since there is only a limited potential 

market for high-sulfur distillate 72 the Department believes that this fuel will not be 

readily available, and will likely be more expensive than the more widely-used 15 ppm 

distillate . Distributors and wholesalers of distillate fuels have noted that supplying highsulfur distillate to a limited market introduces additional costs to their industry in the 

form of segregated storage and transportation/delivery systems, since even incidental 

contamination (co-mingling) can lead to non-compliance issues .73 

Recognizing the potential for incidental contamination of ULSD, segregated storage and 

transportation/delivery systems are probably the only mechanisms that can assure 

compliance with federal and state ULSD requirements for the petroleum marketing 

industry. Given the low demand, and additional storage, transportation and delivery 

costs, the Department does not believe that high sulfur distillate fuel will be widely used 

by the manufacturing sector in 2018 and later. 

74 

'° Rules must be adopted and submitted to the Maine Legislature for approval by January 1, 2014. 

'1 Containing 2,000-5,000 ppm sulfur. 

72 All other users of distillate (diesel) fuel in Maine will be subject to the 15 ppm sulfur limits (including 

eneral use and space heating at manufacturing facilities) . 

,3 For example, only 7 gallons of a 5,000 ppm sulfur fuel added to 7,500 gallons of ULSD would raise the 

sulfur content by 5.0 ppm. 

74 As noted above, Maine believes that future (2018) use of distillate fuel by the manufacturing sector will 

be limited due to cost and compliance concerns . Nevertheless, projected 2018 SOZ emissions for Maine 

have been adjusted to address this exemption, and its impact on non-EGU point source emissions, as 

discussed in Section 12 .10, below. 

187 
The Equivalent Alternative Sulfur Reduction Application 

Under this provision of the Maine low sulfur oil program, the Department of 

Environmental Protection is required to adopt rules providing an opportunity for a 

licensed source that holds an air emission license to apply for an equivalent alternative 

sulfur reduction strategy to the residual fuel oil and distillate fuel requirements . Since 

these rules will require sulfur emission reductions that are equivalent to the use of 0.5% 

sulfur residual or 0.0015% sulfur distillate fuel, there will be no net change to the 

predicted SOZ emission reductions provided by this strategy . The Department will be 

working with EPA to develop these rules, and will submit them for inclusion into the SIP. 

12.9 .2 BART in Maine 

As required by 40 CFR §51 .308(e), the Maine Regional Haze SIP includes emission 

limitations representing Best Available Retrofit Technology (BART) and schedules for 

compliance with BART for each BART-eligible source that may reasonably be 

anticipated to cause or contribute to any impairment of visibility in any mandatory Class I 

Federal area. Maine's implementation of the BART requirements is fully discussed in 

Section 10. 

12 .9 .3 The Targeted EGU Strategy in Maine 

As noted in section 12.5 .3, above, MANE-VU's agreed regional approach for the EGU 

source sector is to pursue a 90 percent control level on S02 emissions from the 167 

identified stacks by 2018 . Maine has one EGU identified in the MANE-VU analysis ; 

FPL Energy (FPLE) Wyman Station Unit #4 . 

FPLE Wyman Station is an 850-megawatt electric generating facility located on Cousins 

Island in Yarmouth, Maine. The facility consists of four generation units, all of which 

fire #6 residual fuel oil. The fifth unit is a smaller oil-fired auxiliary boiler which 

provides building heat and auxiliary steam, and the sixth unit is an emergency backup 

diesel generator that provides electricity for use on-site. 

Unit #4 is powered by a Foster Wheeler boiler with a maximum design heat 

input of 6290 MMBtu/hr, firing #6 and #2 fuel oil. This unit is equipped with 30 

front wall fired burners capable of firing up to 41,333 gal/hr . Boiler #4 was 

manufactured in 1974 and installed in 1975, and therefore is subject to the New 

Source Performance Standards (NSPS) Subpart D, but not Subpart Da. Unit #4 is a 

peaking unit, and operated at an average annual capacity factor of less than 10 percent 

between 2002 and 200975, with annual S02 emissions of 1,170 tpy in 2002. 

Although flue gas desulfurization (FGD) through the use of a wet, semi-dry or dry 

scrubber is technically feasible, this technology is cost prohibitive due to the lowcapacity factor of this unit and site-specific restrictions . In lieu of requiring add-on 

controls, Maine will be utilizing its low-sulfur fuels program to implement the MANE- 

'5 For comparison, the nationwide capacity factor for coal-fired generation in 2008 was 72.2 percent. 

188 
VU Targeting EGU Strategy at this unit. The Maine Low Sulfur Fuel Program will 

require the use of low-sulfur fuel containing no more than 0.5% sulfur beginning January 

1, 2018, providing an 84 percent reduction from baseline (3 .0% sulfur) fuel. 

Maine is also committing to further analyze the visibility benefits that would be provided 

by the use of 0.3% sulfur fuel, and to require the use of this fuel (or an equivalent 

emissions rate) no later than January 1, 2018, if necessary to meet the reasonable progress 

goals at Class I areas in Maine or any other Class I area significantly affected by Maine 

emissions. Maine is committing to undertake this analysis no later than January 1, 2013 

as part of its 5-year periodic implementation plan revision . 

12.9 .4 Wood Smoke Emission Reductions Stratevi es in Maine 

Strategies to reduce wood smoke emissions in Maine will also provide significant 

reductions in regional haze. As detailed in Section 12.7.3, Maine has adopted a 

comprehensive suite of programs designed to reduce wood smoke emissions from 

outdoor wood and pellet boilers and residential wood stoves. Since the visibility 

improvements provided by these programs were not modeled as part of the MANE-VU 

process, Maine has included these programs in its Regional Haze SIP as SIP 

enhancements, or strengthening measures. The 06-096 CMR Chapter 150 Control of 

Emissions from Outdoor Wood Boilers (Attachment BB), is included for incorporation in 

the Maine Regional Haze SIP. 

12.10 Maine's Share of Emission Reductions 

Implementation of the long-term strategy will produce significant reductions in Maine's 

emissions inventory by the end of the first planning period, or 2018. Changes to the 

emissions inventory will also occur as a result of population growth ; changes in land use 

and transportation ; development of industrial, energy, and natural resources; and other air 

pollution measures not directly relate to regional haze. However, it is the expected 

reductions in SOZ emissions that will have the greatest effect on visibility improvement at 

MANE-VU Class I Areas; and those reductions will be largely due to the implementation 

of the control measures developed in this SIP. 

As noted in Subsection 12 .9 (above) the emission controls included in the Maine 

Regional Haze SIP are generally consistent with those modeled in MANE-VU's 

development of reasonable progress goals for Maine and the other MANE-VU Class 1 

states (see Section 11 .2, above). However, since the Maine Low Sulfur Oil Program and 

efforts to reduce emissions at Wyman Station Unit #4 differ slightly from the programs 

and emission reductions modeled as reasonable progress goals, Maine must demonstrate 

that its long-term strategy will achieve the reasonable progress goals established by the 

Regional Haze SIP. 

In an effort to demonstrate that the long-term strategy established by this SIP will achieve 

the modeled reasonable progress goals, Maine undertook a more refined analysis of its 

projected 2018 SOZ emissions that is based on the 2008 Maine DEP Point Source 

189 
Inventory.7b 77The Maine analysis updated projected S02 emissions for point sources 

that included only the reductions provided by the use of 0 .5% sulfur residual oil as 

implemented by the Maine Low Sulfur Fuel Program. 

78 While this approach is 

necessarily very conservative, and does not capture all of the reductions provided by the 

use of low sulfur residual and ultra-low sulfur distillate fuel in Maine, it is more than 

sufficient to demonstrate that projected future emissions in Maine will be well below the 

level used to establish reasonable progress goals. The documentation for this effort and 

the updated Maine 2018 Projected Point Source Inventory are contained in Attachment 

AA. 

After accounting for all facilities that ceased operation and/or surrendered their air 

emission licenses between 2001 and 2009 (25 sources) and accounting for the reductions 

provided by the use of 0.5% residual fuel, Maine's updated 2018 projected point source 

emissions were 8,445 tpy for all point sources (EGU and non-EGU combined); well 

below the 19,888 tpy utilized in the MANE-VU reasonable progress modeling. 

Table 12-3, below, illustrates the MANE-VU 2002 (baseline) and MANE-VU 2018 

(modeling) inventories for Maine, along with the Maine updated 2018 projected 

inventories. The emission inventory for Maine projects changes to point, area and mobile 

source inventories by the end of the first implementation period resulting from population 

growth; industrial, energy and natural resources development; land management; and air 

pollution control. Table 12-4 compares the percentage reductions (S02) for the MANEVU region and Maine for each source category . The implementation of the Long Term 

Strategy will reduce Maine's S02 emissions by 73 .4 percent, as compared to the 

compared to the projected reduction of 67.5 percent in the MANE-VU region . Further 

information on Maine's emissions inventory, including other pollutants that contribute to 

visibility impairment, is available in Section 8 .0, Emissions Inventory, and in 

Attachments I and AA. 

Table 12-2 

76 Since the Maine long-term strategies for non-point sources do not differ from those modeled, it is not 

necessary to update other source categories at this point in time . 

77 Maine's projected 2018 inventory is based on Maine's 2008 Point Source Inventory. Records were 

matched at the process unit level to the 2002 MANE-VU Inventory. In developing the Maine projected 

2018 point source inventory, the Department chose to a unitary growth factor (1). This decision was based 

on the significant reductions in Maine point source SOZ emissions that occurred between 2002 and 2009. 

During this period, 25 facilities ceased operation and/or surrendered their air emission licenses, and were 

removed from the point source inventory. Since Maine experienced a significant decline in point source 

SOZ emissions during the period from 2002 through 2008, we believe that a growth factor of 1 provides an 

appropriately conservative estimate of projected 2018 emissions when applied to the 2008 point source 

inventory. Additional information on growth rates and inventory adjustments I provided in Attachment 

AA, Documentation for 2002-201 SOZ Inventories. 

78 The Department's analysis did not include gny reductions from the use of ULSD (15 ppm) at point 

sources. 

190 
SOZ Emissions from Point, Area and Mobile Sources in Maine 

(tpY) 

Source Category 

MANE-VU 

2002 

Baseline 

MANE-VU 

2018 

Modeling 

Maine (Updated) 

2018 

Projected 

On-Road Mobile 1,804 894 894 

Non-Road Mobile 917 82 82 

EGU Point 9,299 6,806 

Non-EGU Point 14,412 13,082 8,445 

Area 13,149 1,127 1,127 

I TOTAL 39,581 21,991 10,548 

Table 12-3 

SOZ Emissions from Point, Area and Mobile Sources in the MANE-VU Region and 

in Maine 

(tpY) 

Source Category 

MANE-VU 

Region 

Percent 

Reduction 

2002-2018 

Maine 

Percent 

Reduction 

2002-2018 

On-Road Mobile 78.2 50.5 

Non-Road Mobile 84.9 91 .1 

EGU Point 77.6 64.4 

Non-EGU point 65 .4 

Area 54.8 91 .4 

~ AVERAGE 67.5 73.4 

12.11 Emission Limitations and Compliance Schedules 

40 CFR 51 .308(d)(v)(C) requires Maine to establish emission limitations and compliance 

schedules to meet reasonable progress goals. Emission limitations and compliance 

schedules are in place for the Maine programs outlined in Subsection 12.9. Final BART 

determinations and control requirements for all Maine BART-eligible sources are 

included in the Regional Haze SIP, and include emission limitations and compliance 

schedules for all BART-eligible sources. The Maine Low Sulfur Fuel Program, 

implementing the MANE-VU low sulfur fuel strategy and the targeted EGU strategy in 

Maine was enacted by the Maine Legislature on March 25, 2010, and signed into law by 

Governor John Baldacci on April 5, 2010. As noted in Section 12 .9 .3, Maine is 

committing to further analyze the visibility benefits that would be provided by the use of 

0.3% sulfur fuel, and to require the use of this fuel (or an equivalent emissions rate) no 

later than January 1, 2018, if necessary to meet the reasonable progress goals at Class I 

191 
areas in Maine or any other Class I area significantly affected by Maine emissions. 

Maine is committing to undertake this analysis no later than January 1, 2013 as part of its 

5-year periodic implementation plan revision. 

12.12 Enforceability of Emission Limitations and Control Measures 

40 CFR 51 .308(d)(3)(v)(F) requires Maine to ensure that emission limitations and control 

measures used to meet reasonable progress goals are enforceable. All control measures 

incorporated into law or codified in administrative rules will be enforceable. Any facility 

subject to state or federal permit requirements, including BART-eligible and V facilities, 

will be required to comply with the specific permit conditions that reference the 

applicable provisions of those laws and rules. 

In Maine, the authority to create rules, issue permits and enforce laws related to regional 

haze is established in Title 38 Maine Revised Statutes Annotated (MRSA), Chapter 2, 

Department of Environmental Protection, Subchapter 1, Organization and Powers and in 

Title 38 MRSA, Chapter 4, Protection and Improvement of Air. Under 38 MRSA 

Chapter 2 and Chapter 4, the Department is authorized to enforce the state's air laws and 

regulations, establish a permit program, accept and administer grants, and exercise all 

incidental powers necessary to carry out the its statutory obligations. 

Sections of Maine law of particular relevance to the regional haze SIP are: 

" Title 38 Maine Revised Statutes Annotated (MRSA) section 581, Declaration of 

findings and intent, which declares the Legislature's intent to: 

"exercise the police power of the State in a coordinated state-wide program to 

control present and future sources of emission of air contaminants to the end that 

air polluting activities of every type shall be regulated in a manner that 

reasonably insures the continued health, safety and general welfare of all of the 

citizens of the State " 

" 38 MRSA section 585. Establishment of emission standards, which states : 

"The board may establish and may amend standards, herein called "emission 

standards"; limiting and regulating in a just and equitable manner the amount 

and type of air contaminants which may be emitted to the ambient air within a 

region. Such emission standards shall be designed to prevent air pollution and to 

achieve and maintain the ambient air quality standards within the region in which 

applicable " 

" 38 MRSA section585, Establishment of emission standards, which states : 

"The board may establish and amend regulations to implement ambient air 

quality standards and emission standards. These regulations shall be designed to 

achieve and maintain ambient air quality standards and emission standards 

within any region and prevent air pollution " 

192 
" 38 MRSA section 590, Licensing, which states, in relevant part: 

"1. License required. After ambient air quality standards and emission standards 

have been established within a region, the board may by rule provide that a person 

may not operate, maintain or modify in that region any air contamination source or 

emit any air contaminants in that region without an air emission license from the 

department" 

" 38 MRSA sections 347-A, 347-C, and 349, which provide for the enforcement of 

all SIP measures; and 

" 38 MRSA section 353-A, which establishes annual air emission license fees and 

38 MRSA section 353A (1) A, which establishes an annual fee surcharge for 

emissions of hazardous air pollutants . 

The Maine regulations also provide for enforceable emission control measures and 

compliance schedules to meet the applicable requirements of the Clean Air Act and rules 

promulgated by EPA. The following regulations are of particular relevance to the Maine 

Regional Haze SIP: 

06-096 CMR Chapter 100 Definitions Regulation 

06-096 CMR Chapter 101 Visible Emissions Regulation 

06-096 CMR Chapter 102 Open Burning Regulation 

06-096 CMR Chapter 103 Fuel Burning Equipment Particulate Emission Standard 

06-096 CMR Chapter 104 Incinerator Particulate Emission Standard 

06-096 CMR Chapter 105 General Process Source Particulate Emission Standard 

06-096 CMR Chapter 106 Low Sulfur Fuel 

06-096 CMR Chapter 109 Emergency Episode Regulation 

06-096 CMR Chapter 110 Ambient Air Quality Standards 

06-096 CMR Chapter 114 Classification of Air Quality Control Regions 

06-096 CMR Chapter 115 Major and Minor Source Air Emission License 

Regulations 

06-096 CMR Chapter 116 Prohibited Dispersion Techniques 

06-096 CMR Chapter 117 Source Surveillance 

06-096 CMR Chapter 121 Emission Testing of Resource Recovery Facilities 

06-096 CMR Chapter 126 Capture Efficiency Test Procedures 

06-096 CMR Chapter 127 New Motor Vehicle Emission Standards 

06-096 CMR Chapter 138 Reasonably Available Control Technology for 

Facilities that Emit Nitrogen Oxides 

06-096 CMR Chapter 140 Part 70 Air Emission License Regulations 

06-096 CMR Chapter 145 NOx Control Program 

06-096 CMR Chapter 146 Diesel-Powered Motor Vehicle Emission Standards 

06-096 CMR Chapter 148 Emissions from Smaller-Scale Electric Generating 

Resources 

06-096 CMR Chapter 149 General Permit Regulation for Nonmetallic Mineral 

Processing Plants 

06-096 CMR Chapter 150 Control of Emissions from Outdoor Wood Boilers 

193 
06-096 CMR Chapter 160 Outdoor Wood Boiler Replacement and Buy Back 

Program 

The Maine regulations provide for enforceable emission control measures and 

compliance schedules to meet the applicable requirements of the clean Air Act and rules 

promulgated by EPA. The Maine rules also define the State's air emission licensing 

(permit) program for stationary sources to ensure that national ambient air quality 

standards are achieved. 

12.13 Prevention of Significant Deterioration 

Prevention of Significant Deterioration (PSD) requirements for new major stationary 

sources and major modifications (emitting > 50 tons of any air contaminant) are 

implemented in Maine through the 06-096 CMR Chapter 100 Definitions Regulation 

which was approved into the SIP on October 15, 1996'9, the 06-096 CMR Chapter 113 

Growth Offset Regulation which was approved into the SIP on February 14, 1996g°, and 

the 06-096 CMR Chapter 115 Major and Minor Source Air Emission License 

Regulations which were approved into the SIP by EPA on February 14, 1996.g1'82 PSD is 

applicable to all major sources (or existing sources making a major modification), 

triggering significance thresholds, located in an area that is in attainment with the 

National Ambient Air Quality Standards or unclassified . One of the intentions of the 

PSD program is to protect air quality in national parks, wilderness areas, and other areas 

of special natural, scenic, or historic value. The PSD permitting process requires a 

technical air quality analysis and additional analyses to assess the potential impacts on 

soils, vegetation and visibility. 

The required procedures for evaluating the impacts of a proposed PSD source on air 

quality and visibility are provided in Section 7 of Maine's 06-096 CMR Chapter 115 

Major and Minor Source Air Emission License Regulations. The Ambient Air Quality 

Impact Analysis must demonstrate that the new allowable emissions will not result in an 

exceedence of the remaining increments for SO2, NOZ or PMIO in any Class I area. The 

applicant must also demonstrate "that the increase in allowable emissions will not cause 

an adverse impact on visibility in any sensitive area or in any Class I area, and will not 

interfere with reasonable progress toward the remedying of existing man-made visibility 

impairment in a sensitive area. The analysis must be submitted to the Department and the 

appropriate Federal land Manager at least 60 days prior to the close of the public 

comment period on the source or modification . In this manner, new major sources and 

existing sources making major modifications will be constructed in a manner that will not 

degrade air quality or visibility. The PSD permitting program is an integral part of 

Maine's long-term strategy for meeting its regional haze goals. 

'9 61 FR 53639 

8° 61 FR 5694 

" 61 FR 5694 

82 Although these rules have been amended several times since being incorporated into the SIP, these 

revisions did not change any of the major source permitting requirements relevant to PSD, and the current 

state regulations are consistent with the SIP-approved versions for the purposes of implementing the PSD 

requirements . 

194 
12.14 Reasonably Attributable Visibility Impairment 

40 CFR Section 51 .302 (c) provides for general plan requirements in cases where the 

affected FLM has notified the State that Reasonably Attributable Visibility Impairment 

(RAVI) exists in a Class I Area in the state. There are no RAVI sources in the MANEVU region . 
13. Comprehensive Periodic Implementation Plan Revisions 

40 CFR Section 51 .308(f) requires a State/Tribe to revise its regional haze 

implementation plan and submit a plan revision to EPA by July 31, 2018 and every ten 

years thereafter. In accordance with the requirements listed in 40 CFR Section 51 .308(f) 

of the federal rule for regional haze, Maine commits to revising and submitting this 

regional haze implementation plan by July 31, 2018 and every ten years thereafter. 

In addition, 40 CFR Section 51 .308(g) requires periodic reports evaluating progress 

towards the reasonable progress goals established for each mandatory Class I area. In 

accordance with the requirements listed in 40 CFR Section 51 .308(g) of the federal rule 

for regional haze, Maine commits to submitting a report on reasonable progress to EPA 

every five years following the initial submittal of the SIP. The report will be in the form 

of a SIP revision submitted by no later than December 17, 2012. The reasonable progress 

report will evaluate the progress made towards the reasonable progress goal for each 

mandatory Class I area located within Maine and in each mandatory Class I area located 

outside Maine, which may be affected by emissions from within Maine. All 

requirements listed in 51 .308(g) shall be addressed in the SIP revision for reasonable 

progress . 

Section (d)(4)(v) requires periodic updates of the emission inventory . Maine commits to 

update the inventory by no later than December 17, 2012. 
14. Determination of the Adequacy of the Existing Plan 

As required by 40 CFR Section 51 .308(h), depending on the findings of the five-year 

progress report, required under 40 CFR Section 51 .308 (g), Maine commits to taking one 

of the following actions at the same time the State submits the 5-year progress report: 

(1) If the State determines that the existing implementation plan requires no further 

substantive revision in order to achieve established goals for visibility improvement and 

emissions reductions, the State will provide to the Administrator a negative declaration 

that further revision of the existing implementation plan is not needed . 

(2) If the State determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources in another State(s) which participated 

in a regional planning process, the State will provide notification to the Administrator and 

to the other State(s) which participated in the regional planning process with the States . 

The State will also collaborate with the other State(s) through the regional planning 

process for the purpose of developing additional strategies to address the plan's 

deficiencies . 

(3) If the State determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources in another country, the State will 

provide notification, along with available information, to the Administrator. 

(4) If the State determines that the implementation plan is or may be inadequate to ensure 

reasonable progress due to emissions from sources within the State, the State will revise 

its implementation plan to address the plan's deficiencies within one year. 

The findings of the five-year progress report will determine which action is appropriate 

and necessary. 
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Environ. Sci. Technol_, 32, 2706-2714, 1998. 

Byun D.W., and J.K.S . Ching. Science Algorithms of the EPA Models-3 Community 

Multiscale Air Quality (CMAQ) Modeling System . EPA/600/R-99/030. March 

1999. 

Davidson, C., Strader, R., Pandis, S., and Robinson, A., Preliminary Proposal to MARAMA 

and NESCA UM.~ Development of an Ammonia Emissions Inventory for the Mid-Atlantic 

States and New England. Carnegie Mellon University, Pittsburgh, PA. 7-Jan. 1999 . 

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http ://www.epa .gov/ttn/chief/trends/trends98/trends98 .pdf, 2000b. 

MARAMA 2004, http ://www.marama.org/visibility/2002%20NEI/index .html 

NESCAUM, "Development of an Improved Ammonia Emissions Inventory for the 

United States," December 2001b. 

NESCAUM, "Regional Haze and Visibility in the Northeast and Mid-Atlantic States," 

January 2001 a. 

SAI. User's Guide to the Regional Modeling System for Aerosols and Deposition 

(REMSAD), Version 7. ICF Consulting/SAI, San Francisco, CA. 2002 

Strader, R., Anderson, N., and Davidson, C., Development of an Ammonia Inventory for 

the Mid-Atlantic States and New England, Progress Report, October 18, 2000, available 

online : http ://marama.org/rt center/MARAMAprogress10-18-OO .pdf, 2000. 

198