### because they may notreasonably be anticipatedto cause or contribute to anyvisibility

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-VUconducted modeling analyses of BART-eligible sources using CALPUFF in order toprovide a regionally-consistent foundation for assessing the degree ofvisibility improvement which could result frominstallation of BART controls (See Attachment L) . While this modeling analysis differed slightly fromthe statutory language, it was intended to provide a first-order estimate ofthe maximum visibility benefit that could be achieved by eliminating all emissions froma 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 platformand 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 fromboth the NWS and MM5 platforms include each BART eligible unit's maximum24-hr, 8'h highest 24-hr, and annual average impact at the Class I area. These visibility impacts were modeled relative to the 20percent best, 20percent worst, and average annual natural background conditions. In accordance with EPA guidance, which allows the use of either estimates of the 20percent 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 toutilize the more conservative best conditions estimates approach because it is more protective ofthe region. 

### The 2002 baseline modeling provides an estimate of the maximum improvement in visibility at Class I Areas in the region that could result fromthe installation of BART controls (the maximum improvement is equivalent to a "zero-out" ofemissions) . In virtually all cases, the installation ofBART 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 fromBART, 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 fromthe NWSdriven data and 0

.29dv fromthe MM5data. As a result, MANE-VUconcluded 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) ofMaine BART-Eligible sources on selected Class I areas in Maine and New Hampshire. Forthis 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 deciviewimpact on Class I areas. 10.7 The Maine BART Analysis Protocol 40CFR51 .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 systemofcontinuous 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 ofcompliance, 2 . The energy and non-air quality environmental impacts ofcompliance, 3 . Any existing pollution control technology in use at the source, 4 . The remaining useful life ofthe source, and 5 . The degree of visibility improvement which may reasonably be anticipated fromthe use of BART. Although Maine didnot exempt any BART-eligible sources froma BART determination, it did utilize the MANE-VUzero-out modeling (described in the previous section) as a surrogate for estimating the visibility improvement reasonably expected fromthe application ofcontrols. As previously highlighted in Table 10-2, there are ten BARTeligible sources with less than 0 .1 deciviewimpact at any Class I area, with these impacts ranging froma low

of 0 .0018deciviews to a higher (but still insignificant) 0 .0822 deciviews. Since zero-out modeling shows that the elimination ofall emissions from these sources would provide only insignificantvisibility 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 ofthe BART analysis and whether visibility impact modeling need be performed by specific sources. The Maine approach is consistent with that used by other MANE-VUstates 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 levelwere too small to warrant BART controls, the entire MANE-VUpopulation of these units was modeled together to examine their cumulative impacts at each Class I suite . Theresults ofthis modeling demonstrated that the maximum

24-hour impact at anyClass I area of all modeled sources with individual impacts below 0 .1 dv wasonly a0

.35 dv change relative to theestimated best days natural conditions at Acadia National Park. This value is well below the0 .5 dv impact recommended by EPAfor exemptionmodeling and used by most other RPOs. 

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

controls), and the visibility impacts ofthe unit relatively sma1142 as determined by the MANE-VUzero-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 MANEVUClass 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 im

p act 24-hr d im p act 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 #4 Recovery, Boiler 0.2425 

## 0.0634 0 .11W,'

# 0.0173 0.2631

# 0.0424

# 0.2070

# 0.0391

Red Shield Acquisition, Old Town Lime Kiln 0.0851 0.0171 0 .0433 ;0.0278 0.0138 0.0855 0 .0463 Verso, Bucksp

ort 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 

# PowerBoiler#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 0.30 1-, 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 EPAguidance allows BART-eligible sources to adopt a federally enforceable permit limit to permanently limit emissions ofvisibility 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 ofvisibility impairing pollutants of fewer than 250 tons per year, and are BART-eligible only because their potential emissions (PTE) exceed the statutory threshold of 250tons 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 250tons 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 NOXto less than 250TPY . Note that if, in the future, the source requests an increase in PTE greater than 250tons 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 (40Code 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, whichutilizes the Kraft Pulping process andproduces 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 #6fuel 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 nottechnically 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 . ADESP 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 ofPM removed, and found that DESP is not a cost-effective option. SOZ: PowerBoiler #9 is currently controlled through the use ofa wet scrubber and low sulfur fuel (biomass)

. Domtar did not investigate other control technologies because the combination oflow

sulfur fuel andwet scrubber provides maximum emission reductions fromthis 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 frommulti-fuel boilers, and FGRis not technically feasible based on previous failed FGRtrials 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 SNCRat $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 lowcost-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 40CFR, Part 63, Subpart MM

. According to 40CFR, Part 51, AppendixY, According to 40CFRPart 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 ofdollars 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 twowet scrubbers), no further analysis was necessary. NQ, : Anumber 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 drummakes SNCRtechnically infeasible. SCRand NSCR are not feasible due to the known presence of catalyst fouling substances in the Lime Kiln. FGRis 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 EPABACT/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 furtheranalysis is necessary. Unit PM 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 120ppmvd Kiln scubber with 40 scrubber/Process (Existing combustion @ 10% Oz CFRPart 63 control TitleV 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 ofthe new facility is approximately 766,500 tons ofclinker. The BART eligible kiln systemis 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 fromthe kiln flow counter-current to the feed material up the length of the kiln. Heat is transferred to the fed material fromthe direct contact of the flue gases in the kiln and preheater/precaliner tower. BART Analysis Summarv Dragon submitted a 5-step BART analysis ofthe 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 ofvisibility improvement anticipated fromthe use of BART (a CALPUFF version 5.8 analysis was performed by Dragon) . PM : Emissions of PM

from the kiln systemare generated as a function of the clinker production process. The kiln systemis subject to 40 CFR Part 63, Subpart LLL, National Emission Standardsfor Hazardous Air Pollutantsfrom 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 fromcement kilns are generally relatedto the inherent SO2 removal efficiency present in the kiln systemoperation 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 ofthe systemis oxidizing or reducing. Dragon identified wet scrubbing, semi-dry scrubbing, dry scrubbing, fuel switching, andprocess 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 streamcontaining 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 systemand were further evaluated43. The three scrubbing options were reviewed further, and the results are in the following table: 43 Adry scrubbing systemis currently installed on the kiln system but is not operated. 106Expected Expected SO2 SOZ Emission Emissions Emissions Control Rate Performance Reductions Technolo

gy tons/ r Level tons/ r Cost of Com pliance 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 andprocess alterations were also evaluated, but were not found to be viable control options. NOX : Emissions of NOX fromcement 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 NOXburners, selective Non-Catalytic Reduction (SNCR), and Selective Catalytic Reduction (SCR) as available NOXcontrol 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 ofFGRrelies 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. SCRwas notconsidered technically feasible since there are no full scale SCRsystems (ammonia injection upstreamof a catalyst bed) in operation at cement kilns in the United States due to various concerns including exhaust temperature andplugging. 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 Anal ysis for Drag on Products

107

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

solid fuel froma 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 fromthe 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 systemto reduce kiln stratification and improve combustion ofthe fuel, which aids in reducing emissions. Low NOx burners are currently being used on the kiln system . SNCRis 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 ofthe SNCRtechnology at the facility relating to further NOx control . Dragon supplied possible operational changes to the existing SNCRcontrol unit including: increasing the operating time of the SNCRcontrol unit, relocating the reagent injection nozzles, changing the reagent used in the SNCRcontrol unit, and increasing the injection rate of the SNCRcontrol 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 SNCRoperated 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 ofperformance of SNCRover the long term, ." The Department requested that Dragon assess the operation of the SNCRat 50%efficiency. Dragon performed an operational change impact analysis with the following results:

Expected Expected NOx NOx Emission Emissions Emissions Control Rate Performance Reductions Technolo

gy tons/ r Level tons/ r Cost of Com pliance 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 thenearest class I area (Acadia

NOx Control Alternatives Anal sis for Dragon Products

108National 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 drykiln feed rolling efficiency rolling (Existing average on a 24-hour average and Title V (Existing basis 1533.0 tons license; 40 Title V (BART peryear on CFRPart 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 offour generation units, all ofwhich fire #6 residual fuel oil . Afifth unit is a smaller oil-fired auxiliary boiler which provides building heat and auxiliary steam and a sixth unit is an emergency backup diesel generatorthat 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 ofparticulate 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 #6fuel oil (0.7 % sulfur) . The boiler is equipped with an electrostatic precipitator for control ofparticulate 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

ofvisibility 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 fromthe oil fired boilers: low sulfur #2 fuel oil, reduced sulfur #6 fuel oil, and wet or dry scrubbers. Low sulfur #2fuel oil (0.05%down to 0 .0015%) and the use of reduced sulfur #6fuel oil (1%or less) were considered technically feasible options. Post combustion controls ofwet or dry scrubbers on large boilers were researched and generally only typically applied to coal fired boilers. The use ofscrubbing 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 Boiler #4 % sulfur Annual Costs % sulfur Annual Costs 1 .0 $0.68million - - 0 .7 $0.80million - - 0 .5 $3.2 million 0 .5 $9.2 million 0 .3 $5.7 million 0 .3 $18

.3 million Thevisibility cost effectiveness, incremental visibility improvement, and incremental visibility cost effectiveness from switching from2%sulfur to reduced sulfur content fuel oil forboiler #3 was the following:

S02Control Costs Anal sis for W man#3 and #4

44 It is estimated from

the MANE-VUAugust 2006 document Contributions to Regional Haze in the NortheastandMid-Atlantic United States, Tools andTechniquesforApportioning Fine Particle/Visibility Impairment in MANE-YU(pages 3-2, 4-7, 4-8) that course particulate matter hastypicallyless than 4%of thecontribution to visibility impairment at the MANE-VUClass I areas. 

### 110

### Sulfur Ranked Visibility Im p act Visibility Cost Effectiveness $/deciview Incremental

Visibility Im p rovement Incremental

Visibility Cost Effectiveness $/deciview 1 .0 1St $0.69million - - 0 .7 1S` $0.56million 0 .44dv $0

.27 million 0 .5 1St $1 .82 million 0 .35 dv $6.97 million 0 .3 1St $2.64million 0 .37 dv $6.59million Thevisibility cost effectiveness, incremental visibility improvement, and incremental visibility cost effectiveness from switching from0

.7%sulfur to reduced sulfur content fuel oil for boiler #4was the following: Incremental



### Ranked Visibility Cost Incremental Visibility Cost Visibility Effectiveness Visibility Effectiveness % Sulfur Im

pact $/deciview Im p rovement $/deciview 0 .5 Is` $22.3 million - - 0 .3 1St $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 forboiler #3 beginning in 2013, and the current sulfur limit of 0

.7% for boiler #4as BART. NOX. Emissions of NOX fromoil fired boilers are fromthermal and fuel NOX . In order to minimize NOX emissions, FPLE Wyman installed combustion control technologies pursuant to 06-096 CMR145, NOX Control Program Regulation. FPLE Wyman 

### installed combustion control technology upgrades including low NOXfuel 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 of29-35% have been documented with boiler #3 and reductions of 24-47%have been documented with boiler #4depending 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 ofNOXremoved

SOZ Control Visibility Analysis for W man#3

S02Control Visibility Analysis for W man#4

111

### forboiler #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 (ExistingTitle V order) license; 06-096 CMRChapter 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 Vlicense; 40 weight oil rolling CFRPart 60) (Existing average*(Existing Title V TitleVlicense; license, 40 06-096 CMR CFRPart Chapter 145) 60 Alternatively, the NO

., limitfromboilers #3 and#4 averaged shall be limitedto 0 .165 lbs/MMBtuon a 90- dayoperating 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 bottomelectrostatic 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.

BAR T Analysis Summary The LPT BART analysis evaluated the best systemof continuous emissions control technology available for each ofthe 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 ofthe 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 ofthe 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 froma recovery boiler the BACT determination constitutes BART compliance. Maine did not require additional visibility impact modeling because of the limited visibility impacts fromthis source.45 BART Determination 

### The Department determined BART for Lincoln Paper andTissue 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 cubicfoot a 24-hour a 24-hour (0.044 block block gr/dscf) average average (Existing basis basis Title V (Existing (Existing license; 40 TitleV Title V CFRPart 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

. SDWarren Company, Somerset SDWarren 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 steamoperated 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 fromspent pulping liquors and to produce steamfor 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 formof molten salts, are discharged fromthe bottomof 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 (calciumoxide) . 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, andpropane . The Lime Kiln is also licensed to combust LVHCgases 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 fromKraft 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 systemand, afterthe 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 fromKraft mill recovery boilers. SOZ emissions fromrecovery boilers occur due to the volatilization and subsequent oxidation ofsulfur compounds that are present in the black liquor. Proper operation of the recovery boiler maximizes the conversion ofsulfur compounds in the liquor to the principal constituents ofthe pulping chemicals. This occurs through capture ofthese sulfur compounds in the combustion zone of the boiler by sodiumfume released fromthe smelt bed

. Consequently, proper combustion control achieved through the use ofstaged 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 systemoperate 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 equippedwith a three-level staged combustion air control systemand 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,, fromKraft 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 steamboilers, including SNCR, SCR, flue gas recirculation, and lowNOX 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 fromthe 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

ofNO,, emissions fromrecovery boilers other than proper operation ofthe 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 ofthe control analysis. Smelt Tanks PM : SDW currently operates a wetted fan scrubber on each of the smelt tanks forcontrol 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 smelttanks: electrostatic precipitators, wet scrubbers, fabric filters, and mist eliminators. The most common PM emission control systememployed on smelt tanks is wet scrubbers. The use ofwet scrubbers also provides a secondary environmental benefit by controlling reduced sulfur compound emissions. The high moisture content ofthe 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 ofwet 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 generatedwithin the emission unit. SDW

has found that (SOZ) emissions fromthe smelt tanks are dependent on how much sulfur carries over fromthe respective recovery boilers with the smelt . SOZ emissions from

both smelt dissolving tanks combined are very low at approximately 10.5 tons peryear, 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 fromthe 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 fromsmelt tanks. Lime Kiln 

### PM : Particulate emissions fromthe Lime Kiln are currently controlled by a variable throat venturi scrubber systemfollowed by a cyclone separator. SDW identified the 116

### following available retrofit technologies for control of PM fromlime kilns: electrostatic precipitators, wet scrubbers, and fabric filters. Fabric filters have never been appliedto kraft pulp mill lime kilns. They are generally deemed tobe technically infeasible on lime kilns. ESPs provide a greater degree ofparticulate matter control than venturi scrubbers. However, the possible annual reduction in emissions to be gained by replacing the existing scrubber with an ESPis relatively small (estimated at under 40ton/year) . Additionally, the scrubber also helps control emissions of S02and reduced sulfur compounds. This beneficial removal ofother 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 TRSand SOZ emissions fromthe Lime Kiln. With respect to any possible improvement in visibility impacts associated withretrofitting an ESPon the Lime Kiln, the modeling result for current PM emissions fromthe 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 ESPcould 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 ofTRS compounds inthe LVHCgases. Currently emissions of S02are controlled by using a combination of the inherent sulfur removal provided by operation of the kiln itself (i .e. extensive contact betweenburner 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 ofLVHC 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 fromthe Lime Kiln canvary significantly based on the amount of LVHCgases being fired and whether or not the caustic scrubber is in operation. SDW identified the following available retrofit technologies for control of SOz fromlime 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 fromthe 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, fromlime kilns: Combustion Air Systems controls, SNCR, SCR, Low NO,, Burners, Flue Gas Recirculation. There are no technically feasible alternatives for control of NO,, fromlime 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 SCRand SNCR, are not feasible for lime kilns. The temperature window necessary for the SNCRprocess (1500 -2000 °F) is unavailable in a Kraft lime kiln. The high PM load at the exit ofthe kiln precludes the placement ofthe catalyst grid needed forthe SCRprocess upstreamofthe PM control device, and the requisite temperature window required for this process (550

- 750 °F) is not available downstreamof 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 notrequired to performthe remaining steps ofthe control analysis. BART Determination 

### Table 10-7

BART Determination Summarv for SDWarren Unit Recovery Boiler



### Smelt Tanks #1 and #2

Lime Kiln 

### PM

Control Emission Type I Limit and

Reference ESP

Wet scrubber

Wet scrubber 0.030gr/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 CFRPart 63, subpart MM)-- - 261b/hr; 0

.2 lbs/ton BLS 40 CFRPart 63, subpart MM (Existing TitleV license) 0 .10gr/dscf @10% OZ; 581b/hr (Existing Title V license; 40 CFRPart 63) 

### 6 . VersoAndroscoggin S02 NOx ControlType 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 blockaverage basis (BART order) 19751bs/hr (NSR License #A-19-77-2-A)

261b/hr (ExistingTitle Vlicense)

1 .92 lb/MMBtu; 100 tons/year limit on a 12-month rolling average (Existing Title Vlicense) 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 VersoAndroscoggin pulp mill produces bleached Kraft pulp andgroundwood pulp. Thebleached pulp is produced in twoseparate process lines, designated "A" and "B" . Groundwood pulp is produced in another separate process line. Logs and wood chips are received in theWoodyard area, where they are stored andprocessed 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 ofall 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 steamand 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 lowload. 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 systemdesigned to ensure the optimal balance between control ofNOX and limitation of COand 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 2.50and 3.44 million pounds per day ofdry black liquor solids (MMIb/day ofBLS), respectively. Inorganic material (smelt) fromthe bottoms of the recovery boilers is used to produce green liquor, which is a solution of sodium

sulfide and sodiumcarbonate 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 fromboth recovery boilers are currently controlled using an electrostatic

precipitator (ESP) . Smelt Dissolving Tank #1 is rated at 2.50MMlb/day ofdry 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 fromthe 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 formgreen liquor which is pumped to the causticizing area. Sulfur dioxide (SOZ) and particulate matter (PMIO) emissions fromSmelt 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 fromSmelt Dissolving Tank #2are 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 (calciumcarbonate) fromthe causticizing area to regenerate calciumoxide (CaO)

. Inside the lime kilns, the lime mud is dried and heated to a high temperature where the lime mud is converted to lime (calciumoxide or CaO) . "A" and "B" Lime Kilns are each rated at an operating rate of 248tons ofcalcium 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 Aand B Lime Kilns also serve as an incineration device (control device) for select sources of low volume high concentration (LVHC) noncondensable gases (NCG) frompulping operations at the mill . Particulate matter (PMIo) emissions are controlled fromthe "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 VersoAndroscoggin's papermachines. 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 #2fuel 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 systemand S02emissions 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 fromPower 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 PMIOemissions are low based on the firing of fuel oil and that PMIOemissions 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 

### 120Part 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 fromPower Boilers #1 and #2. Low sulfur fuels and wet scrubbing controltechnologies were found to be technically feasible by VersoAndroscoggin and so were evaluated further.46 Asummary ofVersoAndroscoggin's evaluation of the remaining viable SOZ control technologies (lowsulfur 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 Negli g ible 1 .5 0 .7% 60% $631 Negligible 0 .9 Sulfur #6 Fuel Oil Wet 99% $2,278 Disposal 1 .5 Scrubbing Im pacts The cost effectiveness numbers in the table above are based on controlling SOZ emissions fromPower Boilers #1 and #2 at the control effectiveness rates indicated in the table fromthe 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 ofbetween $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 fromPower 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 of0.7%sulfur #6 fuel oil is a feasible andjustifiable cost at $631 per ton of SOZ reduced, but that the other low sulfur fuel options and the wet scrubbing option are not economicallyjustifiable and do not represent BART. Therefore, Verso Androscoggin proposes that the use of lower sulfur (0.7%) #6fuel oil in place of the higher sulfur (1 .8%) #6 fuel oil currently fired, represents BART for control of SOZ emissions fromPower Boilers #1 and #2. ab Dry and semi-dry scrubbing control technologies were evaluated, howeverVerso Androscoggin found that control effectiveness levels wouldbe low (<25%), downstream

particulate matter control devices such as an ESPand/or fabric filter wouldneed to be installed to collect andre-circulate the scrubbing material, and no applications ofthese technologies on fuel oil fired boilers like Power Boilers#1 and #2 were identified during Verso Androscoggin's research ofpotential control technologies. 

### 121

### NQ, : VersoAndroscoggin 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) systemand a flue gas recirculation (FGR) system) as potential control technologies in the reduction ofNO . emissions from Power Boilers #1 and #2. SCRand SNCRcontrol 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 estimatedto 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 PowerBoilers #1 and #2. VersoAndroscoggin found that the size and design ofPower Boilers #1 and #2would provide little room

for the installation ofan overfire air systemand that the application of a flue gas recirculation systemwould result in minimal reductions (7%to 15%) in NO,, emissions. Asummary ofVersoAndroscoggin's evaluation of the remainingviable NO,, control technologies (SCRand SNCR) is provided in the table below . Control Control Cost Energy and Greatest Technology Effectiveness Effectiveness Other Impacts Visibility $/ton removed Im p rovement SCR 90% $5,271 Minor Im pacts 1 .7 SNCR 35% $5,973 Minor Impacts 1 .4 The cost effectiveness numbers in the table above are based on controlling NO, emissions fromPower Boilers #1 and #2 at the control effectiveness rates indicated in the table fromthe 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% ofthe time, which for example, would result in an actual cost effectiveness of $16,313 per ton ofNOX removedwith 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 economicallyjustifiable 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 ofNOX emissions fromPower Boilers #1 and #2 and that no additional level of control is justifiable as BART. 

### Waste Fuel Incinerator Boiler : PM : VersoAndroscoggin did not identify or evaluate potential control technologies for the reduction of PMIOemissions fromthe Waste Fuel Incinerator Boiler (WFI) because this unit is subject to MACT Standards under section 112of 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: VersoAndroscoggin identified and evaluated low sulfur fuels, wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in the reduction of SOz emissions fromthe 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 offuel oil typically used in the boiler (less than 10%of the annual fuel oil heat input capacity) . The WFI currently uses a waterbased wet scrubbing systemfor PM control with the addition ofcaustic to meet S02emission limits when firing #6fuel oil in significant amounts. Dry and semi-dry scrubbing control technologies were not considered byVersoAndroscoggin 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 . VersoAndroscoggin also believes that the cost ofremoving the existing wet scrubber and replacing it with a dry or semi-dry scrubbing systemand a new ESP and/or fabric filterwould be costly. Asummary of VersoAndroscoggin's evaluation ofthe 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 Im provement Addition of 50% $21,800 Disposal Impacts <0 .1 Caustic to Existing Wet 

### Scrubber The WFI has very low

baseline SOZ emissions (-50tons per year) due to the inherent low sulfur content and alkalinity of the primary fuel (biomass) and the small amount offuel oilused 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 inputto the WFI, caustic is added to the wet scrubber to control SOZ emissions. Based on VersoAndroscoggin's identification and evaluation ofcontrol technology options, they propose that additional control of SOZ emissions fromthe WFI cannot bejustified as BART due to the imperceptible effect it would have on visibility. NO,, : VersoAndroscoggin identified and evaluated selective catalytic reduction (SCR), low NO,, burners (LNB), selective non-catalytic reduction (SNCR), and combustion control methods (including an overfire air systemand a flue gas recirculation system) as potential control technologies in the reduction of NO,{ emissions fromthe WFI . SCRand SNCRcontrol 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 forthe majority of the time that the WFI operates, thus VersoAndroscoggin felt LNBs did not warrant further evaluation. Combustion control methods were evaluated, howevernone were found to be viable control options forthe WFI due to the limited NO,{ removalpotential (<15%), potential impacts to other pollutants and boiler equipment, and the limited amount of room available forthe installation of control equipment. A summary ofVersoAndroscoggin's evaluation of technically feasible NO,, control technologies (SCR, SNCR, and FGR) is provided in the table below . SOZ Control Alternatives Analysis for the VersoWaste Fuel Incinerator

123

### Control Control Cost Energy and Greatest Technology Effectiveness Effectiveness Other Impacts Visibility ($/ton removed Im p rovement SCR 90% $4,676 Minor Im pacts 0

.3 SNCR 30% $5,944 Minor Im pacts 0

.1 FGR 15% $17,010 Minor Energy <0 .1 Impacts 

### Although the use of SCRhas the potential to reduce visibility impacts by a perceptible amount, VersoAndroscoggin proposes that the cost effectiveness levels are not economicallyjustifiable for any of the control technologies evaluated, including SCR . Based on VersoAndroscoggin's identification and evaluation of control technology options, they propose that additional control ofNO,, emissions fromthe WFI cannot be justified as BART due to the capital costs ($3 million to more than $7.6 million) and cost effectiveness levels ($4,700to more than $17,000per ton of NO,, removed) . Recovery Boilers #1 and #2 PM : Particulate matter (PM) emissions fromRecovery 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 ofPMIO emissions fromRecovery 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/LAERClearinghouse (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 PMIOand therefore did not identify or evaluate potential control technologies for the additional reduction of PMIOemissions fromRecovery 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 PMIOemissions fromRecovery Boilers #1 and #2. S02: Verso Androscoggin has found that sulfur dioxide (SOz) emissions fromRecovery Boilers #1 and #2 are variable due to several factors including black liquor properties (e.g., sulfidity, sulfur to sodiumratio, 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 VersoWaste Fuel Incinerator

### wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in

the reduction of SOZ emissions fromRecovery 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 ofRecovery Boilers #1 and #2. Based on Verso Androscoggin's identification and evaluation ofcontrol 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 fromRecovery 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 fromthe 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 ofthe liquor spray guns designed to provide secondary and tertiary staged combustionzones 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 systemand a flue gas recirculation system) as potential control technologies in the reduction of NOX emissions fromRecovery 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 SCRcatalyst, 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 SNCRcontrol technologies resulted in a finding that there have been no applications of this technology on recovery boilers in the United States for a variety ofreasons, 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 systemfor the SNCR . Operational concerns associated with SNCRwere found to include the potential formation of acidic sulfates that could result in corrosion and a catastrophic boiler tube failure. As a result ofVerso Androscoggin's initial evaluation of SNCR, no further evaluation was conducted. Recovery Boilers #1 and #2 are currently designed and operated using lowexcess air combinedwith 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 systemand due to the technical challenges re-circulating recovery boiler exhaust gases in a FGRsystemdue 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 ofNOX 

### 125

### emissions from Recovery Boilers #1 and #2are not technically feasible and warrant no further evaluation. Smelt Tanks #1 and #2 PM : Particulate matter (PM) emissions fromSmelt 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 fromSmelt 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 PMIOemissions fromSmelt Dissolving Tanks #1 and #2. SO2: Verso Androscoggin has found that sulfur dioxide (SOZ) emissions fromSmelt Dissolving Tanks #1 and #2 are dependent on how much sulfur carries over fromthe respective recovery boilers with the smelt . Controlled smelt-water explosions in the smelt dissolving tanks can create SOZ as a result of the oxidation ofthe sulfur in the smelt . SOZ emissions fromboth smelt dissolving tanks combined are very low at approximately 5 tons per year. Verso Androscoggin proposes that BART for SOZ emissions fromSmelt Dissolving Tanks #1 and #2 is no additional control based on the following: (1) SOZ emissions fromthe smelt dissolving tanks during the BART baseline periodwere 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 fromthe smelt dissolving tanks have a minimal impact on visibility (<0.1 deciviews) ; and (4)additional control of S02 emissions fromthe smelt dissolving tanks would have a minimal impact on overall visibility. 

### NQ, : Smelt Tanks #1 and #2 do not emit NO . . Lime Kilns Aand B PM : Particulate matter (PMIO) emissions fromthe "A" and "B" Lime Kilns consist primarily of dust entrained fromthe combustion section ofthe kilns. This dust consists of sodium

salts, calciumcarbonate, and calciumoxide. PMIOemissions are currently controlled by existing venturi scrubbers. These units are also subject to MACT Standards under section 112 ofthe 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 fromlime kilns and both are capable of a high level of control . Verso Androscoggin proposes that use ofthe existing venturi scrubbers to control PMIO emissions fromthe "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 ofthe existing venturi scrubbers with dry ESPs could increase SOZ emissions fromthe lime kilns when compared to use ofthe venturi scrubbers; (3) the replacement of the existing venturi scrubbers with wet ESPs would result in high capital costs ($1 .5 millionper kiln) ; and (4)visibility impacts fromthe lime kilns are minimal and installation ofadditional control would result in inconsequential improvement in visibility. SOZ: Verso Androscoggin has found that a significant portion ofthe 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 NCGcollection systemis equipped with a scrubber that uses white liquor (sodiumhydroxide or NaOH) and thus the sulfur loading fromthe NCGs is minimized. S02 emissions fromboth lime kilns combined are very low at less than 4tons per year primarily due to the alkalinity of the lime. VersoAndroscoggin proposes that BART for S02emissions fromthe "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

(<4TPY, 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 fromthe 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), lowNO,, burners (LNB), and selective non-catalytic reduction (SNCR) as potential NOx control technologies. Verso Androscoggin's evaluation ofSCRand 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 fromthermal NOX and to a lesser extent fuel NO,, . These combustion control measures include careful design ofthe fuel feed systemin 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 ofcontrol is technically feasible. Verso Androscoggin also notes in their BART analysis that existing NOX emissions fromthe "A" and "B" Lime Kilns have a minimal impact on visibility (<0.1 deciviews) and that additional control ofNO, emissions would have a minimal impact on the overall improvement to visibility. 

### 127

### Flash Dryer

PM : Particulate matter (PMIo) emissions fromthe 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 fromthe Flash Dryers and that with potential visibility impacts fromthe Flash Dryer being extremely low, any emission reductions would have an inconsequential impact on visibility improvement . 

### SO2 : The Flash Dryeris limited to firing #2 fuel oil with a maximum sulfur content of 0.5%, by weight and so has relatively low SOz emissions. Although VersoAndroscoggin 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 VersoAndroscoggin's identification and evaluation of SOZ control technology options forthe Flash Dryer, they propose that no additional level ofcontrol is representative of BART. NQ, : The Flash Dryer is not equipped with any NOx control equipment. NOXemissions fromthe Flash Dryer are primarily generated fromthe nitrogen component in the fuel oil . VersoAndroscoggin currently uses good maintenance practices to minimize NOX emissions fromthe Flash Dryer. VersoAndroscoggin's investigation ofconventional 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 ControlType 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 Vlicense) average basis (Existing Title V license 

### Table 10-8 BART Determination Summa for VERSO Androsco in

128Recovery ESP Compliance Staged air 120 ppmdv Combustion 150ppmdv, Boiler #1 with 40 CFR combustion @8% OZon a controls when Part 63 30-day rolling (NSR) correctedto 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 S02emissions order) shall not exceed 140ppmdv @8% OZon 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 correctedto Part 63 30-day rolling (RACT) 8% % OZ on Subpart MM average basis a 24-hour (Existing (Existing Title block TitleV Vlicense) average basis license) (Existing Title V license Smelt Wet cyclonic Compliance Wetcyclonic SmeltTank #1- N/A N/A Tanks #1 scrubber with 40CFR scrubber 2.7 lbs/hr and #2 Part 63 Subpart MM Smelt Tank #2- (Existing 3.91bs/hr Title V (Existing Title license Vlicense Lime Venturi Compliance Venturi 6 .7 Lbs/hr, 74.6 Combustion 120ppm @ Kilns A scubber with 40 CFR scubber tpy controls 10%02 and B Part 63 (Existing Title (RACT) (stack test) Subpart MM Vlicense) (Existing Title V license Flash Wetshower 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) Vlicense



### 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. Inthe digester, white liquor is used to dissolve the lignin fromaround the wood fibers. The pulp fromthe digester is then washed in the brownstock washer systemto remove residual spent cooking liquor. After bleachingthe 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) . Adry bottom

electrostatic precipitator (ESP) controls particulate matter fromthe unit. This unit is subject to 40 CFR Part 63, Subpart MM, NESHAPS fromChemical 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 CFRSubpart MM . SO2: SOZ emissions fromthe recovery boiler are limited through the use of lowsulfur (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 . 48Although Red Shield indicatedan intentionto "cap-out" of BART (see Section 10.8.1), the facility subsequently chose to undergo a BART analysis. Whilethe BART analysis for this facility is limited in scope, the Department feels that thesubject units and processes at this facility are similar enough to those at the SDWarren and Verso Androscoggin facilities that these more extensive analyses may be referred to in an effort to provide at least aqualitative 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) fromthe recausticizing slaker systemis 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 systemfor 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 fromthe #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 138contains the applicable NO,, ppm limit (170 ppm

on a dry basis) . The applicable NO,, lb/hr emission limit is 36.0 lb/hr. Unit

~ PM S02 N O,, Control Emission ControlType Emission Limit Control Type Emission 

### ] Type Limit and and Reference Limit and

Reference Reference ESP Compliance Low sulfur Low

sulfur fuel Good 150ppm on Recovery with 40 CFR fuel oil containing combustion a drybasis 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 TitleV 8%02 Vlicense) 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 Vlicense) practices correctedto 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~ ?oilutant 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 40CFRSection 51 .308(e)(1)(iv) BART must be in operation for each applicable source no later than five years after SIP/TIPapproval . Pursuant to 38 M .R.S.A. §603-A, sub-§8 (b), the State ofMaine 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 Voperating 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 Voperating permit programand 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 (40CFRSection 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 touse 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 impaireddays over the State Implementation Plan (SIP) period. The State of Maine must also provide an assessment ofthe number ofyears it would take to attain natural visibility conditions if improvement continues at the rate represented by the reasonable progress goal . Under40CFRSection 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 ofStates 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, theAdministrator will take this information into account in determining whether the State's goalfor visibility improvementprovidesfor 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 forthe period coveredby the implementation plan, and ifthe state proposes a rate of progress slower than the uniform

rate ofprogress, assess the number ofyears itwouldtake to attain natural conditions ifvisibility improvement continues at the rate proposed. 11 .1 Calculation of Uniform Rate of Progress As abenchmarkto aid in developing reasonable progress goals, MANE-VUcompared the baseline visibility conditions to natural visibility condition at each Class I area. The difference between baseline and natural visibility conditions at each MANE-VUClass I area was used to determine the uniform rate ofprogress thatwould 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 ofprogress 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 UniformRate of Progress Calculation

(all values in deciviews) (2000-2004) Natural Baseline Visibility Total Visibility Conditions Deciview Deciview UniformRate (deciviews) (20% Improvement Improvement of (20°/

. Worst Worst Needed by ,Needed by Improvement Class I Area Days) Days) 2018 2064 Annuall y 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 GulfWilderness Area 22.8 12.0 2.5 10.8 0 .180 Lye BrookWilderness 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 visibilityfor the 5yearperiodfrom2000 through 2004were 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 uniformrate of progress shown in Table 11-1, above. 

### 11 .2 Reasonable Progress Goals for Class I Areas in Maine In accordance with the requirements of40 CFRSection 51 .308 (d)(1), this Regional Haze SIPestablishes reasonable progress goals (RPG) for each Class I area in Maine for the period ofthe implementation plan. 40 CFRSection 51 .308(d)(1)(vi) requires that reasonable progress goals represent at least the visibility improvement expected fromimplementation of other Clean Air Act programs during the applicable planning period. As documented in Section 8 Emissions Inventory, and Section 12 Long-TermStrategy, the modeling that formed the basis for reasonable progress goals in MANE-VU Class I areas included estimation ofthe effects

a9"Baseline and Natural Visibility Conditions, Considerations and Proposed Approach to theCalculation of Baseline and NaturalVisibility Conditions at MANE-VUClass IAreas," NESCAUM, December 2006. 

### 134

### ofall other programs required by the CleanAir Act. Further information may be found

in those sections of this SIPand in the documentation for the MANE-VU modeling. Both natural conditions and baseline visibility for the 5-year period from2000through 2004were 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 RPGin deciviews, MANE-VUconducted 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 SIPrevisions between now and 2018 as they are able to adopt control measures to implement these goals. This long-termstrategy to reduce and prevent regional haze will alloweach 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 ofthe 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 deciviewlevel 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 deciviewlevel 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 ofAdditional Reasonable Controls Maine andthe other MANE-VUstates 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 ofa concerted strategy to mitigate regional haze. The proposed additional control measures were incorporated into the regional strategy adoptedby MANE-VUon 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 ofthe MANE-VUstates plus Georgia, Illinois, Indiana, Kentucky, Michigan, North Carolina, Ohio, South Carolina, Tennessee, Virginia andWest 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 inthe subsections which follow . Further elaboration on the reasonable progress measures which make up the Maine/MANE-VUlong-termstrategy is provided so In addition, the Stateof Vermont identified at least one source in the State ofWisconsinas a significant contributor tovisibility impairment at the Lye Brook Wilderness Class I Area. 

### 136

### in Section 12 ofthis SIP . "Underthis plan, the affected states will have until July 31, 2018to implementreasonable and cost-effective control measures to reduce primarily SOz and NO, emissions." For a description of how proposed emission control measures were modeledto estimate resulting visibility improvements, see Subsection 11 .5, Visibility Effects ofAdditional Control Measures. 11 .4 The Foundations for Determining Reasonable Controls 40CFRSection (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 ofcompliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, andthe remaining useful life of any potentially affected sources. The SIPmust 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 AirAct. Focus on SOZ: MANE-VU conducted a Contribution Assessment (Attachment A) and developed a conceptual model that indicated particulate sulfate formed fromemissions of SOZwasthe dominant contributor to visibility impairment at all sites and during all seasons in thebase 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 SOZwill 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 S02emissions. 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®CAIRversus CAIRplus analysis conducted for MARAMA/MANE-VUby ICF. 

### Average Cost in 2006 Energy and dollars Non-Air Quality Primary n Control Measure(s) (per ton of Environmental lft R a Source al

Regio pollutant Compliance _ Impacts h

em 8 Category Haze Timeframe Useful

Pollutant reduction) Life Electric S02 Switch to a low sulfurcoal IPM®* v.2.1 .9 2-3years Fuel supply issues, 50years or Generating (generally <1% sulfur), predicts $775- following SIP potential permitting more Units switch to natural gas $1,690 submittal issues, reductionin (virtually 0%sulfur), coal electricity production cleaning, Flue Gas $170-$5,700based capacity, wastewater Desulfurization (FGD)-Wet, on available issues -Spray Dry, or -Dry. literature industrial, S02 Switch to a low sulfurcoal $130-$11,000 2-3years Fuel supply issues, 10-30years 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, -Sp ray D ry, or -D ry. Cement and S02 Fuel switching, Dry Flue $1,900-$73,000 2-3years Control device energy 10-30years 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 18-25years the fuel . Depends on the on available Capacityissues fumace/boiler state . literature. There is may influence efficiency, Decreased a highuncertainty timeframe for fumace/boiler associatedwith implementation of maintenance this costestimate. new fuel standards req

uirements Residential PM State implementation of $0-$10,000 based Several years - Reduce greenhouse gas 10-15years Wood NSPS, Banon resale of on available dependent on emissions, increase Combustion uncertified devices, installer literature mechanism for efficiency ofcombustion training certification or emission reduction device inspection program, pellet stoves, EPAPhase 11 certified RWC

devices, retrofit requirement, accelerated changeover requirement, and accelerated changeover inducement. 

### 138

### The MANE-VUstates reviewed the four-factoranalysis presented in the Reasonable

Progress Report, consultedwith each other about the measures, and concluded by adopting the statements known as the MANE-VUAsk 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-VUand included in the modeling used to establish reasonable progress goals: BART, emissions reductions fromspecific EGUs, low sulfur fuel oil requirements, and additional measures determined to be reasonable. 11 .4.1 Best Available Retrofit Technology (BART) Controls The MANE-VUstates 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 undernew programs. Previously, EPAdetermined that CAIRfulfilled the BART requirement for all EGUs in CAIR-affected states. Although CAIRhas been remanded to EPA, the determination that CAIRis 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. Acomplete compilation ofBART-eligible sources in the MANE-VUregion is available in Attachment Aof MANE-VU's "Assessment of Control Technology Options for BART-Eligible Sources," March 2005 (Attachment R) . To assess the benefits ofimplementing BART in the MANE-VUregion, NESCAUM estimated reductions for twelve BART-eligible units in the MANE-VUstates 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-VUstate, whothen 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. BestAvailable Retrofit Technology is Reasonable: BART controls are part of the strategy for improving visibility at MANE-VUClass I areas. MANE-VUprepared reports to provide states with information about available control technologies (e.g., MANE-VU's "Assessment ofControl 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 fromBART-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 Pul p 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 Pap er and Pul p Gas 2884 1442** Power Boiler ME IP Jay #2 10200401 2300700021 002 Paper and Pul p Oil 3086+ 1543 Power Boiler ME IP Jay #1 10200401 2300700021 001 Pap er and Pul p Oil 2964+ 1482 KODAKPARK 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-VUInventory) +1999emissions ** The SAPPI Power Boiler #1 was subsequently determined to be exempt fromBART. Theseemissions reductions however, will still take place as a result of other programs.

### 11 .4.2 The MANE-VU Low Sulfur Fuel Strategy The MANE-VUregion, especially the northeast, is heavilyreliant on distillate oil for home space heating, with more than with more than 4million gallons used, according to 2006 estimates fromthe Energy Information Administrations' . Likewise, the heavier residual oils are widely used by non-EGUsources, and to a lesser extent the EGUsector. The sulfur content ofdistillate fuels currently averages above 2000 ppm (0.2percent) . Although the sulfur content ofresidual oils varies by source and across the region, it can exceed 2.0 percent. In 2002, combustion ofdistillate and residual fuel in the MANE-VU region resulted in SOZ emissions totaling approximately 380,000tons. As the second component ofMANE-VU's long termstrategy, the member states agreed to pursue measures that would require the sale and use offuel oils having reduced sulfur content. This strategywould be implemented in two phases: 1 . Phase 1 would require reducing the sulfur content in distillate (#1 and #2) fuel oils fromcurrent 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 ofheavier 

### blends ofresidual (#4and # 5 and #6) fuel oils that have a sulfur content greater than 2,500ppm

(0.25 percent) and 5, ppm (0.5 percent) by weight, respectively. 2. Phase 2would require further reducing the sulfur content of the distillate fraction from500ppm

(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-VUstates. While all MANE-VUstates 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 firmcommitment 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-VUregion will decline from2002 levels by 168,222 tons peryear for combustion of light distillates, andby 42,875 tons per year for combustion ofthe heavier fuels. Together, these reductions represent a 35 percent decrease in the projected 2018 SOZ emissions inventory for non-EGUsources in the region. NESCAUM

analyzed both steps ofthe programseparately, but it is the combined benefit of implementing the program that is relevant to the question ofvisibility improvement by 2018. To estimate the total 2018 emissions reductions fromthis strategy, MANE-VU applied the expected sulfur dioxide emission reductions to all non-EGUsources burning #l, #2, #4, #5, or #6 fuel oil . These emission reductions would result directly fromthe sl U .S. Department ofEnergy, EIA, Table F3a, at http://www .eia.doe.gov/emeu/states/sep fuel/html/fuel_use_df.html . 52The inner zone includes Delaware, Maryland, New Jersey, New

York, and possibly portions of eastern Pennsylvania. 

### 141

### lowering offuel 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 2018will 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 forthe combined first and second phases ofthe low-sulfur fuel strategy as calculated by the CMAQmodel . 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 linkedvisibility 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-FactorAnalysis- 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 50to 90percent reductions in SOZ emissions fromICI 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-VUReasonable 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 from2001 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 ofthe Reasonable Progress Report .) The sulfur content of#4and #6fuels can also be cost-effectively reduced. Residual oil is essentially aby-product ofthe 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 froma low of $71 .38a barrel for 2.00 and 2.2 percent sulfur fuel ; to a high of $91 .38 perbarrel for0 .3 percent sulfur fuel . Low pour" fuel oil with 0

.5 percent sulfur sold for $80 .83 perbarrel in this same period5a. While the costs for achieving the projected emissions reductions withthe 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-VUstates are proceeding with low-sulfur oil requirements much sooner than 2018; however, all of the MANE-VUstates concur that a low-sulfur oil strategy is both reasonable and achievable by 2018. MANE-VUhas concluded that the cost ofrequiring lower sulfur fuel is reasonable. Time Necessary for Compliance MANE-VU's Reasonable Progress Report indicatedthat 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-temperaturepour point (or reduced viscosityat low temperature) for the fuel . sa During this same period, residual oilwith a fuel sulfur content limit of0 .7 percent and 1 .0 percent traded at $75.13 and $72

.63, respectively. 

### 143The 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 ofLSDand 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 ppmfuel could be used to relieve the shortage. With this flexibility, the report concludes that the likelihood of a fuel shortage in the short termdue to use ofULSD 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 lowsulfur fuel oil programis 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 froma regional 500 ppm sulfur standard for heating oil . Suppliers can increase pre-season reserves and look to increase imports fromoffshore 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-VUstates. While the potential for disruptions inthe supply of residual fuels is greater than that for distillate oil, these disruptions would affect only a limited number ofstates during extreme weather events. MANE-VU has identified several mechanisms that could be implemented to address disruptions, including seasonal averaging and emergency waivers. Aseasonal 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-termsupply disruptions. 

### The strategy adopted by Maine andthe other MANE-VUstates proposes to phase in the required use of lower-sulfur fuels over the next 8years, 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 ofbeneficial 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 OverviewofBenefits, Costs and Implementation Issues", December 31, 2005 by NESCAUM . 

### 144State Energy Research and Development Authority (NYSERDA) showing that boiler

deposits are reduced by a factor of two by lowering the fuel sulfur content from1,400 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 ofAny 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 20-25years. As noted above, use of low-sulfur fuel is less damaging to equipment and couldtherefore extend the useful life ofan oil-fired residential furnace or boiler. Available information on the remaininguseful life ofICI boilers indicates a wide range of life expectancies, depending on unit size, capacity factorsb, and level of maintenance performed

. The typical life expectancy ofan ICI boiler ranges from10years to more than 30 years. As in the case ofresidential units, use of lower-sulfur fuels could extend the lifespan ofan ICI boiler. 11 .4.3 Targeted Strategy for Reducing SO2Emissions fromEGU 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 fromS02 emissions are responsible for over half the mass and approximately 70-80 percent ofthe extinction on the days ofworst visibility (NESCAUM's Contribution Assessment and Conceptual Model, Attachment A) . To ensure that EGUcontrols 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 ofthe 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 ofenergy a boiler generates in one year divided by the total amount it couldgenerate ifit ran full time at full capacity. 

### 145

### Figure 11-2 Location of 167 EGUStacks 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 fromthe top 167 stacks no later than 2018 (See the MANE-VU "Ask," described in Section 3.4 ofthis SIP) . NESCAUM's preliminary modeling for MANE-VU showed that reducing SOZ emissions from the targeted facilities by 90percent 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 CMAQto 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 fromimplementing the targeted EGU SOZ strategy. Improvements in PM2.5 

### 146concentrations would occur throughout the MANE-VU region as well as for portions of

the VISTAS and Midwest RPOregions, especially the Ohio River Valley. 

### Figure 11-3 Preliminary Estimate ofAverage Change in 24-hr PM2,5 Due to 90 Percent Reduction in SOZ Emissions from167 EGUStacks 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-VUdetermined, after consultation with affected states, that itwas unreasonable to expect that the full 90-percent reduction in SOZ emissions wouldbe 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 90percent benchmark. For a detailed description of this analysis, see Alpine Geophysics' report for MARAMAentitled "Documentation of 2018 Emissions fromElectric Generating Units in the Eastern United States for MANE-VU's Regional Haze Modeling, Revised Final Draft, April 21, 2008 (Attachment S) . 

### TargetedEGUSOZ EmissionsReductions areReasonable: MANE-VU identified specific EGUstacks that were significant contributors to visibility degradation at MANEVUClass I areas in 2002 based on CALPUFF modeling analyses documented in the Contribution Assessment. MANE-VUobtained information about existing and planned controls on emissions fromthose stacks. These analyses and the information on proposed 147EGUcontrols 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 TermStrategy) of this SIP. 

### Based on information gathered fromthe states and RPOs, MANE-VUanticipates that emissions frommany ofthe specific EGUstacks will be controlled as a result of EPA's CleanAir Interstate Rule (CAIR) . Since CAIRis a cap and trade program, it is not possible to predict with certainty which of the 167 stacks will in fact be controlled under CAIRin 2018. Four-Factor Analvsis - Tarmeted EGU SO Costs of Compliance Technologies to control the precursors of regional haze are commercially available.s7 BecauseEGUs are the most significant stationary source of SOZ, NO, and PM, they have been subjectto extensive federal and state regulations to control all three pollutants. The technical feasibility ofcontrol 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 fromcoal-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 ofControl Technologies for BART Eligible Sources," March 2005, Attachment R) . However, the last fewyears 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 of200to 500dollars 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 ofthe unit, as well as the capital cost of flue gas desulfurization (generally ranges from$150to $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 costvaries considerably among units and was estimated 57The information in this andthe next paragraph comes fromthe "Assessment of Control Technology Options for BART-Eligible Sources: SteamElectric 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 (2006dollars per tonof SOZ removed) Cost Range Technology Description Performance (2006dollars/ton of SO2 Reduced) Switch to a Low

Sulfur Replacehigh-sulfur 50-80%reductionin SO . Potential reductionin coal Coal (generally <1%

sulfiu) bituminous coal combustion emissions by switchingto a costs, bat possibly offset by with lower-sulfur coal lower-sulfur coal expensiveretrofits andloss ofboiler efficiency Switch to natural gas Replacecoal combustion Virtually ehminau SOZ Unknown -cost of switch is (Mrtually0°fa sulfur) with natural gas emissions by switching to currently uneconomical due natural gas to priceofnatural gas Coal Cleaning Coal is washed to remove 20-25% reductionin SO` 2-15% increase in fuel costs some ofthesulfur andash emissions based on current prices of priorto combustion coal Flue Gas Desulfittization SOZis removed from flue 30-95'%-+- reductionin SOZ $570-55,700for EGUs (FGD) -Wet gas by dissolving it in a emissions < :1 .200 MM' lime or limestoneslurry. $330-S570forEGUs (Other alkaline chemicals ==1,200 NM' are sometinies used) Flue Gas Destdlftuization Afine mistcontaining lime 60-95%-+- reductionin SO ; $570-S4,550for EGUs (FGD) -Spray Dry or otherstutable sorbent is etnissions --600 MW injected directly intoflue $170-S340for EGUs gas >dpp MW Flue Gas Desulfinzation Powdered lime or other 40-60''o reduction in S02 S250-S850for EGUs (FGD) -Dry suitable sarbent is injected emissions -300 MW directly intoflue gas Table refererues: 1 . EIAwebsiteaccessed on 2/20l07: huoJlwww .eia.doe.gov/cneaflcoaUpagelcoalnewslcoalmar .html 2 . EIAwebsiteaccessed on 2/20/07: bttaJlwww .eia.doe.govlcneaflcoallRageJacr/table3l_html 3 . STAPPAALAPCO

. Controlling FtneParticulate Matter UndertheCleanAirAct: .4 Menu ofOptions; March 2006. To predict future emissions and further evaluate the costs of emission controls for electric generating units, MANE-VUand 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 complyingwith 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, EPAupdated their input data and 58 CAMRwas also vacated by the federal courts and is no longer in effect . 

### 149developed 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 EPAwill propose a revised or new rule in accordance with the court's July 11, 2008 decision. 

### The RPOs collaborated with each otherto update EPABase 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 firmICF 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 frun 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 _1f 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-VUestimates that the marginal cost of SOZ reductions (the cost of reducing an additional ton ofemissions) 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-VUAsk

. 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 90percent target established in the Ask. Given the significance of SOZ emissions from specific EGU's to visibility impairment in MANE-VUClass I areas, the MANE-VU Commissioners, after weighing all factors- the availability oftechnology to reduce emissions, the estimated cost ofcontrols, 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 forbase-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 fromthe 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 fromthe SIP submittal date. The MANE-VU s9See thereport, Comparison ofCAIRand CAIR+Proposal usingthe Integrated Planning Model (IPM®), ICF Resources LLC, May2007, Attachment U . bo See Table 6, "Allowance Prices (Marginal Costs) ofEmissions Reductions. . ." p. 9, ICF, May2007, 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 aresult ofadditional EGUcontrols. These included potential adverse impacts on fuel supplies if there were large-scale fuel switching, the triggering of NSR requirements, and the generation ofwastewater 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 andnatural landscapes. Reductions would also result in decreases in ambient levels ofPM2,5with corresponding health benefits. The MANEVUstates concluded that the energy andnon-air quality impacts ofadditional EGU controls are reasonable. Maine agrees with this conclusion Remainin 

### Useful Life ofAnv 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 ofmany 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 fromother 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 confusedwith the economic decision ofwhether or not to continue operating a unit or to re-power or replace it. The cost of environmental compliance is only one ofmany factors involved in such a decision. 

### 11 .4.4 Non-EGU S02 Emissions Reduction Strategy Outside the MANE-VURegion 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 lowsulfur 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 MRPOregions, 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 ofthis strategy onvisibility at MANE-VU Class I areas, MANEVU had to make reasonable assumptions aboutwhere the requested emissions reductions would occur in the VISTAS and MRPOstates without knowing precisely how those 

### 151reductions 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 MRPOstates: 

### " Coal-Fired ICI Boilers: SOZ emissions were reducedby 60percent " Oil-Fired ICI boilers: S02emissions were reduced by 75 percent " ICI Boilers lacking fuel specification: SOZ emissions were reduced by 50percent 

### " For additional controls only in the VISTAS states: SOZ emissions from other area oil-combustion sources were reducedby 75 percent (based on the same SCCs identified in MANE-VU's oil strategies list) This modeling scenario representsjust 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. 

### Anumber 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 EPAto hold these states responsible for satisfying the MANE-VUAsk in the course of preparing their first five-year progress reports inorder to meet the CAA national goal of remedying any existing visibility impairment in Class I areas. NonEGUSOZ Emission Reductfons Measures Outside the MANE-VURegion are Reasonable: After EGUs, ICI boilers and heaters are the next largest class of SOZ emitters . ICIboilers 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 25years. However, according to the 1998 survey of industrial boilers by EPA (2004), only 2percent of gas-fired boilers and 3 percent ofoil-fired boilers had installed any kind of airpollution control device. Alarger percentage ofcoalfired boilers had installed airpollution control devices: specifically, 47 percent had installed some type ofcontrol device, mainly to control particulate matter (PM) . Postcombustion SOZcontrols were used by less than one percent of industrial boilers in 1998, with the exception of boilers firing petroleumcoke (2 percent ofboilers firing petroleum coke had acid scrubbers) . Asmall percentage of industrial boilers had combustion controls in place in 1998, although since 1998, additional low-NOXfiring systems may have been installed since that date. Almost all SOZemission control technologies fall in the category of reducing SOZ after its formation, as opposedto minimizing its formation during combustion. The method of SOZcontrol appropriate for any individual ICI boiler is dependent upon the type of boiler, type offuel, capacity utilization, and the types and staging ofother airpollution control devices. However, cost-effective emissions reduction technologies for SOZare available and are effective in reducing emissions fromthe exhaust gas streamofICI boilers. Post152

### combustion SOZcontrol is accomplished by reacting the SOZin 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. S02reduction technologies are commonly referred to as Flue Gas Desulfurization (FGD) and are usually described in terms ofthe process conditions (wet versus dry), byproduct utilization (throwaway versus saleable) andreagentutilization (once-through versus regenerable) . The exceptions to the nearly universal use ofpost-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 from20to 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 20to 25 percent for switching to low-sulfur fuel(s) to a high of 60to 95 percent forwet FGDand spray dry FGD . The majority ofcontrol strategies, however, are capable of achieving a 60percent or greaterreduction. Thus, assuming that coal-fired ICI boilers adopt varying levels ofcontrols, with most choosing a 50to 70 percent reduction strategy and fewer choosing either the 20percent 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 FGDsystems represent 85 percent of the FGDsystems in use in the United States and that FGDsystems have an average S02removal efficiency of 78 percent. MANE-VU's modeling ofa 60 percent reduction in SOZ emission fromcoalfired 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 froma low of 40to 60 percent for dry FGD, to a high of 60to 95 percent for spray dry FGD . For comparison, the MANE-VUlow

sulfur fuel strategy assumes a 50 to 90percent reduction in SOZ emissions from

oil-fired ICI boilers. Assuming a typical distribution ofcontrol 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 50percent 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 fromthe MRPO, this assumption also encompasses some of the uncertainty regarding the implementation ofMANE-VU's non-EGU Ask. Given the paucity ofdata, 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 ofthe suggested S02 control options capable of achieving an average 50percent SOZ reduction at these sources is a reasonable assumption. 

### 153

### Table 11-7 Available S02Control Options for ICI Boilers Technology Description Applicability Performance Switch to a LowSulfur 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 fromflue 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 mediumsulfur 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 mediumsulfur fuels 

### For emissions fromother area oil-combustion sources inthe 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 ofthis strategy was presented in Section 11 .3.2. Four-Factor Analysis - Non-EGU SO_ 2 Emission Reduction Measures Outside MANE-VU 

### Based on the survey of available technologies outlined above and the four-factor analysis summarized below, MANE-VUconcludes that each ofthe strategies assumed for modeling purposes to meet the MANE-VUAsk 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 ofCompliance

Industrial boilers have a wider range ofsizes than EGUs and often operate over awider 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 ofthe 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 $130per 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 fromthis report. Dollar amounts originated fromEPApublications cited in the report and have been converted to 2006 dollars using a conversion factor from www .inflationdata.com

. 

### o Cost ofFuelSwitching: Although fuel switching can be a very effective means of reducing S02emissions (reductions of 50to 99

.9 percent are possible), burning low-sulfur fuel may notbe a technically feasible or economically practical SOZcontrol alternative for every ICI coalfired boiler. Factors impacting applicability include the characteristics of the plant and the particular type offuel 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 #6fuel 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 ofcoal 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), andthe cost ofany necessary boiler or coal handling equipmentmodifications. Many plants will be able to switch fromhighsulfur 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 notbe 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 fromcoal combustion to natural gas combustion virtually eliminates SOZ emissions. It is technically feasible to switch fromcoal 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 ofnatural gas. Natural gas is currently about twice times the price ofcoal in terms of heating value, but has been as high as seven times the price ofcoal in recent years.

6'MANE-VU's Reasonable Progress Reportis entitled "Assessmentof Reasonable Progress for Regional Haze in MANE-VUClass IAreas" prepared by MACTECfor 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 ofphysically cleaning coal varies from$1 to $10per ton of coal cleaned, depending on the coal quality, the cleaning process used, and the degree ofcleaning 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 20to 25 percentreduction in SOZemissions. Coal cleaning also increases the heating value ofthe 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 ofthe 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 SOZcontrols in the formof FGDhas several impacts on facility operations, maintenance, and waste handling procedures. FGDsystems 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 FGDsystem . Solid waste handling is another factor that influences the cost of FGDcontrol systems. Significant waste material may be generatedthat requires disposal . These costs may be mitigated, however, by utilization ofa forced oxidation FGDprocess 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 MMBTUIhri 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

### Tablel l-9 presents the total estimated cost effectiveness ofadding FGD-based SOZ

controls for different boiler sizes, fuel types, and capacity factors. There is no indication that these cost data include revenue fromgypsum sales, which would partially offset the costs of FGDcontrols. 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 FGDcannot yetbe 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 10years. 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 ofpre-combustion controls (fuel switching or cleaning) and a 3-year period for the installation ofpost-combustion controls . MANE-VUhas therefore concluded that there is sufficient time between 2008 and 2018 forthe affected states to adopt emission control requirements and for affected sources to install controls necessary to meet MANE-VU's requested SOZemission reductions fromnon-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 ofthe 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 ofelectricity to operate blowers and circulation pumps. In addition, some combinations of FGDtechnology andplant configuration may require flue gas reheating to prevent physical damage to equipment, resulting in higher fuel usage. The primary non-air environmental impacts offuel switching derive fromtransportation of the fuel . Secondary environmental impacts derive from waste disposal and material handling operations (e.g. fugitive dust) . For FGDsystems, the generation ofwastewater and sludge fromthe SOZremoval process is a consideration. Wastewater fromthe 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 from1,400 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 fromICI boilers wouldhave 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-VUhas concluded that the energy and non-air environmental impacts of

controlling SOZ emissions fromICI boilers arejustified in lightof 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 ofAny Potentially Affected Sources Available information for remaining useful life estimates of ICI boilers indicates a wide range ofoperating time, depending on size of the unit, capacity factor, and level of maintenance performed. Typical life spans range fromabout 10years 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 ofICI boilers, the technical options available, and the flexibility that non-MANE-VUstates would have to meet the Ask, MANE-VUhas concluded that its request for a 28 percent reduction in non-EGUSOz 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 ofvarious 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 "2018Visibility Projections," March 2008, (Attachment Q) . The following information about the effects of specific strategies is taken fromthese reports. The NESCAUM

modeling demonstrates that significant visibility benefits will accrue fromimplementation ofthe 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 yellowbars represent expected visibility at MANEVUClass I areas in 2018. Comparison of these values with the 2018 "glide slope" values (the plum-colored second bars fromthe left) shows that all areas are expected to experience visibility improvements that meet or exceed the uniformrate of progress calculated for each area. The second figure shows that, for the 20percent 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 ofpreventing 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 02018 Glideslope ~ 2018Projected 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 TermStrategy

40 CFRSection 51 .308(d)(3) requires the State ofMaine to submit a long-termstrategy 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 GulfWilderness Area; Presidential Range-Dry River Wilderness; Moosehorn Wilderness and Roosevelt Campobello International Park. The long-termstrategy 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-VUwhen developing the emission management strategies in this SIP . The following describes how Maine meets the long-termstrategy requirements of the Regional Haze Rule. Maine's long termstrategy 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 andreview . In developing this long-termstrategy, Maine also considered the requirements ofthe Clean AirAct, 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 EPAon April 24, 2008. As that document observed, states must include provisions in their implementation plans to prohibit any source or activity fromemitting air pollutants in amounts that would interfere with another state's ability to prevent significant deterioration ofair quality and visibility. The long-termstrategy presented herein is designedto protect visibility in Maine as well as in areas outside ofMaine that are affected by Maine emissions. 12.1 Overview

of the Long TermStrategy Development Process The regional strategy development process identified reasonable measures that would reduce emissions contributing to visibility impairment at MANE-VUClass I areas by 2018 or earlier. The process for identifying potential emission reduction measures and the technical basis forthe long termstrategy 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 ofCAIRand CAIR Plus Proposal using the Integrated Planning Model®" (also known as the CAIR+ Report), May 30 . 2007, ICF/MARAMA (Attachment U) . " "Assessment ofReasonable 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: SteamElectric 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-VUreviewed a wide range ofpotential control measures to reduce regional haze at the affected Class I areas by the 2018 milestone. The process ofchoosing a set of proposed regional haze control measures started in late 2005. The Ozone Transport Commission (OTC) selected a contracting firmto assist with the analysis of ozone and regional haze control measure options, and provided the contractor with a "master list" of some 900potential control measures, based on experience and previous state implementation plan work. With the help ofan internal OTCcontrol measureworkgroup, the contractor narrowed the list ofavailable regional haze control measures for further consideration by MANE-VU . MANE-VUthen developed an interimlist ofcontrol measures for regional haze. The identified control measures can be divided into five general categories: " Beyond-CAIRsulfate 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 CAIRand provides a cost analysis for additional SOZ and NOXcontrols 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: SteamElectric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities." 

### The beyond-CAIREGUstrategy quickly became central to the MANE-VUlong term strategy planning efforts, since EGUsulfate emissions are the largest contributorto 162

### visibility impairment at MANE-VUClass 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 oflow-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 interimlist of control measures to make additional refinements. States determined, for example, that there may be too few coal-fired ICI boilers in the MANEVUstates 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, ofwhich there are fewin 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 fromthese 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 ofconcerns related to enforcement and penetration of existing state regulations" . 

### 12. 3 The Technical Basis for Strategy Development 40 CFRSection 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 ofother 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 ofBaseline andNatural Background Visibility Conditions at MANE-VUClass 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: AConceptual 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- 096CMRChapter 102 Open Burning and06-096 CMRChapter 150Control ofEmissions 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

(AttachmentA) . "Comparison of CAIRand 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-VUClass 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 Paperand 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) . 

### "2018Visibility 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, Maineworked with the other members of MANE-VU and with the OzoneTransport Commission to evaluate a large number of potential emission reduction strategies covering a wide range ofsources 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-termstrategies. 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 ofusing low-sulfur heating oil ; and Residential wood combustion and open burning. 164

### These efforts led to the selection ofthe 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 TermStrategy, 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 notyet 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 thatwere 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 fromElectric 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 EGUemission 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-termstrategy to mitigate regional haze. 

### 165Clean 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 CAIRwas implemented on an interimbasis in 2009, and EPA is expected to issue a revised CAIR rule in response to the remand in 2010or 2011 . To predict future emissions fromEGUs 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 EGUsources as documented in the Alpine Geophysics report listed above. In making these adjustments, emission controls originating fromthe 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) . 

### " RCSAsection 22a-174-22, limiting the non-ozone seasonal NOx emission rate to 0.15 lb NOx/MMBtu for fossil fuel-fired EGUs greaterthan 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 ofStationary Generator Emissions, SOz, PM, VOCandNO,, 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.

64The IPM

model runs alsoanticipated the implementation of EPA's CleanAir Mercury Rule (CAMR), whichwas recently vacated by the courts. However, MANE-VUbelieves that the adjustments made to the predicted SOZ emissions fromEGUs will have a larger effect on the air quality modeling analysis conducted for this SIP than will the vacatur of the CAMRrule. The emission adjustments were basedon state's comments on the actual levels ofSOZ controls expected to be installed in response to state-specific regulations and EPA's CAIR rule. MANE-VUbelieves these adjustments improvethe reliability ofboth the emission inventory and modeling results. 

### 1663. Regulation No. 1148, Control ofStationary 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: S02emissions 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 fromthe 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 102tons in 2018 (a 90 percent reduction) . Maine EGU Regulations: Chapter 145 NOXControl 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 250and 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 EGURegulations: Based on the Massachusetts Department of Environmental Protection's 310CMR 7 .29, Emissions Standardsfor PowerPlants, 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 50percent reduction in NOXemissions 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 NOXand SOZ standards between 2004 and 2008. This regulation also limits the six grandfathered EGUs to a C02emission rate of 1,8001b/MWh. New Hampshire EGURegulations: New Hampshire adopted the following regulations governing EGUemissions: " Chapter Env-A 2900capping NOXemissions at 3,644 tons NOXperyear, SOz emissions at 7,289 tons S02 peryear, and C02 emissions at 5,425,866 tons COZ per year for all existing fossil steamunits by December 31, 2006 . 

### " Chapter Env

A3200NOzBudget TradingProgramlimiting ozone season NO,, emissions on all fossil fuel-fired EGUs greaterthan 15 MW to 0 .15 lb/MMBtu, effective November 2, 2007. New Jersey New

Source ReviewSettlement Agreements: The New Jersey settlement agreement with PSEGrequired the following actions for specific EGUs: " Bergen Unit #2: Repower to combined cycle by December 31, 2002. " Hudson Unit #2: install Dry FGDor approved alternative technology by Dec. 31, 

### 1672006 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 SCRor 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 FGDor approved alternative technology by Dec. 31, 2010to 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 SCRor 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, 2006to limit NOX emissions to 0 .13 lb NOx/MMBtu.

. For Mercer Unit #2: install Dry FGDor approved alternative technology by Dec. 31, 2012 to control SOZ emissions, and operate the control technology atall times the unit operates to limit SOZ emissions to 0.15 lb SOz/MMBtu, and install SCRor approved alternative technology by 2004 to control NOx emissions, and operate the control technology ozone season only in 2004 andyear-round by May 1, 2006 to limit NOXemissions 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 6NYCRR 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 6NYCRR 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 NOXemissions 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 2004consent agreement calls for Santee Cooper in South Carolina to install and commence operation ofcontinuous 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 allocatedto Santee Cooper Systemas a result ofsaid agreement ; and to comply with emission unit limits ofsaid 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 interimpollution reduction measures to reduce emissions while the permanentcontrols 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 S02and NO,, emissions each year fromeight coal-fired electricity generating plants inVirginia andWest Virginia. 

### GulfPower 7

: A2002 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 ofvarious control measures as documented in "Development of Emission Projections for 2009, 2012, and 2018 for Non-EGU, Area, and Nonroad sources in the MANE-VURegion" (Attachment I) . Control factors were applied to the 2018 MANE-VUinventory for non-EGUs to represent the following national, regional, or state control measures:

. NOX SIPCall Phase I (NOX Budget Trading Program) (except ME, NHand VT)

. NOX SIPCall Phase II (except ME, NHandVT ) " NOX RACT in 1-hour Ozone SIPs (already included in the 2002 inventory) " NOX OTC2001 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 inventorywas prepared before the MACT for Industrial Boilers and Process Heaterswas vacated. Control efficiency was assumedto be at 4percent for SOZ and 40 percentfor 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 OzoneTransport 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 committedto adopting these measures in their ozone SIPs) . For specific states, the ozone reduction strategies included in the modeling would reduce NOXemissions fromthe following non-EGUpoint 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 : A2007 agreement calls for E. I . Dupont Nemours &Company's James River plant to install dual absorption pollution control equipmentby September 1, 2009, resulting in emission reductions of approximately 1,000 tons SOZannually. The James River plant is a non-EGUlocated in the state of Virginia. Stone Container: A 2004 agreement calls forthe 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 3,500tons 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 2002Version 3.0 

### inventory. Area source control factors were developed and incorporated in the modeling for the following national or regional control measures:

" OTCVOCModel 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

VOCand NO,, emissions for the following area source categories for some states (as identified below) :

. VOCcontrol measures for adhesives and sealants (controls added in all MANE-VUstates except VT) ; " VOCcontrol measures for emulsified and cutback asphalt paving (controls added in all MANE-VUstates except ME, and VT) ; " VOCcontrol 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 fromthose Region's RPOs. Some of the area source control measures listed above may have been developed by states for the primary purpose of reducing ozonewithin the OzoneTransport 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 (ORVR) Rule: The 1990Clean Air Act (CAA) Amendments contain provisions that require passenger cars to capture refueling emissions . In 1994, EPApublished the ORVRrule 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 CAAauthorizes EPA to allowstate 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 Standardsfor Trucks and Buses: EPAset a PM emissions standard for newheavy-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 NMHCstandards will be 

### 171

### phased-in together between 2007 and 2010for diesel engines. Sulfur in diesel fuel must

be lowered to enable modernpollution-control technology to be effective on these trucks and buses. EPA began requiring the use of 500ppmlow sulfur diesel fuel in 1993. In 2006, the highway diesel sulfur content was lowered to l5ppm (ultra low

sulfur diesel) . Tier 2Motor Vehicle Standards: Tier 2 is a fleet averaging program, modeled after the California LEV II standards. Manufacturers can produce vehicles with emissions ranging fromrelatively dirty to zero, but the mix ofvehicles a manufacturer sells each year must have average NOX emissions belowa 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 calculatedwith 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 ofAir Pollution; Determination ofSignificance for Nonroad Sources and Emissions Standards for New Nonroad Compression Ignition Engines At or Above 37 Kilowatts," 59 FR31306, June 17, 1994. " "Control of Emissions ofAir Pollution FromNonroad Diesel Engines," 63 FR 56967, October 23, 1998. " "Control ofEmissions FromNonroad Large Spark-Ignition Engines and Recreational Engines (Marine and Land-Based) ; Final Rule," 67 FR 68241, November 8, 2002. 

### " "Control of Emissions ofAirPollution 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 CFRSection 51 .308(d)(3)(v), Maine andthe other MANE-VU states applied a four-factoranalysis 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-VUstates have identified other control measures that were found tobe 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-termstrategy for improving visibility at MANE-VUClass I Areas. Specifically, the MANE-VUlong-termstrategy includes the following additional measures to reduce pollutants that cause regional haze: Timely implementation ofBART requirements; " Alow

sulfur fuel oil strategy in the innerzone 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 #6residual oil to 0.3 - 0.5 percent sulfur by weight by no later than 2012, and o Furtherreduce the sulfur content ofdistillate oil to 15 ppm by 2016; " Alow

sulfur fuel oil strategy in the outer zone states (the remainder of the MANE-VUregion) to reduce the sulfur content of- * Distillate oil to 0

.05 percent sulfur by weight (500 ppm) by no laterthan 2014, o #4 residual oil to 0.25 percent-0.50 percent sulfur by weight by no later than 2018, 

### o #6residual oil to no greater than 0 .5 percent sulfur by weight by no later than 2018, and o Further reduce the sulfur content ofdistillate oil to 15 ppm by 2018 depending on supply and availability; " A90percent or greater reduction in sulfur dioxide (SOZ) emissions fromeach 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 ofvisibility in each mandatory Class I Federal area in the MANE-VUregion. If it is infeasible to achieve that 173

### level of reduction fromaunit, alternative measures will be pursued in such State; and " Continued evaluation ofother 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-VUstates have agreed to pursue for the purpose of mitigating regional haze. The corollary is that the MANEVUClass I states (Maine, New Hampshire, Vermont, and New Jersey) are asking states outside the MANE-VUregion that contribute to visibility impairment inside the region to pursue similarmeasures. The control measures that non-MANE-VU states choose to pursue may be directed toward the same emission source sectors identified by MANEVUfor its own emission reductions, or they may be equivalent measures targeting other source sectors. Underthe MANE-VU long-termstrategy, 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 (40CFR51 .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 ofimplementing 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 CMAQmodeling analysis, as described previously in Subsection 11 .5 of this SIP. The modeling assumed that 12 units at seven BART-eligible sources in MANE-VUwould 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-VUas 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 CMAQmodeling. Additional visibility benefits are likely to result fromthe 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-VUClass I Areas that would likely result from such measures. 12.5.2 Low-Sulfur Oil Strategy 66For EGU's , EPA determined that CAIRwould 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 #6residual), and a minimumof 75% andmaximum

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 fromusing the low-sulfur #2distillate for space heating in the residential and commercial sectors. The costs of these emission reductions are estimated at $550to $750per 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 lowsulfur 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 atAcadia National Park and Other Federally Designated Class I Areas," which implements the MANE-VU lowsulfur fuel strategy in Maine. This legislation establishes a statewide sulfur limit for distillate fuels of 50 ppm in 2016, and 15 ppmin 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 froma 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-VUhas identified emissions fromthe top 167 EGUemission points that contribute most to visibility impairment at MANE-VUClass I Areas (see Figure 12-1) . Controlling emissions fromthese 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 fromthe 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 fromdry 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$170to $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-VUanalysis, Wyman Station Unit #4, which is located in 

### 175

### located in Yarmouth, Maine. As a signatory to the MANE-VUstatement ofprinciples

(Attachment D), Maine is committed to pursue additional emission reductions at this facility through its low

sulfur fuel oil program

. Maine DEPbelieves that the use of lowsulfur fuel at this facility (in lieu ofadd-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. Formore 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 inthe long-termstrategy 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 8,900tons) . 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 minimumof 80% removal efficiency. Phase 11 (2013) requires a: 12-month rolling average of a minimumof 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 

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### Figure 12-1 167 EGUStacks 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 ofthe largest fossil fuel-fired power plants in Massachusetts must comply with emissions limitations. For mercury (Hg), 6facilities 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, IC1, 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 SalemHarbor (Units 1, 2, 3 and 4) . New Hampshire EGULaws and Regulations: New Hampshire amended the following laws and regulations governing EGUemissions: 

### " 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 lawallows 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 MACT 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.) ConsentAgreements in the VISTASRegion: The following consent agreements in the VISTAS states were reflected in the emissions inventories used for those states : East Kentucky Power Cooperative: AJuly 2, 2007 consent agreement between the EPAand East Kentucky Power Cooperative requires the utility to reduce its emissions of SOzby 54,000 tons per year and its emissions ofNO,, 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 fromthe plants will decrease between 50and 75 percent from2005 levels. As with all federal consent decrees, EKPCis precluded from using reductions required under other programs, such as CAIR, to meet the reduction requirements ofthe consent decree. EKPC is expected to spend $654 million to install pollution controls. American Electric Power : Under this agreement, American Electric Powerwill spend $4.6 billion dollars for emission controls at sixteen plants located in Indiana, Kentucky, Ohio, Virginia and WestVirginia. These control measures will eliminate 72,000 tons ofNO, emissions each year by 2016and 174,000 tons of S02 emissions each year by 2018. 

### 12.6 Source Retirement and Replacement Schedules 40 CFRSection 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 CFRSection 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 ofconstruction 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 andprecursor emissions (S02 and NOX) from

construction vehicles. At the state level, Maine currently regulates emissions offugitive dust through its 06-096 CMRChapter 101, Visible Emissions rules, which establishes opacity limits for emissions from

several categories ofair contaminant sources, including fugitive emissions fromconstruction activities. Maine also regulates emissions fromboth on-road vehicles and construction activities through its 06-096 CMRChapter 127 New Motor Vehicle Emission Standards rules (new motorvehicle emission standards), the 06-096 CMRChapter 147 Diesel-Powered Motor Vehicle Emission Standards rules (opacity standards), and the 06-096 CMRGeneral 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, froma regional haze perspective, crustal material generally does not play a majorrole at MANE-VUClass I Areas. On the 20percentbest visibility days during the 2000-2004baseline period, crustal material accounted for 6to 11 percent ofthe particle-related light extinction at MANE-VU Class I Areas. On the 20percent worst visibility days, however, the ratio was reduced to between 2and 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 ofconstruction 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 Management 40 CFRSection 51 .308(d)(3)(v)(E) requires Maine to consider smoke management techniques relatedto agricultural and forestry management in developing its long-term strategy. MANE-VU's analysis ofsmoke management in the context ofregional haze SIPs is documented in "Technical Support Document on Agricultural and Forestry Smoke Management in the MANE-VURegion," 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 ofwood 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 andwild lands make up only a minor fraction ofwood burning emissions and cannot be reasonably addressed in this SIP . Fires that are coveredunder 180

### smoke management plans, including agricultural andprescribed forest burning, constitute

less than one percent oftotal wood smoke emissions in MANE-VU6' . Moreover, smoke emissions fromall sources represent only a minor fraction offineparticle 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 4percent offine particle mass on days ofworst and best visibility. Additionally, elemental carbon absorbs light more readily than it scatters light. It is therefore reasonable to conclude that smoke emissions fromcontrolled agricultural and forestry burning contribute, on average, only a small fraction of one percent oftotal light extinction on days ofboth 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-VUregion, and is a significant contributorto 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 ofEmissions fromOutdoor 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 of0.32 lbs/MMBTU heat output (Phase II) . 

### 06-096 CMRChapter 150Control of Emissions fromOutdoor Wood Boilers, which incorporated the OWHHparticulate emission standards adopted by the Legislature, became effective November 1, 2007, and also established setback, stackheight, particulate emission limits, and fuel requirements for outdoor wood boilers (See Attachment BB) . Chapter 150was subsequently amended 61 to control the sale, installation, use, and siting ofoutdoor wood boilers that combust biomass pellets as fuel . Maine is submitting this rule to EPAfor 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' Forexample, PM2

.5 and PM

10 emissions fromagricultural burning andforestry management activities account for only 0

.139%and0.157%oftotal 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 fordetermining whether an outdoor wood boiler constitutes a nuisance condition or threat to public health or safety and is eligible foruse of the fund, compensation criteria and amounts and procedures for certification and verification of removal and possible replacement ofeligible outdoor wood boilers. Pursuant to this legislation, the Department adopted the 06-096 CMRChapter 160, Outdoor Wood Boiler Replacement and Buy Back Program rules, which establish a replacement andbuy back program to remove nuisance outdoor wood boilers that were installed prior to February 1, 2008and replace them with approved heating appliances. The Department will maintain a list of nuisance outdoorwood boilers and prioritize them for the programbased 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 allpossible 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 residentialwoodstove replacement program in the Maine Department of Environmental Protection. Underthis program, eligible participants will be able to receive funding toward the purchase of new cleaner-burning residential heating appliances to replace olderwood stoves that are not certified by the EPAlower 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-TermStrategy 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-termstrategy. 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 longtermstrategy. Those visibility improvements will result, in part, fromthe efforts identified in this SIPto 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 oftheir Class I Areas. The control measures included in this SIP represent the reasonable efforts of Maine, in conjunction withthe efforts of other MANE-VUstates, toward achieving thereasonable progress goals established by the affected states. 182Based 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 ofregional 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 years69- No changes were predicted for sea salt because the model does not track this component. The 2000-2004visibility readings at affected Class I areas provide the baseline against which future visibility readings will be measured to assess progress deriving from implementation ofMaine's Regional Haze SIP and those of the other MANE-VUstates. 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 20percent worst day values represent average visibility conditions for the top and bottom quintiles. To create the series ofvisibility 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 20percent of days having best visibility were averaged, and the process repeated for the 20percent of days having worst visibility. The resulting averages represent the projected upper and lower quintiles ofvisibility 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 20percent best visibility average value as determined frommonitoring data for eachyear of the period 2001-2005. The irregular red line (^') represents the 20percent worstvisibility average value as determined frommonitoring data for eachyear of the period 2001-2005. " The straight orange line (-) represents the 20 percent best visibility average value as determined frommonitoring data for the 5-year period of 2000-2004 . (This line represents the 20percent best visibility baseline condition.) " The straight blue line (-) represents the 20percent worst visibility average value as determined frommonitoring data for the 5-year period of 2000-2004. (This line represents the 20percentworst visibility baseline condition.)

69Specifically, the fire emissions inventory used in VISTAS for the base year relied on an earlierversionof fire emissionsdata than the one used for the 2018 inventory. 

### 183

### " The straight broken line (. . . .) is a continuation of the 20percent best visibility baseline, representing the 20 percentbest visibility condition as it would be with no further degradation or improvement. The straight green line (-) represents the 20percent worstvisibility values that establish the uniform

rate of progress forthe period 2004-2064 . (This line is sometimes referred to as the uniform progress line, or "glide slope . " Itwas created by linear interpolation between the 20percent worst visibility baseline value in 2004 and the 20percent worst visibility value under natural conditions in 2064. Ifvisibility improvements match this rate ofprogress, actual visibilitywill return to natural conditions in 2064) . " The light-green dash ( ) shown at 2064 represents the theoretical 20percent best visibility value undernatural conditions (i .e., no anthropogenic emissions) . " The purple star (*) represents the 20percent best visibility value in 2018 after implementation of MANE-VU's long-termstrategy, as predicted by the CMAQ model . (This value is a reasonable progress goal .) 

### " The blue star (*) represents the 20 percentworst visibility value in 2018after implementation of MANE-VU's long-termstrategy, 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-VUClass I Areas affected by emissions originating in Maine. Figures 12- 2and 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-termstrategy (See the blue cross mark) . This improvement is compared to the Uniform Rate ofProgress for affected Class I areas (see green sloping line) . Notethat the blue cross mark is below the green line as it passes over the 2018 date marked at the bottomof 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 ofdeciviews means better visibility.) Figure 12-4 demonstrates that GreatGulfWilderness Class I area in New

Hampshire, which is significantly affected by Maine emissions, is also projected to meet or exceed the uniformrate of progress goal for 2018. All Class I areas affected by Maine emissions are also projectedto have no degradation fromcurrent baseline bestvisibility. 12.9 Implementation of the Regional Haze Strategies in Maine 40 CFRSection 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-termstrategy 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 anumber of emission control programs. Figure 12-2 Projected Visibility Improvement atAcadia National Park Based On 2018 Best and Final Projections

-'+'-20% Worst Observed ---20%

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### Figure 12-3 Projected Improvement in Visibility at Moosehorn National Wildlife Refuge and Roosevelt Campobello International Park based on 2018 Best and Final Projections

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### Figure 12-4 Projected Visibility Improvement at Great GulfWilderness Based on Most Recent Projections for 2018

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### As previously noted, Maine has adopted, and will implement, the following measures as part of its long-termstrategy to meet the reasonable progress goals: l . A lowsulfur 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 programto reduce wood smoke emissions fromoutdoor 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 followingrestrictions 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%byweight ; (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 fromthe lowsulfur 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 froma 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-sulfur7l 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 forhigh-sulfur distillate72 the Department believes that this fuel will notbe readily available, and will likely be more expensive than the more widely-used 15 ppm distillate. Distributors and wholesalers ofdistillate fuels have noted that supplying highsulfur distillate to a limited market introduces additional costs to their industry in the formofsegregated storage and transportation/delivery systems, since even incidental contamination (co-mingling) can lead to non-compliance issues.73 Recognizing the potential for incidental contamination ofULSD, segregated storage and transportation/delivery systems are probably the only mechanisms that can assure compliance with federal and state ULSDrequirements for the petroleummarketing industry. Given the low demand, and additional storage, transportation anddelivery costs, the Department does not believe that high sulfur distillate fuel will be widely used by the manufacturing sector in 2018and later.74 '°Rules must be adopted and submitted to the Maine Legislature forapproval byJanuary 1, 2014. '1 Containing 2,000-5,000 ppm sulfur. 72All other users ofdistillate (diesel) fuel in Mainewill be subject to the 15 ppm sulfur limits (including eneral use andspace heating at manufacturing facilities) . ,3 For example, only 7 gallons ofa 5,000 ppm sulfur fuel added to 7,500gallons ofULSDwould raise the sulfur content by 5.0 ppm . 74As noted above, Maine believes that future (2018) use ofdistillate fuel by the manufacturing sector will be limited due to cost and compliance concerns. Nevertheless, projected 2018 SOZ emissions for Maine have been adjusted toaddress this exemption, andits 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 anddistillate 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 workingwith EPAto develop these rules, and will submit themfor inclusion into the SIP . 12.9.2 BART in Maine As required by 40 CFR §51 .308(e), the Maine Regional Haze SIPincludes 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 ofvisibility 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 EG UStrategy in Maine As noted in section 12.5.3, above, MANE-VU's agreed regional approach forthe EGU source sector is to pursue a 90percent control level on S02 emissions fromthe 167 identified stacks by 2018. Maine has one EGU identified in the MANE-VUanalysis; 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 offour generationunits, all ofwhich fire #6 residual fuel oil . The fifth unit is a smaller oil-fired auxiliaryboiler which provides building heat and auxiliary steam, and the sixth unit is an emergency backup diesel generator that provides electricity foruse on-site. Unit #4 is powered by a Foster Wheeler boiler with a maximum design heat input of 6290 MMBtu/hr, firing #6and #2 fuel oil . This unit is equippedwith 30 front wall fired burners capable of firing up to 41,333 gal/hr. Boiler #4was 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 1,170tpy 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 ofthis 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 forcoal-fired generation in 2008 was 72.2 percent. 

### 188VUTargeting 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 frombaseline (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 ofthis 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 CMRChapter 150 Control of Emissions fromOutdoor 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-termstrategy 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 otherair 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 ; andthose reductions will be largely due to the implementation ofthe 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 andthe other MANE-VUClass 1 states (see Section 11 .2, above) . However, since the Maine Low Sulfur Oil Programand efforts to reduce emissions at Wyman Station Unit #4 differ slightly fromthe programs and emission reductions modeled as reasonable progress goals, Maine must demonstrate that its long-termstrategy will achieve the reasonable progress goals established by the Regional Haze SIP. In an effort to demonstrate that the long-termstrategy 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 forpoint 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-EGUcombined) ; well below the 19,888 tpy utilized in the MANE-VU reasonable progress modeling. Table 12-3, below, illustrates the MANE-VU2002 (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 andmobile source inventories by the end of the first implementation period resulting frompopulation 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 S02emissions by 73.4 percent, as compared to the compared to the projected reduction of 67.5 percent in the MANE-VUregion. 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 andAA

.

Table 12-2 76Since the Maine long-termstrategies for non-pointsources do notdiffer from those modeled, it is not necessaryto update other source categories at this point in time. 77 Maine's projected2018 inventory is basedon Maine's 2008 Point Source Inventory . Records were matched at the process unit level to the 2002 MANE-VUInventory. In developing the Maineprojected 2018 point source inventory, the Department choseto a unitary growth factor (1) . This decision was based on the significant reductions in Maine point source SOZemissions that occurred between 2002 and 2009. During this period, 25 facilities ceased operationand/or surrendered their air emission licenses, andwere removed fromthe point source inventory. Since Maine experienced a significant decline in point source SOZ emissions during theperiod from 2002 through 2008, we believe that a growth factor of 1 provides an appropriately conservative estimate ofprojected 2018 emissions when appliedto the 2008 point source inventory

. Additional information on growth rates and inventory adjustments I provided in Attachment AA, Documentationfor 2002-201 SOZ Inventories. 78The Department's analysis did not include gnyreductions fromthe use ofULSD (15 ppm) at point sources. 

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### SOZ Emissions fromPoint, 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 EGUPoint 9,299 6,806 Non-EGUPoint 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 fromPoint, Area and Mobile Sources in the MANE-VURegion 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 EGUPoint 77.6 64.4 Non-EGUpoint 65.4 Are a 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 lowsulfur fuel strategy and the targeted EGU strategy in Maine was enacted by the Maine Legislature on March 25, 2010, and signed into lawby Governor John Baldacci on April 5, 2010 . As noted in Section 12.9.3, Maine is committing to further analyze the visibility benefits thatwould 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 

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### 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 40CFR51 .308(d)(3)(v)(F) requires Maine to ensure that emission limitations and control measures usedto meet reasonable progress goals are enforceable. All control measures incorporated into law

or codified in administrative rules will be enforceable. Anyfacility subject to state or federal permit requirements, including BART-eligible and Vfacilities, 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 ofAir. Under 38 MRSA Chapter 2 and Chapter 4, the Department is authorizedto 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 ofMaine law

ofparticular 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 ofthe State in a coordinated state-wide programto controlpresent andfuture sources ofemission ofair contaminants to the end that airpolluting activities ofevery typeshall be regulated in a manner that reasonably insures the continued health, safety and general welfare ofall ofthe citizens ofthe State " 

### " 38 MRSA section 585 . Establishment ofemission standards, which states: "The board may establish andmay amendstandards, herein called "emission standards"; limiting and regulating in ajust and equitable manner the amount and type ofair contaminants which may be emitted to the ambient airwithin a region. Such emission standards shall be designed to prevent airpollution 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 andamend 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 andprevent airpollution " 

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### " 38 MRSAsection 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 contaminationsource or emit any air contaminants in that region without an air emission licensefromthe department" 

### " 38 MRSA sections 347-A, 347-C, and 349, whichprovide for the enforcementof all SIPmeasures; 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 ofthe Clean Air Act and rules promulgated by EPA

. The following regulations are of particular relevance to the Maine Regional Haze SIP: 

### 06-096 CMRChapter 100Definitions Regulation 06-096 CMRChapter 101 Visible Emissions Regulation 06-096 CMRChapter 102 Open Burning Regulation 06-096 CMRChapter 103 Fuel Burning Equipment Particulate Emission Standard 06-096 CMRChapter 104 Incinerator Particulate Emission Standard 06-096 CMRChapter 105 General Process Source Particulate Emission Standard 06-096 CMRChapter 106 Low Sulfur Fuel 06-096 CMRChapter 109 Emergency Episode Regulation 06-096 CMRChapter 110 Ambient Air Quality Standards 06-096 CMRChapter 114 Classification ofAirQuality Control Regions 06-096 CMRChapter 115 Major and Minor Source Air Emission License Regulations 06-096 CMRChapter 116 Prohibited Dispersion Techniques 06-096 CMRChapter 117 Source Surveillance 06-096 CMRChapter 121 Emission Testing of Resource Recovery Facilities 06-096 CMRChapter 126 Capture Efficiency Test Procedures 06-096 CMRChapter 127 New MotorVehicle Emission Standards 06-096 CMRChapter 138 Reasonably Available Control Technology for Facilities that Emit Nitrogen Oxides 06-096 CMRChapter 140 Part 70Air Emission License Regulations 06-096 CMRChapter 145 NOx Control Program 06-096 CMRChapter 146 Diesel-Powered Motor Vehicle Emission Standards 06-096 CMRChapter 148 Emissions fromSmaller-Scale Electric Generating Resources 

### 06-096 CMRChapter 149General Permit Regulation for Nonmetallic Mineral Processing Plants 06-096 CMRChapter 150Control of Emissions fromOutdoorWood Boilers 193

### 06-096 CMRChapter 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) programfor 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 > 50tons of any air contaminant) are implemented in Maine through the 06-096 CMRChapter 100 Definitions Regulation which was approved into the SIP on October 15, 1996'9, the 06-096 CMRChapter 113 Growth Offset Regulation which was approved into the SIP on February 14, 1996g°, and the 06-096 CMRChapter 115 Major and Minor Source Air Emission License Regulations which were approved into the SIP by EPA on February 14, 1996.g1'82 PSDis 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 PSDprogramis 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 CMRChapter 115 Major and Minor Source Air Emission License Regulations. The Ambient Air Quality Impact Analysis must demonstrate that the newallowable emissions will not result in an exceedence ofthe remaining increments for SO2, NOZ or PMIOin 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, andwill 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 60days 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 PSDpermitting programis an integral part of Maine's long-termstrategy 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 beingincorporated into the SIP, these revisions did not change anyof 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. 

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### 12.14 Reasonably Attributable Visibility Impairment 40 CFRSection 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 CFRSection 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 CFRSection 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 CFRSection 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 oftheAdequacy of the Existing Plan

As required by 40 CFRSection 51 .308(h), depending on the findings ofthe five-year progress report, required under 40 CFRSection 51 .308 (g), Maine commits to taking one ofthe 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 fromsources 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) Ifthe 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 reportwill determine which action is appropriate and necessary.

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. S., and Pandis, S.N., "Response of inorganic PM to precursor concentrations," Environ. Sci . Technol_, 32, 2706-2714, 1998. 

### Byun D .W ., andJ .K.S. Ching. Science Algorithms ofthe EPAModels-3 Community MultiscaleAir Quality (CMAQ) ModelingSystem . EPA/600/R-99/030

. March 1999. Davidson, C

., Strader, R

., Pandis, S., and Robinson, A ., Preliminary Proposal to MARAMA andNESCAUM

.~ Development ofanAmmonia Emissions Inventoryfor the Mid-Atlantic States and New

England . Carnegie Mellon University, Pittsburgh, PA . 7-Jan. 1999. Duyzer, J., "Dry Deposition ofAmmonia and Ammonium Aerosols over Heathland," J. Geophys. Res., 99(D9) :18,757 - 18,763, 1994. 

### EarthTech, 2004, http://src.com/calpuff/calpuffl .htm EPA 2005, http://www

.epa.gov/ttn/chief/eiinformation.html . EPA National Emission Standards for Hazardous Air 

### PollutantsforIndustrial/Commercial/Institutional Boilers andProcess Heaters, http://cascade.epa.gov/RightSite/dk-public collection_detail .htm?ObjectType=dk docke t_collection&cid=OAR-2002-0058&ShowList=items&Action=view (Accessed February 25, 2004) . EPA, NationalAir Quality andEmission Trends Report, 1998, EPA454/R-00-003, available online: http://www .epa.gov/oar/aytrnd98/, 2000a. EPA, NationalAirPollutant Trends, 1900-1998, EPA454/R-00-002, available online: http://www

.epa.gov/ttn/chief/trends/trends98/trends98 .pdf, 2000b. MARAMA 2004, http://www .marama.org/visibility/2002%20NEI/index.html NESCAUM, "Development ofan Improved Ammonia Emissions Inventory for the United States," December 2001b. NESCAUM, "Regional Haze andVisibility in the Northeast and Mid-Atlantic States," January 2001a. SAI . User's Guide to the Regional Modeling System for Aerosols andDeposition (REMSAD), Version 7 . ICF Consulting/SAI, San Francisco, CA . 2002 Strader, R

., Anderson, N

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., Development ofan Ammonia Inventoryfor the Mid-Atlantic States and New England, Progress Report, October 18, 2000, available online: http ://marama.org/rt center/MARAMAprogress10-18-OO.pdf , 2000 . 

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