## Draft For FLM Review



## STATE IMPLEMENTATION PLAN
FOR
REGIONAL HAZE

State of Maine Department of Environmental Protection
5/27/105/27/2010
Draft For FLM Review

T ABLE OF C ONTENTS

INTRODUCTION ................................................................................................................... ..................... 8

1.1 W HAT IS R EGIONAL H AZE ? ................................................................................................................. 8
1.2 C LEAN A IR A CT R EGIONAL H AZE R EQUIREMENTS .............................................................................. 9
1.3 T HE F EDERAL R EGIONAL H AZE R ULE ............................................................................................... 10
1.4 R EGIONAL H AZE P LANNING A FTER THE V ACATUR OF CAIR ............................................................ 12
1.5 M AINE C LASS I A REAS ....................................................................................................................... 14
1.5.1 Acadia National Park..................................................................................................... ............ 14 1.5.2 Moosehorn Wildernesss Area, Moosehorn National Wildlife Re fuge....................................... 15 1.5.3 Roosevelt Campobello Internatio nal Park................................................................................ 1 5
1.6 V ISIBILITY T RENDS AT M AINE C LASS I A REAS ................................................................................... 17
1.7 S OURCES OF R EGIONAL H AZE AT M AINE C LASS I A REAS ................................................................. 17
1.8 C LASS I A REAS A FFECTED .................................................................................................................. 20

2. GENERAL PLANNING PROVISIONS AND COMMITMENT TO FUTURE SUBMITTAL .... 21

3. REGIONAL PLANNING .......................................................................................................... ........... 23

3.1 MANE-VU........................................................................................................................ ................ 23
3.2 R EGIONAL C ONSULTATION ................................................................................................................. 24
3.3 M AINE -S PECIFIC C ONSULTATION ...................................................................................................... 28
3.4 T HE MANE-VU “A SK ” ..................................................................................................................... 28
3.5 M EETING THE “A SK ”

– MANE-VU S TATES ...................................................................................... 29
3.6 M EETING THE “A SK ”

– M AINE ........................................................................................................... 30
3.7 M EETING THE “A SK ”

– S TATES O UTSIDE OF MANE-VU .................................................................. 31
3.8 M EETING THE “A SK ”

- EPA............................................................................................................... 32
3.9 T ECHNICAL R AMIFICATIONS OF D IFFERING A PPROACHES ................................................................. 32
3.10 C ONSULTATION I SSUES .................................................................................................................... 33

4. STATE/TRIBE AND FEDERAL LAND MANAGER COORDINATION ..................................... 36

5. ASSESSMENT OF BASELINE AND NATUR AL CONDITIONS (WITH CLASS I AREAS)..... 38

5.1 R EQUIREMENTS
, D ATA
, AND M ETHODOLOGY .................................................................................... 38
5.2 M AINE B ASELINE V ISIBILITY .............................................................................................................. 40
5.3 N ATURAL V ISIBILITY .......................................................................................................................... 40

6. MONITORING STRATEGY........................................................................................................ ....... 42

6.1 F EDERAL R EGIONAL H AZE M ONITORING R EQUIREMENTS ................................................................. 42
6.2 M ONITORING I NFORMATION FOR MANE-VU C LASS I A REAS ........................................................... 44
6.2.1. Acadia Natio nal Park, Maine ............................................................................................. ...... 44
6.2.2. Moosehorn Wild erness Area, Maine........................................................................................ . 45 6.2.3. Roosevelt Campobello Internatio nal Park, New Brunswick, Ca nada....................................... 46

7. SOURCES OF VISIBILITY IMPAIRING POLLUTANTS AND CONTRIBUTION .............. 47

ASSESSMENT............................................................................................................................................ 47

7.1 V ISIBILITY E FFECTS OF P ARTICULATE M ATTER ................................................................................. 47
7.2 P OLLUTANTS C ONTRIBUTING TO V ISIBILITY I MPAIRMENT AT C LASS I A REAS ................................. 48
7.3 G EOGRAPHIC C ONSIDERATIONS AND H AZE C ONTRIBUTION A TTRIBUTION ........................................ 50 7.3.1 Review of T echnical Ap proaches ........................................................................................... .... 51 7.3.2 Summary of Analy tical Techniques for Co ntribution Assessment.............................................. 55

8. EMISSIONS INVENTORY........................................................................................................ .......... 59

8.1 S OURCES OF V ISIBILITY I MPAIRING P OLLUTANTS IN MANE-VU....................................................... 59 8.1.1 Sulfur Dioxide (SO 2 ) .................................................................................................................. 59 8.1.2 Volatile Organic Compound s (VOC) ......................................................................................... 61

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8.1.3 Oxides of Nitrogen (NO X ) .......................................................................................................... 63 8.1.4 Primary Particle Matter (PM 10 and PM 2.5 )................................................................................ 65 8.1.5 Ammonia Emissions (NH 3 )......................................................................................................... 70
8.2 B ASELINE AND F UTURE Y EAR E MISSION I NVENTORIES FOR M ODELING ............................................ 72 8.2.1 Baseline Inventory ....................................................................................................... .............. 72
8.2.2 Future Year Emission Control Inve ntories ................................................................................ 7 3
8.3 E MISSION P ROCESSOR S ELECTION AND C ONFIGURATION ................................................................... 74
8.4 I NVENTORIES FOR S PECIFIC S OURCE T YPES ....................................................................................... 75 8.4.1 Stationary Point Sources................................................................................................. ........... 75 8.4.2 Stationary Area Sources................................................................................................. ........... 77
8.4.3 On-Road Mobile Sources .................................................................................................. ........ 78 8.4.4 Biogenic Emission Sources ............................................................................................... ........ 78
8.5 S UMMARY OF M AINE ’ S 2002 AND 2018 E MISSIONS I NVENTORY ........................................................ 79

9. MODELING .................................................................................................................. ....................... 82

9.1 M ETEOROLOGY

............................................................................................................................... ... 82
9.2 E MISSIONS D ATA P REPARATION ........................................................................................................ 84
9.3 P RIMARY R EGIONAL H AZE M ODELING P LATFORMS .......................................................................... 84 9.3.1 CMAQ ........................................................................................................................................ 86
9.3.2 REMSAD................................................................................................................... ................. 87
9.4 P RIMARY M ODEL E VALUATION .......................................................................................................... 88 9.4.1 CMAQ ........................................................................................................................................ 88
9.4.2 REMSAD................................................................................................................... ................. 90
9.5 A DDITIONAL M ODELING P LATFORMS ................................................................................................. 92
9.5.1 CALGRID................................................................................................................. ................. 92
9.5.2 CALPUFF................................................................................................................. ................ 92

10. BEST AVAILABLE R ETROFIT TECH NOLOGY........................................................................ 93

10.1 T HE F EDERAL BART R ULE .............................................................................................................. 93 10.1.1 Federal BART Requirements fo r Electric Generatin g Units (EGUs) ..................................... 94
10.2 M AINE S TATE BART R EQUIREMENTS ............................................................................................. 95
10.3 BART-E LIGIBLE S OURCES IN M AINE ............................................................................................... 95
10.4 S OURCES S UBJECT TO BART........................................................................................................... 97
10.5 MANE-VU BART M ODELING ......................................................................................................... 97
10.6 T HE M AINE BART A NALYSIS P ROTOCOL ...................................................................................... 100
10.7 S UMMARY OF M AINE BART D ETERMINATIONS ............................................................................ 100 10.7.1 Cap-Outs and Shutdowns.................................................................................................. ..... 101
10.7.2 Maine BART Determinations ............................................................................................... .. 102
10.8 S CHEDULE FOR BART I MPLEMENTATION ...................................................................................... 128

11. REASONABLE PR OGRESS GO ALS ........................................................................................... 129

11.1 C ALCULATION OF U NIFORM R ATE OF P ROGRESS ........................................................................... 129
11.2 R EASONABLE P ROGRESS G OALS FOR C LASS I A REAS IN M AINE .................................................... 130
11.3 I DENTIFICATION OF A DDITIONAL R EASONABLE C ONTROLS .......................................................... 132
10.4 T HE F OUNDATIONS FOR D ETERMINING R EASONABLE C ONTROLS ................................................. 133 11.4.1 Best Available Retrofit Technology (BART ) Controls............................................................ 135
11.4.2 The MANE-VU Low Su lfur Fuel St rategy.............................................................................. 137 11.4.3 Targeted Strategy for Reducing SO 2 Emissions from EGU Stacks ........................................ 141
11.4.4 Non-EGU SO 2 Emissions Reduction Strategy Outside the MANE -VU Region..................... 147
11.5 V ISIBILITY I MPACTS OF A DDITIONAL R EASONABLE C ONTROLS .................................................... 155

12. LONG TERM STRATEGY ........................................................................................................ ..... 157

12.1 O VERVIEW OF THE L ONG T ERM S TRATEGY D EVELOPMENT P ROCESS ............................................ 157
12.2 T HE R EGIONAL P ROCESS FOR I DENTIFYING P OTENTIAL S TRATEGIES ............................................ 158
12. 3 T HE T ECHNICAL B ASIS FOR S TRATEGY D EVELOPMENT ................................................................ 159

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12.4 E MISSION R EDUCTIONS D UE TO O NGOING A IR P OLLUTION R EDUCTION P ROGRAMS ..................... 161
12.4.1 EGU Emissions Contro ls Expected by 2018 .......................................................................... 161
12.4.2 Non-EGU Point Point Source Controls Expect ed by 20 18................................................... 165
12.4.3 Area Source Contro ls Expected by 2018............................................................................... 166
12.4.4 Mobile Sources Cont rols Expected by 2018 ......................................................................... 167
12.4.5 Controls on Non-Road Sources Expected by 2018 ............................................................... 168
12.5 A DDITIONAL R EASONABLE S TRATEGIES ........................................................................................ 169
12.5.1 BART.................................................................................................................... .................. 170 12.5.2 Low-Sulfu r Oil St rategy ................................................................................................ ........ 171 12.5.3 Targeted EGU Strategy................................................................................................... ....... 171
12.7 A DDITIONAL M EASURES C ONSIDERED .......................................................................................... 175 12.7.1 Measures to Mitigate the Im pacts of Construc tion Activitie s ............................................... 175 12.7.2 Agricultural and Fo restry Smoke Management .................................................................... 176 12.7.3 Control of Reside ntial and Commercial Wood Combustion Emissions ................................ 177
12.8 E STIMATED E FFECTS OF THE L ONG -T ERM S TRATEGY ON V ISIBILITY ............................................ 178
12.9 I MPLEMENTATION OF THE R EGIONAL H AZE S TRATEGIES IN M AINE .............................................. 180
12.9.1 The Maine Low Sulfur Oil Program ..................................................................................... 18 2
12.9.2 BART in Maine.......................................................................................................... ............ 184 12.9.3 The Targeted EGU Strategy in Maine.................................................................................... 18 4
12.9.4 Wood Smoke Emission Reduc tions Strategies in Maine........................................................ 185
12.10 M AINE ’ S S HARE OF E MISSION R EDUCTIONS ................................................................................ 185
12.10 E MISSION L IMITATIONS AND C OMPLIANCE S CHEDULES ............................................................. 187
12.11 E NFORCEABILITY OF E MISSION L IMITATIONS AND C ONTROL M EASURES .................................... 188
12.12 P REVENTION OF S IGNIFICANT D ETERIORATION ........................................................................... 190
12.13 R EASONABLY A TTRIBUTABLE V ISIBILITY I MPAIRMENT .............................................................. 191

13. COMPREHENSIVE PERIODIC IMPLEMENTATION PLAN REVISIONS........................... 192

13. DETERMINATION OF THE ADEQU ACY OF THE EXIS TING PL AN .................................. 193

REFERENCES ......................................................................................................................................... 194

L IST OF T ABLES

T ABLE 1-1 S TATES THAT C ONTRIBUTE TO V ISIBILITY I MPAIRMENT AT M AINE C LASS 1 A REAS .................. 20

T ABLE 3-1 MANE-VU M EMBERS ................................................................................................................ 24

T ABLE 5-1 IMPROVE I NFORMATION FOR M AINE C LASS I A REAS .............................................................. 38

T ABLE 5-2 B ASELINE V ISIBILITY FOR THE 20 P ERCENT W ORST D AYS AND 20 P ERCENT B EST D AYS FOR F IVE Y EARS ( FROM 2000-2004) IN M AINE C LASS I A REAS .......................................................................... 40

T ABLE 5-3 S UMMARY OF B ASELINE V ISIBILITY AND N ATURAL C ONDITIONS FOR THE 20 P ERCENT W ORST

AND 20 P ERCENT B EST V ISIBILITY D AYS FOR M AINE C LASS I A REAS ................................................ 41

T ABLE 7-2 S UMMARY OF T ECHNICAL A PPROACHES FOR A TTRIBUTING S TATE C ONTRIBUTIONS TO O BSERVED S ULFATE IN MANE-VU C LASS I A REAS ........................................................................... 51

T ABLE 7-3 A NNUAL AVERAGE S ULFATE I MPACT FROM Q/D (%) ................................................................. 52

T ABLE 7-4 A NNUAL A VERAGE S ULFATE I MPACT FROM THE E MISSIONS X U PWIND P ROBABILITY T ECHNIQUE

............................................................................................................................... ............................. 53

T ABLE 7-5 A VERAGE A NNUAL S ULFATE I MPACT AT N ORTHEAST C LASS I A REAS AS M ODELED U SING REMSAD......................................................................................................................... ................... 54

T ABLE 7-6 C ONTRIBUTION TO S ULFATE L EVELS AT A CADIA N ATIONAL P ARK U SING THE CALPUFF M ODEL

............................................................................................................................... ............................. 56

T ABLE 7-7 I NDIVIDUAL S TATE R ANKINGS P RODUCED BY D IFFERENT A SSESSMENT T ECHNIQUES FOR A CADIA N ATIONAL P ARK .................................................................................................................... 58

T ABLE 8-1 2002 E MISSIONS I NVENTORY FOR M AINE ................................................................................... 79

T ABLE 8-2 2018 OTB/OTW E MISSIONS I NVENTORY FOR M AINE ................................................................ 80

T ABLE 8-3 2018 BOTW E MISSIONS I NVENTORY FOR M AINE ....................................................................... 80

T ABLE 8-4 2018 F INAL M ODELING E MISSIONS I NVENTORY FOR M AINE ...................................................... 80

T ABLE 10-1 BART-E LIGIBLE S OURCES IN M AINE ....................................................................................... 98

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T ABLE 10-2 M ODELED I MPACTS (D ECIVIEWS ) OF M AINE BART-E LIGIBLE S OURCES AT S ELECTED MANEVU C LASS I A REAS ........................................................................................................................... 101

T ABLE 11-1 U NIFORM R ATE OF P ROGRESS C ALCULATION ......................................................................... 130

T ABLE 11-2 R EASONABLE P ROGRESS G OALS —20% W ORST D AYS ........................................................... 131

T ABLE 11-3 R EASONABLE P ROGRESS G OALS —20% B EST D AYS .............................................................. 132

T ABLE 11-4 S UMMARY OF R ESULTS FROM THE F OUR F ACTOR A NALYSIS ................................................. 134

T ABLE 11-5 E STIMATED E MISSIONS FROM BART-E LIGIBLE F ACILITIES MANE-VU S TATES ................... 136

T ABLE 11-6 E STIMATED C OST R ANGES FOR SO 2 C ONTROL O PTIONS FOR C OAL -F IRED EGU B OILERS ..... 145

T ABLE 11-7 A VAILABLE SO 2 C ONTROL O PTIONS FOR ICI B OILERS ........................................................... 150

T ABLE 11-8 E STIMATED D RY S ORBENT I NJECTION (DSI) C OSTS FOR ICI B OILERS ................................... 152

T ABLE 11-9 E STIMATED FGD C OSTS F OR ICI B OILERS ............................................................................. 153

T ABLE 12-1 E STIMATED E MISSIONS FROM N ON -CAIR U NIT BART-E LIGIBLE F ACILITIES L OCATED IN MANE-VU U SED IN F INAL M ODELING ............................................................................................. 173

T ABLE 12-3 SO 2 E MISSIONS FROM P OINT
, A REA AND M OBILE S OURCES IN M AINE ................................... 187

T ABLE 12-4 SO 2 E MISSIONS FROM P OINT
, A REA AND M OBILE S OURCES IN THE MANE-VU R EGION AND IN M AINE

............................................................................................................................... ................ 187

List of Figures

F IGURE 1-1 L OCATIONS OF F EDERALLY P ROTECTED M ANDATORY C LASS I A REAS .................................... 10

F IGURE 1-2 S TATES C OVERED BY THE C LEAN A IR I NTERSTATE R ULE ......................................................... 13

F IGURE 1-3 M AINE C LASS I A REAS .............................................................................................................. 16

F IGURE 1-4 V ISIBILITY T RENDS AT A CADIA N ATIONAL P ARK ..................................................................... 17

F IGURE 1-5 V ISIBILITY T RENDS AT M OOSEHORN N ATIONAL W ILDLIFE R EFUGE AND R OOSEVELT C AMPOBELLO I NTERNATIONAL P ARK .................................................................................................. 18

F IGURE 1-6 M ODELED A NNUAL S ULFATE C ONTRIBUTION AT A CADIA N ATIONAL P ARK IN 2002................ 19

F IGURE 1-7 M ODELED A NNUAL S ULFATE C ONTRIBUTION AT M OOSEHORN N ATIONAL W ILDLIFE R EFUGE

AND R OOSEVELT /C AMPOBELLO I NTERNATIONAL P ARK ...................................................................... 19

F IGURE 3-1 EPA D ESIGNATED R EGIONAL P LANNING O RGANIZATIONS (RPO S ) .......................................... 23

F IGURE 3-2 S UMMARY OF MANE-VU P RINCIPLES FOR R EGIONAL H AZE P LANNING .................................. 25

F IGURE 3-3 S UMMARY OF C ONSULTATIONS ................................................................................................. 27

F IGURE 6-1 M AP OF A CADIA N ATIONAL P ARK ............................................................................................. 44

F IGURE 6-2 M AP OF THE B ARING AND E DMUNDS D IVISIONS OF THE M OOSEHORN N ATIONAL W ILDLIFE R EFUGE AND THE IMPROVE M ONITOR .............................................................................................. 45

F IGURE 6-3 M AP OF R OOSEVELT C AMPOBELLO I NTERNATIONAL P ARK ....................................................... 46

F IGURE 7-1 C ONTRIBUTIONS TO PM2.5 E XTINCTION AT S EVEN C LASS I A REAS .......................................... 49

F IGURE 7-2 R ANKED C ONTRIBUTION TO S ULFATE C ONCENTRATIONS AT A CADIA N ATIONAL P ARK ........... 57
F IGURE 8-1 S TATE L EVEL S ULFUR D IOXIDE E MISSIONS ............................................................................... 60

F IGURE 8-2 2002 SO 2

............................................................................................................................... .... 60

F IGURE 8-3 2002 VOC ............................................................................................................................ ..... 63

F IGURE 8-4 S TATE L EVEL N ITROGEN O XIDES E MISSIONS ............................................................................ 64

F IGURE 8-5 NO X
............................................................................................................................... ............ 65

F IGURE 8-6 S TATE L EVEL P RIMARY PM 10 E MISSIONS .................................................................................. 66

F IGURE 8-7 S TATE L EVEL P RIMARY PM 2.5 E MISSIONS ................................................................................. 66

F IGURE 8-8 W OOD S MOKE S OURCE R EGIONAL A GGREGATION ................................................................... 68

F IGURE 8-9 P RIMARY PM 10 .......................................................................................................................... 69

F IGURE 8-10 P RIMARY PM 2.5 ........................................................................................................................ 69

F IGURE 8-11 S TATE L EVEL A MMONIA E MISSIONS ........................................................................................ 71

F IGURE 8-12 S TATE A MMONIA E MISSIONS BY S OURCE C ATEGORY .............................................................. 71

F IGURE 9-1 M ODELING DOMAINS USED IN MANE-VU AIR QUALITY MODELING STUDIES WITH CMAQ...... 83

F IGURE 9-2 E XAMPLES OF P ROCESSED M ODEL -R EADY E MISSIONS ............................................................. 85

F IGURE 9-3 D OMAIN -W IDE P AIRED C OMPARISON F OR S ULFATE A ND O THER PM 2.5 S PECIES CMAQ VS IMPROVE/STN.................................................................................................................... .............. 89

F IGURE 9-4 S ULFATE C ONCENTRATIONS F ROM THE IMPROVE/STN M EASUREMENTS AND THE REMSAD

M ODEL

............................................................................................................................... ................. 91

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F IGURE 9-5 C OMPARISON OF M EASUREMENT AND M ODELED D ATA FOR A LTERNATIVE A NNUAL M ODEL S IMULATIONS

............................................................................................................................... ....... 91

F IGURE 11-1 A VERAGE C HANGE IN 24- HR PM 2.5 D UE TO L OW S ULFUR F UEL S TRATEGIES R ELATIVE TO OTB/OTW ........................................................................................................................................ 138

F IGURE 11-2 L OCATION OF 167 EGU S TACKS C ONTRIBUTING THE M OST TO V ISIBILITY I MPAIRMENT AT MANE-VU C LASS I A REAS .............................................................................................................. 142

F IGURE 11-3 P RELIMINARY E STIMATE OF A VERAGE C HANGE IN 24- HR PM 2.5 D UE TO 90 P ERCENT R EDUCTION IN SO 2 E MISSIONS FROM 167 EGU S TACKS A FFECTING MANE-VU............................. 143

F IGURE 11-3 D EMONSTRATION OF R EQUIRED AND R EASONABLE V ISIBILITY P ROGRESS FOR 20% W ORST V ISIBILITY D AYS

............................................................................................................................... 156

F IGURE 11-4 D EMONSTRATION OF R EQUIRED AND V ISIBILITY M AINTENANCE FOR 20% B EST V ISIBILITY D AYS

............................................................................................................................... .................. 156

F IGURE 12-1 167 EGU S TACKS A FFECTING MANE-VU C LASS I AREA ( S ) ................................................. 174

F IGURE 12-2 P ROJECTED V ISIBILITY I MPROVEMENT AT A CADIA N ATIONAL P ARK B ASED O N 2018 B EST AND F INAL P ROJECTIONS .......................................................................................................................... 181

F IGURE 12-3 P ROJECTED I MPROVEMENT IN V ISIBILITY AT M OOSEHORN N ATIONAL W ILDLIFE R EFUGE AND R OOSEVELT C AMPOBELLO I NTERNATIONAL P ARK BASED ON 2018 B EST AND F INAL P ROJECTIONS . 181

F IGURE 12-4 P ROJECTED V ISIBILITY I MPROVEMENT AT G REAT G ULF W ILDERNESS B ASED ON M OST R ECENT P ROJECTIONS FOR 2018 ..................................................................................................................... 182

F IGURE 12-5 C ONTAMINATION OF U LTRA L OW S ULFUR D ISTILLATE (D IESEL ) F UEL ................................. 184

List of Attachments

A TTACHMENT A C ONTRIBUTIONS TO R EGIONAL H AZE IN THE N ORTHEAST AND M ID -A TLANTIC S TATES A TTACHMENT B I NTER -RPO S TATE /T RIBAL AND FLM C ONSULTATION F RAMEWORK A TTACHMENT C S UMMARY OF C ONSULTATIONS A TTACHMENT D T HE MANE-VU “A SK ”
A TTACHMENT E VISTAS C OMMENTS A TTACHMENT F FLM C OMMENTS -RESERVED
A TTACHMENT G B ASELINE AND N ATURAL V ISIBILITY C ONDITIONS A TTACHMENT H TSD S UPPORT FOR 2002 MANE-VU SIP M ODELING I NVENTORY V ERSION 3
A TTACHMENT I D EVELOPMENT OF E MISSION P ROJECTIONS FOR 2009, 2012, AND 2018

F OR N ON EGU P OINT
, A REA
, AND N ONROAD S OURCES A TTACHMENT J D EVELOPMENT OF MANE-VU M OBILE S OURCE P ROJECTION I NVENTORIES FOR SMOKE/MOBILE6 A PPLICATION A TTACHMENT K NYS T ECHNICAL S UPPORT D OCUMENTS FOR M ODELING A TTACHMENT L C ALPUFF M ODELING A TTACHMENT M M AINE BART D ETERMINATIONS A TTACHMENT M-1 T HE M AINE BART P ROCESS A TTACHMENT N F IVE -F ACTOR A NALYSIS OF B ART E LIGIBLE S OURCES A TTACHMENT O BART R ESOURCE G UIDE A TTACHMENT P MANE-VU M ODELING FOR R EASONABLE P ROGRESS A TTACHMENT Q 2018 V ISIBILITY P ROJECTIONS A TTACHMENT R A SSESSMENT OF C ONTROL T ECHNOLOGY O PTIONS FOR BART
A TTACHMENT S D OCUMENTATION OF 2018 E MISSIONS FROM E LECTRIC G ENERATION U NITS A TTACHMENT T A SSESSMENT OF R EASONABLE P ROGRESS FOR REGIONAL H AZE IN MANE-VU C LASS 1
A REAS A TTACHMENT U C OMPARISON OF CAIR AND CAIR P LUS P ROPOSAL USING THE I NTEGRATED P LANNING M ODEL (IPM®)
A TTACHMENT V T HE N ATURE OF THE F INE P ARTICLE AND R EGIONAL H AZE A IR Q UALITY P ROBLEMS IN

THE MANE-VU R EGION : A C ONCEPTUAL D ESCRIPTION A TTACHMENT W T OP E LECTRIC G ENERATING E MISSION P OINTS C ONTRIBUTING TO VISIBILITY

I MPAIRMENT IN MANE-VU

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vii A TTACHMENT X T ECHNICAL S UPPORT D OCUMENT ON M EASURES TO M ITIGATE THE V ISIBILITY I MPACTS

OF C ONSTRUCTION A CTIVITIES IN THE MANE-VU R EGION A TTACHMENT Y T ECHNICAL S UPPORT D OCUMENT ON A GRICULTURAL AND F ORESTRY S MOKE M ANAGEMENT IN THE MANE-VU R EGION A TTACHMENT Z T HE M AINE L OW S ULFUR F UEL PROGRAM A TTACHMENT AA M AINE 2018 P ROJECTED P OINT S OURCE I NVENTORY A TTACHMENT BB 06-096 CMR C HAPTER 150 C ONTROL OF E MISSIONS FROM O UTDOOR W OOD B OILERS5/27/2010
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8 

### Introduction

1.1 What is Regional Haze?

Haze is a form of air pollution th at impairs visibility over a wide region, and is a problem affecting many areas throughout the U.S., especi ally national parks and wilderness areas. Average visual range in many parks in the western U.S. is 100–150 kilometers, or about one-half to two-thirds of the visual range that would exist without manmade air pollution. In most of the eastern half of the U.S., the average visual range is less than 30 kilometers,
or about one-fifth of the vi sual range that would exist under natural conditions. Surveys have shown that visitors to national parks and wilderness areas consistently rank visibility
and clear scenic vistas as one of the most important aspects of their experience.

The particle pollution that causes haze also poses a threat to hu man health, and it can
cover an area of several hundred miles. H azy days of summer ar e a result of human activity formed by emissions from many sources in a wide geographic area. The emissions come from power plants, factories, and vehicles that combine with moisture in the air. Haze is not just a summertime problem, it can occu r at any time of the year.

Air pollution, including pa rticulates (soot) and related gase s (sulfur dioxide and nitrogen dioxide) can scatter and absorb light, limiting the distance that one can see and obscuring color and clarity. Visibility can often be reduced over large regi ons, and is therefore called regional haze.

Visibility impairment can be quantified usi ng three different, but ma thematically related measures: light extinction per unit distance (e.g., Mm -1 ) 1 ; visual range (i.e., how far one can see); and deciviews (dv), a useful metric for measuring increments of visibility change that are just perceptible to the hum an eye. Each can be estimated from the
ambient concentrations of i ndividual particle constituents , taking into account their unique light-scattering (or absorbing) propert ies and making appropriate adjustments for relative humidity. Assuming natural conditions , visibility in the Northeast and MidAtlantic is estimated to be about 23 Mm -1 , which corresponds to a visual range of about 106 miles or 8 dv. Under current polluted c onditions in the regi on, average visibility ranges from 103 Mm -1 in the south to 55 Mm -1 in the north; these va lues correspond to a visual range of 24 to 44 miles or 23 to 17 dv, respectively. On th e worst 20 percent of days, visibility impairment in Northeast and Mid-Atlantic Class I areas ranges from about
25 to 30 dv.

The principal pollutants that aff ect fine particle formation, and thus contribute to regional haze, are sulfur oxides (SO X ), organic carbon (OC), nitrogen oxides (NO X ), volatile organic compounds (VOC), ammonia (NH 3 ), and particles with an aerodynamic diameter less than or equal to 10 and 2.5 μm (i.e., primary PM 10 and PM 2.5 ). In the eastern U.S.

1 In units of inverse length. An inverse megameter (Mm -1 ) is equal to one over one thousand kilometers.5/27/2010
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9 ammonium sulfate, formed from sulfur oxides and ammonia, is respon sible for more than 50 percent of regional visibility impairment , and most regional control efforts are directed at reducing emissions of sulfur oxides.

1.2 Clean Air Act Regional Haze Requirements

Regional ha ze and visibility were first addressed in amendments to the Clean Air Act in 1977, when Congress added Section 169 (42 U.S.C. 7491) establishing forth the following national visibility goal:

“Congress hereby declares as a nationa l goal the prevention of any future, and the remedying of any existing, impai rment of visibility in mandatory Class I Federal areas which impairment results from man-made air pollution.”

The "Class I" designation was given to each of 158 areas in existence as of August 1977 that met the following criteria:

 all national parks grea ter than 6000 acres

 all national wilderness areas and national memorial parks greater than 5000 acres

 one international park

In 1980, Bradwell Bay, Florida, and Rainbow Lake, Wisconsin, were excluded for purposes of visibility protection as federal Cl ass I areas. Figure 1-1 illustrates the 156 national park and wilderness areas that rema in as Class I visibility protection areas.

Over the following years modest steps were taken to address the visibility problems in Class I areas. The control measures taken mainly addressed Plume Blight from specific pollution sources and did little to address re gional haze issues in the Eastern United
States.

When the CAA was amended in 1990, Congre ss added Section 169B (42 U.S.C. 7492), authorizing further research and regular assessm ents of the progress made so far. In 1993, the National Academy of Sciences conclude d that “current scient ific knowledge is adequate and control technologi es are available for taking re gulatory action to improve and protect visibility.”

In addition to authorizing creation of visibi lity transport commissions and setting forth their duties, Section 169B(f) of the CAA mandated creation of the Grand Canyon Visibility Transport Commission (GCVTC) to make recommendations to EPA for the region affecting the visibility of the Grand Canyon National Park. The Grand Canyon Visibility Transport Commission (Commission) submitted its report to EPA in June 1996, following four years of research and policy development. The Commission report, as well as the many research reports prepared by the Commission, contributed invaluable information to EPA in its development of the federal regional haze rule.5/27/2010
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Figure 1-1 Locations of Federally Protected Mandatory Class I Areas

1.3 The Federal Regional Haze Rule

The federal requirem ents that st ates must meet to achieve national visibility goals are
contained in Title 40: Protection of Environment, Part 51 – Requirements for Preparation, Adoption, and Submittal Of Implementation Plans, Subpart P – Protection of Visibility (40 CFR 51.300-309) 2 . Known more simply as the Regional Haze Rule, these regulations were adopted on July 1, 1999, a nd went into effect on August 30, 1999. The
rule seeks to address the combined visibil ity effects of various pollution sources over a

2 The specific requirements for States’ regional haze SIPs are set forth in 40 CF R 51.308, Regional Haze Program Requirements.

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11 . large geographic region, with the result that all states – even those without Class I areas – are required to participate in haze reduction efforts

In consultation with the states and trib es, EPA designated five Regional Planning Organizations (RPO) to assist with the coordination and co operation needed to address
the haze issue. The Mid-Atlantic / Northeast states, including the District of Columbia,
formed the Mid-Atlantic / Northe ast Visibility Union (MANE-VU). 3

EPA’s Regional Haze Rule was the subject of considerable controversy, and was challenged on several legal grounds. On May 24, 2002 the U.S. Court of Appeals for the
District of Columbia Circuit ruled on th e challenge brought by the American Corn Growers Association against EPA’s Regi onal Haze Rule of 1999. The Court remanded the BART provisions of the rule to EPA, and denied industry’s challenge to the haze rule goals of natural visibility and no degr adation requirements. On June 15, 2005, EPA finalized a rule addressing the Court’s remand.

On February 18, 2005, the U.S. Court of Appeal s for the District of Columbia Circuit issued another ruling vacating the Regional H aze Rule in part and sustaining it in part.
For more information see Center for Energy and Economic Development v. EPA , no. 03- 1222, (D.C. Cir. Feb. 18, 2005)(“ CEED v. EPA”). In this case, the court granted a petition challenging provisions of the Re gional Haze Rule governing the optional emissions trading program for certain West ern States and Tribes (the WRAP Annex Rule).

EPA’s subsequent final rulemaking provided the following changes to the Regional Haze Regulations:

1. Revised the regulatory text in 40 CFR S ection 51.308(e)(2)(i) in response to the
CEED court’s remand, to remove the requirement that the determination of BART “benchmark” be based on cumulative visibility analyses, and to clarify the process for making such determinations, including the application of BART presumptions
for EGUs as contained in Attachment Y to 40 CFR 51.

2. Added new regulatory text in 40 CFR Section 51.308(e)(2)(vi), to provide minimum elements for cap and trade program s or alternative measures in lieu of
BART.

3. Revised regulatory text in 40 CFR S ection 51.309, to reconcile the optional
framework for certain Western Stat es and Tribes to implement the recommendations of the Grand Canyon Visibility Transport Commission (GCVTC) with the CEED decision.

3 A description of MANE-VU and a full list of its members is described in the Regional Planning Section
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12 1.4 Regional Haze Planning After the Vacatur of CAIR

On March 10, 2005, EPA issued the Clean Air In terstate Rule (CAIR). This important federal rule was designed to achieve major pe rmanent reductions in sulfur dioxide (SO 2 ) and nitrogen oxides (NO

x ) emissions in the eastern Unite d States through a cap-and-trade system using emission allowances. As promulgated, CAIR permanently caps emissions originating in 28 eastern stat es and the District of Colu mbia (Figure 1-2). Although Maine was not designated as a participati ng CAIR state, this program would greatly affect future air quality in the state.

According to EPA’s CAIR website, SO 2 emissions in the affected states would be reduced by more than 70 percent from 2003 levels, and NO

x emissions by more than 60 percent from 2003 levels, upon full implementation of CAIR (See http://www.epa.gov/cair/ ). Resulting improvements in air quality would yield $85 to $100 billion in health benefits and nearly $2 billion in visibility benefits per year by 2015, and premature mortality would be substa ntially reduced across the eastern U.S.

This program came to an abrupt end, however, on July 11, 2008, when the U.S. Court of Appeals for the District of Columbia Circuit found that CAIR violated basic provisions of
the Clean Air Act. The Cour t vacated CAIR in its entirety and remanded to EPA to promulgate a new rule consistent with the court’s opinion. On September 24, 2008, EPA petitioned the D.C. Circuit for a rehearing or rehearing en banc on the vacatur of CAIR. Thereafter, the D.C. Circuit issued an order requesting briefs on the issue of whether any party is seeking vacatur of CA IR, and whether the court should stay its vacatur until EPA promulgates a revised rule. Maine, along with more than 20 other states, filed an amicus brief in support of staying the court decision vacating CAIR while EPA promulgates a revised rule that complies with the Court’s decision. The states argue d that because they “reasonably relied on CAIR in formulating long-term plans for improving air quality, in the short term, even a flawed rule is better than none at all.”

The vacatur of CAIR presented a major difficu lty for the individual states in attempting to comply with the Regional Haze Rule. Because CAIR formed the regulatory underpinnnings for most of the emission reductions that woul d produce visibility improvements in mandatory Class I areas, the pr obable demise of CAIR left a structural
void around which states must build their re gional haze SIPs. While all states have depended in varying degree on CAIR in the preparation of their Regional Haze SIPs,
some Southeast states have relied almost entirely on CAIR to demonstrate compliance with the Regional Haze Rule. As a major ra mification, the vacatur of CAIR invalidated
EPA’s decision that CAIR satisfies the requirements for Best Available Retrofit Technology (BART) for the affected sources. The vacatur of CAIR also called into question the validity of MANE-VU’s and ot her RPO’s emission inventories and air quality modeling studies already completed fo r the member state’s regional haze SIPs.5/27/2010
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Figure 1-2 States Covered by the Clean Air Interstate Rule

However, on December 23, 2008, the D.C. Circ uit decided that “a remand without vacatur is appropriate in this case” because “notwithstanding the relative flaws of CAIR, allowing CAIR to remaining in effect until it is replaced by a rule consistent with our opinion would at least temporar ily preserve the environmental values covered by CAIR.” State of North Carolina v. EPA, No. 05- 1244, slip op. at 3 (D.C. Cir. Dec. 23, 2008).

In light of this decision, Main e believes that future emissions and air quality levels will not be vastly different from the values predicted by MANE-VU’s completed modeling, even though that modeling was based on implem entation of CAIR and did not take into
account the remand of CAIR to EPA. Consequently, the reasonable progress goals and long-term strategy developed for Maine’s regi onal haze SIP still represent a defensible position from which to move forward with m easures to improve visibility in Maine’s
Class I areas.

Further, Maine and the other MANE-VU stat es have maintained all along that the Regional Haze SIPs should look beyond the prov isions of CAIR to identify additional emission control measures that could be effectively employed to mitigate regional haze. In this respect, Maine and the rest of M ANE-VU stand apart form the other states in asserting that additional measures beyond CAIR are essential to meeting the established visibility goals at MANE-VU’s Class I areas.

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14 In describing Maine’s present situation, it may be helpful to note that the remand of
CAIR without vacatur is a co mplicating factor for the long- term, but does not present an impediment to making visibility progress in the near term. The salient points to consider
are as follows:

 Because Maine is a non-CAIR state, CAIR does not direct ly affect any of Maine’s proposed in-state visibility im provement control strategies.

 Maine will meet its “fair share” of emi ssion reductions in comparison with other MANE-VU states and the original CAIR states, as Maine’s long-term strategy demonstrates (See Section 12).

 Sources in upwind states release most of the pollutants contributing to visibility impairment at Maine’s Class I areas. Therefore, Maine will continue to be dependent on mitigative actions by other st ates if visibility goals are to be
achieved for these Class I areas.

 By the time the first regional haze SIP pr ogress report, in 2013, the regulatory framework for the CAIR replacement shoul d be clearer, and new modeling results should be available. It should then be possible to fine-tune regional haze plans to address any rule that EPA has promulga ted to replace CAIR. Maine is committed to reviewing and updating its regional haze SIP as new information becomes
available.

Given the D.C. Circuit’s remand without vaca tur of CAIR, Maine ha s chosen to retain appropriate references to CAIR in the comp letion of its Regional Haze SIP. We believe this will help to maintain continuity with the large body of completed work- much of it
based on CAIR- that serves as the foundati on for regional haze planning in the MANEVU states.

1.5 Maine Class I Areas

Maine has three Class I areas: 1) Acadia Na tional Park; 2) Moosehorn National Wildlife Refuge Wilderness Area; and 3) Roosevelt Ca mpobello International Park (See Figure 1- 3).

1.5.1 Acadia National Park

When Acadia National Park was designated in 1919, it was called Lafayette National Park and was the first national park designated east of the Mississippi River. Created with 6,000 acres of land, the park changed its name in 1929 and now encompasses about 40,000 acres of mixed ecol ogy including Atlantic shoreline, mixed hardwood forests, spruce and fir forests, m ountains, lakes and islands. Facilities at the park include 45 miles of carriage roads for wa lking and biking with 27 miles of scenic driving, plus 120 miles of hiking only tra ils, 2 campgrounds, a restaurant and 3 gift5/27/2010
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15 shops. Acadia averages 3 million visitors each year with the majo rity visiting during July and August (almost 700,000 visitors per month) and the fewe st during December, January, and February (almost 38,000 visitors per month). Open year round, Acadia provides an abundance of recreational opportuni ties. The average park visitor stays at Acadia 1-4 days.

1.5.2 Moosehorn Wildernesss Area, Moosehorn National Wildlife Refuge

Moosehorn National Wildlife Refuge, which was officially established in 1937, is comprised of two units, the Baring Unit (17,200 acres) and the Edmunds Unit (7,200 acres). Within the refuge, a combined 7,460 acres of land (2780 acres from the Edmunds Unit and 4680 acres from the Baring Unit) are protected as a Class I wilderness area. The refuge includes rocky shores , rolling forested hills, la kes, bogs, and marshes that provide protected habitat a nd breeding grounds for migratory land and water birds. Moosehorn was the first migrator y bird refuge to be establis hed in what is now a chain of refuges extending south to Florida. It features American bald eagles, and the American woodcock among the more than 220 sp ecies of birds that have been spotted here. While birding is the primary attract ion of Moosehorn Refuge, visitors also
utilize over 50 miles of road s and trails for hiking, bi king, cross country skiing, and snowmobiling. Non-motorized boats are also allowed access to streams and lakes in the refuge for fishing. In November, the re fuge is open for white-tailed deer hunting. Education programs also draw visitors to the refuge, where wild life biologists invite visitors to join them on bird banding operations.

1.5.3 Roosevelt Campobe llo International Park

Roosevelt Campobello Internationa l Park is the only internati onal park in North America. The park is located on Campobello Isla nd in Canada, but is of historical significance to the U.S. as the life-long summer home of President Franklin Delano Roosevelt. U.S. President Lyndon Johnson and Canadian Prime Minister Lester Pearson established the park on January 22, 1964 by international agreement. The park remains a symbol of neighborly relati ons between the U.S. and Canada, and of the importance of FDR’s achievements to both nations. The Roosevelt Campobello International Commission manages the pa rk. Commission members are appointed by
the Governor General of th e Council of Canada and by the U.S. President. The agreement splits equally all costs of development, operation, and management. The park itself is a mixture of historic cott ages and scenic natural landscapes. There are 8.4 miles of scenic roads in the park and 8 miles of walking paths. The grounds of the park include coastal headla nds, rocky shores, beaches, wetlands, fields, forest, and the landscaped gardens of the cottages. The mix of habitat is excellent for a variety of migratory and shore birds. Wh ile the historic cottage s are only open from Memorial Day to Columbus Day, the natural ar eas and visitor center are open year round.5/27/2010
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Figure 1-3
Maine Class I Areas

This unique historic, natural area attracts approximately 150,000 visitors annually, with most arriving in August. The National Park Service recommends visitors plan on 2 to 4 hours to view the cottages, and 8 or more hours for full appreciation of the natural areas. In addition to the historic setting, several recreational activities are permitted
on the island. There are no admission fees for this park, although donations are accepted.

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1.6 Visibility Trends at Maine Class I Areas

Figures 1-4 and 1-5 present recent visibility trends, baseline and natural conditions (in deciviews) at Acadia National Park, Moose horn National Wildlife Refuge and Roosevelt Campobello International Park Class I areas fo r the 20 percent greatest and least impaired visibility days. The figures also illustrate the uniform rate of progress ‘glide path’ needed to reach natural background level goal esta blished by the Clean Air Act. As of 2008, visibility conditions at all Class I areas in Maine are currently at or below the uniform rate of progress glide path.

Figure 1-4 Visibility Trends at Acadia National Park

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 301990199319961999200220052008201120142017202020232026202920322035203820412044204720502053205620592062deciview (dv)

Worst 20% Worst 20% 2000-2004 Baseline Worst 20% 5-yr Avg Worst 20% Glide Path
Worst 20% Default natural conditions Best 20%
Best 20% 2000-2004 Baseline Best 20% 5-yr Avg
Best 20% Glide Path Best 20% Default natural conditions

1.7 Sources of Regional Haze at Maine Class I Areas

In order to identify states where em issions are most likely to influence visibility in MANE-VU Class I areas, MANE-VU identified and evaluated the major contributors to regional haze at MANE-VU Class I areas as well as Class I areas in nearby regional planning organizations (RPO s). The MANE-VU findings are available in a report produced by the Northeast States for C oordinated Air Use Management (NESCAUM) entitled “Contributions to Regional Haze in the Northeast and Mid-Atlantic United States,” August 2006, also known as the “Cont ribution Assessment” (Attachment A).

Based on that work, MANE-VU concluded that it was appropriate to define an area of influence including all of the states particip ating in MANE-VU, plus other states that
contributed at least 2% of the modeled sulf ate ion at MANE-VU Class I areas in 2002. Figures 1-6 and 1-7 illustrate modeled a nnual sulfate ion contribution at Acadia

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Figure 1-5 Visibility Trends at Moosehorn National W ildlife Refuge and Roosevelt Campobello
International Park 4

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25199519982001200420072010201320162019202220252028203120342037204020432046204920522055205820612064deciview (dv)

Worst 20% Worst 20% 2000-2004 Baseline Worst 20% 5-yr Avg Worst 20% Glide Path
Worst 20% Default natural conditions Best 20%
Best 20% 2000-2004 Baseline Best 20% 5-yr Avg
Best 20% Glide Path Best 20% Default natural conditions

National Park and Moosehorn National Wild life Refuge in 2002 based on the use of REMSAD (Regional Modeling System for Aerosols and Deposition) modeling. The REMSAD modeling clearly shows that Maine Class I Areas are most influenced by
emissions from the northern states and Canada 5

.

Rather than relying solely on a grid-based source model, such as REMSAD, Maine utilized a variety of analytical and assessment tools to determine the sources of visibility impairment at Maine Class I areas, includi ng Lagrangian (air pa rcel-based) source dispersion models, as well as a variety of data analysis t echniques that include source apportionment models, back trajectory calcu lations, and the use of monitoring and inventory data. Using these techniques, the stat es in Table 1-1 were identified as causing or contributing two percent or more of the visibility impairment in Acadia National Park, Moosehorn National Wildlife Refuge, and Roos evelt Campobello International Park.

Additional information about procedures by wh ich monitoring data and other information were used in determining the contribution of emissions from w ithin these State to regional haze visibility impairment at MANE-VU Class I areas is included in Section 7 of the Maine State Implementation Plan for Regional Haze and in the MANE-VU Contribution Assessment in (Attachment A). Additional information on the sources of

4 The Moosehorn National Wildlife Refuge IMPROVE monitor is also used for Roosevelt Campobello
International Park.

18 5 Note that the large “other” fraction of sulfates incl udes all sources outside the analysis domain, which includes some portions of the VISTAS and CENWRAP RPO, Northern and Western Canada, in addition to all other (e.g., intercontinental) sources of SO 2

.5/27/2010
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SO 2 emissions and why sulfur is the key pollu tant targeted by MANE-VU and Maine is included in Section 8, Emissions Inventory.

Figure 1-6
Modeled Annual Sulfate Contribution at Acadia National Park in 2002 (percent co ntribution)

Average Annual Sulfate Impact by Source at Acadia National Park

ME, 6.54

MD, 2.20

MA, 10.11

NH, 2.25

NJ, 1.40

NY, 4.74 Other, 33.79 CT, 0.76 DE, 0.96

DC, 0.01 CENRAP, 0.88

MS, 0.01 NC, 1.45

KY, 1.17 WI, 0.85 SC, 0.43 VA, 1.48 WV, 2.35

IL, 1.37 MI, 2.02 RI, 0.28 PA, 6.81

VT, 0.13 Canada, 8.69

TN, 0.61

GA, 0.67 AL, 0.32 OH, 5.62

IN, 2.13 Canada CENRAP

CT DE

DC ME

MD MA

NH NJ

NY PA

RI VT

IL IN

MI OH

WI AL

GA KY

MS NC

SC TN

VA WV

Other

Figure 1-7
Modeled Annual Sulfate Contribution at Moosehorn National Wildlife Refuge and Roosevelt/Campobello International Park (percent co ntribution)

19 Average Annual Sulfate Impact by Source at Moosehorn Wildlife Refuge

ME, 8.01

MD, 1.60

MA, 6.78

NH, 1.74
NJ, 1.03

NY, 3.83 Other, 44.17

IN, 2.02 OH, 4.62

AL, 0.25 GA, 0.56 TN, 0.50 Canada, 7.85

VT, 0.09 PA, 5.53

RI, 0.19

MI, 1.74 IL, 1.30 WV, 1.75 VA, 1.13

SC, 0.36 WI, 0.72

KY, 0.98 NC, 1.14 MS, 0.01 CENRAP, 0.82

DC, 0.01 DE, 0.71 CT, 0.56 Canada CENRAP

CT DE

DC ME

MD MA

NH NJ

NY PA

RI VT

IL IN

MI OH

WI AL

GA KY

MS NC

SC TN

VA WV

Other5/27/2010
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20 1.8 Class I Areas Affected

In accordance with 40 CFR Section 51.308(d)(4)(ii i), emissions sources within the State
of Maine affect Class I areas in Maine al ong with the Great Gulf and Presidential-Dry River Wilderness Areas in New Hampshire 6

.

Table 1-1
States that Contribute to Visibility Impairment at Maine Class 1 Areas

State Assessment Technique
MANE-VU

Member REMSAD Q/D Calpuff
NWS Calpuff
MM5 % Time Upwind
Connecticut X

Delaware X
District of Columbia X Georgia X
Illinois X X X
Indiana X X X X X Kentucky X X X X

Maine X X X Maryland X X X
Massachusetts X X X X X

Michigan X X X X X New Hampshire X X X X

New Jersey X
New York X X X X X X
North Carolina X X
Ohio X X X X X Pennsylvania X X X X X

Rhode Island X

Tennessee X

Vermont X Virginia X West Virginia X X X X X

6 The modeled annual sulfate ion im pact of Maine emissions at the Great Gulf and Presidential-Dry Wilderness Areas in New Hampshire is more than 2% of all modeled sulfate ion impacts.5/27/2010
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21 

### 2. General Planning Provisions and Commitment to Future Submittal

In accordance with 40 CFR Section 51.308(a) and (b), Maine is submitting this SIP to meet the requirements of EPA’s Regional Haze Rule. This SIP addresses the core requirements of 40 CFR Sect ion 51.308(d) and th e Best Available Re trofit Technology (BART) components of 40 CFR Section 50.308(e). In addition, this SIP addresses requirements pertaining to re gional planning, and state/trib e and Federal Land Manager (FLM) coordination and consultation.

40 CFR Section 51.308(f) requires the State of Maine to submit its SIP revision by July 31, 2018 and every ten years thereafter. Ma ine acknowledges and commits to this
schedule.

40 CFR Section 51.308(g) requires Maine to s ubmit a report to EPA every 5 years that evaluates progress toward the reasonable progress goal for each mandatory Class I area located within the state and each mandatory Class I area located outside the state that may be affected by emissions fr om within the stat e. Maine commits to submitting the first progress report, in the form of a SIP revision, no late r than December 17, 2012.

Pursuant to 40 CFR Section 51.308(d)(4)(v), Maine also commits to making periodic updates to the emissions inventory (see Secti on 7), and will complete these updates to coincide with the progress reports.

Lastly, pursuant to 40 Section CFR 51.308(h) , Maine will submit a determination of adequacy of its regional haze SIP revision whenever a progress report is submitted. Depending on the findings of its five-year revi ew, Maine will take one or more of the following actions at that time, whichever actions are appropriate or necessary:

 If Maine determines that the existing State Implementation Plan requires no
further substantive revision in order to achieve established goals for visibility improvement, it will provide to the EPA Ad ministrator a negative declaration that
further revision of the exis ting plan is not needed.

 If Maine determines that its implementation plan is, or may be, inadequate to ensure reasonable progress as a result of emissions from sources in one or more other state(s) which participated in the regional planning process, it will provide
notification to the EPA Administrator and to those other state(s). Maine will also collaborate with the other state(s) th rough the regional pla nning process for the purpose of developing additional strategies to address any such deficiencies in its plan.

 If Maine determines that its implementation plan is, or may be, inadequate to ensure reasonable progress as a result of emissions from sources in another country, it will provide notification, along with available information, to the EPA
Administrator.

 If Maine determines that the implementation plan is, or may be, inadequate to ensure reasonable progress as a result of emissions from sources within the State,5/27/2010
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22 it will revise its implementation plan to a ddress the plan's deficiencies within one year from this determination.5/27/2010
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### 3. Regional Planning

In 1999, EPA and affected States/Tribes ag reed to create five Regional Planning Organizations (RPOs) to facilitate intersta te coordination on State Implementation Plans (SIPs) for regional haze. The RPOs and stat es/tribes within each RPO are required to consult on the development of emission manageme nt strategies directed towards visibility improvement in affected Class1 areas. Figure 3-1 illustrates the five RPOs—MANE-VU (Mid-Atlantic/Northeast Visibility Union), VISTAS (Visibility Improvement State and
Tribal Association of the S outheast), MRPO (Midwest Regi onal Planning Organization), CenRAP (Central Regional Air Planning A ssociation), and WRAP (Western Regional Air Partnership). As shown, Maine is part of MANE-VU.

Figure 3-1 EPA Designated Regional Pla nning Organizations (RPOs)

3.1 MANE-VU

MANE-VU’ s work is managed by the Ozone Transport Commission (OTC) and carried out by the OTC, the Mid-Atlantic Regiona l Air Management A ssociation (MARAMA),
and the Northeast States for Coordinated Air Quality Management (NESCAUM). The states, tribes and federal agencies comp rising MANE-VU are listed in Table 3-1. Individuals from the states, tribes and federa l agencies, along with the professional staff

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24 from OTC, MARAMA, and NESCAUM, make up the various committees and workgroups.
Table 3-1
MANE-VU Members

1. Connecticut 10. Pennsylvania

2. Delaware 11. Penobscot Nation

3. District of Columbia 12. Rhode Island

4. Maine 13. St. Regis Mohawk Tribe

5. Maryland 14. Vermont

6. Massachusetts 15. U.S. Environmental Protection Agency*

7. New Hampshire 16. U.S. National Park Service*

8. New Jersey 17. U.S. Fish and Wildlife Service*

9. New York 18. U.S. Forest Service* *Non-voting members

MANE-VU established an active committee stru cture to address bot h technical and nontechnical issues related to regional haze. The primary committees are:

 The Technical Support Committee (TSC), charged with assessing the nature and magnitude of the regional haze problem within MANE-VU, interpreting the results of technical work, and reporting on such work to the MANE-VU Board;
and

 The Communications Committee, charged w ith developing approaches to inform the public about the regional haze pr oblem in the region and making any
recommendations to the MANE-VU Bo ard to facilitate that goal.

In addition to the formal working committees, there are also three standing working groups of the TSC. They are broken down by topic area: Em issions Inventory, Modeling, and Monitoring/Data Analysis Workgroups.

MANE-VU also established a Policy Adviso ry Group (PAG), which met on an as-needed basis to provide advice to decision-makers on policy questions. Ultimately, decisions are made by the MANE-VU Board.

3.2 Regional Consultation

On May 10, 2006, MANE-VU adopted the “I nter-RPO State/Tribal and FLM
Consultation Fram ework” (Attachment B). The Inter-RPO State/Tribal and FLM Consultation Framework established the principles presented in Figure 3-2, which were applied to the consultation and SIP deve lopment process by the MANE-VU states and
tribes. The MANE-VU consultations addres sed (among others) regional haze baseline5/27/2010
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determinations, natural background levels, and the development of reasonable progress goals, all of which are discussed at le ngth in later sections of this SIP.

Figure 3-2 Summary of MANE-VU Principles for Regional Haze Planning

25 1) All State, Tribal, RPO, and Fe deral participants are committed to continuing dialogue and information sharing in order to create understandi ng of the respective concerns and needs of the parties.

2) Continuous documentation of all communications is necessary to develop a record for inclusion in
the SIP submittal to EPA.

3) States alone have the authority to undertake sp ecific measures under their SIP. This inter-RPO framework is designed solely to facilitate needed communication, coordination and cooperation among jurisdictions but does not establish binding obligation on the part of participating agencies.

4) There are two areas which require State-to-State and/or State-to-Tribal consultations (“formal” consultations): (i) development of the reasonable progress goal for a Class I area, and (ii) development of long-term strategies. While it is anticipated that the formal consultation will cover the technical components that make up each of these policy decision areas, there may be a need for the RPOs, in coordination with their State and Tribal members, to have informal consultations on
these technical considerations.

5) During both the formal and informal inter-RPO co nsultations, it is anticipated that the States and Tribes will work collectively to facilitate the consultation process through their respective RPOs,
when feasible.

6) Technical analyses will be transparent, when possible, and will reflect the most up-to-date
information and best scientific methods for the d ecision needed within the resources available.

7) The State with the Class I area retains the responsibility to establish reasonable progress goals. The
RPOs will make reasonable efforts to facilitate th e development of a consensus between the State with a Class I area and other States affecting that area. In instances where th e State with the Class I area can not agree with such other States that the goal provides for reasonable progress, actions taken to resolve the disagreement must be included in the State’s regional haze implementation plan (or plan revisions) submitted to the EPA Administra tor as required under 40 CFR §51.308(d)(1)(iv).

8) All States whose emissions are reasonably anticipated to contribute to visibility impairment in a Class I area, must provide the Federal Land Manage r (“FLM”) agency for that Class I area with an opportunity for consultation, in person, on their regional haze implementation plans. The States/Tribes will pursue the development of a memorandum of understanding to expedite the submission and consideration of the FLM’s comments on the reasonable progress goals and related implementation plans. As required under 40 CFR §51.308(i)(3), the plan or plan revision must include a description of how the State addressed any FLM comments.

9) States/Tribes will consult with the affected FLMs to protect the air resources of the State/Tribe and
Class I areas in accordance with the FLM coordinatio n requirements specified in 40 CFR §51.308(i) and other consultation procedures developed by consensus..

10) The consultation process is designed to share information, define and document issues, develop a range of options, solicit feedback on options, deve lop consensus advice if possible, and facilitate informed decisions by the Class I States.

11) The collaborators, including States, Tribes and affected FLMs, will promptly respond to other RPO’s/States’/Tribes’ requests for comments.5/27/2010
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26 The following points highlight several of th e many ways MANE-VU member states and tribes have cooperatively addressed regional haze.

 Budget Prioritization: MANE-VU developed a pr ocess to coordinate MARAMA, OTC and NESCAUM staff in de veloping budget priorities, project rankings, and federal grant requests.

 Issue Coordination: MANE-VU establishes a c onference call and meeting
schedule for each of its committees and workgroups. In addition, the MANE-VU Directors regularly discuss pertinent issues.

 SIP Policy and Planning: MANE-VU states/tribes collaborated on the development of a SIP Template and the technical aspects of the SIP development

process.

 Capacity Building: To educate its staff and members, MANE-VU included technical presentations on conference calls and organized workshops with nationally recognized expert s. Presentations on data analysis, BART work, inventory topics, modeling, control measures etc. were an effective education, and
coordination tool.

 Routine Operations: MANE-VU staff at OT C, MARAMA, and NESCAUM established a coordinated approach to : budget, grant deliverables/due-dates, workgroup meetings, inter-RPO feedback, etc.

40 CFR Section 51.308(d)(3)(i) requires the State of Maine to consult with other States/Tribes to develop coor dinated emission management st rategies. This requirement applies both where emissions from the Stat e/Tribe are reasonably anticipated to contribute to visibility impair ment in Class I areas outside the State/Tribe, and when
emissions from other States/Tribes are reasonab ly anticipated to cont ribute to visibility impairment in Class I areas within the State/Tribe.

Maine consulted with other st ates and tribes by participation in the MANE-VU and interRPO processes that developed technical information necessary for development of coordinated strategies. Stra tegy development considered the impacts of the state and
tribe’s emissions on Class I areas within and out side the state or tribe and culminated inthe adoption by MANE-VU on June 20, 2007 of the “Statement of the MidAtlantic/Northeast Visibility Union (MANE-VU) Concerning a Request for a Course of Action by States Within MANE-VU Toward Assuring Reasonable Progress.”

The consultations between the MANE-VU stat es and other states/t ribes and provinces occurred throughout much of 2007. Documentation of consultation meetings and calls is summarized below, in Figure 3-3, with furthe r documentation provided in Attachment C.5/27/2010
Draft For FLM Review

Figure 3-3 Summary of Consultations

27  MANE-VU Intra-Regional Consultation meeting, March 1, 2007

o At this meeting, MANE-VU members reviewed the requirements for regional haze plans, preliminary modeling results, the work being done to prepare the MANE-VU report on reasonable progress factors, and control strategy options under review.

 MANE-VU Intra-State Consultati on meeting, June 7, 2007

o At this meeting the MANE-VU Class I states adopted a statement of principles, and all MANE-VU members discussed draft statements concerning reasonable controls within and outside of MANE-VU. Federal Land Managers also attended the meeting, which was open to
stakeholders.

 MANE-VU Conference Call, June 20, 2007

o On this call, the MANE-VU states concluded disc ussions of statements concerning reasonable controls within and outside MANE-VU and ag reed on the statements called the MANE-VU “Ask,” including a statement concerning cont rols within MANE-VU, a statement concerning controls outside MANE-VU, and a statement requesting a course of action by the U.S. EPA. Federal Land Managers also participated in the call. Upon approval, all statements as well as the statement of principles adopted on June 7 were posted and publicly available on the
MANE-VU web site. The MANE-VU “Ask” was de termined to represent Maine’s needs for meeting Regional Haze rule re quirements and was thus adopted as the Maine Regional Haze
“Ask”.

 MANE-VU Class I States’ Consultation Open Technical Call, July 19, 2007

o On this call, the MANE-VU / Maine “Ask” was pres ented to states in other RPOs, RPO staff, and Federal Land Managers, and an opportunity was provided to request further information. This call was intended to provide information to facilitate informed discussion at follow-up meetings.

 MANE-VU Consultation Meeting with MRPO, August 6, 2007

o This meeting was held at LADCO offices in Chicago, Illinois and was attended by representatives of both MANE-VU and MRPO states as well as staff. The meeting provided an opportunity to formally present the MANE-VU / Maine “Ask” to MRPO states and to consult with them regarding the reasonablene ss of the requested controls. Federal Land Manager agencies also attended the meeting.

 MANE-VU Consultation Meeting with VISTAS, August 20, 2007

o This meeting was held at State of Georgi a offices in Atlanta and was attended by representatives of both MANE-VU and VISTAS stat es as well as staff. The meeting provided an opportunity to formally present the MANE -VU / Maine “Ask” to VISTAS states and to consult with them regarding the reasonablene ss of the requested controls. Federal Land Manager agencies also attended the meeting.

 MANE-VU – Midwest RPO Consultation Conference Call, September 13, 2007

o This call was a follow-up to the meeting held on August 6 in Chicago and provided an opportunity to further clarify what was being as ked of the MRPO states. The flexibility in the “Ask” was explained. Both MRPO and MANE-VU staff agreed to work together to facilitate
discussion of further controls on ICI boilers and EGUs.

 MANE-VU Air Directors’ Consultation Conference Call, September 26, 2007

o This call allowed MANE-VU members to clarify their understanding of the “Ask” and to provide direction to modeling staff as to how to interpret the “Ask” for purposes of estimating visibility impacts of the requested controls.5/27/2010
Draft For FLM Review

28 3.3 Maine-Specific Consultation

On February 26, 2007, Maine sent letters fo rm ally requesting consultation under the Regional Haze Rule to each state shown th rough modeling to contri bute to at least 2 percent of the sulfates to th e Class I Areas in Maine and/orstates located within MANEVU (See Table 3-2). As a matter of procedure, every member state (plus the District of Columbia) of MANE-VU was requested to cons ult with Maine. Additional states from outside of MANE-VU were also requested to join our consultati on, based on the results
of the MANE-VU Contribution A ssessment (Attachment A).

Table 3-2 States Contributing to Vi sibility Impairmen t at Class I Areas in Maine (By Regional Planning Organization)

MANE-VU VISTAS MRPO

Connecticut Georgia Illinois
Delaware Kentucky Indiana
District of Columbia North Carolina Michigan
Maine Tennessee Ohio Maryland Virginia
Massachusetts West Virginia New Jersey
New York Pennsylvania
Rhode Island

Vermont

Formal inter-regional consultation meetings took place on August 6, 2007 in Rosemont, Illinois (for Midwestern states ) and on August 20, 2007 in Atlanta (for Southern states).
Consultation continues with the Midwestern states, seeking common approaches for reducing power plant emissions beyond the leve ls defined under the federal Clean Air Interstate Rule (CAIR), controls on industr ial boilers, and clea ner burning fuels for
mobile sources. While this consultation was mostly focused on the health benefits of reducing ozone and small particles, the meas ures would also result in visibility improvements.

3.4 The MANE-VU “Ask”

In addition to having a set of guiding princi ples f or consultation (as described in Figure 3-2, above), MANE-VU needed a consistent technical basis for emission control strategies to combat regional haze. After mu ch research and analys is, on June 20, 2007, MANE-VU adopted a set of documents (See Attachment D), which provide the technical basis for consultation among the interested pa rties and define the basic strategies for controlling pollutants that cause visibility impairment at Class I areas in the eastern
United States:5/27/2010
Draft For FLM Review

29  “Statement of the Mid-Atlantic / No rtheast Visibility Union (MANE-VU) Concerning a Course of Action within MANE-VU toward Assuring Reasonable Progress”

 “Statement of the Mid-Atlantic / No rtheast Visibility Union (MANE-VU) Concerning a Request for a Course of Action by Stat es outside of MANE-VU toward Assuring R easonable Progress ”

 “Statement of the Mid-Atlantic / No rtheast Visibility Union (MANE-VU) Concerning a Request for a Course of Action by the U.S. Environmental Protection Agency (EPA) Towards Assuring Reasonable Progress”

Together, these documents are known as the MANE-VU “Ask.” Maine believes that these documents outline reasonable strategies for visibility improvement as required by the Clean Air Act, and fully supports the la nguage and substance of these documents.
The MANE-VU “Ask” is therefore the Ma ine “Ask”. The particular emission management strategies that comprise th e Ask are described, in detail, below.

3.5 Meeting the “Ask” – MANE-VU States

The member states of MANE-VU stated their in tention to meet the terms of the “Ask” in their SIPs. Maine conditionally supports the SIPs of each of its fellow MANE-VU members, with this support contingent upon the adoption an d implementation of regional haze emission control measures and programs satisfying the MANE-VU “Ask”. The Ask
for member states calls for each state to pursue the adoption and implementation of the following “emission management” strategi es, as appropriate and necessary:

 Timely implementation of BART requirements in accordance with 40 CFR 51.308(e);

 A low sulfur fuel oil strategy in the inner zone states (New Jersey, New York, Delaware and Pennsylvania, or portions th ereof) to reduce the sulfur content of: distillate oil to 0.05% sulfur by wei ght (500 ppm) by no later than 2012, of #4 residual oil to 0.25% sulfur by weight by no later than 2012, of #6 residual oil to 0.3 – 0.5% sulfur by weight by no later than 2012, and to further reduce the sulfur
content of distillate oil to 15 ppm by 2016;

 A low sulfur fuel oil strategy in the outer zone states (the remainder of the MANE-VU region) to reduce the sulfur content of distillate oil to 0.05% sulfur by weight (500 ppm) by no later than 2014, of #4 residual oil to 0.25 – 0.5% sulfur by weight by no later than 2018, and of #6 residual oil to no greater than 0.5 % sulfur by weight by no later than 2018, and to further reduce the sulfur content of distillate oil to 15 ppm by 2018, depending on supply availability;

 A targeted EGU strategy for each of the top 100 electric generating unit (EGU) emission points or stacks, identified by MANE-VU as contributing to visibility impairment at each mandatory Class I area in the MANE-VU region. (The5/27/2010
Draft For FLM Review

30 combined list for all seven MANE-VU Cl ass I Areas contains 167 distinct emission points. Consequently, this st rategy is sometimes referred to as the 167- stack strategy.) The targeted EGU strategy calls for a ninety-percent or greater
reduction in sulfur dioxide (SO 2 ) emissions from all identified units. If it is
infeasible to achieve that level of re duction from specific units, equivalent alternative measures will be pursued in such state 7 ; and

 Continued evaluation of other control measures, including energy efficiency, alternative clean fuels, and other measures to reduce SO 2 and nitrogen oxide (NOx) emissions from all coal-burning facilities by 2018 and new source performance standards for wood combustion. These measures and other measures
identified will be evaluated during the consultation proc ess to determine if they
are reasonable and cost-effective.

3.6 Meeting the “Ask” – Maine

Maine, being a MANE-VU m ember state, adopted the “Statement of the MidAtlantic/Northeast Visibility Union (MANE-VU) Concerning a Course of Action Within MANE-VU Toward Assuring Reasonable Progr ess” at the MANE- VU Board Meeting on June 7, 2007. Maine intends to meet the terms of this agreement by controlling its BART eligible sources with timely control strategies as well as adopting the low sulfur limits for “outer zone” MANE-VU states and targeted EGU strategies in the near future.

Maine has already obtained stat utory authority to modify th e sulfur in fuel limits in
accordance with the MANE-VU Ask. The 124 th Second Regular Session of the Maine Legislature (2010) adopted LD 1662, “An Ac t To Improve Maine's Air Quality and Reduce Regional Haze at Acadia Nati onal Park and Other Federally Designated Class I Areas,” which implements the MANE-VU low sulfur fuel strategy in Maine. This legislation esta blishes a statewide sulfur limit for distillate fuels of 50 ppm in 2016, and 15 ppm in 2018. For residual (#6) fu el oil, the statewide sulfur limit will be
reduced to 0.5% in 2018.

Maine has one oil-fired EGU (Wyman Stati on Unit #4) that is on the list of top 100 contributing EGUs, and this unit will use lowe r-sulfur fuel oil to comply with BART requirements by 2013. At this point in time, Maine does not believe that SO 2 emissions from this unit can be cost-effectively controlle d at the 90-percent level of the Ask through add-on controls such as flue gas desulfuriza tion because of the very low capacity factor 8

. In lieu of add-on controls for this unit, Main e will be requiring th e use of 0.5 percent lowsulfur fuel oil providing an 84 percent reduction from baseline SO 2 emissions 9 . For more details, refer to Section 12.0, Long Term Strategy.

7 For additional information on the targeted EGU strategy, see section 10.4.3, and Attachment W.

8 The capacity factor for this unit averaged 11.35% during the period 2000-2007.

9 Baseline (uncontrolled) sulfur concentrations for #6 fuel are assumed to be 3,000 ppm, or 3.0%.5/27/2010
Draft For FLM Review

31 3.7 Meeting the “Ask” – States Outside of MANE-VU

For consulting states outside the MANE- VU region, Maine agrees with the MANE-VU “Ask” requesting pursuit of the adoption a nd im plementation of the following control strategies, as appropriate and necessary:

 Timely implementation of BART requirements , as described for the MANEVU states;

 A targeted EGU strateg y, as described for the MANE-VU states, for the top 167 EGU stacks contributing the most to visibi lity impairment at mandatory Class 1 areas in the MANE-VU regi on, or an equivalent SO 2 emission reduction within
each state 10 ;

 Installation of reasonable control measures on non-EGU sources by 2018 to
achieve an additional 28% reduction in non-EGU SO 2 emissions beyond current on-the-books/on-the-way (O TB/OTW) measures, resulting in an emission reduction that is equivalent to that from MANE-V’s low- sulfur fuel oil strategy;
and

 Continued evaluation of other measures including measures to reduce SO 2 and nitrogen oxide (NOx) emissions from all coal-burning f acilities by 2018 and promulgation of new source performance standards for wood combustion. These measures and other measures identified will be evaluated during the consultation process to determine if they are reasonable.

Maine looks for each consulting states to spec ifically address thei r responses to each element of the Maine/MANE-VU “Ask” in their Regional Haze SIPs.

Maine is concerned that non-MANE-VU states may not be inclined to easily adopt our “Ask” due to associated costs, conflicts, a nd relative lack of benefit within their jurisdictions. During cons ultations, MANE-VU members thought that some non-MANEVU states were not going to pursue reduc tions beyond CAIR controls and BART.

There are some positive exceptions, however. Many states of the MRPO are working with MANE-VU states to investigate the poten tial for widespread low sulfur fuel use and
controls on industrial boilers. Unfortunatel y, the low sulfur oil strategy does not lend itself very well to wide-spread application wi thin the VISTAS states because they do not have the same degree of oil use and inventory in frastructure. States of both regions claim

10 While many of the 167 identified stacks will be cont rolled under the Clean Air Interstate Rule (CAIR), cap and trade programs such as CAIR cannot, as cu rrently formulated, ensure that specific stacks or contributing states will adequately reduce their emission contribution (as discussed in the July 11, 2008 U.S. Court of Appeals for the District of Columbia Ci rcuit decision on CAIR). The MANE-VU strategy is designed to provide a guarantee that those units having the greatest impact on visibility in the MANE-VU region will be adequately controlled. It should al so be noted that the MANE-VU strategy also includes stacks located in non-CAIR states (e.g ., Wyman Station in Yarmouth, Maine).5/27/2010
Draft For FLM Review

32 that a substantial portion of the top 167 contributing EGU stacks will be controlled. However, instead of taking concrete ac tions on uncontrolled or under-controlled facilities, many of these states appear to be satisfied with meeting CAIR requirements and not looking beyond CAIR for ad ditional emission reductions.

3.8 Meeting the “Ask” - EPA

Although th e CAIR rule will result in substantial reductions in sulfur dioxide emissions from power plants in the Eastern United St ates, power plants will remain a significant source of visibility impairing pollutants in Maine and other MANE -VU Class I states. Maine supports the “Statementof the Mid-Atlantic / Northeast Visibility Union (MANEVU) Concerning a Request for a Course of Action by the U.S. Environmental Protection Agency (EPA) Towards Assuring Reasonable Progress,” which requests that EPA work with the eastern RPOs to develop a proposal for tightening the CAIR program to achieve
an additional 18% reduction in SO 2 by no later than 2018. ”

3.9 Technical Ramifications of Differing Approaches

MANE-VU states intended to develop a m odeling platform th at was common in terms of meteorology and emissions with each of the ot her nearby RPOs. The RPOs worked hard
to form a common set of emissions with sim ilar developmental assumptions. Even with the best of intentions, it became difficu lt to keep up with each RPO’s updates and
corrections. Each rendition of emissions inventory improved its quality, but because when even a single update was made to one RPO’s emissions, each of the other RPOs then needed to adopt the updates. With each rendition, the revised emissions had to be
re-blended with the full set of emission file s for all associated RPOs in the modeling
domain.

The RPOs also took differing perspectives on which version of the EGU dispatching model (IPM) to use. At the beginning of the process, In tegrated Planning Model (IPM) version 2.1.9 was available, and EPA agreed to its use for emissions preparation. IPM version 3.0 subsequently became available a nd became EPA’s preferred version because of its updated fuel costs. MRPO adopted IP M v3.0 for its use, but VISTAS stayed with IPM v2.1.9. Rather than develop non-comparativ e datasets for its previous IPM analyses, MANE-VU opted to also remain with IPM v2.1.9. Therefore, for each of the three eastern RPOs, differing emissions assumptions ev entually worked their way into the final set of modeling assumptions.

MANE-VU’s final modeling takes into acc ount on-the-books/on- the-way (OTB/OTW) emissions programs for 2018, and goes further by also including a dditional reasonable controls in its region, as de veloped through the Maine/MANE- VU “Ask”. It should be noted that other RPOs may not have included such measures in their final modeling and as a result may have been able to comple te their analyses ahead of the MANE-VU member states. In these instances, there will be an inconsistency in that these states will not have adequately addressed our “Ask” in their SIPs.5/27/2010
Draft For FLM Review

33 3.10 Consultation Issues

40 CFR Section 51.308(d)(1)(iv) describes anothe r consultation requirem ent for Class I States only. If a contributi ng State does not agree with a Class I State on its reasonable progress goal, the Class I State must describe in its SIP submittal the actions taken to resolve the disagreement.

While states without Class I ar eas are required to consult at the request of states with Class I areas, the Regional Haze Rule does not actually require that the states agree on a
common course of action. In stead, if agreement cannot be reached, the disagreement needs to be described in each state’s SIP along with a description of the actions taken to resolve the disagreement. As expected, most states willingly consulted with Maine and took Maine’s regional haze “Ask” under serious consideration. In fact, all of the MANEVU states worked together to strategize on how to develop a common approach to meeting the “Ask”. All states involved in these discussions found that working together helped them to develop plans that would pr oduce region-wide haze a nd health benefits. Lowering ambient PM 2.5 concentrations helped all the MANE-VU states meet the NAAQS as well as having direct benefits to public health and welfare.

Some states in the MRPO and VISTAS regi ons had interpretations of the requirements for BART and for establishing reasonable prog ress goals which differed from those in the
MANE-VU states. Some stat es claimed that CAIR al one set the standard for reasonableness. By this ra tionale, any measure more expe nsive than CAIR (on a costper-ton basis) would not be reasonable. A uni form rate of progress was all that some states felt was required; and if that set of conditions could be met with CAIR, then no
other measures need be considered. Maine is also concerned that some states may have performed modeling for the es tablishment of reasonable pr ogress goals without including the effects of a rigorous BART determination fo r BART-eligible sources. It is apparent that the various regions of the country have differing interpretations of how the Regional Haze Rule should be applied.

In a letter to MANE-VU dated April 25, 2008 (Attachment E), VISTAS indicates that most actions beyond CAIR by states within th is region would not be reasonable. MANEVU takes a more rigorous position with re spect to additional control measures – including the belief that controls on ICI boilers and use of low-sulfur fuels are reasonable
measures and that it is not reasonable to assume reductions fro m EGUs for planning purposes unless they are explicitly incorporated in to State Implementation Plan. More specifically, MANE-VU believes that a sect or-wide average of 50 percent control on coal-fired boilers and 75 percent control on oil-fired boilers are reasonable targets that can be achieved cost-effectively. MANE-VU also believes that low sulfur fuels – even though they are less widely available in the S outheast U.S. than in the Northeast – still represent a reasonable control m easure in light of the widesp read requirement for use of such fuels throughout the MANE-VU region. The reasonableness of these additional controls is examined more fully in Section 11.0, Reasonable Progress Goals.5/27/2010
Draft For FLM Review

34 West Virginia expressed c oncern that while MANE-VU in cluded a 28 percent reduction from the non-EGU sector, they (West Virginia) did not have any measures to meet this additional reduction requirement. West Virginia also indicated that the implementation of CAIR would provide signi ficant emission reductions abov e and beyond those modeled by MANE-VU, and that these reductions shou ld be creditable towa rd the 28 percent nonEGU sector “Ask”. Maine believes that these additional EGU emission reductions should be creditable towards meeting the non-EGU emission reductions measure included in the MANE-VU “Ask,” as long as they are not offset by additional increases in EGU emissions under the CAIR or other cap and trade program.

During the consultation process, disagreements were worked through as best as possible
and are summarized below:

Issue : BART analyses and projecte d controls were not fully in corporated in the VISTAS emissions inventory provided to MANE-VU. VISTAS stated they would further review BART applicable controls.

Resolution : In MANE-VU’s modeling to dete rmine reasonable progress goals, MANE-VU made no adjustments to contro ls in the VISTAS region to reflect application of BART beyond the info rmation that VISTAS provided .

Issue : The low sulfur oil strategy adopted by MANE-VU elicited concerns from MRPO and VISTAS as being unreasonable because of the limited availability of low-sulfur fuel oil and the historically lower usage of this fuel within their regions.

Resolution : MANE-VU agreed to modify the “A sk” to reflect a greater degree of flexibility and provide for alternative measures that would produce a comparable rate of emission reductions. Accordingly, the “Ask” for non-MANE-VU states was modified to provide for an overall 28 percent reduction in SO 2 emissions, wherever they were found to be reasonable. In MANE-VU’s modeling to determine reasonable progress goals, SO 2 emissions from non-E GU sources in non-MANE-VU contributing states were re duced by this same amount.

Issue : MANE-VU received no response from other RPOs concerning non-EGU control measures that they considered reasonable.

Resolutio n: As a default position, MANE-VU’s modeling included emission adjustments for those regions based on MANE-VU’s own analysis of which nonEGU control measures were reasonable (S ee Section 11, Reasonable Progress Goals).

Issue : The targeted EGU strategy was thought by some non-MANE-VU states to be too
restrictive and too difficult to achieve. MANE-VU recognized that a 100 percent compliance with this portion of the “Ask” was unlikely to occur because the CAIR trading market would probably dominate. However, MANE-VU had hoped that nonMANE-VU states would make a more concerte d effort toward meeting this request. MANE-VU did receive a partial list of fac ilities that were expected to comply.5/27/2010
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35 Resolutio n: For the top contributing EGU stacks located within the MANE-VU, MRPO, and VISTAAS regions, expected em ission reductions resulting from the “Ask” were distributed among facilities on the basis of recommendations received during inter- and intra-regiona l consultations. To maintain the CAIR emissions budget as predicted by the modeling, excess emission reductions (also predicted by the modeling) were uniformly added back to EGUs in all three regions.

While CAIR is the primary determinant of which EGUs among the top 167 stacks are to be fitted with emission controls, at the same time, MANE-VU recognized that these units are the primary sources affecting visibility in the MANE-VU stat es. For the initial planning, MANE-VU expects that , over time, these actual facilities will need to be controlled if significant improvements in visibi lity at affected Class I areas are to be
realized.

MANE-VU believes that the goals of the “Ask” will be attained only by means of binding obligations to EGU emission reducti ons beyond what CAIR was expected to provide. MANE-VU therefore maintains that additional federal action is needed to achieve the visibility benef its shown to be feasible th rough sensitivity modeling (See Attachment P, “MANE-VU Modeling fo r Reasonable Progress Goals: Model Performance Evaluation, Pollution apportionment and Control Measure Benefits,” Feb. 7, 2008) and demonstrated to be available at r easonable cost (See Attachment S, Alpine Geophysics, LLC, “Documentation of 2018 Emissi ons from Electric Generating Units in
the Eastern United States for MANE-VU’ s Regional Haze Modeling,” Revised Final Draft, April 28, 2008).

MANE-VU’s position on this issue is forma lly expressed in its “Statement of the
Mid/Atlantic/Northeast Visi bility Union (MANE-VU Concerning a Request for a Course of Action by the U.S. Environmental Pr otection Agency (EPA) toward Assuring Reasonable Progress” adopted June 20, 2007. This statement, more commonly known as MANE-VU’s National “Ask,” is included in Attachment D. Although other RPOs did not adopt all of the same philosophies or processes for their re gional haze Sips, the consultation process maintains a central role in regional haze planning. Maine is pleased with the significant opport unities identified for ongoing cons ultation with other states concerning long-term strategies, not only for regional haze mitigation, but also for improved air quality in general.

Maine and other MANE-VU states are committed to continuing consultation with states in the MRPO and VISTAS regions, through pa rticipation in the State Collaborative process, in which new regional control strategi es are discussed to reduce future emissions of multiple pollutants of common regional concern.5/27/2010
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36 

### 4. State/Tribe and Federa l Land Manager Coordination

40 CFR Section 51.308(f) requires the State of Maine to submit its SIP revision by July 31, 2018 and every ten years thereafter.

40 CFR Section 51.308(i) requires coordination between States/Tribes and the Federal Land Managers (FLMs). Oppor tunities have been provi ded by MANE-VU for FLMs to
review and comment on each of the techni cal documents developed by MANE-VU and included in this SIP. Maine has provided agency contacts to the FLMs as required. In the development of this Regional Haze Pl an, the FLMs were consulted in accordance with the provisions of 40 CFR Section 51.308( i)(2). The State of Maine has provided the FLMs an opportunity for consultation, in person and at least 60 days prior to holding any public hearing on the SIP. This SIP was submitted to FLMs on May 25, 2010 for formal
review and comment.

In accordance with 40 CFR Section 51.308(i) (3) the State of Maine has received comments regarding the SIP from FLMs. Comments received from the Federal Land Managers on the Plan were addressed. The comments and responses are included in Attachment F of this plan.

40 CFR Section 51.308(i)(4) requires procedures for continuing consultation between the State/Tribe and FLMs on the implementation of the visibility protection program. The
State of Maine will consult with the Federa l Land Manager(s) on the status of the following implementation items:

1. Implementation of emissions strategies id entified in the SIP as contributing to achieving improvement in the worst-day visibility
2. Summary of major new source permits issued
3. Status of State/Tribe actions to meet commitments for completing any future assessments or rulemakings on sources identified as likely contributors to visibility impairment, but not directly a ddressed in the most recent SIP revision
4. Any changes to the monitoring strategy or monitoring stations status that may affect tracking of reasonable progress

5. Work underway for preparing the 5-year review and / or 10-year revision
6. Items for FLMs to consider or provide suppor t for in preparation for any visibility protection SIP revisions (based on a 5-y ear review or the 10-year revision schedule under EPA’s RHR)

7. Summary of topics discussion (meetings, emails, other records) covered in ongoing communications between the State/Tribe and FLMs regarding implementation of the visibility program.

The consultation will be coordinated with th e designated visibility protection program coordinators for the National Park Service, U. S. Fish and Wildlife Service and the U.S. Forest Service, and will cons ist of an annual report to th e respective FLMs , along with an opportunity for an in-person or teleconferen ce consultation.5/27/2010
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37 40 CFR Section 51.308(g) requires the State of Maine to submit a report to the EPA every 5 years evaluating progr ess towards the reasonable pr ogress goal for each Class I
Federal area located within the State and in each Class I area located outside the State that may be affected by emissions from within the State. The first progress report is due 5 years from submittal of the initial implementation plan and must be in the form of implementation plan revisions.

In accordance with 40 CFR Section 51.308(h), at the time of the report submission, the State of Maine will also submit a determination of the adequacy of its existing Regional
Haze SIP revision.5/27/2010
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38 

### 5. Assessment of Baseline and Natur al Conditions (with Class I Areas)

5.1 Requirements, Data, and Methodology

Under the Clean Air Act, the Regional H aze SIPs must contain measures to make reasonable progress toward the goal of achievi ng natural visibility. Each state containing
a Class I area must determine baseline and na tural visibility conditions for their Class I area(s) in consultation with FLMs and stat es identified as containing sources whose emissions contribute to visibility impair ment in Class I areas . Comparing baseline conditions to natural visibility conditions de termines the uniform rate of progress that
must be considered as states set reasona ble progress goals for each Class I area.

The Interagency Monitoring of Protected Visual Environments (IMPROVE) program
was initiated in 1985 to establish current visi bility conditions, track changes in visibility, and help determine the causes of visibili ty impairment in Class I Areas. IMPROVE stands for Interagency Monitoring and Prot ected Visual Environments. IMPROVE data
was used to calculate baseline and natu ral conditions for MANE-VU Class I areas.

Data from the following IMPROVE monitors (s ee the table below) is representative of
Class I Areas in Maine 11 . As described in the Monitori ng Section of this SIP, Maine accepts the IMPROVE designation of these site s as representative of Class I areas in
Maine in accordance with 40 CFR Section 51.308(d)(2)(i).

Table 5-1
IMPROVE Information for Maine Class I Areas

Class I Area IMPROVE
Site Location (latitude
and longitude)
Acadia National Park ACAD1 44.38, -68.26
Moosehorn Wilderness Area and Roosevelt campobello International
Park MOOS1 45.13, -67.27 Source: VIEWS ( http://vista.circa.colostate.edu/views/ ), prepared on 7/06/06

In September 2003, EPA issued guidance for the calculation of na tural background and baseline visibility conditions. The guidan ce provided a default method and describes certain refinements that states may wish to ev aluate in order to tailor these estimates to a

11 The IMPROVE program has utilized representative monitoring since its inception, since man-made structures such as monitoring sites are restricted in national wilderness areas. Since regional haze sources and impacts are distributed over broad geographic regions, a representative monitoring site does not need to be located in close proximity to the Class I area bein g represented. For additional information see “Spatial and Seasonal Patterns and Temporal Variability of H aze and its Constituents in the United States: Report III, Chapter 1 ( http://vista.cira.colostate.edu/improve/Publications/Reports/2000/2000.htm ).5/27/2010
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39 specific Class I area if it is poorly represen ted by the default method. At that time, NESCAUM calculated natural visibility for each of the MANE-VU Class I areas using the default method for the 20 percent best and worst days. NESCAUM also evaluated ways to refine the estimates. Potential refinements included: increasing the multiplier used to calculate impairment attributed to ca rbon, adjusting the form ula used to calculate the 20 percent best and worst visibility days , and accounting for visibi lity impairment due
to sea salt at coastal sites. However, MANE-VU found that these refinements did not significantly improve the accuracy of the estimates and MANE-VU states desired a consistent approach. Therefore, default estimates were used with the understanding that use of the default methodology would be reconsidered as better scie ntific unde rstanding
warranted.

Once the technical analysis was complete, MANE-VU provided an opportunity to comment to federal agencies and stakeholde rs. The proposed approach was posted on the MANE-VU website on March 17, 2004 and a stak eholder briefing was held on the same day. Comments were received by Electric Power Research Institute, Midwest Ozone Group, the Appalachian Mountain Club, the Na tional Parks Conservation Association, the National Park Service, and the U.S. Forest Service.

Several commenters supported the proposal a nd other comments addressed four main topics: the equation used to calculate visibility, the sta tistical technique used to estimate the 20 percent best and worst visibility days , the inclusion of tr ansboundary effects and fires, and the timing of when new inform ation should be included. All comments were reviewed and summarized by MANE-VU, and me mber state’s Air Directors were briefed on comments, proposed response options, and implications.

The MANE-VU position on natural background c onditions was issued in June 2004, and stated that, “Refinements to other aspects of the default method (e.g., refinements to the assumed distribution or treatment of Rayl eigh extinction, inclusion of sea salt, and improved assumptions about the chemical composition of the organic fraction) may be warranted prior to submission of SIPs de pending on the degree to which scientific consensus is formed around a specific approach...”

In 2006, the IMPROVE Steering Committee ad opted an alternative reconstructed extinction equation to revise certain aspects of the defau lt method. The aspects revised were scientifically well understood, and the Committee determined that revisions improved the performance of the equation at reproducing observed visibility at Class I
sites.

In 2006, NESCAUM conducted an assessment of the default and alternative approaches
for calculation of baseline and natural background conditions at MANE-VU Class I areas, and the baseline and na tural conditions reported herein were calculated using the alternative method approved by the IMPR OVE Steering Committee in 2006 (See the MANE-VU document, “Baseline and Natural Background Visibility Conditions: Considerations and Proposed Approach to the Calculat ion of Baseline and Natural Background Visibility Conditions at M ANE-VU Class I Areas”, (Attachment G )

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40 MANE-VU will continue to participate in furt her research efforts on this topic and will reconsider the calculation methodology as scientific understanding evolves.

5.2 Maine Baseline Visibility

The IMPROVE program has calculated the 20 percent worst baseli ne (2000-2004) and 20 percent best baseline conditions for each IMPROVE m onitoring site at MANE-VU Class I Areas. These values are posted on the Visi bility Information Exchange Web System (VIEWS) operated by the Regional Planni ng Organizations (available online at http://vista.cira.colostate.edu/views/ ). The values for the Maine Class I areas can be seen
below in Table 5-2. Table 5-2 lists the ba seline visibility for the 20 percent worst visibility days as a five-year averag e for 2000-2004 using the alternative IMPROVE algorithm approved in 2006 by the IMPROVE Steering Committee.

Table 5-2 Baseline Visibility for the 20 Percent Worst Days and 20 Percent Best Days for Five Years (from 2000-2004) in Maine Class I Areas

Class I Area (IMPROVE Monitor) Year 20 Percent Worst Days Deciviews (dv) 20 Percent Best Days Deciviews (dv)

Acadia National Park 2000 21.64 8.89

2001 23.28 8.87

2002 23.91 8.77

2003 23.65 8.77

2004 21.98 8.56 Five Year Average 22.89 8.77

Moosehorn Wilderness Area and Roosevelt Campobello International Park 2000 20.63 8.93

2001 22.13 9.3

2002 23.06 9.12

2003 22.5 9.48

2004 20.28 8.93 Five Year Average 21.72 9.15

Source: VIEWS ( http://vista.circa.colostate.edu/views ), prepared on 10/16/07

5.3 Natural Visibility

A five year average (2000 to 2004) visibi lity in deciviews wa s calculated for each MANE-VU Class I area for the 20 percent best and 20 percent worst days in accordance with 40 CFR 51.308(d)(2) and detailed in the NESCAUM Baseline and Natural Background document found in Attachment G. Th e deciview visibility for the worst and best days are based on calculations and data included in Attachment G of this SIP.5/27/2010
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41 Natural visibility represents the visibility for each Class I area representative of the
conditions before human activities affected air quality in the ar ea. Certain natural phenomena can reduce visibility. The Clean Air Act goal is to remedy visibility impairment resulting from human activity.

Table 5-3 displays the baseline visibility fo r the 20 percent worst a nd the 20 percent best visibility days based on the five-year aver age for 2000-2004, natural vi sibility for the 20 percent worst and the 20 percen t best visibility days, and the difference between baseline and natural visibility conditions for the Maine Class I areas.

Table 5-3 Summary of Baseline Visibility and Natural Conditions for the 20 Percent Worst and 20 Percent Best Visibility Days for Maine Class I Areas

Class I Area 2000-2004 Baseline (dv) Natural Conditions (dv) Difference (dv)

Worst
20 % Best
20 % Worst
20 % Best
20 % Worst
20 % Best
20 %
Acadia National Park 22.89 8.77 12.43 4.66 10.46 4.11
Moosehorn Wilderness Area and Roosevelt campobello
International Park 21.72 9.15 12.01 5.01 9.71 4.14

Source: VIEWS ( http://vista.circa.colostate.edu/views/ ), prepared on 6/22/20075/27/2010
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42 

### 6. Monitoring Strategy

In the mid-1980’s, the IMPROVE program (Interagency Monitoring of Protected Visual Environments) was established to m easure visibility impairment in mandatory Class I areas throughout the United States. The monitoring sites are operated and maintained through a formal cooperative rela tionship between the U.S. EPA, National Park Service, U.S. Fish and Wildlife Serv ice, Bureau of Land Management, and U.S. Forest Service. In 1991, several additional or ganizations joined the effort: State and Territorial Air Pollution Program Administra tors and the Association of Local Air Pollution Control Officials (which now goes by The National Associ ation of Clean Air Agencies), Western States Air Resources Council, Mid-Atlantic Regional Air Management Association, and Northeast States for Coordinated Air Use Management.

Data collected at these sites are used by la nd managers, industry planners, scientists, public interest groups, and air quality regulators to understand and protect the visual air quality resource in Class I areas. Most importantly, the IMPROVE program scientifically documents for American citizens, the visual air quality of thei r wilderness areas and national parks. Program objectives include:

 Establish current visibility and aerosol conditions in mandatory Class I areas.

 Identify chemical species and emi ssion sources responsible for existing anthropogenic visibility impairment.

 Document long-term trends for assessing progress towards the national visibility goals.

 Provide regional haze monitoring representing all visibility-protected federal Class I areas where practical, as require d by EPA’s Regional Haze Rule.

6.1 Federal Regional Haze Monitoring Requirements

Section 51.3 08(d)(4) of EPA’s Regional Haze Rule requires a monitoring strategy for measuring, characterizing, and reporting regi onal haze visibility impairment that is representative of all mandatory Class I Areas within the State of Maine. The monitoring strategy relies upon participa tion in the Interagency Mon itoring of Protected Visual Environments (IMPROVE) network.

The State of Maine participates in IMPROVE network, and will evaluate the monitoring network periodically and make those change s needed to be able to assess whether reasonable progress goals are being achieved in each of Maine’s mandatory Class I Areas. Maine is committing to continued support of the IMPROVE network at Acadia
National Park and Moosehor n National Wildlife Refuge.

40 CFR 51.308(d)(4)(i) requires states to establish addi tional monitoring sites or equipment as needed to assess whether re asonable progress goals are being achieved5/27/2010
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43 toward visibility improvement at mandatory Class I areas. At this time, the current
monitors are sufficient to make this asse ssment. Maine’s commitment to maintain the current level of monitoring, and to expand mon itoring and/or analysis should such action become necessary, will remain conti ngent on federal funding assistance.

40 CFR Section 51.308(d)(4)(ii) requires th e inclusion of procedures by which monitoring data and other information are used in determining the contribution of
emissions from within the Stat e to regional haze visi bility impairment at mandatory Class
I Federal areas both within and outside th e State. MANE-VU and the State of Maine accepts the contribution assessment anal ysis completed by NESCAUM entitled, “Contributions to Regional Haze in th e Northeast and Mid-Atlantic States.” (See Attachment A). We agree that NESCAUM is providing quality technical information by using the IMPROVE program data and the VIEW S site. Information about the use of the default and alternative approach es to the calculation of ba seline and natural background
conditions can be found in Section 5 “Asse ssment of Baseline, Natural and Current
Conditions” of this SIP.

Maine commits to meet the requiremen ts under 40 CFR Section 51.308(d)(4)(iv) to report to EPA visibility data for each of Maine’s Class I Areas annually.

40 CFR Section 51.305 requires each state containi ng a mandatory Class I Federal area to include in its SIP a strategy for evaluating r easonably attributable visibility impairment (RAVI) in any such Class I Area by visual obs ervation or other appropriate monitoring techniques. The plan must provide for the cons ideration of available visibility data and must provide a mechanism for its use. This requirement does not apply to the State of Maine because no specific sources have been id entified as subject to RAVI requirements.

40 CFR Section 51.308(d)(4)(v) requires a statewide inventory of emissions of pollutants that are reasonably anticipated to cause or contribute to visibility impairment in mandatory Class I Federal areas within the State of Maine. The Emissions Inventory Section (Section 8) of this SI P addresses this requirement.

EPA’s Regional Haze Rule (40 CFR Section 51. 308(d)(4)(vi)) requires the inclusion of other monitoring elements, including repor ting, recordkeeping, and other measures, necessary to assess and report vi sibility. While the State of Maine feels that the current IMPROVE network provides sufficient data to adequately measur e and report progress toward the goals set for MANE-VU Class I s ites that we contribut e to, Maine has also found additional monitoring information useful to assess visibility and fine particle pollution in the region in the past. Examples of these data include results from the MANE-VU Regional Aerosol Intensive Netw ork (RAIN), which provides continuous, speciated information on rural aerosol characte ristics and visibility parameters; the EPA Clean Air Status and Trends Network (CAS TNET), which has provided complementary rural fine particle speciation data at non-class I sites; th e EPA Speciation Trends Network (STN), which provides speciated, urban fi ne particle data to help develop a comprehensive picture of local and regiona l sources; state-operated rural and urban speciation sites using IMPROVE or STN meth ods; and the Supersites program, which has provided information through special studies that generally expands our5/27/2010
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understanding of the processes th at control fine particle fo rm ation and transport in the region. Maine will continue to utilize these and other data -- as they are available and fiscal realities allow -- to improve our understanding of visibility impairment and to document progress toward our reasonable progress goals under the Regional Haze Rule.

6.2 Monitoring Information for MANE-VU Class I Areas

6.2.1. Acadia National Park, Maine

The IMPROVE monitor for Acadia National Pa rk (indicated as ACAD1) is located at Acadia National Park Headquarters in Maine at an elevation of 157 me ters, a latitude of
44.38  ̊ and a longitude of -68.26  ̊ . The haze data for Acadia National Park is collected by an IMPROVE monitor (ACAD1) that is operated and maintained by the National Park
Service. The State considers the ACAD1 s ite as adequate for assessing reasonable progress goals of Acadia National Park and no additional monitoring sites or equipment are necessary at this time. The State routin ely participates in the IMPROVE monitoring program by sending regional representa tives to the IMPROVE meetings.

Figure 6-1 Map of Acadia National Park

Acadia National Park IMPROVE Site

Created by Tom Downs, MEDEP 4/17/07 IMPROVE MONITOR LOCATION

ACADIA NATIONAL PARK LEGEND

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6.2.2. Moosehorn Wilderness Area, Maine

The IMPROVE monitor for the Moosehorn W ilderness Area (indicated as MOOS1) is located near McConvey Road, about one mile northeast of the National Wildlife Refuge Baring Unit Headquarters in Maine at an el evation of 78 meters, a latitude of 45.13  ̊ and a longitude of -67.27  ̊ . This monitor also represents the Roosevelt Campobello International Park in New Brunswick, Canada. The haze data for Moosehorn Wilderness Area is collected by an IMPROVE monitor (M OOS1) that is operated and maintained by
the Fish & Wildlife Service. The State c onsiders the MOOS1 site as the only current IMPROVE monitoring site in Maine adequate for assessing reasonabl e progress goals of
the Moosehorn Wilderness Area and no addition al monitoring sites or equipment are necessary at this time. The State routinel y participates in the IMPROVE monitoring program by sending regional representa tives to the IMPROVE meetings.

Figure 6-2 Map of the Baring and Edmunds Division s of the Moosehorn National Wildlife Refuge and the IMPROVE Monitor

(source: The Refuge Manager at Moosehorn Wilderness Area)

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6.2.3. Roosevelt Campobello Interna tional Park, New Brunswick, Canada

The IMPROVE monitor for the Moosehorn W ilderness Area is also the monitor for Roosevelt Campobello International Park (indicated as MOOS1) (see section 6.2.2, above). The State considers the MOOS1 s ite as the only current IMPROVE monitoring site in Maine or Canada adequate for asse ssing reasonable progress goals of Roosevelt Campobello International Park. No additio nal monitoring sites or equipment are

necessary.

Figure 6-3 Map of Roosevelt Campobello International Park

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47 

### 7. Sources of Visibility Impairing Pollutants and Contribution
Assessment

7.1 Visibility Effects of Particulate Matter

Visibility impairment in the eastern United Stat es is primarily due to the presence of fine particles in the atmosphere which absorb and scatter light. Visibil ity impairing particlelight interactions are sensitive to the chemi cal composition of the particles involved, and also depend strongly on ambient relative humidit y. Secondary particles, which form in the atmosphere through chemical reactions, ar e generally smaller than one micrometer
(  m ) which is the size range that is most effective at scattering visible light 12

.

The degree of visibility impairment is expr essed in deciviews, a unit-less value. The calculation of visibility impa irment utilizes two equations, one to calculate light extinction coefficient (B ext ), and then its transformation in to visibility impairment as expressed in deciviews ( dv). The latest equation, 13 approved by the Interagency Monitoring of Protected Visual Environm ents (IMPROVE) Steering Committee, to calculate light extinction coefficient is:

The Extinction Equation

B ext = 2.2 x f S (RH) x [Small Sulfate] + 4.8 x f L (RH) x [Large Sulfate]
+ 2.4 x f S (RH) x [Small Nitrate] + 5.1 x f L (RH) x [Large Nitrate] + 2.8 x [Small Organic Mass] + 6.1 x [Large Organic Mass] + 10 x [Elemental Carbon] + 1 x [Fine Soil Mass]
+ 1.7 x f SS (RH) x [Sea Salt Mass] + 0.6 x [Coarse Mass] + Rayleigh Scattering (Site Specific) + 0.33 x [NO 2 (ppb)]

Where:

B ext = The light extinction coeffici ent in inverse megameters [Mm -1 ]
f s (RH) and f L (RH) = Humidity factor associated with small and large mode mass size
distributions
f ss (RH) = Humidity factor associated with Sea Salt

The on-site air monitoring of visibility causing pollutants by the IMPROVE monitoring
network is discussed in more detail in Section 6 of this document. In the extinction equation, total sulfate, nitrate and organic carbon compound concentrations are each divided into two particle size fractions, representing small and large size particle components. Site-specific Rayleigh scatte ring is calculated by IMPROVE for the

12 The particles that contribute most to visibility impa irment are also of concern under the health-based National Ambient Air Quality Standard (NAAQS) for fine particulate matter, which is defined as all particles with an aerodynamic diameter less than 2.5  m. 13 Review of the IMPROVE Equation for Estimating Ambi ent Light Extinction Coefficients - Final Report Jenny L. Hand and William C. Malm, March 20065/27/2010
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48 elevation of the site as well as annual aver age temperature of each IMPROVE monitoring
site.

Once light extinction is calculated, visibility levels (in deciviews (dv)) can be calculated. The deciview equation is as follows:

The Deciview Equation

Deciviews (dv) = 10 ln (b ext /10)

Where: ln is the natural log function and B ext is calculated using the IMPROVE equation previously described. The calculated decivi ews are unit-less values where the higher the value, the greater amount of visibility impairment exists.

The extinction and deciview equations were us ed to calculate the baseline and projected visibility impairment at Acadia Nati onal Park, Moosehorn Wilderness Area and Roosevelt Campobello International Park, and to set the progress goals as established in
this Document.

7.2 Pollutants Contributing to Visibility Impairment at Class I Areas

The pollutants prim arily responsible for fine particle formation, and contributing to regional haze, include SO 2 , NO 2 , VOCs, NH 3 , PM 10 , and PM 2.5 . The MANE-VU Contribution Assessment (Attachment A) develo ps a conceptual model for regional haze
in the Northeast and Mid-Atlantic states th at identifies sulfate as the single most important constituent of haze forming fine pa rticle pollution, and th e principal cause of visibility impairment across the Northeast region. Sulfate alone accounts for anywhere from one-half to two-thirds of total fine part icle mass on the 20 percen t haziest days at all MANE-VU Class I sites, and 40 percent or mo re of total fine particle mass on the 20 percent clearest days.

After sulfate, organic carbon (O C) consistently accounts for the next largest fraction of total fine particle mass, contributing from 20- 30 percent of total fine particle mass on the haziest days. Relative contri butions to overall fine part icle mass from nitrate (NO 3 ), elemental carbon, and fine crustal material (i .e., soil) are all smaller, generally under 10 percent of the total, with relative ranking of the three species varying with location. Nitrate plays a noticeably more important role at urban sites compared to Northeastern
and Mid-Atlantic Class 1 sites.

Almost all particle sulfate orig inates from sulfur dioxide (SO 2 ) oxidation 14 and typically associates with ammonium (NH 4 ) in the form of ammonium sulfate ((NH 4 (SO 4 )).

14 Sulfate is produced from SO 2 in the atmosphere under two major pathways. In the gas phase, SO 2 is oxidized to sulfuric acid (H 2 SO 4 ), ammonium bisulfate (NH 4 HSO 4 ), or ammonium sulfate, depending on the availability of ammonia (NH 4 ). In the presence of small wet particles (typically smaller than fog), an aqueous phase process can oxidize SO 2 to sulfate extremely quickl y (@ 10 percent per hour).5/27/2010
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Approxim ately 95 percent of SO 2 emissions are from anthropogenic sources (primarily fossil fuel combustion), while the majority of ammonium comes from agricultural
activities.

Sulfate is not only the dominant contributor to fine particle mass in the region, but also accounts for anywhere from 60 percent to al most 80 percent of the difference between fine particle concentrations on the clearestand haziest days at Northeastern and MidAtlantic Class I sites, including those in Ma ine. Some of the do minant components of total fine particle mass have an even larg er effect when considering the differential visibility impacts of different particle species. Sulfate typically accounts for more than 70 percent of estimated particle -induced light extinction at No rtheastern and Mid-Atlantic sites. Organic carbon is the second most im portant contributor to particle-induced light extinction on days with the greatest visibili ty impairment, with nitrate being the third greatest contributor to regi onal haze at Class I sites in the MANE-VU region, including
those in Maine.

Figure 7-1 shows the dominance of sulfate in visibility extinction calculated from 2000-
2004 baseline data for seven Northeast Class I Areas.

Figure 7-1
Contributions to PM2.5 Extincti on at Seven Class I Areas

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50 Given the dominant role of sulfate in the fo rmation of regional haze in the Northeast and Mid-Atlantic Regions, MANE- VU concluded that an effective emissions management approach would rely heavily on broad-based regional SO 2 control measures in the eastern
United States. The focus on SO 2 as MANE-VU’s first priority makes sense not only because of its dominant role in regional haze but also because its emission sources are well understood. Moreover, the control measures needed for SO 2 emission reductions are readily available, cost-effective, and could be implemented quickly. On the basis of the scientific evidence, it is apparent that the bulk of haze-causing pollution can be eliminated by pursuing SO 2 emission controls.

Organic carbon was found to be the next la rgest contributor to haze after sulfate, however, in comparison with sulfate, the emi ssion sources of organi c carbon are diverse, variable, more diffuse, and less well understood. Organic carbon particulates can be emitted as a primary organic aerosol, or th ey can be formed as a secondary organic aerosol. Secondary organics are formed when volatile organic compound (VOC)
emissions react with oxides of nitrogen in the presence of sunlight to form ozone, which acts as a catalyst for particulate formation. VOCs may also condense to from particulate organic carbon. For these r easons, MANE-VU considered organic carbon to be the subject of possible future contro l measures but not a specific ta rget pollutant in the initial strategy to mitigate regional haze. 15

7.3 Geographic Considerations and Haze Contribution Attribution

As noted in the Contribution Assessm ent (Attachment A), high levels of particle pollution in the eastern United States of ten causes hazy conditions extending over thousands of square kilometers (km 2 ). As a result, visibility is often impaired at even the most remote and pristine Class I areas.

To better identify the sources of visibility impairing pollutants, the MANE-VU Contribution Assessment utilized a variety of modeling, air quality data analysis, and emissions inventory analysis techniques to identify source categories and states that contribute to visibility impairment in MANE-VU and nearby Class I areas. The analytical and assessment tools utilized for the Contribution Assessm ent include Eulerian (grid-based) source models, Lagrangian (air parcel-based) source di spersion models, and a variety of data analysis techniques in cluding source apporti onment models, back trajectory calculations, and the use of monitoring and inventory data. Table 7-2 below, summarizes the methodological approach es of these analytical tools.

15 Although sulfur is the primary regional haze pollutant of concern for this SIP, Maine has taken measures to address organic carbon emissions, primarily from residential wood burning activities. These measures are discussed in Section 12 “Long-Term Strategy .”5/27/2010
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51 Table 7-2 Summary of Technical Approaches for Attributing State Contributions to
Observed Sulfate in MANE-VU Class I Areas

Analytical Technique Approach
Emissions/distance Empirical Incremental probability Lagrangian trajectory technique Cluster-weighted probability Lagrangian trajectory technique Emissions × upwind probability Empirical/trajectory hybrid Source apportionment approaches Receptor model/trajectory hybrid REMSAD tagged species Eulerian source model CALPUFF with MM5-based meteorology Lagrangian source dispersion model CALPUFF with observation-based meteorology Lagrangian source dispersion model

7.3.1 Review of Technical Approaches

The MANE-VU Contribution Assessment a nd Appendices (Attachments A, A-1, A-2, A3 and A-4) provide a detailed description of the multiple technical approaches used to assess regional haze (sulfate) contributions to the MANE-VU region. Following is a summary of four of these techniques.

I. Emissions/Distance

The emissions/distance empirical technique ca lculates the ratio of annual emissions (Q) to source-receptor distance (d), with the ratio (Q/d) which is then multiplied by a factor to account for the frequency effect of prevailing winds. 16 The geographic domain of the sources included in the Q/d study consisted of U.S. states in the CENRAP, MANE-VU, VISTAS, and MRPO regions. Canadian provinces in the lower eastern region were also included. The categories of SO 2 emission sources included in this analysis were area sources (e.g., residential boilers and heaters), non-road mob ile sources (e.g., tractors and construction vehicles), and point sources (e.g., industrial smokestacks and power

16 Aggregated over long periods of time and large geographic areas, the total atmospheric sulfate contribution from a specific source, state, or region should be approximately proportionate to its SO 2 emissions. For specific receptor locations, like a Clas s 1 visibility area, relativ e impacts decrease with increasing distance from the source. Impacts diminish over distance as pollutants are dispersed in the atmosphere and removed through deposition. For non-r eactive primary pollutant emissions, the relationship between atmospheric concentrations and distance (d) can be approximated as a function of 1/d 2 . For secondary pollutants like sulfate, reductions in ambient concentrations that occur as a result of dispersion and deposition mechanisms are partially offset by the formation of secondary aerosol such that an increasing fraction of the remaining downwind sulfur is converted to ae rosol sulfate. In these cases, the effects of distance are better characterized by the function 1/d. During regional sulfate episodes when sulfur conversion rates are enhanced by th e presence of gas and aqueous-phase oxidants, pollutant concentrations decline even less rapidly with distan ce as accelerated aerosol formation rates work to both generate more sulfate and reduce the remaining sulfur available for deposition (deposition rates are roughly an order of magnitude slower for sulfate than for SO 2 ).5/27/2010
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generation facilities). R esu lts were calculated for seven receptors in the MANE-VU and VISTAS regions including: Acad ia National Park, Brigantine Wilderness in the Forsythe Wildlife Preserve, Dolly Sods Wilder ness, Lye Brook Wilderness, Moosehorn Wilderness, Presidential Range-Dry River Wilderness, and Shenandoah National Park.

To calculate the impact that each state ha d on a given receptor, the area and nonroad
SO 2 emission sources were summed across the entire state, and the distance to the receptor site for those emission sources was calculated based on that state’s geographic center, adjusted for population density. In this way, the area and non-road emissions were treated as a single poi nt source located at the popul ation-weighted center of each state. These impacts were then added to th e impact of the point sources that were calculated individually. The su m of area, non-road, and point source impacts for each state was used to compare the contributions rela tive to other states in the eastern U.S. and parts of Canada.

The principal contributors to the MANE-VU r eceptors, according to this method, include
the Midwestern states of Indi ana and Ohio, as well as Pe nnsylvania and New York. This is due not only to the large emissions from these states, but also to the predominantly westerly winds that carry Midwest polluti on eastward. Table 7-3 shows the relative
contribution of eastern states and Canadian provinces on several receptor sites in the region.
Table 7-3 Annual average Sulfate Impact from Q/D (%)

From: Table 8.2 of Contributions to Regional Haze in the Northeast and Mid-Atlantic United States, NESCAUM, 2006

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II. Em issions Times Upwind Probability

Another empirical approach ut ilized in the Contribution Assessment is the emissions times upwind probability technique, which multiplies the back-trajectory calculated residence time probability for a grid cell wi th the total emissions (over the same time period) for that grid cell 17 . This technique results in an emissions-weighted probability field that can be integrated within state bounda ries to calculate the relative probabilities of each state contributing to pollution transport. Table 7-4 illustrates the average ranked
contributions to several MANE- VU and VISTAS Class I areas.

Table 7-4 Annual Average Sulfate Impact from the Emissions x Upwind Probability Technique

From: Table 8.5 of Contributions to Regional Haze in the Northeast and Mid-Atlantic United States, NESCAUM, 2006

53 17 A back trajectory is the path that an air parcel is calculated to have taken prior to arriving at a given receptor. The back traject ories utilized in this analysis were 72 hours in length, and have calculated endpoints, or locations, that specify the air mass path at hourly intervals. The endpoints from all trajectories were mapped into a matrix of residence times spent in the individual grid cells over the five year study period, with the result providing the likelihood that air spent time in a particular grid cell. By then multiplying the “residence time” by the MANE-VU SO 2 emission inventory for the grid cell, the contribution of each grid cell (a nd state) can be calculated.5/27/2010
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III. REMS AD Tagged Species Modeling

Table 7-5 displays the results of an Euleri an source model (the REMSAD model) used to assess state-by-state and regiona l contributions to annual sulf ate impacts in nine Class I areas. The Regional Modeling System for Aerosols and Deposition (REMSAD) is a three-dimensional Eulerian model designe d to support a better understanding of the distributions, sources, and remova l processes relevant to fine particles and other airborne pollutants. It calculates the concentrations of both inert and chemically reactive pollutants by simulating the physical and chemical processe s in the atmosphere that affect pollutant
concentrations. The basis for the model is an atmospheric diffusion equation representing
a mass balance in which all of the relevant emissions, transport, diffusion, chemical reactions, and removal processes are e xpressed in mathematical terms.

Table 7-5 Average Annual Sulfate Impact at Northe ast Class I Areas as Modeled Using
REMSAD

From: Table 8.1 of Contributions to Regional Haze in the No rtheast and Mid-Atlantic United States, NESCAUM, 2006.

As in the empirical analytical techniques, the REMSAD model identifies the States of Ohio, New York, and Pennsylvania as the predominant contributors to visibility impairment at MANE-VU Class I areas, including those in Maine. Unlike the

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55 previously-described empirical approaches , the REMSAD model identifies Maine as the single greatest contri butor to visibility impairment at Maine Class I areas. 18

IV. CALPUFF

A fourth approach to contribution assessment is the use of a dispersion model such as CALPUFF. CALPUFF is commonly used study the impacts of pollutant plumes or specific point source emissions on surrounding areas. While the geographic scale of these models has traditionally been limited to a fe w hundred kilometers because of a perceived lack of ability to accurately reproduce horizontal dispersion beyond these distances, recent advances in the CALPUFF system ha ve resulted in improved performance over much greater distances. The Contribution Assessment provides specific information related to two CALPUFF platforms that have been developed for MANE-VU by the Vermont Department of Environmental C onservation (VT DEC) Air Pollution Control Branch and by the State of Maryland’s De partment of the Environment (MDE) and Department of Natural Resources (MDNR). The two platforms, one using MM5 meteorological inputs, and the other National Weather Service (NWS)-based meteorological data, were used to model th e entire 2002 calendar year. These simulations have been configured to provide estima tes for both individual source impacts and cumulative state impacts, and to allow for inter-platform comparisons. 19 The following table (Table 7-6) illustrates th e contribution of emissions from individual states to overall
sulfate levels at Acadia National Park. 20 Once again, Ohio, New York, Indiana and Pennsylvania are among the greatest contributors to sulfate levels at Maine Class I areas. Unlike the previous contribution assessment techniques, Massachusetts is identified as a major contributor to visibility impair ment in Maine by the CALPUFF modeling.

7.3.2 Summary of Analytical Techniques for Contribution Assessment

By normalizing the results of the four di fferent empirical and modeling techniques summarized above, MANE-VU was able to id entify those states having the largest
influence on sulfate levels at each Class I site. Figure 7-2, below, compares the normalized results using different techniques for ranking state contributions to sulfate
levels at Acadia National Park. While th ere is some variation in the contribution estimates among the different assessment techniques employed, there is a general consistency of results from one method to another.

18 It should be pointed out that the listed values for VISTAS, CenRAP, and Canada understate the actual percentage contributions from thos e regions because they count only emissions originating within the modeling domain (see Table 7-5). Actual contributions, especially in the case of CenRAP, would be considerably higher than stated. Differences between act ual and stated values are aggregated into “Other” category. These findings highlight the importance of emissions from outside MANE-VU to visibility impairment inside the region.

19 Overall, the CALPUFF modeling results to date demonstrate reasonably good comparability between the two platforms but they also suggest a consistent pattern of under prediction for one platform relative to the other.

20 See Attachment A-4 for the ranked contribution of emissions from individual states to overall sulfate
levels at Moosehorn NWR and other MANE-VU Class I areas.5/27/2010
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Table 7-6
Contribution to Sulfate Levels at A cadia National Park Using the CALPUFF Model

From: Table 7-2a of Contributions to Regional Haze in the No rtheast and Mid-Atlantic United States, NESCAUM, 2006.

An alternative means of displaying the above results is in Table 7-7, which shows the individual state rankings pr oduced by different assessm ent techniques for Acadia National Park, Maine. In the left-side column of Table 7-7, states are colored according to their average ranking acro ss the different assessment me thods. Those states that are ranked in the top five on av erage, across all techniques ar e colored red, while states ranked in the top six through ten are colored magenta, and so on for each group of five going down the left-side column. Through this color scheme, one can see how the states’ average ranking compares to their rankings under each individual assessment method given in the other columns of the table. Th e fact that all techniques tend to come to
consistent conclusions about which states are top contribut ors provides confidence that the source regions with the most influence on sulfate levels at MANE-VU Class I sites can be correctly identified. Note that the CE NRAP states and severa l other states along the border of the analysis domain repres ent only partial st ate contributions.

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Figure 7-2
Ranked Contribution to Sulfate Concentr ations at Acadia National Park

The ranking of emissions contributions to visi bility impairment in the MANE-VU Class I Areas by methods such as these has direct relevance to the consulta tion process described previously in Section 3, Regional Planning a nd Consultation. Using results from the results from the Contribution Assessment, Main e utilized the following criteria to identify states and regions for the purposes of consultation on regional haze:

1. Any state/region th at contributed 0.1  g/m 3 sulfate or greater on the 20 percent worst visibility days in the base year (2002),

2. Any state/region that cont ributed at least 2 percent of total sulfate observed on the 20 percent worst visibility days in 2002, and

3. Any state/region among the top ten contributors on the 20 percent worst visibility days in 2002.

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Table 7-7 Individual State Rankings Produced by Different Assessment Techniques for
Acadia National Park

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59 

### 8. Emissions Inventory

8.1 Sources of Visibility Impa iring Pollutants in MANE-VU

This section explores the origin and quanti ty of haze-forming pollutants emitted in the

Eastern and the mid-Atlan tic United States.

Section 51.308(d)(4)(v) of EPA’s Regional Haze Rule requires a statewide emission inventory of pollutants that are reasonably anti cipated to cause or contribute to visibility impairment in any mandatory Class I area. The pollutants inventoried by Maine that affect fine particle formation, and thus c ontribute to regional haze, are sulfur oxides (SO X ), nitrogen oxides (NO X ), volatile organic compounds (VOC), ammonia (NH 3 ), and particles with an aerodynamic diameter less than or equal to 10 and 2.5 μm (i.e., primary

PM 10 and PM 2.5 ).

The emissions dataset illustrated below is the 2002 MANE-VU Version 3 regional haze emissions inventory. The emission inventories include carbon monoxide (CO), but it is

not considered here as it does not contribu te to regional haze. The MANE-VU regional haze emissions inventory version 3.0, released in April 2006, has superseded version 2.0 for modeling purposes. This inventory update was developed through the Mid-Atlantic Regional Air Management Association (M ARAMA) for the MANE-VU RPO. This section describes emission characteristics by pollutant and source ty pe (e.g., point, area, and mobile).

8.1.1 Sulfur Dioxide (SO 2 )

SO 2 is the primary precursor pollutant for su lfate particles. Sulfate particles commonly account for more than 50 percent of particle -related light extinction at northeastern Class I areas on the clearest days and for as much as or more than 80 percent on the haziest days. Hence, SO 2 emissions are an obvious target of opportunity for reducing regional
haze in the eastern United States. Combustion of coal and, to a lesse r extent, of certain petroleum products accounts for most anthropogenic SO 2 emissions. In fact, in 1998 a single source category, coal-bur ning power plants, was responsi ble for two-thirds of total
SO 2 emissions nationwide (NESCAUM, 2001a).

Figure 8-1 shows SO 2 emissions trends in the MANE- VU states as extracted from the 2002 MANE-VU inventory (EPA, 2005). Most stat es in the region showed declines in
annual SO 2 emissions through 2002 compared with thos e in previous inventories. This decline can be attributed in part to impleme ntation of Phase 2 of the Acid Rain Program,
which in 2000 further reduced allowable em issions below Phase I levels and extended emission limits to a greater number of power plants.

The bar graph in Figure 8-2 shows the pe rcent contribution from different source categories to overall, annual 2002 SO 2 emissions in the MANE-VU states. The graph shows that point sources dominate SO 2 emissions, which primarily consist of stationary5/27/2010
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Figure 8-1
State Level Sulfur Dioxide Emissions

Figure 8-2
2002 SO 2 (Bar graph: Percentage fraction of four source categories,

Circle: Annual emissions amount in 10 6 tons per year)

0% 25% 50% 75% 100%

C

o nn

e cti

c ut Dela ware
Distric t of

C

olumb i a Ma i ne

M ary

l and

M

as

s a c hu

se

tt s New Hampshire

N

e w Je rs

ey Ne w York

Pen

nsylvan ia

R h o de I

s la

n d Vermo n t 0.0 0.2 0.4 0.6 0.8 1.0 1.2million t/y

AREA NONROAD ONROAD POINT Emission

combustion sources for generating electric ity, industrial energy, and heat. Smaller stationary combustion sour ces called “area sources” (primarily commercial and

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61 residential heating, and smaller industrial facilities) are another important source category in the MANE-VU states. By contrast, on-ro ad and non-road mobile sources make only a relatively small contribution to overall SO 2 emissions in the region (NESCAUM, 2001a).

8.1.2 Volatile Organic Compounds (VOC) Existing emission inventories generally refe r to “volatile organic compounds” (VOCs) for hydrocarbons whose volatility in the atmos phere makes them particularly important from the standpoint of ozone formation. From a regional haze perspec tive, there is less concern with the volatile organic gases emitted directly to the atmosphere and more with the secondary organic aero sol (SOA) that the VOCs form after condensation and oxidation processes. Thus the VOC inventory ca tegory is of interest primarily from the organic carbon perspective of PM2.5.

After sulfate, organic carbon gene rally accounts for the next larg est share of fine particle mass and particle-related light ex tinction at northeastern Cla ss I sites. The term organic carbon encompasses a large number and variet y of chemical compounds that may come directly from emission sources as a part of pr imary PM or may form in the atmosphere as secondary pollutants. The organic carbon pr esent at Class I sites includes a mix of species, including pollutants originating from anthropogenic (i.e., manmade) sources as well as biogenic hydrocarbons emitted by ve getation. Recent efforts to reduce manmade organic carbon emissions have been undertak en primarily to address summertime ozone
formation in urban centers. Future efforts to further reduce organic carbon emissions may be driven by programs that addre ss fine particles and visibility.

Understanding the transport dynamics and source regions for organic carbon in northeastern Class I areas is likely to be more complex than for sulfate. This is partly because of the large number and variety of OC species, the fact that their transport characteristics vary widely, and the fact that a given species may undergo numerous complex chemical reactions in the atmosphe re. Thus, the organic carbon contribution to visibility impairment at most Class I site s in the East is likely to include manmade pollution transported from a distance, ma nmade pollution from nearby sources, and biogenic emissions, especially terpen es from coniferous forests.

Organic carbon emissions in the form of smoke from both natural (wildfire) and anthropogenic (prescribed and agricultural burning activities) have been shown to have a significant impact on visibility in Class I ar eas. In the western United States, organic carbon is responsible for a signifi cant portion of visibility impacts at Class I areas, with wildfire and prescribed burning the principal emissions sources. In the eastern United States, organic carbon emissions play a lesser, but still important role in visibility degradation, with fire (bot h wildfire and anthropogenic) responsible for a smaller proportion of organic carbon emissions.

The National Park Service investigated the im pact of fire on regional air quality using several modeling and air qua lity analysis techniques 21 . One of the more interesting

21 “Fire Effects on Regional Air Quality Including Visi bility,” Draft Report, National Park Service, Air Resources Division, August 1, 2006.5/27/2010
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62 approaches analyzed the rati o of organic carbon to black (or elemental) carbon at
IMPROVE monitor sites. The ratio of organic to elementa l carbon (OC/EC) can be used to identify the likely source of organic car bon emissions, since this ratio displays significant variability, depending on the source of combustion. For example, internal combustion engines, which burn relatively efficiently, typically have a ratio of about 3, while less efficient combustion, which is char acteristic of open fires, result in OC/EC ratios on the order of 10 or more. Using th is approach, researchers estimated that fire was responsible for approximately 55% of a ll organic carbon monitored in the eastern
United States. 22 An alternative apportionment me thod utilizing a fire occurrence database and back trajectories was also u tilized to estimate fire impacts on observed organic carbon measurements. This appro ach estimated that approximately 20% of organic carbon observed at easte rn United States IMPRIOVE sites was due to wildland fires, but likely is an underes timation of the impact of fire on visibility, since the fire activity datasets and back trajectory databases are incomplete.

Although organic carbon is responsible for approximately 13 percent of the baseline worst visibility (throughout the MANE-VU re gion), sulfates account for approximately 75 percent of baseline visibility degradation. 23 Conversely, for natural background visibility conditions, organic ca rbon is estimated to be responsible for approximately 50 percent of visibility degradation, while sulf ates are responsible for only about 20 percent of the visibility degradation on the worst visibility days. This result arises from the fact that organic carbon concentrations under wors t day baseline conditi ons differ relatively little from estimated worst day concentrations under natural background conditions. Sulfate concentrations, however, are appr oximately 90 percent higher under worst day baseline conditions. With sulfates being re sponsible for the preponderance of visibility degradation, and many organic carbon emissions being biogenic in nature (as confirmed by the minimal difference between base line and natural background estimated concentrations), it makes sense to target sulfate levels for the first (and perhaps subsequent rounds) of regional haze controls. As noted above, organic carbon could be the subject of future control measures to m itigate regional haze, but is not the focus of initial planning efforts.

As shown in Figure 8-3, the VOC inventory is dominated by mobile and area sources.
On-road mobile sources of VOCs include exhaust emissions from gasoline passenger vehicles and diesel-powered heavy-duty vehi cles as well as evaporative emissions from transportation fuels. VOC emissions may also originate from a variety of area sources (including solvents, architectural coatings, and dry cleaners) as well as from some point sources (e.g., industrial facilities and petroleum refineries).

22 This technique tends to overestimate the OC/EC ratio due to the presence of secondary organic aerosols,
that are not associated with elemental carbon.

23 Nitrate and elemental carbon at 8% and 4%, respectively, account for most of the rest of the visibility degradation on the 20 percent worst days.5/27/2010
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Figure 8-3
2002 VOC

(Bar graph: Percentage fraction of four source categories, Circle: Annual emissions in million tons per year)

0% 25% 50% 75% 100%

Con nect

i cut

Dela w are

Distr i ct

of C o l u mbia Maine Mary l a n d

Ma

ssa

ch

u se

t ts

Ne

w Ha mpsh i r e New Jer se

y

New York

P

e nnsylvania Rhod e Isl

an

d Ve r montmillion t/y

0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6

AREA NONROAD ONROAD POINT Emission
Biogenic VOCs may play an important role w ithin the rural settings typical of Class I sites. The oxidation of hydrocarbon molecule s containing seven or more carbon atoms is generally the most significant pathway for the formation of light-scattering organic aerosol particles (Odum et al., 1997). Sm aller reactive hydrocarbons that may contribute significantly to urban smog (ozone) are less li kely to play a role in organic aerosol formation, though it was noted that high ozone levels can have an indirect effect on visibility by promoting the oxidation of other available hydrocar bons, including biogenic emissions (NESCAUM, January 2001). In short, further work is needed to characterize the organic carbon contribution to regional haze in the Northeas t and Mid-Atlantic states and to develop emissions inventories that will be of greater value for visibility planning

purposes.

8.1.3 Oxides of Nitrogen (NO X )

NO X emissions contribute to visibility impair ment in the eastern U.S. by forming lightscattering nitrate particles. Nitrate generally accounts for a substantially smaller fraction of fine particle mass and related light ex tinction than sulfate and organic carbon at
northeastern Class I sites. Nota bly, nitrate may play a more important role at urban sites and in the wintertime. In addition, NO X may have an indirect effect on summertime visibility by virtue of its ro le in the formation of ozone, which in turn promotes the formation of secondary organi c aerosols (NESCAUM 2001a).

Since 1980, nationwide emissions of NO X from all sources have shown little change. To a large extent, increases from the industria l and power plant com bustion sectors have been offset by emission reductions from mob ile source controls implemented during the

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sam e time period. Figure 8-4 shows NO X emissions in the MANE-VU region at the state level. In the several years just prio r to 2002, most MANE-VU states experienced declining NO

x emissions.

Figure 8-4 State Level Nitrogen Oxides Emissions

Power plants and mobile sources ge nerally dominate state and national NO

x emissions inventories. Nationally, power plants account for more than one-quarter of all NO

x emissions, amounting to over six million tons. Th e electric sector plays an even larger role, however, in parts of the industrial Midwest where high NO

x emissions have a particularly significant power plant contribution. By contra st, mobile sources dominate
the NO

x inventories for more urbanized Mid-Atla ntic and New England states to a far greater extent, as shown in Figure 8-5. In these states, on-road mobile sources - a category that mainly includes highway vehi cles - represent the most significant NO

x source category. Emissions from non-road (i .e., off-highway) mobile sources, primarily diesel-fired engines, also re present a substantial fraction of the inventory. While there are
fewer uncertainties associated with available NO

x estimates than in the case of other key haze-related pollutants - including primary fine particle and ammonia emissions - further efforts could improve current inventories in a number of areas (NESCAUM, 2001a).

In particular, better information on the c ontribution of area and non-highway mobile sources may be of most interest in the cont ext of regional haze pl anning. First, available emission estimation methodologies are weaker for these types of sources than for the large stationary combustion sources. Moreover, because SO 2 and NO X emissions must mix with ammonia to particip ate in secondary particle fo rmation, emissions that occur

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over large areas at the su rface may be more efficient in secondary fine particulate
formation than concentrated emissions fr om isolated tall stacks (Duyzer, 1994).

Figure 8-5
NO X (Bar graph: Percentage fraction of four source categories, Circle: Annual emissions amount in 10 6 tons per year)

0% 25% 50% 75% 100%

C

o n n e ctic

u t Delaware

D is trict o f C

o lumbia Main e

M

a ryl

a n d

M

a ss

achu se

tt s

N

e w

Ha

m pshi re New Jersey New Yo

r k Pennsyl v an

i a

R h o d

e I slan

d Vermontmillion t/y

0.0 0.3 0.6 0.9

AREA NONROAD ONROAD POINT Emission

8.1.4 Primary Particle Matter (PM 10 and PM 2.5 )

Directly-emitted or “primary” particles (as dis tinct from secondary particles that form in the atmosphere through chemical reacti ons involving precursor pollutants like SO 2 and
NO X ) can also contribute to regional haze. For regulatory purposes, a distinction is made between particles with an aer odynamic diameter less than or equal to 10 micrometers and smaller particles with an aerodynamic diamet er less than or equal to 2.5 micrometers (i.e., primary PM 10 and PM 2.5 , respectively).

Figure 8-6 and Figure 8-7 show PM 10 and PM 2.5 emissions, respectively, for the MANEVU states as reported for the 2002 base year. Most states showed a steady decline in
annual PM 10 emissions over this time period. By contrast, emission trends for primary

PM 2.5 are more variable.

Crustal sources are signifi cant contributors of primary PM emissions. This category includes fugitive dust emissions from construction activities, paved and unpaved roads, and agricultural tilling. Typi cally, monitors estimate PM 10 emissions from these types of sources by measuring the horizontal flux of particulate mass at a fixed downwind sampling location within perhaps 10 meters of a road or field. Comparisons between

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estim ated emission rates for fine particles using these types of measurement techniques
and observed concentrations of crustal matte r in the ambient air at downwind receptor sites suggest that physical or chemical proces ses remove a significant fraction of crustal

Figure 8-6 State Level Primary PM 10 Emissions

Figure 8-7 State Level Primary PM 2.5 Emissions *

* 1996 and 1999 Maine PM2.5 data augmented. 665/27/2010
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67 material relatively quickly. As a result, it rarely entrains in to layers of the atmosphere where it can transport to downwind receptor locations. Because of this discrepancy
between estimated emissions and observed am bient concentrations, modelers typically
reduce estimates of total PM 2.5 emissions from all crustal s ources by applying a factor of
0.15 to 0.25 to the total PM 2.5 emissions before including it in modeling analyses.

From a regional haze perspective, crustal mate rial generally does not play a major role. On the 20 percent best-visibility days during the baseline period (2000-2004), it accounted for six to eleven percent of pa rticle-related light extinction at MANE-VU Class 1 sites. On the 20 percent worst-visibili ty days, however, crustal material generally plays a much smaller role relative to other haze-forming pollutants, ranging from two to three percent. Moreover, the crustal fraction includes material of natural origin (such as soil or sea salt) that is not targeted under the Haze Rule. Of course, the crustal fraction can be influenced by certain human activities, such as construction, agricultural practices, and road maintenance (including wintertime salti ng). Thus, to the exte nt that these types
of activities are found to affect visibility at northeastern Cl ass I sites, control measures targeted at crustal material may prove benefi cial and are within th e purview of EPA and state agencies.

Experience from the western United States , where the crustal component has generally played a more significant role in driving overall particulate levels, may be helpful to the
extent that it is relevant in the eastern context. In additi on, a few areas in the Northeast, such as New Haven, Connecticut and Presque Is le, Maine, have some experience with the
control of dust and road-salt as a result of regulatory obligati ons stemming from their past non-attainment status with respect to the NAAQS for PM 10

.

Current emissions inventories for the enti re MANE-VU area indicate residential wood combustion represents 25 percent of primary fi ne particulate emissions in the region. This finding implies that rural sources can play an important role in addition to the contribution from the region’s many highl y populated urban areas. An important consideration in this regard is that reside ntial wood combustion occurs primarily in the winter months, while managed or prescribed burning activities o ccur largely in other seasons. The latter category includes agricultural field-burning activities, prescribed burning of forested areas and ot her burning activities such as construction waste burning. Particulate emissions from many of these sources can be managed by limiting allowed burning activities to times when favorable meteorological conditions can efficiently disperse the emissions.

Although the data are currently limited, Ma ine and the other M ANE-VU states are concerned about the growing use of reside ntial woodstoves and outdoor wood boilers by homeowners seeking alternatives to petroleum-based fuels for home heating. Over the next several years, Maine will continue to ev aluate monitored particulate mater levels in the state and in particular, assess the smoke component of the monitored particulate matter to determine if there is any trend in smoke levels in Maine. If smoke levels increase significantly, that might be cause for evaluating whether additional control
measures for this source category may be necessary.5/27/2010
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Figure 8-8, taken from Appendix B of the MANE-VU Contribution Assessment (Attachment A), represents th e results of source apportionmen t and trajectory analyses on wood smoke in the region extending form the Gu lf States to the Northeast. The greenhighlighted portion of the map depicts the wood smoke source region in the northeast states. The stars on the map represent air monitoring sites (including those at several Class I areas) whose data sets were determined to be useful to th e modeling analysis.

Figure 8-8 Wood Smoke Source Regional Aggregation

MANE-VU’s “Technical Support Document on Agricultural and Forestry Smoke Management in the MANE-VU Region, Sept ember 1, 2006 (Attachment Y), concluded that fire from land management activities wa s not a major contributor top regional haze in the MANE-VU Class I areas, and that the majo rity of emissions from fires were from
residential wood combustion.

Figures 8-9 and Figure 8-10 show that area and mobile sources dominate primary PM emissions. (The NEI inventory categorizes residential wood combustion and some other

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com bustion sources as area sources.) The relativ e contribution of point sources is larger in the primary PM 2.5 inventory than in the primary PM 10 inventory since the crustal component (which consists mainly of larger or “coarse-mode” particles) contributes mostly to overall PM 10 levels. At the same time, pollu tion control equipment commonly installed at large point sources is usually more efficient at capturing coarse-mode particles.Figure 8-9

Primary PM 10

(Bar graph: Percentage fraction of four source categories, Circle: Annual emissions amount in 106 tons per year)

0% 20% 40% 60% 80% 100%

Con

n ecticut
De

l a wa

re

D istrict o f C

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Maryland

Massachusetts

N ew Ha mpsh ire

N

ew

Je

rse

y New York

Pe

nn

syl

v ania

R ho

d e Island

V e rmon

tmillion t/y

0.0 0.1 0.2 0.3 0.4 0.5

AREA NONROAD ONROAD POINT Emission

Figure 8-10 Primary PM 2.5 (Bar graph: Percentage fraction of four source categories, Circle: Annual emissions amount in 106 tons per year)

0% 25% 50% 75% 100%

C

o n ne

cti

c u t Del

a w a re

D is trict of Co l umbi a Ma i ne

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y l an

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Hamp s h i r e New Jersey New Y ork Pennsylvania

R hod

e I s la

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AREA NONROAD ONROAD POINT Emission

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70 8.1.5 Ammonia Emissions (NH 3 )

Knowledge of ammonia emission sources will be necessary in developing effective regional haze reduction strategies because of the importance of ammonium sulfate and ammonium nitrate in determining overall fine particle mass and light scattering. According to 1998 estimates, livestock agri culture and fertilizer use accounted for approximately 86 percent of all ammonia emissions to the atmosphere (EPA, 2000b). However, improved ammonia inventory data are needed as inputs to the photochemical models used to simulate fine particle forma tion and transport in the eastern United States. States were not required to include ammonia in their emissions data collection efforts until fairly recently (See C onsolidated Emissions reporting rule, 67 CFR 39602, June 10, 2002). Therefore, emissions data for ammonia do not exist at the same level of detail or reliability as exist for other pollutants.

Ammonium ion (formed from ammonia emissi ons to the atmosphere) is an important constituent of airborne particulate ma tter, typically accounting for 10–20 percent of total fine particle mass. Reductions in ammoni um ion concentrations can be extremely beneficial because a more-than-proportional re duction in fine particle mass can result. Ansari and Pandis (1998) showed that a one  g/m 3 reduction in ammonium ion could result in up to a four  g/m 3 reduction in fine particulate matter. Decision makers, however, must weigh the benefits of amm onia reduction against the significant role it plays in neutralizing acidic aerosol. 24

To address the need for improved amm onia inventories, MARAMA, NESCAUM and EPA funded researchers at Carnegie Mellon Un iversity (CMU) in Pittsburgh to develop a regional ammonia inventory (Davidson et al., 1999). This study focused on three issues with respect to current emissions estimates: (1) a wide range of ammonia emission factor values, (2) inadequate temporal and spatial resolution of ammonia emissions estimates, and (3) a lack of standardized ammonia source categories.

The CMU project established an inventory fr amework with source categories, emissions factors, and activity data that are readily accessible to the user. With this framework,
users can obtain data in a variety of formats 25 and can make updates easily, allowing
additional ammonia sources to be added or em issions factors to be replaced as better information becomes available (Strad er et al., 2000; NESCAUM, 2001b).

Figure 8-11 shows that estimated ammonia em issions for the MANE-VU states in 2002. Area and on-road mobile sources dominate according to Figure 8-12. Specifically, emissions from agricultural sources and lives tock production account for the largest share
of estimated ammonia emissions in the M ANE-VU region, except in the District of

24 SO 2 reacts in the atmosphere to form sulfuric acid (H 2 SO 4 ). Ammonia can partially or fully neutralize this strong acid to form ammonium bisulfate or ammonium sulfate. If planners focus future control strategies on ammonia and do not achieve corresponding SO 2 reductions, fine particles formed in the atmosphere will be substantially more acidic than those presently observed.

25 For example, the user will have the flexibility to choose the temporal resolution of the output emissions data or to spatially attribute emissions based on land-use data.5/27/2010
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Figure 8-11
State Level Ammonia Emissions

Figure 8-12 State Ammonia Emissions by Source Category (Bar graph : Percentage fracti on of four source categories)

(Circle: Annual emissions amount in 10 6 tons per year)

0% 25% 50% 75% 100%

Co

n necticut Delaware

Distr i c t of Co l u mbi

a M aine Marylan d

M

a ss

a ch

us

e t t s New Hamp s hire

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w Jer s ey

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y l v an

i a Rho

d e

I s l a n d

Ver

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ntmillion t/y

0.00 0.06 0.12

AREA NONROAD ONROAD POINT Emission
Columbia. The two remaining sources with a significant emissions contribution are wastewater treatment systems and gaso line exhaust from highway vehicles.

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72 8.2 Baseline and Future Year Emission Inventories for Modeling

40 CFR Section 51.308(d) (3) (iii) requires the State of Maine to identify the baseline

em ission inventory on which strategies are base d. The baseline inventory is intended to be used to assess progress in making emission reductions. Based on EPA guidance entitled, “2002 Base Year Emission Inve ntory SIP Planning: 8-hour Ozone, PM 2.5 , and Regional Haze Programs” which identifies 2002 as the anticipated baseline emission inventory year for regional haze, all of the MANE-VU states are using 2002 as the baseline year for regional haze inventories

With contractor assistance, MARAMA de veloped a 2002 baseline modeling inventory using the inventories that Maine and other states submitted to EPA to meet their SIP obligations and the requirements of the Cons olidated Emissions Reporting Rule (CERR). To create the 2002 baseline inventory fo r modeling, MARAMA and its contractor quality-assured and augmented states’ inventor ies and generated the necessary input files for the emissions processing model.

Future-year inventories for 2009, 2012, and 2018 were projected from the 2002 base year. These future-year emissions inventories include emissions growth due to projected
increases in economic activit y as well as emissions re ductions expected from the implementation of cont rol measures. While the 2009 and 2012 emissions pr ojections were originally developed in support of participatin g state’s ozone attainme nt demonstrations, the inventory for 2018 (the year ta rgeted by the Regional Haze Rule) was developed for the specific purposes of regional haze SIP planni ng. Therefore, alth ough the 2009 and 2012 projected inventories are menti oned in subsequent sections, on ly the 2002 base line inventory and 2018 projected inventory are described be low in Section 7.5, Su mmary of Emissions
Inventories.

Accurate baseline and future-year emissions inventories are crucial to the analyses required for the regional haze SIP process. These emissions inventories were used to drive the air quality modeling simulations undertaken to assess the visibility improvements that would result from possibl e control measures. Air quality modeling was also used to perform a pollution apporti onment, which evaluate s the contribution to visibility impairment by geographi c region and emission source sector.

To be compatible with the air quality mode ling simulations, the baseline and future-year emissions inventories were processed with th e Sparse Matrix Operator Kernel Emissions (SMOKE) emissions pre-processor for subs equent input into the CMAQ and REMSAD air quality models. Further de scription of the base and future-year emissions inventories is provided below.

8.2.1 Baseline Inventory

The starting point for the 2002 baseline emi ssions inventory was the 2002 inventory submittals that were made to EPA by state and local agencies as part of the Consolidated Emissions Reporting Rule (CERR). With contractor assistance (E.H. Pechan &5/27/2010
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73 Associates), MANE-VU then coordinated and quality-assured the 2002 inventory data, and prepared it for input into the SMOKE em issions model. The 2002 emissions from non-MANE-VU areas within the modeling domain were obtained from other Regional Planning Organizations for their corr esponding areas. These Regional Planning Organizations included the Vi sibility Improvement State an d Tribal Association of the Southeast (VISTAS), the Midwest Regiona l Planning Organization (MRPO), and the Central Regional Air Planning Association (CENRAP).

The 2002 baseline inventory went through severa l iterations. Work on Version 1 of the 2002 MANE-VU inventory began in April 2004, and the final inventory and SMOKE input files were completed during January 2005. Work on Version 2 (covering the period of April through September 2005) involved in corporating revisions requested by some MANE-VU state/local agencies on the point, area, and on-road categories. Work on Version 3 (covering the period from D ecember 2005 through April 2006) included additional revisions to the point , area, and on-road categories as requested by some states. Thus, the Version 3 inventory for point, area, and on-road sources was built upon
Versions 1 and 2. This work also included development of the biogenic inventory. In Version 3, the non-road inventory was comple tely redone because of changes that EPA
made to the NONROAD2005 non-road mobile emissions model.

Version 3 of the MANE-VU 2002 baseline emissi ons inventory was used in the regional air quality modeling simulations, including perf ormance testing of the air quality models used in the development of this SIP. Furt her description of the data sources, methods,
and results for this version of the 2002 baseline inventory is presented in E.H. Pechan & Associates, Inc. “Technical Support Do cument for 2002 MANE-VU SIP Modeling Inventories, Version 3, Nove mber 20, 2006” (Attachment H)

. Emissions inventory data
files are available on th e MARAMA website at: http://www.marama.org/visibility/EI_Projects/index.html

.

8.2.2 Future Year Emission Control Inventories

Future-year emissions inventories are provided in MACTEC’s technical support document “Development of Emissions Projections for 2009, 2012, and 2018 for NonEGU Point, Area, and Nonroad Sources in the MANE-VU Region,” Final Report, February 28, 2007, (Attachment I). This doc ument describes the data sources, methods, and modeling results for three future years, five emission source sectors, two emission control scenarios, seven pollutant s, and eleven states plus th e District of Columbia. The following summarizes the basic framework of the future-year inventories that were developed:

 Projection years : 2009, 2012, and 2018;

 Emission source sectors : point-source electric gene rating units (EGUs), pointsource non-electric generating units (non-EGUs), area sources, non-road mobile sources, and on-road mobile sources.

 Emission control scenarios :

o A combined on-the-book s/on-the-way (OTB/OTW) control strategy5/27/2010
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74 accounting for emission control regulations already in place as of June 15, 2005, as well as some emission contro l regulations that are not yet finalized but are expected to achie ve additional emission reductions by
2009.

o A beyond-on-the-way (BOTW) scenario to account for controls from potential new regulations that may be necessary to meet attainment and other regional air quality goals, mainly for ozone.

o An updated scenario (referred to as the “final modeling inventory”) to account for additional potentially reas onable control measures. For the MANE-VU region, these include: SO2 reductions at a set of 167 EGUs which were identified as contributing to visibility impairment at northeast Class I areas; implementation of a low-sulfur fuel strategy for non-EGU sources; and implementation of a BART strategy for BART-eligible
sources not controlled under other programs. The final modeling inventory was used to develop the r easonable progress goals in this SIP.

o Pollutants: ammonia, carbon monoxide (CO), oxides of nitrogen (NOx), sulfur dioxide (SO2), volatile organi c compounds (VOCs), fine particulate matter (PM2.5, sum of filterable and c ondensable components), and coarse particulate matter (PM10, sum of filte rable and condensable components).

 States: The states are those that comprise the MANE-VU region. In addition to the District of Columbia, the 11 MANE -VU states are Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont.

8.3 Emission Processor Sel ection and Configuration

The Sparse Matrix Operator Kernel Em issi ons (SMOKE) model (Version 2.1) was used by the New York State Department of Envir onmental Conservation (NYSDEC) to format
the emissions inventories for use with the air quality models that are discussed in Chapter 9. SMOKE is principally an emissions proces sing system, as opposed to a true emissions inventory preparation system, in which emi ssions estimates are simulated from “first principles.” This means that, with the ex ception of mobile and biogenic sources, its purpose is to provide an effici ent, modern tool for convert ing emissions inventory data into the formatted emissions files required for a photochemical air quality model. A detailed description of all SMOKE input f iles such as area, mobile, fire, point and biogenic emissions files and the SMOKE model configuration are provided in
Attachment I.

As discussed in detail in Ch apter 11, the MANE-VU member states selected several control strategies for inclusion in the modeling. Emission reduction requirements mandated by the Clean Air Act were also included in projecting future year emissions. In addition, 40 CFR Section 51.308(d)(3 )(v)(D) requires the Stat e of Maine to consider source retirement and replacement schedules in developing the future inventories and long-term strategy.5/27/2010
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75 8.4 Inventories for Specific Source Types

There are five em ission source classifications in the emissions inventory as follows:

1) Stationary point, 2) Stationary area, 3) Off-road mobile, 4) On-road mobile, and 5) Biogenic.

Stationary point sources are large sources that emit great er than a specified tonnage per

year. Stationary area sources are those sources whose em issions are relatively small but due to the large number of these sources, the colle ctive emissions could be significant, i.e., dry cleaners, service stations, agricultural sources, fire emissions, etc.
Off-road mobile sources are equipment that can move but do not use the roadways, i.e., lawn mowers, construction equipment, railroad locomotives, aircraft, etc. On-road
mobile sources are automobiles, trucks, and motorc ycles that use the roadway system.
The emissions from these sources are esti mated by vehicle type and road type. Biogenic

sources are natural sources like trees, crops, grasses and natural decay of plants. Stationary point sources emission data is tracked at the facility level. For all other source types emissions are summed on the county level.

The subsections below provide an overview of each of the sour ce categories and the methods that were used to develop thei r corresponding baseli ne and future-year
emissions estimates. All emissions data were prepared for modeling in accordance with EPA guidance.

8.4.1 Stationary Point Sources

Point source emissions are emissions from large individual sources. Generally, point sources have permits to operate and their emissions are individually calculated based on source specific factors on a regular schedule. Emissions estimates for point sources are usually made on a regular basis, with the la rgest point sources inventoried annually. Sources with emissions greater than or equal to 100 tons per year (tpy) of a criteria pollutant, 10 tpy of a single hazardous ai r pollutant (HAP), or 25 tpy total HAP are considered to be major sources. Emissions from smaller sources are also calculated individually but less frequen tly. Point sources are grouped into EGU sources and other industrial point sour ces, termed as non-EGU point sources.

8.4.1.1 Electric Generating Units

The base-year inventory for EGU sources were based on 2002 continuous emissions monitoring (CEM) data reported to EPA in co mpliance with the Acid Rain Program or 2002 state emissions inventory data. The CE M data provided actual hourly emission values used in the modeling of SO 2 and NO

x emissions from these large sources. Emissions of other pollu tants (e.g., VOCs, CO, NH 3 , and PM 2.5 ) were provided by the
states in most instances.5/27/2010
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76 Future-year inventories of EGU emissi ons for 2009, 2012 and 2018 were developed using ICF International’s Integrated Planning Model (IPM) to forecast growth in electric demand and replacement of older, less effi cient and more polluting power plants with newer, more efficient and cleaner units. Th is effort was undertaken by an inter-RPO workgroup. While the output of the IPM model predicts that a certa in number of older plants will be replaced by newer units to meet future electric growth and state-specific NOx and SO2 caps, the MANE-VU/Maine invent ory did not directly rely on the closure of any particular plant in establishi ng the 2018 inventory upon which the reasonable progress goals were set.

The IPM model results do not provide a reliable basis upon which to predict EGU closures. Specific plant closures in the Ma ine inventory are addr essed in Chapter 12, Reasonable Progress Goals. Preliminary modeling was performed with unchanged IPM 2.1.9 model results. However, prior to the most recent modeling, future-year EGU inventories were adjusted as follows:

• First, IPM predictions were reviewed by permitting and enforcement staff of the MANE-VU states. In many cases, staff belie ved that the IPM shutdown predictions were unlikely to occur. In particular, many oil-fired EGUs in urban areas were predicted to be shut down by IPM. Simila r source information was solicited from
states in both VISTAS and MRPO. As a result of this model validation, the IPM modeling output was adjusted before th e most recent modeling to reflect staff knowledge of specific plant status in M ANE-VU, VISTAS, and MRPO states. Where expected EGU operating status was contrary to what was predicted by IPM modeling, the future-year emissions inve ntory was adjusted to reflec t the expected operation of those plants.

• Second, as a result of inter- and intr a-RPO consultations, MANE-VU agreed to pursue certain emission control measures (see Section 3.0, Regional Planning). For EGUs, the agreed-upon approach was to pur sue emission reductions from each of the top 167 stacks located in MANE-VU, MRPO, and VISTAS that contributed the most to visibility impairment at any Class I area in the MANE-VU region. This approach, known as the targeted EGU strategy, is furt her described in Section 11.0 of this SIP.

8.4.1.2 Non-EGU Point Sources

The non-EGU category used annual emissions as reported by state and local agencies pursuant to the Consolidated Emission Repor ting Rule (CERR) for the base year 2002 (or MANE-VU Version 3). As described in section 8.2 , MANE-VU’s contractor, E.H. Pechan & Associates (Pechan), c oordinated the quality assurance of the inventory and prepared the necessary f iles for input into the SMOKE emissions model. Further information on the prep aration of the MANE-VU 2002 baseline point source modeling emissions inventory can be found in Chapter II of the Baseline Emissions Report (Attachment I). Project ed non-EGU point source emissions were developed for the MANE-VU region by MA CTEC Federal Programs, Inc. under
contract to the Mid-Atlan tic Regional Air Management Association (MARAMA).5/27/2010
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77 The specific methodologies that were empl oyed are described in Section 2 of the Emissions Projections Report (Attachment I). MACTEC used state-supplied growth factor data, where available, to project future-year emissions. Where state-supplied data were not available, MACTEC used EPA’s Economic Growth and Analysis System, Version 5.0 (EGAS 5.0) to develop applicable growth factors for the nonEGU component. MACTEC also incorporated the applicable federal and state emissions control program s to account for the expected emissions reductions that will take place under the OTB/ OTW and BOTW scenarios.

8.4.2 Stationary Area Sources

Stationary area sources include sources whose individual emissions are relatively small, but due to the large number of these sources, the collective emissions are significant. Some examples include solvent cleaning, serv ice stations and resi dential heating. Area source emissions are estimated by multiplying an emission factor by some known
indicator of collectiv e activity, such as fuel usage, or number of households or population.

The area source emissions inventory submittals made for the CERR became the basis for the area source portion of the 2002 baseline i nventory. MANE-VU’s consultant, Pechan, prepared the area source modeling inventory using the CERR submittals as a starting point. Pechan quality-assure d the inventory and augmente d it with additional data, including MANE-VU sponsored inventories for categories such as residential wood combustion and open burning. Details on the preparation of MANE-VU’s 2002 baseline area source emissions inventory can be found in Chapter III of the Baseline Emissions report (Attachment H).

In a similar fashion, MACTEC prepared futu re-year area source emission projections for the MANE-VU region. The specific methodolog ies employed are described in Section 3 of the Emissions Projection Report (Attachment I). MACTEC applied growth factors to the 2002 baseline area source inventory using st ate-Supplied data, where available, or using the EGAS 5.0 growth factor model. MACTEC also accounted for the appropriate control strategies in the future year projections.

8.4.2.2 Non-Road Mobile Sources Non-road mobile sources are equipment that can move but do not use the roadways, such as construction equipment, aircraft, railroad locomotives, lawn and garden equipment. For the majority of the non-road mobile so urces, the emissions for base year 2002 were estimated using the EPA’s NONROAD Model contained within the Mobile6 model. Aircraft, railroad locomotives, and commercia l marine vessels are not included in the NONROAD model; their emissions are estima ted using applicable references and methodologies. Again, Pechan prepared the 2002 baseline modeling inventory using the state and local CERR submittals as a starting po int. Details on the preparation of the 2002 baseline non-road inventory are described in Chapter IV of the Baseline Emissions Report (Attachment H).5/27/2010
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78 Future-year non-road mobile source emissions were projected for the MANE-VU region by MACTEC. The methodologies employed are discussed in Section 4 of the Emission Projections Report (Attachment I). MA CTEC used EPA’s NONROASD2005 non-road
vehicle emissions model as contained in EPA’s National Mobile Inventory Model (NMIM). Since the calendar year is an expl icit input into the NONROAD model, futureyear emissions for non-road vehicles could be calculated directly for the applicable projection years. For the non -road vehicle types that ar e not included in the NONROAD model (i.e., aircraft, locomotives and comme rcial marine vessels), MACTEC used the 2002 baseline inventory and th e projected inventories that EPA developed for these categories for the Clean Air Interstate Rule (CAIR) to develop emission ratios and subsequent combined growth and control fact ors. Since the future years for the CAIR projections did not precisely match those re quired for the purposes of ozone, particulate mater and the regional haze analyses (i .e., 2009, 2012, and 2018), MACTEC used linear interpolation to develop factors for the required future years.

8.4.3 On-Road Mobile Sources

The on-road emissions source cate gory consists of vehicles that are meant to travel on public roadways, including cars, trucks, bus es and motorcycles. The basic methodology
used for on-road mobile source calculations is to multiply vehicle-miles-travelled (VMT) by emission factors developed using EPA’s MOBILE6.2 motor vehicle emission factors model. The on-road mobile category requi res that SMOKE model inputs be prepared
instead of the SMOKE/IDA emissions data form at that is required by the other emission source categories. Therefore, for the 2002 baseline inventory, Pechan prepared the necessary VMT and MOBILE6 inputs in SMOKE format.

Projected on-road mobile source inventor ies were developed by NESCAUM for the MANE-VU region for ozone, particulate matter, and regional haze SIP purposes. As with other emission source categories, proj ected on-road mobile inventories were developed for calendar years 2009, 2012, and 2018. As part of this effort, MANE-VU member states were asked to provide VM T data and MOBILE6 emissions model inputs for the applicable calendar years. Using the inputs supplied by the MANE-VU member states, NESCAUM compiled and generate d the required SMOKLE/MOBILE6 emission model inputs. Further details regarding th e on-road mobile source projections can be
found in NESCAUM’s “Technical Memorandu m, Development of MANE-VU Mobile Source Projection Inventories for SM OKE/MOBILE6 Application,” June 2006 (Attachment J).

8.4.4 Biogenic Emission Sources

Biogenic emissions for the 2002 baseline mode ling emissions inventory were calculated for the modeling domain by the New York State Department of Environmental Conservation (NYSDEC). NYSDEC used the Biogenic Emissions Inventory System (BEIS) Version 3.12 as contained within the SMOKE emissions processing model. Biogenic emissions estimates were made for CO, nitrous oxide (NO) and VOCs. Further details about the biogenic emissions pro cessing can be found in NYSDEC’s technical5/27/2010
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79 support document TSD-1c, “Emission Processing for the Revised 2002 OTC Regional and Urban 12 km Base Case Simulations,” September 19, 2006, and in Chapter VI: Biogenic Sources, of the “Technical Support Document for 2002 MANE-VU SIP Modeling Inventories,” Version 3, Novemb er 20, 2006 (Attachment H) . Biogenic
emissions were assumed to remain constant for the future-years analysis, a reasonable approximation reflecting the expectation that most of the region will remain heavily forested for the duration of the planning period.

8.5 Summary of Maine’s 2002 and 2018 Emissions Inventory

Tables 8-1 t hrough 8-4, below, summarize the Maine baseline and future-year emission inventories. As previously discussed in s ection 8.2.2, there are three projected control scenarios for the 2018 inventory. The on-the-books/on-the-way (OTB/OTW) control strategy scenario accounts for emission control re gulations that were al ready in place as of June 15, 2005, as well as some regulations that are not yet finalized, but are expected to
achieve additional emission reductions by 2009. The beyond-o n–the- way (BOTW) scenario includes emission controls that may be necessary to for a ttainment of the ozone and PM NAAQS, along with mee ting other regional air quality goals. The final modeling emission inventory accounts for additional potentially reasonable control measures for reducing regional haze as discussed in Section 11 and 12 of this SIP, and was used to generate Maine’s reasonable progress goals.

Table 8-1 2002 Emissions Inventory for Maine

(tons per year)

CO NH 3 NO X PM 10 PM 25 SO 2 VOC
Mobile 410,958 1,468 54,687 1,239 934 1,804 23,037

Nonroad 153,424 11 9,820 1,437 1,329 917 31,144

EGU Point 7,962 145 7,831 1,169 888 9,299 842

Non-EGU Point 9,043 700 12,108 6,120 4,899 14,412 4,477

Area 109,223 8,747 7,360 168,953 32,774 13,149 100,621 Biogenics 64,936 2,018 600,205

Total 755,545 11,071 93,824 178,919 40,825 39,581 760,3275/27/2010
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80 Table 8-2
2018 OTB/OTW Emissions Inventory for Maine (tons per year)

CO NH 3 NO X PM 10 PM 25 SO 2 VOC
Mobile 237,170 1,715 12,828 272 266 894 10,414

Nonroad 166,679 15 6,543 1,086 978 82 21,988

EGU Point 4,057 139 1,827 296 279 5,436 53

Non-EGU Point 11,433 859 15,753 7,496 5,935 18,794 5,709

Area 94,181 12,312 7,424 189,619 33,820 13,901 92,410 Biogenics 64,936 2,018 600,205

Total 578,456 15,041 46,393 198,768 41,278 39,107 730,779

Table 8-3 2018 BOTW Emissions Inventory for Maine (tons per year)

CO NH 3 NO X PM 10 PM 25 SO 2 VOC

Mobile 237,170 1,715 12,828 272 266 894 10,414

Nonroad 166,679 15 6,543 1,086 978 82 21,988

EGU Point 4,057 139 1,827 296 279 5,436 53

Non-EGU Point 11,433 859 14,137 7,477 5,922 18,692 5,708

Area 94,181 12,312 7,036 188,928 33,201 4,940 90,866 Biogenics 64,936 2,018 600,205

Total 578,456 15,041 44,389 198,058 40,646 30,044 729,234

Table 8-4 2018 Final Modeling Emissions Inventory for Maine (tons per year)

CO NH 3 NO X PM 10 PM 25 SO 2 VOC
Mobile 237,170 1,715 12,828 272 266 894 10,414

Nonroad 166,679 15 6,543 1,086 978 82 21,988
EGU Point 4,057 139 1,827 296 279 6,806 53
Non-EGU Point 11,433 859 14,137 7,477 5,922 13,082 5,708

Area 94,181 12,312 7,036 57,411 18,877 1,127 90,866 Biogenics 64,936 2,018 600,205

Total 578,456 15,041 44,390 66,542 26 26,321 21,991 729,235

26 An adjustment factor was applied during the processi ng of emissions data to restate fugitive particulate

matter emissions. Grid models have been found to overestimate fugitive dust impacts when compared with ambient samples; therefore, an adjustment is typically applied to account for the removal of particles by vegetation and other terrain features. The summary emissions for PM 10 in Table 8.4 reflect this adjustment. Comparable adjustments were not made to PM 10 values listed in Tables 8.1 through 8.3.5/27/2010
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82 

### 9. Modeling

Air quality modeling to assess regional h aze has been done cooperatively by the MANEVU member states, with major mode ling efforts being conducted by NESCAUM 27 and screening modeling being conducted by the New Hampshire Department of Environmental Services (NHDES) 28 . These modeling efforts include emissions processing, meteorological input analysis, a nd chemical transport modeling to conduct regional air quality simulations for cale ndar year 2002 and seve ral future periods, including the 2018 primary target period for this SIP. M odeling was conducted in order to assess contribution from upw ind areas, as well as Main e’s contribution to its own Class I areas. Further, the modeling evaluate d visibility benefits of control measures being considered for achieving reasonable progress goals and establishing a long-term emissions management strategy for MANE -VU Class I areas. The modeling tools utilized for these analyses include the following:

 The Fifth-Generation Pennsylva nia State University/National Center for Atmospheric Research (NCAR) Mesoscale Model (MM5 ) was used to derive the required meteorological inputs for th e air quality simulations.

 The Sparse Matrix Operator Kernel Emissions (SMOKE) emissions modeling system was used to process and format the emissions inventories for input into the air quality
models.

 The Community Mesoscale Air Quality mode l (CMAQ) was used for the primary SIP modeling.

 The Regional Model for Aerosols and Deposition (REMSAD) was used during contribution apportionment.

 The California Grid Model (CALGRID) and its associated EMSPROC6 emissions processor was used to screen specific control strategies.

Each of these tools has been evaluated a nd found to perform adequately, and the SIP pertinent modeling underwent full performance testing and the results were found to meet the specifications of EPA modeling guidance.

For more details on the regional haze m odeling, refer to the NESCAUM report “MANEVU Modeling for Reasonable Progress Goals, Model Performance Evaluation, Pollution Apportionment, and Control Measure Benefits ,” February 7, 2008 (Attachment P). The detailed modeling approach for the most r ecent 2018 projected scenario can be found in the NESCAUM report “2018 Visibility Proj ections,” May 13, 2008 (Attachment Q).

9.1 Meteorology

The meteorological inputs for the air quali ty simulations were developed by the University of Maryland (UMD) using the MM5 meteorological modeling system. Meteorological inputs were generated for 2002 to correspond with the baseline emissions inventory and analysis year. The MM5 simula tions were performed on a nested grid as

27 Along with the NYSDEC, NJDEP/Rutgers, VADEQ, and UMD.

28 Along with the VTDEP and MDEQ.5/27/2010
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illus trated in Figure 9-1. As shown in the fi gure, the modeling domain is comprised of a 36-km, 145 x 102 continental grid and a nested 12-km, 172 x 172 grid encompassing the

Figure 9-1 Modeling d omains used in MANE-VU air quality modeling studies with CMAQ.

Outer (blue) domain grid is 36 km and inner (red) domain is 12 km grid The gridlines are shown at 180 km intervals (5 × 5 36 km cells/15 × 15 12 km cells)

Eastern United States and parts of Canada. In cooperation with the New York State Department of Conservation (NYSDEC), an assessment was made to compare the MM5 predictions with observations from a variety of data sources, including:

 Surface observations from the National Weat her Service and the Clean Air Status and Trends Network (CASTNet);

 Wind-profiler measurements from the Cooperative Agency Profilers (CAP) network;

 Satellite cloud image data from the UMD Department of Atmospheric and Oceanic Science; and

 Precipitation data from the Earth Obse rving Laboratory at NCAR. This assessment was performed for the period covering May through September 2002.

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84 Further details regarding the MM5 meteor ological processing and the modeling domain can be found in NYSDEC’s technical suppor t document TSD-1a, “Meteorological Modeling Using Penn State/NCAR 5 th Generation Mesoscale Model (MM5),” February 1, 2006 (Attachment K), and in the NE SCAUM report “MANE-VU Modeling for Reasonable Progress Goals, Model Perfor mance Evaluation, Pollution Apportionment, and Control Measure Benefits,” November 27, 2007 (Attachment P).

9.2 Emissions Data Preparation

Em issions were prepared for input into the CMAQ and REMSAD air quality models using the SMOKE emissions modeling system . SMOKE supports point, area, mobile (both on-road and non-road), and biogenic emissions. The SMOKE emissions modeling system uses flexible processing to apply ch emical speciation as well as temporal and spatial allocation to the emissions invent ories. SMOKE incorporates the Biogenic Emission Inventory System (BEIS) and EPA’s MOBILE6 motor vehicle emission factor model to process biogenic a nd on-road mobile emissions, respectively. Vector-matrix multiplication is used during the final processing step to merge the various emissions components into a single model-ready emissions file. Examples of processed emissions outputs are shown below in Figure 9-2.

Further details on the SMOKE processing conducted in support of the air quality simulations is provided in NYSDEC’s t echnical support document TSD-1c, “Emission Processing for the Revised 2002 OTC Re gional and Urban 12 km Base CaseSimulations,” September 19, 2006 (Attachment I), and in NESCAUM’s report, “MANEVU Modeling for Reasonable Progress Goals, Model Performance Evaluation, Pollution Apportionment, and Control Measure Benef its,” February 7, 2008 (Attachment P).
Additional details on the emissi ons inventory preparation can be found in Section 8.0 of this report.

9.3 Primary Regional Haze Modeling Platforms

MANE-VU used two reg ional-scale air quality models to perform its primary air quality simulations. These are the Community Mu lti-scale Air Quality modeling system (CMAQ; Byun and Ching, 1999) and the Regi onal Modeling System for Aerosols and Deposition (REMSAD; SAI, 2002). CMAQ was developed by USEPA, while REMSAD was developed by ICF Consulting/Systems Applications International (ICF/SAI) with USEPA support. CMAQ has undergone extens ive community development and peer review (Amar et al., 2005) and has been su ccessfully used in a number of regional air quality studies (Bell and E llis, 2003; Hogrefe et al., 2004; Jimenez and Baldasano, 2004; Mao and Talbot, 2003; Mebust et al., 2003). RE MSAD has also has been peer reviewed (Seigneur et al., 1999) and us ed by USEPA for regulatory ap plications) to study ambient concentrations and deposition of sulfate and other PM species 29

.

29 www.epa.gov/otaq/regs/hd2007/frm/r00028.pdf and www.epa.gov/clearskies/air_quality_tech.html5/27/2010
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Figure 9-2 Examples of Processed Model-Rea dy Emissions

(a) SO 2 from Point; (b) NO 2 from Area; (c) NO 2 from On-road; (d) NO 2 from Non-road; (e) ISOP from Biogenic; (f) SO 2 from all source categories

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86 9.3.1 CMAQ

The CMAQ air quality simulations were perf ormed cooperatively between five modeling centers, including NYSDEC, the New Jersey Department of Environmental Protection (NJDEP) in association with Rutgers Un iversity, the Virginia Department of Environmental Quality (VADEQ), UMD, and NESCAUM. NYSDEC also performed an annual 2002 CMAQ simulation on the 36-km domain shown in Figure 9-1; this simulation was used to derive the boundary conditions for the inner 12-km eastern modeling domain. Boundary conditions for the 36-km simulations were obtained from a run of the GEOS-Chem (Goddard Earth Obse rving System) global chemistry transport model that was performed by resear chers at Harvard University.

The CMAQ modeling system is a three-dimens ional Eulerian model that incorporates output fields from emissions and meteorologi cal modeling systems and several other data sources through special interface processors into the CMAQ Chemical Transport Model (CCTM). The CCTM then performs chemical transport modeling fo r multiple pollutants on multiple scales. With this structure, CMAQ retains the flexibility to substitute other emissions processing systems and meteorologi cal models. CMAQ is designed to provide an air quality modeling system with a “one atmosphere” capability containing state-ofscience parameterizations of atmospheric pro cesses affecting transport, transformation, and deposition of such pollutants as ozone, part iculate matter, airborne toxics, and acidic and nutrient pollutant sp ecies (Byun and Ching, 1999).

MANE-VU SIP modeling on both 36 km a nd 12 km domains used CMAQv4.5.1, IOAPI V2.2 and NETCDF V3.5 libraries. The CMAQ model is configured with the Carbon Bond IV mechanism (Gery et al., 1989) usi ng the EBI solver for gas phase chemistry
rather than the SAPRC-99 mechanism due to better computing efficiency with no significant model performance differences for ozone and PM as compared to observations. NY DEC completed annual 2002 CMAQ modeling on the 36 km domain to provide dynamic boundary conditions for all simulations performed on the 12 km domain. Three-hourly boundary conditions for the outer domain were derived from an annual model run performed by researcher s at Harvard University using the GEOSCHEM global chemistry transport model (Park et al., 2004). Model resolution was species dependent at eith er 4° latitude by 5° longitude or 2° by 2.5°.

Annual CMAQ modeling on the 12 km domain is divided into five periods. UMD was responsible for the period from January 1 to February 28; NJ DEP/Rutgers were responsible for the period from March 1 to May 14; NYSDEC was responsible for the period from May 15 to September 30; VADE Q was responsible for the period from October 1 to October 31; and NESCAUM was re sponsible for the period from November 1 to December 31. Each period uses a 15-day sp in-up run to minimize the impact of the
default initial concentrati on fields. Each modeling group performed CMAQ simulations on its period for a series of scenarios including 2002 Base Case, 2009 Base Case, 2018 Base Case, 2009 Control Case, and 2018 Contro l Case. All scenarios adopt the same meteorological field (2002) and boundary c onditions, varying only emission inputs. To ensure consistency, a benchmark test was conducted by ea ch modeling group.5/27/2010
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87 In addition to the annual simulations conducted with CMAQ by the five modeling centers, NESCAUM conducted limited sensitivity analysis of severa l control measures using the beta version of CMAQ with the particle and precurs or tagging methodology (CMAQ-PPTM) (ICF, 2006). The technical opt ions that were used in performing the CMAQ simulations are describe d in detail in NYSDEC’s technical support document TSD-1d, “8hr Ozone Modeling using the SM OKE/CMAQ system,” February 1, 2006 (Attachment K). Further technical detail s regarding the CMAQ model and its execution are also provided in NESCAUM’s report, “MANE-VU Modeling for Reasonable Progress Goals, Model Performance Evalua tion, Pollution Apportionment, and Control Measure Benefits,” February 7, 2008 (Attachment P).

9.3.2 REMSAD

The REMSAD modeling simulations were used to satisfy the haze rule requirement that a pollution apportionment be performed to assess contribution to visibility improvement by geographic region or source se ctor. REMSAD’s species tagging capability makes it an important tool for this purpose. The Regional Modeling System for Aerosols and Deposition (REMSAD) is a three-dimensiona l Eulerian model designed to support a better understanding of the distributions, sources , and removal processes relevant to fine particles and other airborne pollutants. It ca lculates the concentrations of both inert and chemically reactive pollutants by simulating the physical and chemical processes in the atmosphere that affect pollutant concentrations. The basis for the model is the atmospheric diffusion equation re presenting a mass balance in which all of the relevant emissions, transport, diffusion, chemical reactions, and removal pr ocesses are expressed
in mathematical terms. The REMSAD model performs a four-step solution procedure: emissions, horizontal advection/diffusion, ver tical advection/diffusion and deposition, and chemical transformations during one-hal f of each advective time step, and then
reverses the order for the fo llowing half-time step. The maximum advective time step for stability is a function of the grid size a nd the maximum wind velocity or horizontal
diffusion coefficient. Vertical diffusion is so lved on fractions of th e advective time step to keep their individual numerical schemes stable.

REMSAD uses a flexible horizon tal and vertical coordinate system with nested grid capabilities and user-defined vertical layers. It accepts a geodetic (latitude/longitude) horizontal coordinate system or a Cartesian horizontal coor dinate system measured in kilometers. REMSAD uses a simplified versi on of CB-IV chemistry mechanism that is
based on a reduction in the number of diffe rent organic compound species and also
includes radical-radical termina tion reactions. The organic portion of the chemistry is based on three primary organic compound species and one carbonyl species.

The model parameterizes aerosol chemistr y and dynamics for PM and calculates secondary organic aerosol (SOA) yiel ds from emitted hydrocarbons. REMSAD V7.12 and newer versions have capabilities that a llow model tags of sulfur species (up to 11 tags), nitrogen (4 tags), mercury (up to 24 tags), and cadmium (up to 10 tags) to identify the impact of specific tagged species. Un like CMAQ, REMSAD provides no choice of chemical and physical mechanisms. Due to the simplified chemistry mechanism, REMSAD may not simulate atmospheric pr ocesses as well as CMAQ. However,5/27/2010
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88 advantages such as the tagging feature for su lfur, more efficient modeling, and reasonable correspondence with measurements for many species, make REMSAD an important source apportionment tool for MANE-VU. The MANE-VU REMSAD modeling utilized the same 12 km eastern modeling domain shown in Figure 9-1, above. Multiple runs are necessary to permit tagging of sulfur emissions for all of the states in the domain, Canada, and the boundary conditions. NE SCAUM’s report, “MANE-VU Modeling for Reasonable Progress Goals, Model Perfor mance Evaluation, Pollution Apportionment, and Control Measure Benefits,” February 7, 2008, further describes the REMSAD model and its application to the regional ha ze SIP efforts (See Attachment P).

9.4 Primary Model Evaluation

9.4.1 CMAQ

NYSDEC extensively analyzed the CMAQ mo del performance to evaluate model predictions against observations of ozone, PM 2.5 , and other chemical species. To do this, model predictions for the base year simulati on are compared to the actual ambient data observed in the historical episode. This veri fication is a combinati on of statistical and graphical evaluations. If the model appears to be predicting fine particles and other airborne pollutants in the right locations for the right reasons, then the model can be used as a predictive tool to evaluate various c ontrol strategies and th eir effects on regional haze. CMAQ modeling was conducted for the year 2002 (completed by cooperative modeling efforts from NYDE C, UMD, NJDEP, Rutgers, VADEP, and NESCAUM) under the Base B4 emission scenario (See Attachment P). CMAQ performance for PM 2.5 species and visibility is examined ba sed on this CMAQ run on a 12 km resolution
domain. Measurements from IMPROVE and STN networks are paired with model predictions by location and time for evalua tion. Figure 9-3 presents the domain-wide paired comparison for sulfate and other PM2.5 species including nitr ate, OC, EC, fine soil, and PM 2.5 daily average concentration from th e CMAQ simulation and two sets of observations (STN and IMPROVE). It shows that predicted PM 2.5 sulfate and measured sulfate are in a good 1:1 linear relati onship with varying from 0.6 to 0.7. PM 2.5 nitrate (top row right panel) also has close to a 1: 1 linear relationship between the model and observations, although the values are much lowe r (from ~0.2 to ~0.5) than for sulfate. Paired OC (middle row left panel) concentra tions have a scattered distribution with overand under-estimation and a very weak linear relationship (r 2 of ~0.1). CMAQ tends to overestimate EC (middle row right panel) and fine soil (bottom row left panel)
concentrations. 30

30 EC and soil are inert species not involved in chemi cal transformation. Poor emission inventory data may be the main cause for the weak linear relationships be tween prediction and measurem ent. In addition, there are no fire emissions considered in CMAQ modeling. The wild fire in Quebec, Canada in early July of 2002 led to high concentrations of observed OC , EC, and fine soil that are not predicted by CMAQ.5/27/2010
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Figure 9-3 Domain-Wide Paired Comparison For Sulfate And Other PM 2.5 Species CMAQ vs IMPROVE/STN

Because sulfate is the dominant PM 2.5 species, modeled PM 2.5 (bottom row right panel) shows a relatively strong near 1:1 linear relationship.

Additional model performance evaluations include assessin g the ability of the CMAQ model to correctly model PM2.5 species across the modeling domain (spatial distribution

895/27/2010
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90 of the correlation coefficient between CM AQ predictions and Improve observations), mean fractional error of CMAQ predictions, m ean fraction bias of CMAQ predictions, and paired comparisons of the haze inde x between CMAQ predictions and Improve
measurements at selected Class I sites we re undertaken. In summary, the CMAQ model was demonstrated to perform best for daily average SO 4 mass and PM 2.5. Many other species vary significantly over the course of a day, or from day to day, and small model over- or underprediction at low concentrations can lead to large biases on a composite basis. These model performance evaluations are described in detail in NYSDEC’s technical support document TSD-1e, “CMAQ M odel Performance and Assessment, 8-Hr OTC Ozone Modeling,” February 23, 2006 (Attachment K) and in NESCAUM’s report , “MANE-VU Modeling for Reasonable Progress Goals, Model Performance Evaluation, Pollution Apportionment, and Control Measure Benefits,” February 7, 2008 (Attachment P).

9.4.2 REMSAD

The Regional Modeling System for Aerosols and Deposition (REMSAD) model was utilized by MANE-VU for its contribution assessment. REMSAD model performance has been evaluated as part of several previ ous national and regional modeling exercises. EPA evaluated REMSAD performance as for th eir Clear Skies Act base case study using 1996 meteorology and 1996 NET inventory. 31 Modeling results were compared with IMPROVE measurement, with REMSAD found to perform better in the Eastern US than
in the Western US on PM sulfate and PM 2.5 , although it underestimates ambient levels countrywide and performs relatively poorly on soil, carbonaceous aerosols and PM
nitrate. 32

A spatial performance evaluation of REMAS AD simulations for sulfate on the 12km northeast US domain for the year 2002 was conducted through comparison with IMPROVE/STN measurements, as illustrate d in Figure 9-4. These comparisons are inexact, because the discrete measurements represent a uniform gridded concentration field. This approach, however, does provide a first order examination of measurement and modeling results, which is appropri ate for an annual averaged analysis.

In general, the REMSAD simulation field is well-matched with measurement data. Figure 9-5 shows the comparison of paired 24-hour surface sulfate concentrations between five different air quality mode l results (including REMSAD) and IMPROVE measurements during the year 2002 for Ly e Brook Wilderness Area (Vermont) and

31 See Clear Skies Act Air Quality Modeling Technical Support Document at http://www.epa.gov/air/clearskies/aq_modeling_tsd_csa2003.pdf

32 NESCAUM also performed REMSAD modeling using the 1996 meteorology, but with the 2001 Proxy emission inventory, therefore a direct comparison to the EPA CSA modeling results could not be completed. To evaluate REMSAD for this exerci se, NESCAUM first compared its own modeling results with EPA’s CSA 2001 case modeling results, which also used the 1996 meteorology. NESCAUM’s results were an exact match with EPA’s REMSAD modeling on PM 2.5 and PM sulfate distributions. In addition, NESCAUM also compared the long term modeling av erage (annual mean) of PM species to IMPROVE
annual means for three sites. These comparisons show good agr eement for REMSAD modeling of PM sulfate, NH4, OC and EC.5/27/2010
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Shenandoah National Park (Virginia). The com parison illustrates that the two CMAQ model runs show the best performance in te rms of slope, intercep t and coefficient of correlation (r2), with the REMSAD results showing the 2 nd best performance. Along with EPA’s previous evaluation (Timin B. et al., 2002) the NESCAUM performance evaluation confirms that REMSAD performs reasonably well for longer-term (annual averaged) sulfate simulation.

Figure 9-4
Sulfate Concentrations From the IM PROVE/STN Measurements an d the REMSAD
Model

Figure 9-5
Compariso n of Measurement and Modeled Data for Alternative Annual Model
Simulations

915/27/2010
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92 9.5 Additional Modeling Platforms

9.5.1 CALGRID

In addition to the SIP-quality modeling pl atforms that were described above, an additional modeling platform was developed fo r use as a screening tool to evaluate additional control strategies or to perfor m sensitivity analyses. The CALGRID model was selected as the basis for this platform. CALGRID is a grid-based photochemical air quality model that is designed to be run in a Windows environment. In order to make the CALGRID model the best pos sible tool to supplement the SIP-quality CMAQ and REMSAD modeling, the current ve rsion of the CALGRID platfo rm was set up to be run with the same set of inputs as the SIP- quality models. The CALGRID air quality
simulations were run on the same 12-km eas tern modeling domain that was used for CMAQ and REMSAD. This model’s performan ce was relative to the performance of the already evaluated CMAQ and REMSAD models and was thus determined to perform adequately.

Conversion utilities were developed to re-f ormat the meteorological inputs, the boundary conditions, and the emissions for use with the CALGRID modeling pl atform. Pre-merged
SMOKE emissions files were obtained from the modeling centers and re-formatted for input into EMSPROC6, the emissions pre-pro cessor for the CALGRID modeling system. EMSPROC6 allows the CALGRID user to adju st emissions temporally, geographically, and by emissions category for control stra tegy analysis. The pre-merged SMOKE files that were obtained from the modeling centers were broken down into the biogenic, point, area, non-road, and on-road emissions categorie s. These files by component were then converted for use with EMSPROC6, thus gi ving CALGRID users the flexibility to analyze a wide variety of emissions c ontrol strategies. The MANE-VU CALGRID modeling is described in greater detail in Attachment P.

9.5.2 CALPUFF

CALPUFF is a non-steady-state Lagrangian pu ff model that simulates the dispersion, transport, and chemical transformation of atmospheric pollutants. Two parallel CALPUFF modeling platforms were deve loped by the Vermont Department of Environmental Conservation (VTDEC) a nd the Maryland Department of the Environment (MDE). The VTDEC CA LPUFF modeling platform utilized meteorological observation data from the Na tional Weather Service (NWS) to drive the CALMET meteorological model. The MDE platform utilized the same MM5 meteorological inputs that we re used in the modeling done in support of the ozone and regional haze SIPs. These two platforms were run in parallel to evaluate individual
states’ contributions to sulfate levels at No rtheast and Mid-Atlantic Class I areas. The CALPUFF modeling effort is described in de tail in NESCAUM’s report, “Contributions to Regional Haze in the Northeast and Mi d-Atlantic United States,” August 2006 (Attachment A).5/27/2010
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93 

### 10. Best Available Retrofit Technology

The Best Available Retrofit Technology (BART) requirement of Section 169A of the Clean Air Act (42 U.S.C.§7491(b)(2)(A)) and implementing rules (40 C.F.R. Part 51, Attachment Y) are intended to re duce visibility impairing pollutants 33 emitted from existing stationary sources which were gr andfathered from the New Source Review (NSR) requirements of the Clean Air Act. The federal definition of BART in 40 CFR
Part 51.301 is as follows:

“ Best Available Retrofit Technology (BART ) means an emission limitation based on the degree of reduction achievable through the application of th e best system of continuous emission reduction for each po llutant which is emitted by an existing stationary source facility. The emission lim itation must be established, on a case-bycase basis, taking into consideration the technology available, the costs of compliance, the energy and nonair quality environmental impacts of compliance, any pollution control equipment in use or in exis tence at the source, the remaining useful life of the source, a nd the degree of improvement in visibility which may reasonably be anticipated to result from the use of such technology.”

The BART requirements apply to certain ol der industrial sources that began operating before the federal Prevention of Significant Deterioration (PSD) ru les were adopted in 1977 to protect visibility in Class I areas. PSD and BART represent the two primary regulatory tools for protecting visibility a nd addressing regional haze from industrial sources. The PSD rules apply to new sour ces and major modifications of existing

sources 34 , while BART applies to 26 types of st ationary sources which began operation between August 7, 1962 and August 7, 1977 with the potential to emit more than 250 tons per year of a visibility impairing pollu tant. Once the Regional Haze SIP is approved by the EPA, the BART facility has up to five years to install the a ppropriate controls and comply with the established emission standard s. Maine is requiring sources subject to BART to install, operate and maintain BART rather than implement an emissions trading program or other alternative measure.

10.1 The Federal BART Rule

In June 2005, EPA adopted the final BART rule . The BART r ule requir es states/tribes to develop an inventory of sources within each state or tribal jurisdiction that would be eligible for controls. The rule contains the following elements that:

33 The visibility impairing pollutants are defined by the EPA as sulfur dioxide (SO 2 ), oxides of nitrogen (NO

x ) and particles with an aerodynamic diameter less than or equal to 10 and 2.5 μ m (i.e., PM 10 and PM 2.5 , respectively).

34 The PSD rules are part of the Ne w Source Review rules, which apply to major new sources and major modifications of existing sources, to protect both vi sibility and air quality in general. See further description in Section 12. Since BART addresses exis ting sources, the evaluation of controls considers the effectiveness and the remaining life of the existing controls, and the cost of replacing them. While PSD and BART may end up evaluating similar types of controls, the criteria and selection of controls for BART
is different due to the retrofit factors an d visibility improvement that would result.5/27/2010
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94  Outline methods to determine if a source is “reasonably anticipated to cause or
contribute to haze”

 Defines the methodology for conducti ng a BART control analysis

 Provides presumptive limits for electric ity generating units (EGUs) larger than 750 Megawatts

 Provides a justification for the use of the Clean Air Interstate Rule (CAIR) as
BART for CAIR affected EGUs

Beyond the specific elements listed above, EPA pr ovided the states with a great deal of flexibility in implementing the BART program.

10.1.1 Federal BART Requirements fo r Electric Generating Units (EGUs)

According to 40 CFR Section 51.308(e)(4) of th e Regional Haze Rule, a State that opts to participate in the Clean Air Interstate Rule (CAIR) Cap and Trade program under 40 CFR Part 96AAA-EEE need not require affected BART eligible EGUs to install, operate, and
maintain BART. Since Maine and Maine so urces were not include d in the CAIR Cap and Trade Program, EGUs in Maine that are su bject to BART must install, operate and
maintain emission controls.

Section V of the Regional Haze Regulations a nd Guidelines for Best Available Retrofit Technology (BART) Determinations Preamble se ts forth presumptive requirements for States to require EGUs to reduce SO 2 and NO

x emissions for units greater than 200 MW in capacity at plants greater than 750 MW in capacity that significantly contribute to visibility impairment in Federal Class I area s. The analysis conducte d presents alternative control scenarios of possible ad ditional controls for EGUs lo cated at plants less than 750 MW in capacity.

Under 40 CFR Section 51.308(e)(1 )(i)(B) of the Regional Ha ze Rule, the determination
of BART for fossil fuel fired power plants having a total generating capacity of greater than 750 megawatts must be made pursuant to th e guidelines of Attachment Y of this part of the CFR (Guidelines for BART Determinations under the Regional Haze Rule). EPA adopted those guidelines on July 6, 2005. Th e guidelines provide a process for making BART determinations that States can use in implementing the regional haze BART requirements on a source-by-source basis, as provided in 40 CFR 51.308(e)(1). States must follow the guidelines in making BART de terminations on a source-by-source basis for power plants of greater than 750 megawa tts (MW), but are not required to use the process in the guidelines when making BART de terminations for other types of sources. For oil-fired EGUs, the presumptive level of BART control for SO 2 is the use of oil containing 1 percent or less sulfur by we ight. Combustion controls constitute the presumptive BART control for NO

x at these units.5/27/2010
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95 10.2 Maine State BART Requirements

In 2007, the Maine Legislature enacted enabli ng legislation establ ishing deadlines and

contro l requirements/limitations fo r BART eligible units in Maine 35 . 38 MRSA §603-A, sub-§8 states:

“8. Best available retrofit techno logy or BART requirements



### . For those BART eligible units determined by the department to need additional sulfur air pollution controls to improve visib ility, the controls must:

A. Be installed and operational no later than January 1, 2013; and

B. Either:

(1) Require the use of sulfur oil having 1% or less of sulfur by weight; or

(2) Be equivalent to a 50% reduction in sulfur emissions from a BART eligible unit based on a BART elig ible unit source emission baseline determined by the department under 40 Code of Federal Regulations, Section 51.308 (d)(3)(iii)(2006) and 40 Code of Federal Regulations, Section 51 Attachment Y (2006).”

10.3 BART-Eligible Sources in Maine

Determ ining BART-eligible sources is the firs t step in the BART process. The Maine BART-eligible sources were identified in accordance with the methodology in Appendix Y of the Regional Haze Rule, Guidelines fo r BART Determinations Under the Regional Haze Rule, Part II, How to Identify BART-Eligible Sources (70 FR 39158). This guidance consists of the following criteria:

1. The facility contains emission units 36 which fall into one or more of 26 source categories:

 Fossil-fuel fired steam electri c plants of more than 250 million British thermal units (BTU) per hour heat input

 Coal cleaning plants (thermal dryers)

 Kraft pulp mills

 Portland cement plants

 Primary zinc smelters

 Iron and steel mill plants

 Primary copper smelters

 Municipal incinerators capable of charging more than 250 tons of refuse per day

 Hydrofluoric, sulfuric, and nitric acid plants

35 Sources may also cap their emissions below the 250 ton BART eligibility threshold.

36 EPA rules (40 CFR Part 51.166) define emission unit as “any part of a stationary source that emits or has the potential to emit any pollutant”.5/27/2010
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96  Petroleum refineries

 Lime plants

 Phosphate rock processing plants

 Coke oven batteries

 Sulfur recovery plants

 Carbon black plants (furnace process)

 Primary lead smelters

 Fuel conversion plants

 Sintering plants

 Secondary metal production facilities

 Chemical process plants

 Fossil-fuel boilers of more than 250 million BTUs per hour heat input

 Petroleum storage and transf er facilities with a capacity exceeding 300,000 barrels

 Taconite ore processing facilities

 Glass fiber processing plants

 Charcoal production facilities

2. The units “began operation” after August 7, 1962 (defined as “engaged in activity related to the primary desi gn function of the facility”) , and were the units “in existence on August 7, 1977 (defined as “the owner or operator has obtained all the necessary pre-construction approvals or permits required by Federal, State or local air pollution emissions and air quality laws or regul ations and either has (1) begun, or caused to begin, a continuous program of physical on-site construction of the facility or (2) ente red into a binding agreements or contractual obligation,
which cannot be canceled or modified wit hout substantial loss to the owner or operator, to undertake a program of construction of the fac ility to be completed in a reasonable time”).

[Note: Sources that were in ope ration before August 7, 1962, but were reconstructed during the August 7, 1962 to August 7, 1977 time period are also subject to BART if “the fixed capital cost of the new component exceeds 50 percent of the fixed capital cost of a comparable entirely new source”]

3. The potential emissions from these units 250 tons per year or more for sulfur dioxide (SO 2 ), nitrogen oxides (NO

x ), particulate matter (PM), volatile organic compounds (VOC), or ammonia (NH4). The BART Guidelines recommend addressing SO 2 , NO
x , and particulate matter. The State of Maine addressed these three pollutants, and used particulate matter less than 10 microns in diameter (PM 10 ) as an indicator for particulate matter to identify BART eligible units, as the Guidelines suggest. Consistent with the Guidelines, the State of Maine did
not evaluate emissions of VOCs and ammonia in BART determinations for these

reasons:

 The majority of VOC emissions in Ma ine are biogenic in nature, with the areas near Maine Class I areas especially so (the ability to further reduce total ambient VOC concentrations at Class I areas is limited);

 Point, area and mobile sources of VOCs in Maine are already comprehensively controlled as part of our ozone attainment and maintenance strategy;5/27/2010
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97  The overall ammonia inventory is very uncertain, and the amount of anthropogenic emissions at sources that were BART-eligible was relatively small, and

 No additional sources were identified that had greater than 250 tons per year ammonia and required a BART analysis.

The identification of BART sources in Main e was undertaken as part of a multi-state analysis conducted by the Northeast Stat es for Coordinated Air Use Management (NESCAUM). NESCAUM worked with Main e DEP licensing engineers to review all sources and determine their BART eligibil ity. Maine DEP identified 10 sources as BART-eligible. These sources are listed below in Table 10-1.

10.4 Sources Subject to BART

Maine, working with MANE-VU, found that every MANE-VU state with BART-eligible sources contributes to visibility im pairment at one or more Class I areas to a significant degree (See the MANE-VU Contribution Assessme nt in Attachment A). As a result, Maine has found that all eligible sources within Maine are subject to BART. The State of Maine is utilizing this option for demonstrating its sources are reasonably anticipated to
cause or contribute to visibi lity impairment at Class I ar eas for three reasons: (1) the BART sources represent an opportunity to achieve greater reas onable progress; (2) additional public health and welfare benefits will accrue for the resulting decreases in fine particulate matter; and (3) to demonstr ate its commitment to federal land managers (FLMs) and other RPOs as it seeks the implementation of re asonable measures in other

states. 37

According to Section III of the 2005 Regiona l Haze Rule, once the state has compiled its list of BART-eligible sources, it needs to determine whether to make BART
determinations for all of the sources or to consider exempting some of them from BART because they may not reasonably be anticipated to cause or c ontribute to any visibility impairment in a Class I area.

Based on the collective importance of BA RT sources, Maine has decided that no exemptions would be given for sources; a BA RT determination will be made for each BART-eligible source.

10.5 MANE-VU BART Modeling

MANE-VU conducted modeling analyses of BA RT-eligible sources using CALPUFF in order to provide a regionally-consistent foundation for assessing the degree of visibility
im provement which could result from installati on of BART controls (See Attachment L).

37 Maine’s decision that all BART eligible sources are subject to BART should not be misconstrued to mean that all BART-eligible sources must insta ll BART. Maine’s approach simply requires the consideration of each of the five statutory factors before determining whether or not controls are warranted.5/27/2010
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98 Table 10-1 BART-Eligible Sources in Maine

Source and Unit Location I.D BART Source Category FPLE Wyman Station
Boiler #3
Boiler #4 Yarmouth, ME 2300500135
-004
-005 SC 1- Fossil fuel fired electric plants

Domtar
Power Boiler #9
Lime Kiln Woodland, ME 2302900020
-001
-002 SC 3 - Kraft pulp mills

Dragon Products
Kiln Thomaston, ME 2301300028
-005 SC 4 – Portland cement plants

Red Shield Acquisition, LLC #4 Recovery Boiler
Lime Kiln Old Town, ME 2301900034
-002
-004 SC 3 - Kraft pulp mills

Verso Bucksport
#5 Boiler Bucksport, ME 2300900004
-001 SC 22 – Fossil fuel fired boilers

SAPPI Somerset Recovery Boiler Smelt Tanks #1, #2
Lime Kiln Hinckley, ME 2302500027
-003
-007
-004 SC 3 - Kraft pulp mills

Verso Androscoggin
Power Boiler #1
Power Boiler #2
Waste Fuel Incinerator Recovery Boilers #1 and #2
Smelt Tank #1
Smelt Tank #2
Lime Kiln A
Lime Kiln B Flash Dryer Jay, ME 2300700021
-001
-002
-003
-004/005
-009
-010
-007
-008
-018 SC 3 - Kraft pulp mills

Katahdin Paper
Power Boiler #4 Millinocket, ME 2301900056
-004 SC 22 – Fossil fuel fired boilers

Lincoln Paper and Tissue Recovery Boiler #2 Lincoln, ME 2301900023
-002 SC 3 - Kraft pulp mills

Rumford Paper
Power Boiler #5 Rumford, ME 2301700045
-003 SC 3 – Kraft pulp mills

While this modeling analysis differed s lightly from the statutory language, it was intended to provide a first-orde r estimate of the maximum visi bility benefit that could be achieved by eliminating all emissions from a BART source, and provides a useful metric for determining which sources are unlikely to warrant (additional) controls to satisfy
BART.5/27/2010
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99 The MANE-VU modeling effort analyzed 136 BART-eligible sources in the MANE-VU region using the CALPUFF modeling platform and two meteorological data sets: 1) a
wind field based on National Weather Servic e (NWS) observations; and 2) a wind field based on the MM5 meteorological model (MM5 2006). Modeling results from both the NWS and MM5 platforms include each BA RT eligible unit’s maximum 24-hr, 8 th highest 24-hr, and annual average impact at the Cla ss I area. These visi bility impacts were modeled relative to the 20 percent best, 20 percent worst, and average annual natural background conditions. In accordance with EPA gui dance, which allows the use of either estimates of the 20 percent best or annual average natural background visibility conditions as the basis for calculating the deciview difference that individual sources would contribute for BART modeling purposes , MANE-VU opted to utilize the more conservative best conditions estimates appro ach because it is more protective of the region.

The 2002 baseline modeling provides an estimate of the maximum improvement in visibility at Class I Areas in the region that could result from the installation of BART controls (the maximum improvement is equiva lent to a “zero-out” of emissions). In virtually all cases, the installation of BART controls would result in less visibility improvement than what is represented by a source’s 2002 impact, but this approach does provide a consistent means of identifying thos e sources with the greatest contribution to visibility impairment.

In addition to modeling the maximum pot ential improvement from BART, MANE-VU also determined that 98 percent of the cumulative visibility impact from all MANE-VU BART eligible sources corresponds to a ma ximum 24-hr impact of .22 dv from the NWSdriven data and 0.29 dv from the MM5 data. As a result, MANE-VU concluded that, on the average, a range of 0.2 to 0.3 dv would represent a significant impact at MANE-VU Class I areas, and sources having less th an 0.1 dv impact are unlikely to warrant
additional controls under BART. 38

Table 10-2 illustrates the m odeled impacts (maximum) of Maine BART-Eligible sources
on selected Class I areas in Maine and New Hampshire. For this table, SO 4 , NO 3 and

PM 10 modeled impacts at these Class I areas were totaled to provide an estimate of the maximum 24-hr impact at these nearby Class I areas. It should be noted that a number of BART-eligible sources (highlighted) have less than a 0.1 deciview impact on Class I

areas.

38 As an additional demonstration that sources whose imp acts were below the 0.1 dv level were too small to warrant BART controls, the entire MANE-VU population of these units was modeled together to examine their cumulative impacts at each Class I suite. The results of this modeling demonstrated that the maximum 24-hour impact at any Class I area of all modeled sources with individual impacts below 0.1 dv was only a 0.35 dv change relative to the estimated best days natural conditions at Acadia National Park. This value is well below the 0.5 dv impact recommended by EPA for exemption modeling and used by
most other RPOs.5/27/2010
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100 10.6 The Maine BART Analysis Protocol

40 CFR 51.308(e)(1)(ii)(A) require s that, for each BART-eligible source within the state, any BART determ ination must be based on an analysis of the best system of continuous emission control technology available and the associated emission reductions achievable. In addition to considering avai lable technologies, this analysis must evaluate five specific
factors for each source:

1. The costs of compliance,
2. The energy and non-air quality enviro nmental impacts of compliance,
3. Any existing pollution control tech nology in use at the source,
4. The remaining useful life of the source, and

5. The degree of visibility improvement which may reasonably be anticipated
from the use of BART.

Although Maine did not exempt any BART-eligib le sources from a BART determination, it did utilize the MANE-VU zero-out modeling (d escribed in the previous section) as a surrogate for estimating the visibility improvement reasonably expected from the application of controls. As previously hi ghlighted in Table 10-2, there are ten BARTeligible sources with less than 0.1 deciview impact at any Class I area, with these impacts ranging from a low of 0.0018 deciviews to a higher (but still insignificant) 0.0822 deciviews. Since zero-out modeling shows th at the elimination of all emissions from these sources would provide only insignificant visibility benef its at nearby Class I areas, and recognizing that the majority of these units already have cont rols fully satisfying BART requirements, the Department used th e “anticipated visibility improvement from
BART” factor to determine the scope of the BART analysis a nd whether visibility impact modeling need be performed by specific sources. The Maine approach is consistent with that used by other MANE -VU states that are not allowing sources to utilize exemption modeling. With the Maine approach, all BART-eligible sources were required to undertake an engineering analysis of their existing and possibl e future controls. If an
emissions unit was found to be well-contro lled (in comparison with possible future controls), and the visibility im pacts of the unit relatively small 39 as determined by the MANE-VU zero-out modeling, BART was de termined 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).

10.7 Summary of Maine BART Determinations

The f ollowing section details the BART determ inations for all BART-eligible sources in Maine. All BART requirements are incorpor ated in a Title V air emissions license (operating permit) for each source; draft Title V licensee are included in Attachment M.

39 Sources with less than 0.1 deciview impact on Cl ass I areas are presumed to have a small impact.5/27/2010
Draft For FLM Review

101 Table 10-2 Modeled Impacts (Deciviews) of Maine BA RT-Eligible Sources at Selected MANEVU Class I Areas (Sources with < 0.1 deciview total impact highlighted)

Facility Name Stack Name NWS CALPUFF MM5 CALPUFF

Total SO4 NO3 PM10 Total SO4 NO3 PM10

24-hr dv impact 24-hr dv impact FPLE Wyman Station Boiler_4 0.1423 0.1276 0.0334 0.0010 0.4749 0.3846 0.1072 0.0005 FPLE Wyman Station Boiler_3 0.2212 0.1715 0.0704 0.0004 0.3049 0.2545 0.0508 0.0014

Domtar Ind. #9_Power_Boiler 1.3630 0.2828 0.7988 1.3134 1.6506 0.1815 0.7279 1.3717

Domtar Ind. Lime_Kiln 0.5296 0.0559 0.4309 0.1207 0.4589 0.0427 0.3820 0.1048

Dragon Products Kiln 2.0155 0.2434 1.7614 0.0604 1.8626 0.3208 1.7234 0.0413
Red Shield Acquisition, Old
Town #4_Recovery_Boiler 0.2425 0.0634 0.1633 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 0.1338 0.0138 0.0855 0.0463

Verso, Bucksport Boiler_#5 0.0543 0.0260 0.0267 0.0021 0.1591 0.0817 0.0721 0.0098

SAPPI Somerset Recovery_Boiler 0.2159 0.0151 0.1971 0.0087 0.4421 0.0179 0.4168 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, Androscoggin Power_Boiler_#1 0.6948 0.5720 0.1235 0.0094 1.7631 1.2176 0.5867 0.0290 Verso, Androscoggin Power_Boiler_#2 0.7223 0.5948 0.1287 0.0095 1.8289 1.2646 0.6105 0.0293 Verso, Androscoggin Waste_Fuel_Incinerator Boiler_ 0.4256 0.0036 0.3651 0.0591 0.4956 0.0064 0.4544 0.0367 Verso, Androscoggin Recovery_Boiler_#1_and_#2 0.1101 0.0454 0.0598 0.0078 0.3856 0.0952 0.2723 0.0215 Verso, Androscoggin Smelt_Tank_#1 0.0139 0.0002 0.0000 0.0137 0.0122 0.0002 0.0000 0.0120 Verso, Androscoggin Smelt_Tank_#2 0.0129 0.0004 0.0000 0.0125 0.0135 0.0006 0.0000 0.0129 Verso, Androscoggin Lime_Kiln_A 0.0441 0.0001 0.0273 0.0167 0.0457 0.0004 0.0337 0.0123 Verso, Androscoggin Lime_Kiln_B 0.0296 0.0001 0.0197 0.0098 0.0293 0.0004 0.0228 0.0062 Verso, Androscoggin 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 0.1569 0.0210 0.4458 0.3832 0.1164 0.0216 Lincoln Paper and
Tissue Recovery_Boiler_#2 0.1151 0.0141 0.0806 0.0224 0.1200 0.0073 0.0882 0.0322

Rumford Paper PB_#5 0.0369 0.0039 0.0327 0.0026 0.1025 0.0108 0.0897 0.0020

> 0.1 dv TOTAL and a pollutant > 0.1 dv TOTAL only

10.7.1 Cap-Outs and Shutdowns EPA guidance allows BART-eligible sources to adopt a federally enforceable permit limit to permanently limit emissions of visibi lity impairing pollutants to less than 250 tons per year, thereby “cappi ng-out” of BART. Four Ma ine sources capped out of
BART:5/27/2010
Draft For FLM Review

102 1. Katahdin Paper Company, LLC
2. Red Shield Acquisition, LLC
3. Rumford Paper Company
4. Verso Bucksport, LLC

These sources have actual emissions of visibility impairing pollutants of fewer than 250 tons per year, and are BART-eligible only because their potential emissions (PTE) exceed the statutory threshold of 250 tons per year. Pursuant to their requests, the Maine DEP has established federally enforceable pe rmit conditions that limit the PTE of these
units to less than the statutor y threshold of 250 tons per year for all visibility impairing pollutants, which makes these units not subject to BART requirements.

Federally enforceable terms and conditions were established for each source that limit the
PTE for SO 2 , PM 10 and NO

x to less than 250 TPY. Note that if, in the future, the source requests an increa se in PTE greater than 250 tons per year per visibility impairing pollutant, then they shal l be subject to the Be st Available Retrofit Technology (BART) provisions of the Envi ronmental Protection Agency’s (EPA) Regional Haze Program Requirements (40 Code of Federal Regulations, Part 51, Section 308).

10.7.2 Maine BART Determinations

In general, the following determinations summarize the controls and limits that are currently required under existi ng air emission licenses (as not ed), or will be required specifically due to BART.

1. Domtar Maine, LLC

The Domtar Woodland Pulp facility is a pulp mill, which utilizes the Kraft Pulping process and produces market pulp. The Mill also operates suppor t facilities including woodyards, wastewater treatment plant, sludge press, pulp production labs, environmental labs, finishing, shipping, and rece iving operations, storage areas, a landfill, and a power boiler. There are two BART e ligible units at the facility; the #9 Power Boiler, and the Lime Kiln.

#9 Power Boiler is rated at 625 MMBtu/hr and was placed into operation in 1971. #9 Power Boiler is fueled primarily by biomass but is also licensed to burn #6 fuel oil, sludge, TDF, specification waste oil, HVLC, LV HC, mill yard waste, oily rags, stripper off-gas, and propane. Emissions are cont rolled using a variable-throat wet venturi
scrubber and low-NO

x burners. The Lime Kiln is ra ted at 75 MMBtu/hr and was placed into operation in 1966. Emissions are contro lled using a variable -throat wet venturi
scrubber and a Ceilcote cross-flow scrubber. The Lime Kiln is fueled by #6 fuel oil.5/27/2010
Draft For FLM Review

103 BART Analysis Summary

#9 Power Boiler

PM: Domtar evaluated the use of Fabric Filte rs, Wet Electrostatic Precipitator (WESP), Dry Electrostatic Precipitator (DESP), and We t Scrubbers to control PM at the #9 Power
Boiler. Fabric filters were found not tec hnically feasible due to fire risk from combustible fly-ash, while WESP is not technically feasible due to operational
difficulties with multi-fuel boilers. A DESP co uld not be installed post-scrubber due to excess moisture levels, but could be inst alled upstream. A DESP was evaluated and found to provide a 98-99% control efficiency for biomass a 90% efficiency for oil (for comparison, a wet scrubber provides an 85-98% control efficiency) . Domtar estimated the cost for DESP installation at $4,640 per ton of PM removed, and found that DESP is not a cost-effective option.

SO 2 : Power Boiler #9 is curren tly controlled through the us e of a wet scrubber and low sulfur fuel (biomass). Domtar did not inves tigate other control technologies because the
combination of low sulfur fuel and wet sc rubber provides maximu m emission reductions
from this unit.

NO
x : Domtar identified a nu mber of potential NO

x control strategies for use on Power Boiler #9, including: NOx tempering, flue gas recirculation (FGR), selective noncatalytic reduction (SNCR), selective catalytic reduction (SCR), low NOx burners and good combustion practices. Several potential NO x 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 fr equency of catalyst fouling from multi-fuel boilers, and FGR is not technically feasib le based on previous failed FGR trials conducted on the #9 Power Boiler. SNCR, w ith a 30-40% control efficiency, and low NOx Burners, with 10% control efficiency, were identified as technically feasible control strategies. Domtar’s anal ysis estimated the cost-effec tiveness of SN CR at $7,360 per ton, and noted that SNCR has a reduced effec tiveness on boilers with significant load swings (such as Power Boiler #9). Given the low cost-effectiveness of SNCR, Domtar
identified the continued use of low NO

x burners as BART.

Lime Kiln

PM: T he Lime Kiln is subject to the MACT standard for PM found in 40 CFR, Part 63, Subpart MM. According to 40 CFR, Part 51, Appendix Y, According to 40 CFR Part 51, 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 C ontrol Technology (MACT) standards without identifying control options that would cost many thousands of dollars per ton. Unless there are new technologies subs equent to the MACT standard s 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.5/27/2010
Draft For FLM Review

104 SO 2 : Domtar identified the use of a wet scr ubber and in-process cap ture as feasible technologies for the control of SO 2 from the lime kiln. Sinc e both technologies are currently employed by Domtar (including two wet scrubbers), no further analysis was

necessary.

NO
x : A number of potential NO

x control strategies were identified for the lime kiln, including: SNCR, SCR, non- selective catalytic reducti on (NSCR), FGR, low NOx burners and good combustion practices. The impracticality of installing chemical injection nozzles inside a rotating Kiln dr um makes SNCR technically infeasible. SCR and NSCR are not feasible due to the known pr esence of catalyst fou ling substances in
the Lime Kiln. FGR is not feasible as it re duces the temperature in the flame zone, thus hindering the chemical reaction taki ng place in the Lime Kiln. Low NO

x burners are a non-demonstrated technology and are not listed in the EPA BACT/RACT/LEAR Clearinghouse for Lime Kiln emissions contro l. Good combustion practices are the only feasible option, which is already employed at the Lime Kiln. No further analysis is

necessary.

BART Determination for Domtar

Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference

#9 Power
Boiler Wet
scrubber 0.15
lb/MMBtu (Existing
Title V license) Wet scrubber 0.3
lbs/MMBtu
on a 24-
hour basis (BART order) Low-NO

x burners 0.4
lb/MMBtu
on a 24-
hour basis (Existing
Title V license) Lime
Kiln Wet
scubber Compliance
with 40
CFR Part 63 Subpart

MM Wet
scrubber/Process
control 8.3 lbs/hr. (Existing
Title V license) Good
combustion practices 120 ppmvd @10% O 2 (Existing
Title V 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 th at was converted to the more efficient dry cement manufacturing process beginning in 2003. The modernization project converted the existing wet process cement kiln to a dr y process (preheater/p recalciner type), converted the existing (wet) raw mill to a pregrinding finish cement mill, and improved other ancillary operations with in the facility. The planned annual production rate of the new facility is approximately 766,500 tons of clinker.

The BART eligible kiln system is a single dry process rotary kiln and inline raw mill equipped with a preheater/precalciner. Vari ous allowable fuels, including petcoke, #25/27/2010
Draft For FLM Review

105 fuel oil, #4 fuel oil, specification waste oi l, 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 ra w material additives) into ca lcium silicates or ‘clinker’. Hot flue gases from the kiln flow counter-curre nt to the feed material up the length of the
kiln. Heat is transferred to the fed material fr om the direct contact of the flue gases in the kiln and preheater/precaliner tower.

BART Analysis Summary

Dragon submitted a 5-step BART analysis of the technical feasibility and cost of compliance, the energy and non-air quality impacts of compliance, any existing air pollution control technology in us e at the source, the remaining useful life of the source, and the degree of visibility improvement antic ipated from the use of BART (a CALPUFF version 5.8 analysis was performed by Dragon).

PM : Emissions of PM from the kiln system are generated as a function of the clinker production process. The kiln system is subject to 40 CFR Part 63, Subpart LLL, National Emission Standards for Hazardous Air Po llutants from the Portland Cement Manufacturing Industry . Since the MACT is curren t and Dragon complies with the particulate matter limits in §63.1343 and uses a fabric filter dust collector for PM 10 control, no further BART analysis was performed.

SO 2 : Emissions of SO 2 from cement kilns are generally related to the inherent SO 2 removal efficiency present in the kiln sy stem operation itself, the pyritic sulfur concentration of the raw feed materials, the sulf ur to alkali ratio of th e raw feed materials, and whether the prevailing condition of th e system is oxidizing or reducing. Dragon identified wet scrubbing, semi-dry scrubbi ng, dry scrubbing, fuel switching, and process alterations as possible retrofit co ntrol technologies for reducing SO 2 emissions.

Wet caustic scrubbing, where one or more soluble components of an acid gas are dissolved in a liquid with a low volatilit y, semi-dry scrubbing, based on atomizing a reagent slurry stream containing lime and cont acting the flue gases in a spray dryer type vessel, and dry scrubbing, consis ting of injecting a dry reagen t into the gas stream prior to the particulate matter contro l device, were considered tech nically feasible for the kiln system and were further evaluated 40 . The three scrubbing options were reviewed further, and the results are in the following table:

40 A dry scrubbing system is currently installe d on the kiln system but is not operated.5/27/2010
Draft For FLM Review

106 Control Technology Expected
SO 2 Emission

Rate (tons/yr) Emissions
Performance
Level Expected
SO 2 Emissions
Reductions

(tons/yr) Cost of Compliance

Wet Scrubbing 49.0 95% 46.6 Total Cap. Investment: $9,419,115 Total Annualized Cost:$2,238,950 Ave Cost Effectiveness:$48,098/ton Ave Cost Effectiveness per deciview: $12,508,101/dv Semi-Dry Scrubbing 49.0 90% 44.1 Total Cap. Investment: $2,359,464 Total Annualized Cost:$675,978 Ave Cost Effectiveness:$15,328/ton Ave Cost Effectiveness per deciview: $3,907,387/dv Dry Scrubbing 49.0 50% 24.5 Total Cap. Investment: $0 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 SO 2 control cost effectiveness values, and the predic ted visibility at the nearest Class I area, it was determined that these are not viable BART options.

Fuel switching and process alterations were also evaluated, but were not found to be viable control options.

NO X : Emissions of NO X from cement kilns are generally related to thermal NO X , fuel
NO X , and raw feed material NO X . Dragon identified fuel switching, process optimization, flue gas recirculation (FGR), indirect fuel firing, staged ai r combustion/mid-kiln firing,
low NO X burners, selective Non-Catalytic Re duction (SNCR), and Selective Catalytic Reduction (SCR) as available NO

x control retrofit technologies.

Fuel switching was not consider ed technically feasible sinc e the nitrogen content of the fuel used in the kiln burning z one has little or no effect on NO X generation in a portland cement kiln. Flue gas recirculation was not considered technically feasible since the effectiveness of FGR relies on cooling the flame and generating a reducing combustion atmosphere to reduce thermal NO X emissions, which is not compatible with the high flame temperature and an oxidizing combusti on zone atmosphere in the kiln system required to produce quality clinker. SCR was not considered technically feasible since there are no full scale SCR systems (ammonia injection upstream of a catalyst bed) in operation at cement kilns in the United States due to various con cerns including exhaust temperature and plugging.

Process optimization is currently being used on the kiln system, with advanced computer controls and instrumentation to improve overa ll facility operation and fuel efficiency.5/27/2010
Draft For FLM Review

107 Indirect fuel firing is curren tly the kiln system’s method of operation, whereby pulverized solid fuel from a solid fuel mill is captured in a cyclone or fabric filter and is stored before being conveyed to the kiln. This separates the mill conveyance air from the fuel
and the fuel is introduced in a controlled manner from storage, reducing primary kiln
combustion air to less than 10% of the total combustion air (i n a direct-fired cement kiln, the primary combustion air can make up to 20% of the total combustion air). Staged air combustion/mid-kiln firing is currently being used in the kiln system to reduce kiln stratification and improve combustion of the fu el, which aids in re ducing emissions. Low
NO X burners are currently being used on the ki ln system. SNCR is currently being used on the kiln system, with ammonia injection at a location in the corr ect temperature range for proper reaction to reduce NO X emissions.

Dragon initially proposed the use of the existing NO X controls as they are currently operated as BART. However, the Departme nt requested additional information on the use of the SNCR technology at the facility relating to further NO X control. Dragon supplied possible operational changes to the existing SNCR cont rol unit including: increasing the operating time of the SNCR cont rol unit, relocating the reagent injection nozzles, changing the reagent us ed in the SNCR control unit, and increasing the injection rate of the SNCR control unit reagent. The un it 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 f easible, since the SNCR unit operates at the optimum injection point an d reagent type based on the original trial test. Increasing the injection rate is a feasible option.

Records show that from April 2005 through December 2008, the SNCR operated at an average control efficiency of approximately 22%, and in 2008, the efficiency was slightly
lower at 18%. Since the June 18, 2008 comments of the MACT standards for the Portland Cement amendments, EPA has stated th at that ‘for an SNCR (control unit) with optimal injection configuration a nd reagent injection rate, a 50% NO X emission reduction represents a reasonable level of perfor mance of SNCR over the long term,.” The Department requested that Dragon assess the operation of the SNCR at 50% efficiency. Dragon performed an operational change imp act analysis with the following results:

Control Technology Expected
NO X Emission

Rate (tons/yr) Emissions
Performance
Level Expected
NO X Emissions
Reductions

(tons/yr) Cost of Compliance

SNCR operating at
50% 1130.6 927.1 565.3 Total Cap. Investment: $0 Total Annualized Cost:$1,483,877 Ave Cost Effectiveness:$4101/ton Ave Cost Effectiveness per deciview: $7,419,385/dv

Dragon proposed no increased reagent reacti on rate due to additional cost, additional ammonia slip, and no perceptible change in vi sibility at the nearest class I area (Acadia5/27/2010
Draft For FLM Review

108 National Park). However, the Departme nt is setting a 45% removal efficiency requirement to further reduce NO X .

BART Determination

The Department determined BART for Dragon as follows:

BART Determination for Dragon Products Company
Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference

Kiln baghouse 9.3 lb/hr and
0.3 lb/ton dry kiln feed (Existing
Title V license; 40
CFR Part 63) N/A 70.00 lb/hr. on a 90-day rolling

average (Existing
Title V license) and
200 tons/year on
a 12-month rolling

average (BART order) SNCR
45% control efficiency
on a 24-hour
basis (BART order) 350.0 lb/hr on a 90-day rolling average and
1533.0 tons

per year on a 12-month rolling total
basis (Existing
Title V license)

3. FPL Energy Wyman, LLC.

FPLE Wyman is an 850-megawatt electric gene rating facility locat ed on Cousins Island in Yarmouth, Maine. The plant consists of four generation units, all of which fire #6
residual fuel oil. A fifth unit is a smaller oi l-fired auxiliary boiler which provides building heat and auxiliary steam and a sixth unit is an emergency backup diesel generator that provides electricity for use on-site. There ar e two BART eligible units at the facilityUnit 3 and Unit 4.

Boiler #3 is a Combustion Engineering boiler, installed in 1963, with a maximum design heat input capacity of 1190 MMBtu/hr firing #6 fuel oil (2 % sulfur). The boiler is equipped with multiple centrifugal cyclones for control of particulate matter and optimization and combustion controls for NO X . Boiler #4 is a Fost er Wheeler boiler, installed in 1975, with a maximum design he at input capacity of 6290 MMBtu/hr firing #2 or #6 fuel oil (0.7 % sulfur). The boiler is equipped with an elec trostatic precipitator for control of particulate matter and op timization and combustion controls for NO X .5/27/2010
Draft For FLM Review

109 BART Analysis Summary

PM : Emissions of PM from oil fired boilers are a function of fuel firing. 41 Both boilers #3 and #4 have high efficiency combustion systems in conjunction with PM control devices; boiler #3 having multiclones and boiler #4 having an ESP. The cost analysis of installing an ESP on boiler #3 resulted in pollutant removal cost effectiveness of $19,000/ton of PM removed and visibility improvement cost effectiveness of $143 million per deciview of visibility improvement. This was determined to be excessive and
not cost-effective.

SO 2: Emissions of SO 2 from oil fired boilers are related to the sulfur in the fuel. FPLE Wyman identified the following available re trofit control technol ogies for reducing SO 2 emissions from the oil fired boilers: low sulfur #2 fuel oil, reduced sulfur #6 fuel oil, and wet or dry scrubbers. Low sulfur #2 fuel oil (0.05% down to 0.0015%) and the use of reduced sulfur #6 fuel oil (1% or less) were c onsidered technically feasible options. Post combustion controls of wet or dry scrubbe rs on large boilers we re researched and generally only typically applie d to coal fired boilers. Th e use of scrubbing systems on oil fired boilers is considered cost prohibitiv e and was not considered as a BART option.

FPLE Wyman performed a cost analysis on lowe ring the sulfur conten t 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 follo wing (based on the differential fuel costs):

Boiler #3 Boiler #4

% sulfur Annual Costs % sulfur Annual Costs

1.0 $0.68 million

- - 0.7 $0.80 million

- - 0.5 $3.2 million 0.5 $9.2 million

0.3 $5.7 million 0.3 $18.3 million

The visibility cost effectiveness, incremen tal visibility improvement, and incremental visibility cost effectiveness fr om switching from 2% sulfur to reduced sulfur content fuel oil for boiler #3 was the following:

% Sulfur Ranked Visibility Impact Visibility Cost
Effectiveness ($/deciview) Incremental Visibility Improvement Incremental Visibility Cost
Effectiveness ($/deciview)

1.0 1 st

8 th $0.69 million $1.95 million -

- -

- 0.7 1 st

8 th $0.56 million $1.67 million 0.44 dv
0.13 dv $0.27 million $1.92 million

41 It is estimated from the MANE-VU August 2006 document Contributions to Regional Haze in the Northeast and Mid-Atlantic United States, Tools and Techniques for Apportioning Fine Particle/Visibility Impairment in MANE-VU (pages 3-2, 4-7, 4-8) that course particulate matter has typically less than 4% of the contribution to visibility impairment at the MANE-VU Class I areas.5/27/2010
Draft For FLM Review

110 0.5 1 st

8 th $1.82 million $5.41 million 0.35 dv
0.12 dv $6.97 million $20.3 million

0.3 1 st

8 th $2.64 million $8.12 million 0.37 dv
0.10 dv $6.59 million $24.4 million

The visibility cost effectiveness, incremen tal visibility improvement, and incremental visibility cost effectiveness from switching from 0.7% sulfur to reduced sulfur content fuel oil for boiler #4 was the following:

% Sulfur Ranked Visibility Impact Visibility Cost
Effectiveness ($/deciview) Incremental Visibility Improvement Incremental Visibility Cost
Effectiveness ($/deciview)

0.5 1 st

8 th $22.3 million $39.8 million -

- -

- 0.3 1 st

8 th $19.5 million $35.2 million 0.53 dv
0.29 dv $17.3 million $31.6 million

Based on the sulfur contributions in the Northeast and the information above, FPLE Wyman proposed 1% sulfur fuel oil for boiler #3 beginning in 2013, and the current
sulfur limit of 0.7% fo r boiler #4 as BART.

NO X: Emissions of NO X from oil fired boilers are from thermal and fuel NO X . In order
to minimize NO X emissions, FPLE Wyman installed combustion control technologies pursuant to 06-096 CMR 145, NO X Control Program Regulation . FPLE Wyman
installed combustion co ntrol technology upgrades including low NO X fuel atomizers, improved swirler design, and overfire and in terstage air ports. The burners were optimized and fuel/air flows were balanced to the burners on each unit. The combustion control technology upgrades were complete d in April 2003 and reductions of 29-35%
have been documented with boiler #3 and reductions of 24-47% have been documented with boiler #4 depending on each unit’s load. These reductions are equivalent to the use of SNCR (Selective Non-Catalytic Re duction) technology on the boilers.

The cost analysis of installing additional NO X controls of regenerati ve selective catalytic reduction (RSCR) on the boilers in addition to the current combustion controls resulted in a pollutant removal cost effectiv eness of $125,000/ton and $83,000/ton of NO X removed for boiler #3 and boiler #4, re spectively. This was determined to be excessive and not
cost effective.

BART Determination

The Department determined BA RT for FPLE Wyman as follows:5/27/2010
Draft For FLM Review

111 BART Determination for FPLE Wyman
Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference Control Type Emission Limit
and Reference

Boiler
#3 multiclones 0.15lb/MMBtu (BART order) Lowsulfur oil 1% sulfur by weight
oil (BART order) Combustion engineering 0.175 lb/MMBtu on a 90-day rolling average* (Existing Title V license; 06-096 CMR Chapter 145) Boiler
#4 ESP 0.1 lb/MMBtu (Existing Title V license; 40 CFR Part 60) Lowsulfur oil 0.7% sulfur by weight oil (Existing
Title V license, 40
CFR Part 60) Combustion engineering 0.170 lb/MMBtu on a 90-day rolling average*(Existing Title V license;
06-096 CMR Chapter 145)

Alternatively, the NO

x limit from boilers #3 and #4 averaged shall be limited to 0.165 lbs/MMBtu on a 90— day operating rolling average

4. Lincoln Paper and Tissue, LLC

Lincoln Paper & Tissue (LPT) is an integrat ed 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 a nd 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 m achines 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. Emi ssions 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. Norma lly, oil is used only during start-ups,
shutdowns and to stabili ze operation of the boiler.

The Recovery Boiler is exhausted to a wet bottom electrostatic precipitator (ESP) to control particulate emissions. This unit also serves to re-introduce salt cake into the black liquor which further con centrates the solids content.

BART Analysis Summary

The LPT BART analysis evaluated the best system of continuous emissions control technology available for each of the visibility-impairing pollutants (SO 2 , PM, and NO

x ). LPT’s BART analysis submittal demonstrated that additional emission controls are neither feasible nor necessary for Recovery Boiler #2. PM emissions are controlled with5/27/2010
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112 the ESP to levels meeting compliance with MACT standards and therefore meet BART.
SO 2 emissions are controlled by proper operation of the recovery boiler, including a three-level staged combustion air control system, and limitations on fuel oil use and
sulfur content. NO

x emissions are minimized through staged combustion (having independently operating primary, secondary, a nd tertiary air dampers) and by the low nitrogen content of black liquor solids along with proper operation of the Recovery Boiler. Existing SO 2 and NO

x controls on the #2 Recovery Boiler were determined by the Department and EPA to meet BACT in th e PSD/NSR licensing of the facility. As no new control technologies are available for fu rther control of thes e pollutants from a recovery boiler the BACT determination cons titutes BART compliance. Maine did not require additional visibility impact modeling because of the limite d visibility impacts
from this source. 42

BART Determination

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

BART Determination for Lincoln Paper and Tissue
Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference Control Type Emission
Limit and
Reference

Recovery
Boiler ESP 0.044 grains per dry
standard
cubic foot (0.044 gr/dscf) (Existing
Title v license; 40
CFR Part 63) Low-sulfur
oil 141 ppmv (dry basis) @8% O 2 on a 24-hour
block

average basis (Existing
Title v license) Combustion engineering 233 ppmv (dry basis) @ 8% O 2 on a 24-hour
block

average basis (Existing
Title v license)

5. SD Warren Company, Somerset

SD Warren Company (SDW) is an integrated kraft pulp and paper mill. Whole logs, chips, and biomass, are delivered to the mill by truck and/or train. The logs are sawn, debarked, chipped and stored in the mill’s w oodyard. The biomass is stored in piles and then conveyed to the boilers. The chips are st ored in piles and then conveyed to the chip bin, chip steaming vessel, and then the di gester. 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 proces s for reclamation of the pulping chemicals.
There are two multi-fuel boilers and an oil fired package boiler to supply the mill with steam. SDW has three paper machines which produce paper. There are also two pulp machines. One pulp machine has a steam operated dryer and both machines produce

42 Modeled visibility impacts attributable to Recovery Boiler #2 as 0.0073 deciviews (dv) for SO2, 0.0882 dv for NOx, 0.0322 dv for PM, and 0.12 dv total impacts.5/27/2010
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113 bailed pulp. The mill also operates suppor t facilities, includ ing the wood yard, wastewater treatment plant, sludge pr esses, pulp and paper production labs, environmental labs, roll wr apping, shipping and receiving operations, and a landfill.

There are four emissions units that were determ ined to be BART eligible at this facility; the Recovery Boiler, Smelt Tanks #1 and #2, and the Lime Kiln. The Recovery Boiler
was installed in 1975-1976. It is used to recover chemicals from spent pulping liquors and to produce steam for mill operations. The R ecovery Boiler is licensed to fire black liquor (spent pulping liquor), residua l (#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 ma ximum black liquor firing rate will become 5.5 million pounds per day of BLS after the boiler upgrade project is completed (scheduled for October 2010). The Recovery Boiler is subject to MACT standards for Chemical Recovery Combustion Sources at Kraft Soda, Sulfite, and Stand-Alone Semichemical Pulp Mills (40 CFR 63, Subpart MM).

SDW operates two smelt tanks which were installed in 1975-1976. The Smelt Tanks operate in conjunction with the Recovery Boiler. Recovered sodium-based pulping chemicals, in the form of molten salts, are discharged from the bottom of the Recovery Boiler into the Smelt Tanks, where they are mi xed 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 li me mud (principally calcium carbonate) to lime (calcium oxide). Fuel is fired in the Lime Kiln to generate the
heat that is needed to convert lime mud to lime. The Lime Kiln is licensed to fire residual (#6) fuel oil, distillate (#2) fuel oil, used oil, and pr opane. The Lime Kiln is also licensed to combust LVHC gases a nd 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 followi ng available retrofit te chnologies for control
of PM from Kraft mill recove ry boilers: electrostatic pr ecipitators, wet scrubbers, and
fabric filters. Wet scrubbers were eliminat ed as a feasible control strategy because the ESP currently installed is capable of a great er degree of emissions control at a lower operating cost. Fabric filters ar e generally considered to be e quivalent 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 st ringent 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.5/27/2010
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114 SO 2 : SDW’s Recovery Boiler is currently equipp ed with a three-level staged combustion air control system and, after the upgrade pr oject, will be equipped with a four-level staged combustion air system. SDW identi fied staged combustion systems and wet
scrubbers as available retrofit technologies for control of SO 2 from Kraft mill recovery
boilers. SO 2 emissions from recovery boilers occur due to the volatilization and subsequent oxidation of sulfur compounds that are present in the black liquor. Proper operation of the recovery boiler maximizes the conversion of sulfur compounds in the liquor to the principal constituents of the pul ping chemicals. This occurs through capture of these sulfur compounds in the combustion zone of the boiler by sodium fume released from the smelt bed. Consequently, proper combustion control achieved through the use of staged combustion air systems re sults in effective control of SO 2 emissions. The only
available alternative for SO 2 emission control is a wet sc rubber. However, recovery boilers with a properly operated staged ai r combustion system operate at much lower
concentrations of SO 2 in the flue gas than emission units to which wet scrubbers are routinely applied. Since the controls alrea dy 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 re maining steps of the control analysis.

NO
x : SDW’s Recovery Boiler is cu rrently equipped with a three-level staged combustion air control system and is in the process of upgrading with a four-level staged combustion air system. SDW identified the following av ailable retrofit technol ogies for control of
NO
x from Kraft mill recovery boilers: staged combustion systems, Selective NonCatalytic Reduction (SNCR), Selectiv e Catalytic Reduction (SCR), Low NO

x Burners, Flue Gas Recirculation, and Lo w-Temperature Oxidation. Emission controls which have
been demonstrated on conventional steam boilers, including SNCR, SCR, flue gas recirculation, and low NO

x 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 pur e oxygen is injected into the evaporation process to drive ammonia from the black liquor. However, the company currently looking into this technology has advised SDW th at they are not aware of any commercial size case where this technology has been used. Therefore, this technology is not considered technically-feasible. There are no technically-feasible alte rnatives for control
of NO

x emissions from recovery boilers other than proper operation of the boiler and the staged combustion control system. Since the c ontrols already in plac e are considered the most stringent available, and these cont rols are already re quired by a federally enforceable condition, SDW was not required to perform the remaining steps of the control analysis.

Smelt Tanks

PM: SDW currently operates a wetted fan scrubber on each of the smelt tanks for control of particulate emissions. The scrubbing media for the scrubbers is ei ther water or weak wash from the white liquor clarification system. SDW identified the following available retrofit technologies for contro l of PM from smelt tanks: electrostatic precipitators, wet scrubbers, fabric filters, and mist eliminat ors. The most common PM emission control system employed on smelt tanks is wet scrubber s. The use of wet scrubbers also provides5/27/2010
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115 a secondary environmental benefit by cont rolling reduced sulfur compound emissions. The high moisture content of the smelt tank exhaust gases makes dry PM control systems, including fabric filters and dry ESPs, technically infeasible on this type of emission unit. The only remaining control t echnology, mist eliminators, provide a lower degree of PM emission control than the use of wet scrubbers. Since the controls already in place are considered the most stringent available, and these controls are already required by a federally enforceable conditi on, SDW was not required to perform the remaining steps of th e control analysis.

SO 2 : Since no combustion takes pl ace within smelt tanks, SO 2 is not generated within the emission unit. SDW was not able to identify any retrofit control technologies applicable
to the control of SO 2 emissions from smelt tanks.

NO
x : Since no combustion takes pl ace within smelt tanks, NO

x is not generated within
the emission unit. SDW was not able to identify any retrofit control technologies applicable to the control of NO

x emissions from smelt tanks.

Lime Kiln

PM: Particulate emissions from the Lime Kiln are currently controlled by a variable throat venturi scrubber system followed by a cyclone separator. SDW identified the following available retrofit technologies for control of PM from lime kilns: electrostatic precipitators, wet scrubbers, and fabric filters. Fabric filter s have never been applied to kraft pulp mill lime kilns. They are generally deemed to be technically infeasible on lime kilns. ESPs provide a greater degree of particulate matter co ntrol than venturi scrubbers. However, the possible annual reduction in emissions to be gained by replacing the existing scrubber with an ESP is relatively small (estimated at under 40 ton/year). Additionally, the scrubber also helps control emissions of SO 2 and reduced sulfur compounds. This beneficial removal of othe r pollutants is not available to lime kilns equipped with ESPs. Consequently, replacem ent of the existing scrubber with an ESP would be expected to result in higher TRS and SO 2 emissions from the Lime Kiln. With respect to any possible improvement in visibil ity impacts associated with retrofitting an ESP on the Lime Kiln, the modeling result for current PM emissions from the Lime Kiln was 0.0463 dv; well below the State’s de minimis level of 0.1 dv. Therefore, any
additional emission reductions th at might be achieved by retrof itting the Lime Kiln with an ESP could only result in visibility imp acts that would similarly be de minimis.

SO 2 : SO 2 forms in the Lime Kiln from either th e combustion of sulfur in the fuel or combustion of TRS compounds in the LVHC gases. Currently emissions of SO 2 are controlled by using a combination of the inherent sulfur removal provided by operation of the kiln itself (i.e. extensive contact be tween burner exhaust gases and the calcium compounds in the kiln) enha nced through the use of a venturi wet scrubber (postcombustion). SDW also uses a caustic sc rubber (pre-combustion) on the LVHC gases fired in the boiler. Firing of LVHC gases in the Lime Kiln without pre-treatment with the
caustic scrubber causes formati on of rings within the Lime Kiln leading to excessive down-time of the equipment. Emissions of SO 2 from the Lime Kiln can vary significantly based on the amount of LVHC gases being fire d and whether or not the5/27/2010
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116 caustic scrubber is in operation. SDW identified th e following available retrofit technologies for control of SO 2 from lime kilns: lime kiln operation and wet scrubbers. Since the controls already in place are considered the most stringent available, and these controls are already re quired by a federally enforceable condition, SDW was not required to perform the remaining step s of the control analysis.

NO
x : NO
x emissions from the Lime Kiln are currently controlled by good combustion controls and operation of the unit’s combusti on air system. SDW identified the following
available retrofit technol ogies for control of NO

x from lime kilns: Combustion Air Systems controls, SNCR, SCR, Low NO

x Burners, Flue Gas Recirculation. There are no technically feasible alternatives for control of NO

x from lime kilns beyond the measures currently employed. Low NO

x burner systems, which seek to reduce thermal NO

x formation through either combustion air or fuel staging, are not possible on the lime kilns because such systems negatively impact the efficiency, energy use, and calcining capacity of a lime kiln. Post combustion controls, such as SCR and SNCR, are not feasible for lime kilns. The temperatur e window necessary for the SNCR process (1500

– 2000  F) is unavailable in a Kraft lime kiln. The high PM load at the exit of the kiln precludes the placement of the catalyst grid needed for the SCR process upstream of the PM control device, and the requisite temper ature window required fo r this process (550 –

750  F) is not available downstream of the PM control system. Since the controls already in place are considered the most stringent available, and these controls are already required by a federally enforceable conditi on, SDW was not required to perform the remaining steps of th e control analysis.

BART Determination

BART Determination for SD Warren

Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission Limit
and Reference Control Type Emission
Limit and
Reference

Recovery
Boiler ESP 0.030 gr/dry
standard
cubic foot (dscf) when
all three ESP
chambers are
online and 0.038 gr/dscf
when less
than three
chambers are online; 207 lb/hr (NSR
License #A19-77-2-A,
40 CFR Part 63, subpart MM) Low-sulfur
oil 100 ppmv (dry basis) @8% O 2 on a 24-hour block average basis (BART order)

1975lbs/hr (NSR License #A-19-77-2-A) Combustion engineering 120 ppmv (dry basis) @ 8% O 2 on a 24-hour
block

average basis; 750 lb/hr (NSR
License #A19-77-2-A)5/27/2010
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117 Smelt
Tanks #1
and #2 Wet scrubber 26lb/hr; 0.2
lbs/ton BLS
40 CFR Part 63, subpart

MM (Existing
Title V license) N/A 26lb/hr (Existing Title V license) N/A N/A

Lime Kiln Wet scrubber 0.10 gr/dscf @10% O 2 ; 58 lb/hr (Existing
Title V license; 40 CFR Part 63) Wet scrubber 1.92 lb/MMBtu; 100 tons/year limit
on a 12-month rolling average (Existing Title V license) Staged
Combustion 120 ppmvw @ @10% O 2 (Existing
Title V license)

6. Verso Androscoggin

The Verso Androscoggin pulp mill produces bleached Kraft pulp and groundwood pulp. The bleached pulp is produced in two separa te process lines, designated “A” and “B”. Groundwood pulp is produced in another separate process line. Logs and wood chips are received in the Woodyard area, where they ar e stored and processed for eventual use in the Pulp Mill or Groundwood Mill. The Pulp Mill consists of two separate, parallel Kraft chemical pulping process lines. Pulp pr oduced at the Verso Jay Mill is either used in the paper mill area or dried in the Fl ash Dryer for storage and/or sale.

The Paper Mill consists of all the equipment a nd operations used to convert pulp to paper, including stock preparation, additive prepara tion, 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-concentratio n (HVLC) emission streams from certain
other units are collected and sent to the Re generative Thermal Oxidizer where they are incinerated. The Mill produces steam and electric power for mill operations with Power
Boilers #1 and #2 and the Waste Fuel Incinerator (WFI).

There are ten BART-eligible units at Verso Jay: (1) Power Boiler #1; (2) Power Boiler #2; (3) Waste Fuel Incinerator; (4) Recovery Boilers # 1; (5) Recovery Boiler #2; (6) Smelt Tank #1; (7) Smelt Tank #2; (8) Lime Kiln A; (9) Lime Kiln B; and (10) Flash Dryer. Power Boilers #1 and #2 are each rated at 680 MMBtu/hr and began operation in 1965 and 1967, respectively. Power Boilers #1 and #2 are licensed to fire #6 fuel oil, #2 fuel oil, and used oil. The lic ense currently limits the sulfur content of the fuel oil to no more than 1.8%, by weight. In additi on, each boiler is equipped with low NO

x 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 opera ting. Typically when the cogeneration plant is operat ing, Power Boilers #1 and #2 do not operate. When the cogeneration plant is not ope rating, both boilers are operate d, however, one boiler will typically carry the bulk of the load and the other boiler is idled or run at low load. There5/27/2010
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118 are occasions when both boilers operate at hi gh 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 SO 2 emission limit. In addition, the WFI is equipped with a combusti on system designed to ensure the optimal
balance between control of NO

x and limitation of CO and VOC.

Recovery Boilers #1 and #2 generate steam while regenerating chemicals used in the wood pulping process, and began operation in 1965 and 1976, respectively. Recovery Boilers (#1 and #2) have rated processi ng capacities of 2.50 and 3.44 million pounds per day of dry black liquor solids (MMlb/day of BLS), respectively. Inorganic material (smelt) from the bottoms of the recovery boile rs is used to produ ce green liquor, which is a solution of sodium sulfide and sodium carbonate salts, when it is dissolved in water or weak wash in the Smelt Dissolving Tanks (#1 and #2). Although the recovery boilers primarily fire black liquor, they also fire small quantities of #2 a nd #6 fuel oils during startup, shutdown, and load stabilization cond itions. The license currently limits the
sulfur content of the fuel oils to no more than 0.5%, by weight. Particulate matter emissions from both recovery boilers are cu rrently controlled using an electrostatic precipitator (ESP).

Smelt Dissolving Tank #1 is rated at 2.50 MMl b/day of dry BLS and began operation in 1965. Smelt Dissolving Tank #2 is rated at 3.44 MMlb/day of dry BLS and began operation in 1975. Inorganic materials from th e recovery boiler floors drain into Smelt Dissolving Tanks #1 and #2 as molten smelt. In the smelt dissolving tanks, the smelt is mixed with weak wash to form green liquor which is pumped to the causticizing area. Sulfur dioxide (SO 2 ) and particulate matter (PM 10 ) emissions from Smelt Dissolving
Tank #1 are controlled with a dual-nozzle we t cyclonic scrubber which utilizes an alkaline scrubbing solution and was inst alled in 1983. Sulfur dioxide (SO 2 ) and particulate matter (PM 10 ) emissions from Smelt Dissolvi ng Tank #2 are controlled with a triple-nozzle wet cyclonic scrubber which ut ilizes an alkaline scrubbing solution and was
installed in 1976.

The “A” and “B” Lime Kilns process lime mud (calcium car bonate) from the causticizing area to regenerate calcium oxide (CaO). Inside the lime kilns, the lime mud is dried and heated to a high temperature where the lime mud is converted to lime (calcium oxide or CaO). “A” and “B” Lime Kilns are each rated at an operating rate of 248 tons of calcium oxide (CaO) per day and a heat input of 72 MMBtu/hr and bega n 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 lim its the sulfur content of the fuel oil to no more than 1.8%, by weight. The A and B Lime Kilns also serve as an incineration device(control device) for select sources of low volume high concentration (LVHC) noncondensable gases (NCG) from pulping operati ons at the mill. Particulate matter (PM 10 )5/27/2010
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119 emissions are controlled from the “A” and “B ” Lime Kilns using a fixed throat venturi
scrubber.

The Flash Dryer is used to dry pulp for resa le or for storage and future use on one of Verso Androscoggin’s paper machines. The Fl ash Dryer has a rated heat input capacity of 84 MMBtu/hr and began operation in 1964. The flash dryer is licensed to fire #2 fuel oil, which contains a maximum sulfur content of 0.5% as defined by ASTM D396
standards. Particulate matter emissions ar e controlled using a wet shower system and
SO 2 emissions are limited through the firing of #2 fuel oil.

BART Analysis Summary

Power Boilers #1 and #2:

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

PM 10 emissions from Power Boilers #1 and #2 b ecause these units are subject to MACT
Standards under section 112 of the CAA. In addition, Verso stated in their application
that PM 10 emissions are low based on the firing of fuel oil and that PM 10 emissions from Power Boilers #1 and #2 have a minimal imp act on visibility and a reduction in these emissions would have no impact on the contribu tion of either boiler to overall visibility impacts. Verso Androscoggin proposed that the final “Boiler MACT” standards (40 CFR Part 63, Subpart DDDDD) that the boilers are subject to will also represent BART for
Power Boilers #1 and #2.

SO 2: Verso Androscoggin identifie d and evaluated low sulfur fuels, wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in the reduction of
SO 2 emissions from Power Boilers #1 and #2. Low sulfur fuels and wet scrubbing control technologies were found to be technica lly feasible by Verso Androscoggin and so
were evaluated further. 43 A summary of Verso Andr oscoggin’s evaluation of the remaining viable SO 2 control technologies (low sulfur fuels and wet scrubbing) is provided in the table below.

SO 2 BART Analysis Summary for Power Boilers #1 and #2

43 Dry and semi-dry scrubbing control technologies were evaluated, however Verso Androscoggin found that control effectiveness levels would be low (<25%), downstream particulate matter control devices such
as an ESP and/or fabric filter would need to be insta lled to collect and re-circulate the scrubbing material, and no applications of these techno logies on fuel oil fired boilers like Power Boilers #1 and #2 were identified during Verso Androscoggin’s research of potential control technologies.

Control Technology Control
Effectiveness Cost
Effectiveness ($/ton removed) Energy and Other Impacts Greatest Visibility Improvement

Natural
Gas 99% $3,334 Negligible 1.5

#2 Fuel Oil 97% $3,341 Negligible 1.5
0.7% 60% $631 Negligible 0.95/27/2010
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Sulfur #6
Fuel Oil
0.7%
Sulfur #6
Fuel Oil 60% $631 Negligible 0.9

Wet Scrubbing 99% $2,278 Disposal Impacts 1.5

The cost effectiv eness numbers in th e table above are ba sed on controlling SO 2 emissions
from Power Boilers #1 and #2 at the control effectiveness rates indicated in the table from the highest estimated two year aver age annual emissions between 2002 and 2008. In recent years (2008 and 2009) these boilers have been operating close to only 20% of the time, which for example, would result in an actual cost effectiveness of between $4,920 and $7,133 per ton of SO 2 removed with the installation of a wet scrubber. The
use of low sulfur fuels or a wet scrubber ha s the potential to reduce visibility impacts from Power Boilers #1 and #2 by a perceptible amount; however there are significant cost differences among the three low sulfur containing fuels evaluated by Verso Androscoggin and the wet scrubber. Based on Verso Androscoggin’ s identification and evaluation of control technology options, they propose that the use of 0.7% sulfur #6 fuel oil is a feasible and justifia ble cost at $631 per ton of SO 2 reduced, but that the other low sulfur fuel options and the wet scrubbing option are not economically justifiable and do not represent BART. Therefore, Verso A ndroscoggin proposes that the use of lower sulfur (0.7%) #6 fuel oil in pl ace of the higher sulfur (1.8 %) #6 fuel oil currently fired, represents BART for control of SO 2 emissions from Power Boilers #1 and #2.

NO
x : Verso Androscoggin identified and evalua ted selective cataly tic reduction (SCR),
low NO

x burners (LNBs), selective non-catal ytic reduction (SNCR), and combustion control methods (including an overfire air (OFA) system and a flue gas recirculation (FGR) system) as potential control te chnologies in the reduction of NO

x emissions from
Power Boilers #1 and #2. SCR and SNCR c ontrol technologies were found to be technically feasible and so were evaluated furt her. LNBs are current ly installed and used on Power Boilers #1 and #2, and are estima ted to provide a 15% reduction in NO

x emissions, so were not evaluated further. Combustion control methods were evaluated, however none were found to be viable control options for Power Boilers #1 and #2. Verso Androscoggin found that the size and design of Power Boilers #1 and #2 would provide little room for the instal lation of an overfire air system and that the application of a flue gas recirculation system would resu lt in minimal reductions (7% to 15%) in NO

x emissions. A summary of Ve rso Androscoggin’s evaluation of the remaining viable NO

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

Control Technology Control
Effectiveness Cost
Effectiveness ($/ton removed) Energy and Other Impacts Greatest Visibility Improvement
SCR 90% $5,271 Minor Impacts 1.7
SNCR 35% $5,973 Minor Impacts 1.4

1205/27/2010
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121 The cost effectiveness numbers in th e table above are ba sed on controlling NO

x emissions from Power Boilers #1 and #2 at the control effectiveness rates indicated in the table from the highest estimated two year average annual emissions between 2002 and 2008. In recent years (2008 and 2009) these bo ilers have been ope rating close to only 20% of the time, which for example, would re sult in an actual cost effectiveness of $16,313 per ton of NO

x removed with the installation of SCR. Although the use of SCR or SNCR has the potential to reduce visibi lity impacts by a perceptible amount, Verso Androscoggin proposes that the cost effectiven ess levels are not ec onomically justifiable
based on the limited use of Power Boilers #1 and #2. Based on Verso Androscoggin’s
identification and evaluation of control techno logy options, they propose that the current use of LNBs represents BART for control of NO

x emissions from Power Boilers #1 and
#2 and that no additional level of control is justifiable as BART.

Waste Fuel Incinerator Boiler:

PM: Verso Androscoggin did not id entify or evaluate potentia l control technologies for
the reduction of PM 10 emissions from the Waste Fuel Incinerator Boiler (WFI) because this unit is subject to MACT Standard s under section 112 of the CAA. Verso Androscoggin proposed that the final “B oiler MACT” standards (40 CFR Part 63, Subpart DDDDD) that the WFI is subject to will also represent BART for the WFI.

SO 2 : Verso Androscoggin identifie d and evaluated low sulfur fuels, wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in the reduction of
SO 2 emissions from the WFI. While using low sulfur fuels is technically feasible, Verso Androscoggin believes that it is not a practic ally feasible option fo r the WFI based on the limited amount of fuel oil typically used in th e boiler (less than 10% of the annual fuel oil heat input capacity). The WF I currently uses a water based wet scrubbing system for PM
control with the addition of caustic to meet SO 2 emission limits when firing #6 fuel oil in significant amounts. Dry and semi-dry scrubbing control technologies were not considered by Verso Androscoggi n to be either pract ical or technically feasible for the WFI due to the fact that they could not find any applications of th ese technologies on any other biomass-fired grate type boilers like the WFI. Verso Androscoggin also believes that the cost of removing the existing wet scr ubber and replacing it with a dry or semi-dry scrubbing system and a new ESP and/or fabric filter would be costly. A summary of Verso Androscoggin’s evaluation of the only remaining viable SO 2 control technology (adding caustic to the existing wet scrubbing system) is provided in the table below.

SO 2 BART Analysis Summary for the Waste Fuel Incinerator
Control Technology Control
Effectiveness Cost
Effectiveness ($/ton removed) Energy and Other Impacts Greatest Visibility Improvement
Addition of
Caustic to Existing Wet
Scrubber 50% $21,800 Disposal Impacts <0.15/27/2010
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122 The WFI has very low baseline SO 2 emissions (~50 tons per yea r) due to the inherent low sulfur content and alkalinity of the primary fuel (biomass) and the small amount of fuel oil used in the WFI. In addition, during the limited amount of time that #6 fuel oil is used to provide a significant portion of the heat input to the WFI, caustic is added to the wet
scrubber to control SO 2 emissions. Based on Verso A ndroscoggin’s iden tification and evaluation of control technology options, they propose that additional control of SO 2 emissions from the WFI cannot be justified as BART due to the imperceptible effect it would have on visibility.

NO
x : Verso Androscoggin identifie d and evaluated selective catalytic reduction (SCR),
low NO

x burners (LNB), selective non-catal ytic reduction (SNCR), and combustion control methods (including an overfire air system and a flue gas recirculation system) as potential control technologi es in the reduction of NO

x emissions from the WFI. SCR and SNCR control technologies were found to be technically feasible a nd so were evaluated further. Since the WFI primarily fires bioma ss on the grate, LNBs would not be effective for the majority of the time that the WFI operates, thus Verso Androscoggin felt LNBs
did not warrant further ev aluation. Combustion contro l methods were evaluated,
however none were found to be viable contro l options for the WFI due to the limited NO

x removal potential (<15%), potenti al impacts to other pollutant s and boiler equipment, and
the limited amount of room available for th e installation of control equipment. A summary of Verso Androscoggin’s eval uation of technically feasible NO

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

Control Technology Control
Effectiveness Cost
Effectiveness ($/ton removed) Energy and Other Impacts Greatest Visibility Improvement
SCR 90% $4,676 Minor Impacts 0.3
SNCR 30% $5,944 Minor Impacts 0.1
FGR 15% $17,010 Minor Energy Impacts <0.1

Although the use of SCR has the potential to reduce visibili ty impacts by a perceptible amount, Verso Androscoggin proposes that th e cost effectiveness levels are not economically justifiable for any of the cont rol technologies evalua ted, including SCR. Based on Verso Androscoggin’s identifica tion and evaluation of control technology options, they propose that additional control of NO

x emissions from the WFI cannot be justified as BART due to the capital costs ( $3 million to more than $7.6 million) and cost effectiveness levels ($4,700 to more than $17,000 per ton of NO

x removed).

Recovery Boilers #1 and #2

PM: Particulate matter (PM) emissions from Recovery Boilers #1 and #2 are currently controlled by an existing shared/common electrostatic precipitator (ESP). Verso Androscoggin did not identify or evaluate po tential control technologies for the reduction
of PM 10 emissions from Recovery Boilers #1 and #2 because these units are subject to
MACT Standards under section 112 of the C AA. Recovery Boilers #1 and #2 are5/27/2010
Draft For FLM Review

123 subject to MACT standards pursuant to 40 CFR Part 63, Subpart MM (MACT II). Verso Androscoggin reviewed the RACT/BACT/LA ER Clearinghouse (RBLC) and believes that the current control configuration is th e most current control technology in use on recovery boilers and that there are no new technologies subsequent to the MACT
standard that should be c onsidered. Based on this information, Verso Androscoggin proposed in its BART analysis that it was not necessary to expand the BART analysis for

PM 10 and therefore did not identify or evalua te potential control technologies for the
additional reduction of PM 10 emissions from Recovery Boilers #1 and #2. Verso Androscoggin proposes that “MACT II” sta ndards (40 CFR Part 63, Subpart MM) that the boilers are currently subj ect to represent BART for PM 10 emissions from Recovery
Boilers #1 and #2.

SO 2 : Verso Androscoggin has found that sulfur dioxide (SO 2 ) emissions from Recovery
Boilers #1 and #2 are variable due to several factors includi ng black liquor properties (e.g., sulfidity, sulfur to sodi um ratio, heat value, and so lids 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 operati ng scenario for the recovery
boilers. SO 2 emission levels during fuel oil firing conditions are directly related to the
sulfur content of the fuel oils. Black li quor solids (BLS) firing produces sodium fume, which effectively scrubs SO 2 emissions. Verso Androsc oggin identified and evaluated wet scrubbing, dry scrubbing, and semi-dry scrubbing as potential control technologies in
the reduction of SO 2 emissions from Recovery Boilers #1 and #2, however none of these technologies were found to have been a pplied to recovery boilers and Verso Androscoggin believes that operation of thes e technologies could negatively affect the operation of Recovery Boilers #1 and #2. Ba sed on Verso Androscoggin’s identification and evaluation of control technology options, they propose that each of the control technologies evaluated are not technically f easible and therefore were not evaluated further. Verso Androscoggin proposes that existing combustion cont rols represent BART
for the control of SO 2 emissions from Recovery Boilers #1 and #2.

NO
x : Kraft recovery boilers are a unique type of combusti on source that inherently produce low levels of NO

x emissions. Most of the NO

x emissions produced by recovery
boilers can be attributed to fuel based NO

x resulting from the pa rtial oxidation of the nitrogen contained in the black liquor. Both Recovery Boilers (#1 a nd #2) operate with a reducing zone in the lower part of the boiler and an oxidizi ng zone in the region of the liquor spray guns designed to provide secondary a nd tertiary staged combustion zones to complete combustion of the black liquor and minimize NO

x emissions.

Verso Androscoggin identified and evaluated selective catalytic reduction (SCR), low
NO
x burners (LNB), selective non-catalytic reduction (SN CR), and combustion control methods (including the addition of a fourth le vel or quaternary air system and a flue gas recirculation system) as potential cont rol technologies in the reduction of NO

x emissions from Recovery Boilers #1 and #2. SCR ha s not been applied or demonstrated successfully on any recovery boilers according to Verso Androscoggin and they do not know how the unique characterist ics of recovery boiler exha ust gas constituents would5/27/2010
Draft For FLM Review

124 react with a SCR catalyst, so they did not fu rther evaluate this c ontrol technology. Verso Androscoggin’s evaluation of LNB technology is that it is not feasible to use this technology in the firing of black liquor gi ven its tar-like quali ties 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 r ecovery boilers. Verso Androscoggin’s evaluation of SNCR control t echnologies resulted in a finding that there have been no applications of this technology on recovery boilers in the United States for a variety of reasons, including safety concerns associated with the risk of a smelt/water explosion should boiler tube walls corrode and leak near urea injec tion points and risks associated with an ammonia handling syst em for the SNCR. Operational concerns
associated with SNCR were found to include th e potential formation of acidic sulfates that could result in corrosion and a catastrophi c boiler tube failure. As a result of Verso Androscoggin’s initial evaluation of SN CR, no further evaluation was conducted. Recovery Boilers #1 and #2 ar e currently designed and ope rated using low excess air
combined with three levels of staged combustion to minimize NO

x emissions. Additional
combustion control methods were evaluate d by Verso Androscoggin, however none were found to be viable control options for Rec overy Boilers #1 and #2 due to the limited amount of space in the boilers to install a fourth or quaternary air system and due to the technical challenges re-circula ting recovery boiler exhaust gases in a FGR system due to the unique characteristics of the exhaust gases. Based on Verso Androscoggin’s
identification and evaluation of control t echnology options, they proposed that the existing combustion control methods represen t BART and that additional control of NO

x emissions from Recovery Boilers #1 and #2 ar e not technically feas ible and warrant no
further evaluation.

Smelt Tanks #1 and #2

PM: Particulate matter (PM) emissions from Smelt Dissolving Tanks #1 and #2 are currently controlled by existing wet cycloni c scrubbers. Verso Androscoggin did not identify or evaluate other potential cont rol technologies for the reduction of PM 10 emissions from Smelt Dissolving Tanks #1 a nd #2 because these units are subject to
MACT Standards under section 112 of the C AA. 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/LA ER Clearinghouse (RBLC) and believes that the current control configuration is th e most current control technology in use on smelt dissolving tanks and that there are no new technologies subse quent to the MACT
standard that should be c onsidered. Verso Androscoggi n proposes that “MACT II” standards (40 CFR Part 63, Subpart MM) that the smelt dissolving tanks are currently subject to represent BART for PM 10 emissions from Smelt Dissolving Tanks #1 and #2.

SO 2 : Verso Androscoggin has f ound that sulfur dioxide (SO 2 ) emissions from Smelt Dissolving Tanks #1 and #2 are dependent on ho w much sulfur carries over from the respective recovery boilers with the smelt. Controlled smelt-water explosions in the smelt dissolving tanks can create SO 2 as a result of the oxidation of the sulfur in the
smelt. SO 2 emissions from both smelt dissolvin g tanks combined are very low at approximately 5 tons per year. Verso Androscoggin proposes that BART for SO 2 emissions from Smelt Dissolving Tanks #1 and #2 is no additional control based on the5/27/2010
Draft For FLM Review

125 following: (1) SO 2 emissions from the smelt dissol ving tanks during the BART baseline period were and are expected to continue to be extremely low (~5 TPY, combined); (2) the smelt dissolving tanks and associated scrubbers are designed and operated to
minimize SO 2 emissions; (3) SO 2 emissions from the smelt dissolving tanks have a minimal impact on visibility (<0.1 deciviews); and (4)additi onal control of SO 2 emissions from the smelt dissolving tanks would have a minimal impact on overall visibility.

NO
x : Smelt Tanks #1 and #2 do not emit NO

x .

Lime Kilns A and B

PM: Particulate matter (PM 10 ) emissions from the “A” and “B” Lime Kilns consist primarily of dust entrained from the combustion section of the kilns. This dust consists of sodium salts, calcium car bonate, and calcium oxide. PM 10 emissions are currently controlled by existing venturi scrubbers. Thes e units are also subject to MACT Standards under section 112 of the CAA, and 40 CF R Part 63, Subpart MM (MACT II). Verso Androscoggin reviewed the RACT/BACT/LA ER Clearinghouse (RBLC) and believes that there are two control technologies that represent the most stringent PM control (ESPs and venturi scrubbers). Both ESPs and ventur i scrubbers have been used to control PM emissions from lime kilns and both are capab le of a high level of control. Verso Androscoggin proposes that use of the ex isting venturi scrubbers to control PM 10 emissions from the “A” and “B” represents BART for the following reasons: (1) the existing venturi scrubbers maintain complia nce with the MACT II PM emission limits; (2) the replacement of the ex isting venturi scrubbers withdry ESPs could increase SO 2 emissions from the lime kilns when compared to use of the ventur i scrubbers; (3) the replacement of the existing venturi scrubbers with wet ESPs would result in high capital costs ($1.5 million per kiln); and (4)visibility impacts from the lime kilns are minimal
and installation of additional control would result in inconsequential improvement in visibility.

SO 2 : Verso Androscoggin has found that a signifi cant portion of the sulfur dioxide (SO 2 ) formed during the combustion process in the lime kilns is removed as the regenerated quicklime in the kilns functions as a scr ubbing agent. In addition, the NCG collection system is equipped with a scrubber that us es white liquor (sodium hydroxide or NaOH)
and thus the sulfur loading from the NCGs is minimized. SO 2 emissions from both lime kilns combined are very low at less than 4 tons per year primarily due to the alkalinity of the lime. Verso Androscoggin proposes that BART for SO 2 emissions from the “A” and “B” Lime Kilns is no additional control based on the following: (1) SO 2 emissions from the lime kilns during the BART baseline period were and are expected to continue to be extremely low (<4 TPY, combined); (2) ther e are no control technol ogies available for lime kilns that are more cost effective than the inherent scrubbing that occurs for SO 2 due to the alkalinity of the lime in the process; (3) SO 2 emissions from the smelt dissolving tanks have a minimal impact on visibility (<0.1 deciviews); and (4 )additional control of
SO 2 emissions from the lime kilns would ha ve a minimal impact on overall visibility.

NO x: Verso Androscoggin identified and eval uated selective catal ytic reduction (SCR),
low NO

x burners (LNB), and selec tive non-catalytic re duction (SNCR) as potential NOx5/27/2010
Draft For FLM Review

126 control technologies. Verso Androscoggin’ s evaluation of SCR and SNCR as potential
NO
x control technologies revealed that they ha ve 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 re search with respect to lime kilns and LNB technology revealed that the te chnology is actually a combination of passive combustion
control measures used to minimize NO

x formation primarily from thermal NO

x and to a
lesser extent fuel NO

x . These combustion control measures include careful design of the fuel feed system in order to ensure proper mixing of the fuel with air and burner “tuning” or optimization which impacts fuel burning e fficiency and overall flame length. Verso Androscoggin already incorporates burner “t uning” in the operation and maintenance of the “A” and “B” Lime Kilns to op timize the relationship between NO

x emissions and operating efficiency. Based on Verso Andros coggin’s identification and evaluation of control technology options, they propose that the current use of LNB (referred to as
combustion control measures on lime kiln s) represents BART for control of NO

x emissions from “A” and “B” Lime Kilns and that no additional le vel of control is technically feasible. Verso A ndroscoggin also notes in their BART analysis that existing
NO
x emissions from the “A” and “B” Lime Kilns have a minimal impact on visibility (<0.1 deciviews) and that additional control of NO

x emissions would have a minimal impact on the overall improvement to visibility.

Flash Dryer

PM: Particulate matter (PM 10 ) emissions from the Flash Dryer are currently controlled by the use of a wet shower system. Verso A ndroscoggin proposes that the application of
add-on controls and the use of cleaner fu els are not practical considerations for controlling PM emissions from the Flash Dryers and that with potential visibility impacts from the Flash Dryer being extremely low, any emission reductions would have an inconsequential impact on visibility improvement.

SO 2 : The Flash Dryer is limited to firing #2 fuel oil with a maximum sulfur content of 0.5%, by weight and so has relatively low SO 2 emissions. Although Verso Androscoggin could replace the use of #2 fuel oil with lowe r sulfur containing fuels such as low sulfur (0.05%) diesel fuel or natural gas, the Flash Dryer is predic ted to have peak visibility impacts of 0.1 deciviews or less. Base d on Verso Androscoggin’ s identification and
evaluation of SO 2 control technology options for the Flash Dryer, they propose that no
additional level of control is representative of BART.

NO
x : The Flash Dryer is not equipped with any NO

x control equipment. NO

x emissions from the Flash Dryer are primarily generated from the nitrogen component in the fuel oil. Verso Androscoggin currently uses good maintenance practices to minimize NO

x emissions from the Flash Dryer. Verso A ndroscoggin’s investiga tion of conventional
NO
x combustion controls (e.g., LNB, OFA, and FGR) lead to findings that they are either
unavailable for installation on th e Flash Dryer or are not feasible for a combustion source as small as the Flash Dryer.5/27/2010
Draft For FLM Review

127 BART Determinations:

BART Determination for VERSO Androscoggin
Unit PM SO 2 NO
x Control Type Emission
Limit and
Reference Control Type Emission Limit
and Reference Control Type Emission
Limit and
Reference

Power
Boilers #1
and #2 Low sulfur
oil/
combustion
control Compliance
with 40 CFR
Part 63 Subpart

DDDD Low sulfur
fuel Low sulfur fuel oil containing
no more than 0.7 % sulfur, by weight. (BART order) Low NO

x burners 0.447
lbs/MMBtu
on a 24-hour
block average basis (Existing
Title V license)
Waste
Fuel
Incinerator Combustion controls, wet
scrubber Compliance
with 40 CFR
Part 63 Subpart

DDDD Wet scrubber 0.8 lbs/MMBtu
on a 3-hour

average (Existing Title V license) Combustion
controls 0.4 lbs/

MMBtu on a
24-hour
block average basis (Existing
Title V license) Recovery
Boiler #1 ESP Compliance
with 40 CFR
Part 63 Subpart MM Staged air
combustion 120 ppmdv @8% O 2 on a 30-day rolling average basis when operating at a black liquor
recover rate of 50% or higher.
SO2 emissions
shall not exceed 140 ppmdv @8% O 2 on a 30-day rolling average basis when operating at a black liquor
recover rate of
less than 50% (BART order) Combustion
controls (NSR) 150 ppmdv,
when
corrected to
8% % O 2 on a 24-hour
block average basis (BART order)

Recovery
Boiler #2 ESP Compliance
with 40 CFR
Part 63 Subpart MM (Existing
Title V license) Staged air
combustion 120 ppmdv @8% O 2 on a 30-day rolling average basis (Existing Title V license) Combustion
controls (RACT) 206 ppm
corrected to
8% % O 2 on a 24-hour
block average basis (Existing
Title V license)5/27/2010
Draft For FLM Review

128 Smelt
Tanks #1
and #2 Wet cyclonic
scrubber Compliance
with 40 CFR
Part 63 Subpart MM (Existing
Title V license) Wet cyclonic
scrubber Smelt Tank #1-
2.7 lbs/hr

Smelt Tank #2-
3.9 lbs/hr (Existing Title V license) N/A N/A

Lime
Kilns A
and B Venturi
scubber Compliance
with 40 CFR
Part 63 Subpart MM Venturi
scubber 6.7 Lbs/hr, 74.6 tpy (Existing Title V license) Combustion
controls (RACT) 120 ppm @
10% O 2 (stack test) (Existing
Title V license) Flash Dryer Wet shower 5 lbs/hr (Existing
Title V license) Low sulfur fuel (#2 oil) Low sulfur fuel oil containing
no more than 0.5 % sulfur, by weight (Existing Title V license) Good
combustion practices (Existing
Title V license) 11.8 lbs/hr

10.8 Schedule for BART Implementation

As provided in 40 CFR Section 51.308(e)(1)( iv) BART must be in operation for each applicable source no later than five years after SIP/TIP approval. Pursuant to 38 M.R.S.A. §603-A, sub-§8 (b), the State of Main e is requiring that e ach source subject to BART shall install and operate BART as exped itiously as practicable but in no event later than January 1, 2013.

As provided in 40 CFR Section 51.308(e)(1)(v ) the Title V operating permits for BART sources must include a requirement that each source maintain the control equipment and establish procedures to ensure such equipmen t is properly operated and maintained. This requirement will be included in the Title V operating permit for each source subject to BART. The BART requirements for Maine Bart eligible sources will be federally enforceable through the Title V operating pe rmit program and through incorporation in the Maine Regional Haze SIP.

Copies of the draft Title V operating permits for each source are included in Attachment

M5/27/2010
Draft For FLM Review

129 

### 11. Reasonable Progress Goals

The Regional Haze Rule (40 CFR Section 51.308 (d)(1)) requires each state with Class I
areas to establish reasonable progress goals providing for reasonable progress towards achieving natural visibility in each Class I ar ea. In addition, EPA released guidance on June 7, 2007 to use in setting reasonable progress goals. The goals must provide improvement in visibility for the most im paired days, and ensure no degradation in visibility for the least impaired days over the State Implementation Plan (SIP) period. The State of Maine must also provide an assessmen t of the number of year s it would take to attain natural visibility conditions if improve ment continues at the rate represented by the reasonable progress goal.

Under 40 CFR Section 51.308 (d)(1)(iv), cons ultation 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 contri bute to visibility impairment in the mandatory Class I Federal area. In any situation in which the State cannot agree with another such State or group of States that a goal provides for reasonable progress, the State must desc ribe in its submittal the actions taken to resolve the disagreement. In revi ewing the State's implementation plan submittal, the Administrator will take this information into account in determining whether the State's goal for visibility improvement provides for reasonable progress towards natural visibility conditions.

As discussed in Section 3, Maine consulted wi th states that contri bute to visibility impairment at its Class I areas and with st ates that requested c onsultation with Maine regarding their Class I areas (New Hampshire, Vermont and New Jersey). Maine worked closely with these states duri ng the consultation process and agrees with the reasonable progress goals established by New Ha mpshire, Vermont and New Jersey.

In developing the reasonable progress goals the Class I state must also consider four factors (cost, time needed, energy & non-ai r quality environmental impacts, and remaining useful life). The state also must show that it considered the uniform rate of improvement and the emission reduction measur es needed to achieve it for the period covered by the implementation plan, and if th e state proposes a rate of progress slower than the uniform rate of progress, assess the number of years it would take to attain
natural conditions if visib ility improvement continues at the rate proposed.

11.1 Calculation of Uniform Rate of Progress

As a benchm ark to aid in developing r easonable progress goals, MANE-VU compared the baseline visibility conditions to natural vi sibility condition at each Class I area. The
difference between baseline and natural visi bility conditions at each MANE-VU Class I
area was used to determine the uniform rate of progress that would be needed during each5/27/2010
Draft For FLM Review

130 im plementation period in order to attain natu ral visibility. Table 11-1 presents baseline visibility, natural visibility and required uniform rate of progress for each MANE-VU Class I area. Visibility values are expr essed in deciviews (dv) where a single-unit decrease would represent a barely per ceptible improvement in visibility.

Table 11-1 Uniform Rate of Progress Calculation

(all values in deciviews)

Class I Area (2000-2004)
Baseline Visibility (deciviews) (20% Worst Days) Natural Visibility
Conditions (20%
Worst Days) Deciview Improvement

Needed by
2018 Total
Deciview Improvement

Needed by
2064 Uniform Rate
of Improvement Annually

Acadia National Park 22.9 12.4 2.4 10.5 0.174 Roosevelt/Campobello
International Park 21.7 12.0 2.3 9.7 0.162
Moosehorn Wilderness
Area 21.7 12.0 2.3 9.7 0.162 Presidential Range/Dry
River Wilderness Area 22.8 12.0 2.5 10.8 0.180
Great Gulf Wilderness
Area 22.8 12.0 2.5 10.8 0.180 Lye Brook Wilderness 24.5 11.7 3.0 12.8 0.212 Brigantine Wilderness 29.0 12.2 3.9 16.8 0.280 Note: Both natural conditions and baseline visibility for the 5-year period from 2000 through 2004 were calculated in conformance with an alternative method recommended by the IMPROVE Steering

Committee

. 44

The reasonable progress goals established for the Maine Class I areas are expected to provide greater visibility impr ovements than the uniform rate of progress shown in Table 11-1, above.

11.2 Reasonable Progress Goals for Class I Areas in Main e

In accordance with the requirements of 40 CFR Section 51.308 (d)(1), this Regional Haze SIP establishes reasonable progress goals (R PG) for each Class I area in Maine for the period of the implementation plan.

40 CFR Section 51.308(d)(1)(vi) requ ires that reasonable progre ss goals represent at least the visibility improvement expected from implementation of other Clean Air Act programs during the applicable planning peri od. As documented in Section 8 Emissions

44 “Baseline and Natural Visibil ity Conditions, Considerations and Proposed Approach to
the Calculation of Baseline and Natural Visibility Conditions at MANE-VU Class I Areas,” NESCAUM, December 2006.5/27/2010
Draft For FLM Review

131 Inventory, and Section 12 Long-Term Strate gy, the m odeling that formed the basis for reasonable progress goals in MANE-VU Class I areas included estimation of the effects of all other programs required by the Clean Air Act. Furt her information may be found
in those sections of this SIP and in the documentation for the MANE-VU modeling.

Both natural conditions and ba seline visibility for the 5- year period from 2000 through
2004 were calculated in conformance with an alternative method recommended by the IMPROVE Steering Committee. Progress to ward the 2018 target will be calculated based on 5-year averages calculated in a na tionally consistent manner consistent with EPA’s “Guidance for Tracking Prog ress Under the Regional Haze Rule” (EPA-454/B-03- 004, September 2003) as updated by the alternative method fo r calculating regional haze recommended by the IMPROVE Steering Committee.

To determine the RPG in deciviews, MANE -VU conducted modeling wi th certain control measure assumptions. The control measures reflected in these r easonable progress goals are summarized below. In establishing its reasonable progress goals for 2018, Maine recognizes that contributing states have the flexibility to submit SIP revisions between now and 2018 as they are able to adopt contro l measures to implement these goals. This long-term strategy to reduce and prevent re gional haze will allow each state up to 10 years to pursue adoption and implementa tion of reasonable and cost-effective SO 2, NO
x and PM control measures.

Tables 11-2 and 11-3 below, provide a summary of the Reasonable Progress Goals for
Maine Class I areas.
Table 11-2 Reasonable Progress Goals—20% Worst Days

(all values in deciviews)

Class I Area Baseline Visibility (deciviews) (20% Worst Days 2000-2004) Reasonable Progress Goals,

20% Worst Days (expected
deciview level by 2018) Deciview Improvement Expected by
2018 Natural Visibility Conditions (20% Worst Days)

Acadia National Park 22.9 19.4 3.5 12.4

Moosehorn
Wilderness Area/ Roosevelt Campobello
International Park 21.7 19.0 2.7 12.05/27/2010
Draft For FLM Review

132 Table 11-3 Reasonable Progress Goals—20% Best Days

(all values in deciviews)

Class I Area Baseline Visibility (deciviews) (20% Best Days) Reasonable Progress Goals, 20% Best Days (expected
deciview level by 2018) Deciview Improvement Expected by 2018 Natural Visibility (20% Best Days) (deciviews)

Acadia National Park 8.8 8.3 0.5 4.7

Moosehorn
Wilderness Area/ Roosevelt Campobello
International Park 9.2 8.6 0.6 5.0

11.3 Identification of Additi onal Reasonable Controls

Maine and the other MA NE-VU states have identified specific emission control measures- beyond those which individual st ates or RPOs have already made commitments to implement- that would be reas onable to undertake as part of a concerted strategy to mitigate regional haze. The pr oposed additional control measures were incorporated into the regional strategy adopted by MANE-VU on June 20, 2007, to meet the reasonable progress goals establ ished in this SIP. The basic elements of this strategy are described in the MANE-VU “Ask” (see Subsection 3.4). St ates targeted for coordinated actions toward achieving these goa ls include all of the MANE-VU states plus Georgia, Illinois, Indiana, Kentucky, Mich igan, North Carolina, Ohio, South Carolina, Tennessee, Virginia and West Virginia 45

.

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 reduc tions 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 mode ling accounts for six coal-burning EGUs in Canada having a comb ined output of 6,500 MW that are scheduled to be shut down and replaced by nine natural gas turbine units with selective catalytic reduction (SCR) by 2018.

The process of identifying reasonable progress measures and setting reasonable progress goals is described in the subsections which fo llow. Further elaboration on the reasonable progress measures which make up the Main e/MANE-VU long-term strategy is provided

45 In addition, the State of Vermont identified at least one source in the State of Wisconsin as a significant contributor to visibility impairment at the Lye Brook Wilderness Class I Area.5/27/2010
Draft For FLM Review

133 in Section 1 2 of this SIP. Under this pla n, the affected states w ill have a maximum of 10 years to implement reasonable and cost-effec tive control measures to reduce primarily
SO 2 and NO

x emissions. For a description of how proposed emission control measures were modeled to estimate resulting visi bility improvements, see Subsection 11.5, Visibility Effects of Additional Control Measures.

10.4 The Foundations for Determining Reasonable Controls

40 CFR Section (d)(1)(i)(A) of EPA’ s Clean Air Visibility Rule requires that, in establishing reasonable progress goals for each Class I area, the State must consider the costs of compliance, the time necessary for compliance, the energy and non-air quality environmental impacts of compliance, and th e remaining useful lif e of any potentially
affected sources. The SIP must include a de monstration showing how these factors were taken into consideration in setting the reas onable progress goals. These factors are sometimes termed the “four statutory factors, ” since their considera tion is required by the
Clean Air Act.

Focus on SO 2: MANE-VU conducted a Contribution A ssessment (Attachment A) and developed a conceptual model that indicated particulate sulfate formed from emissions of
SO 2 was the dominant contributor to visibility impairment at all sites and during all seasons in the base year. While other po llutants, including organic carbon and NOx, will
need to be addressed in order to achie ve the national visibility goals, MANE-VU’s contribution assessment suggested that an early emphasis on SO 2 will yield the greatest near-term benefit. Therefore, it is reasonabl e to conclude that th e additional measures considered in establishing reasonable progre ss goals require reductions in SO2 emissions.

Contributing Sources: The MANE-VU Contribution Assessment indicates that
emissions in 2002 from within the MANE-VU region were re sponsible 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 SO 2 emissions. Therefore, the MANE-VU’s long-term strategy, includes additional measur es to control sources of SO 2 both within the MANEVU region and in other states that were dete rmined to contribute to regional haze at
MANE-VU Class I areas.

The Contribution Assessment documented the source categories most responsible for visibility degradation at M ANE-VU Class I areas. As desc ribed in the Section 12, Long Term Strategy, there was a collaborativ e effort between the Ozone Transport
Commission and MANE-VU to eval uate a large number of po tential control measures.
Several measures that would reduce SO 2 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 Progre ss Report (Attachment T), which documented an analysis of the four stat utory factors for five major source categories. Table 11-4
summarizes the results of MANE-VU’s Reas onable Progress Report, which considered EGUs, ICI boilers, cement kilns, heati ng oil and residential wood combustion.5/27/2010
Draft For FLM Review

134 Table 11-4 Summary of Results from the Four Factor Analysis

Source Category Primary Regional

Haze
Pollutant Control Measure(s) Average
Cost in 2006
dollars
(per ton of pollutant reduction) Compliance
Timeframe Energy and Non-Air Quality
Environmental Impacts Remaining
Useful

Life

Electric
Generating

Units SO 2 Switch to a low sulfur coal (generally <1% sulfur), switch to natural gas (virtually 0% sulfur), coal cleaning, Flue Gas Desulfurization (FGD)-Wet,
-Spray Dry, or -Dry. IPM®* v.2.1.9
predicts $775-
$1,690

$170-$5,700 based

on available

literature 2-3 years
following SIP

submittal Fuel supply issues,
potential permitting

issues, reduction in
electricity production
capacity, wastewater

issues 50 years or

more

Industrial,

Commercial,

Institutional

Boilers SO 2 Switch to a low sulfur coal (generally <1% sulfur), switch to natural gas (virtually 0% sulfur), switch
to a lower sulfur oil, coal cleaning, combustion
control, Flue Gas Desulfurization (FGD) -
Wet, -Spray Dry, or -Dry. $130-$11,000

based on available
literature. Depends

on size. 2-3 years
following SIP

submittal Fuel supply issues,
potential permitting

issues, control device
energy requirements,

wastewater issues 10-30 years

Cement and

Lime Kilns SO 2 Fuel switching, Dry Flue Gas Desulfurization-Spray Dryer Absorption (FGD),

Wet Flue Gas Desulfurization (FGD),

Advanced Flue Gas Desulfurization (FGD). $1,900-$73,000

based on available
literature. Depends

on size. 2-3 years
following SIP

submittal Control device energy
requirements,

wastewater issues 10-30 years

Heating Oil SO 2 Lower the sulfur content in the fuel. Depends on the

state. $550-$750 based

on available

literature. There is
a high uncertainty

associated with

this cost estimate. Currently feasible.
Capacity issues
may influence

timeframe for
implementation of

new fuel standards Increases in

furnace/boiler
efficiency, Decreased

furnace/boiler

maintenance
requirements 18-25 years

Residential

Wood

Combustion PM State implementation of
NSPS, Ban on resale of
uncertified devices, installer training certification or inspection program, pellet
stoves, EPA Phase II
certified RWC devices, retrofit requirement, accelerated changeover requirement, and accelerated changeover inducement. $0-$10,000 based

on available

literature Several years -
dependent on

mechanism for

emission reduction Reduce greenhouse gas

emissions, increase
efficiency of combustion

device 10-15 years

* Integrated Planning Model® CAIR versus CAIR plus analysis conducted for MARAMA/MANE-VU by ICF.5/27/2010
Draft For FLM Review

The MANE-VU states reviewed the f our-fact or analysis presented in the Reasonable Progress Report, consulted with each other about the measures, and concluded by adopting the statements known as the MANE-VU Ask on June 20, 2007. These statements identify the control measures that would be pursued toward improving visibility in the region.. The following disc ussion focuses on the four basic control strategies chosen by MANE-VU and include d in the modeling used to establish reasonable progress goals: BART, emissions reductions from specific EGUs, low sulfur fuel oil requirements, and additional meas ures determined to be reasonable.

11.4.1 Best Available Retrofit Technology (BART) Controls

The MANE-VU states have identified appr oximately 100 BART-eligib le sources in the region. Most of these faciliti es are already controlling emissions in response to other federal or state air programs , or are likely to install emission controls under new programs. Previously, EPA determined that CAIR fulfilled the BART requirement for all EGUs in CAIR-affected states. Although CAIR has been remanded to EPA, the determination that CAIR is equivalent to BART is still in place. Maine anticipates that those same units will be covered by successo r legislation or new rulemaking undertaken in response to the CAIR remand. A complete compilation of BART-eligible sources in the MANE-VU region is available in Att achment A of MANE-VU’s “Assessment of Control Technology Options for BART-Eligible Sources,” March 2005 (Attachment R).

To assess the benefits of implementing BART in the MANE-VU region, NESCAUM estimated reductions for twelve BART-eligible units in the MANE- VU states that would probably be controlled as a re sult of BART requirements al one. These sources include
one EGU and eleven non-EGUs. The affected units were identified by staff members in each MANE-VU state, who then furnished data on potential control technologies and expected emission levels for these units under BART implementation. The twelve sources are listed in Table 11-5, along with their 2002 baseline and 2018 projected
emissions. Information on these units wa s incorporated into the 2018 emissions inventory projections that were used to establish reasona ble progress goals.

Best Available Retrofit T echnology is Reasonable: BART controls are part of the strategy for improving visibility at MANE -VU Class I areas. MANE-VU prepared reports to provide states with informati on about available cont rol technologies (e.g., MANE-VU’s “Assessment of Control Technolog y Options for BART-Eligible Sources,” March 2005), estimated cost ranges and other fa ctors 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 wi ll make determinations demonstrating the

reasonableness of BART controls for sources in their states.

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Table 11-5 Estimated Emissions from BART-Elig ib le Facilities MANE-VU States

State Facility Name Unit

Name SCC

Code Plant ID * Point

ID * Facility Type Fuel 2002

SO 2 Emis

sions (tons) 2018

SO 2 Emissions

(tons)

MD EASTALCO

ALUMINUM 28 30300101 021-0005 28 Metal

Production 1506 1356

MD EASTALCO

ALUMINUM 29 30300101 021-0005 29 Metal

Production 1506 1356

MD LEHIGH

PORTLAND

CEMENT 39 30500606 013-0012 39 Portland Cement 9 8

MD LEHIGH

PORTLAND

CEMENT 16 30500915 021-0003 16 Portland Cement 1321 1,189

MD LEHIGH

PORTLAND

CEMENT 17 30500915 021-0003 17 Portland Cement 976 878

MD WESTVACO

FINE PAPERS 2 10200212 001-0011 2 Paper and Pulp 8923 1338

ME Wyman Station Boiler 3 10100401 2300500135 004 EGU Oil 616 308

ME SAPPI Somerset Power

Boiler

#1 10200799 2302500027 001 Paper and Pulp Oil/Wood

Bark/Process

Gas 2884 1442

ME IP Jay Power

Boiler

#2 10200401 2300700021 002 Paper and Pulp Oil 3086+ 1543

ME IP Jay Power

Boiler

#1 10200401 2300700021 001 Paper and Pulp Oil 2964+ 1482

NY KODAK PARK

DIVISION U00015 10200203 8261400205 U00015 Chemical

Manufacturer 23798 14216

NY LAFARGE

BUILDING

MATERIALS

INC 41000 30500706 4012400001 041000 Portland Cement 14800 4440 *( from the MANE-VU Inventory)
+1999 emissions

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11.4.2 The MANE-VU Low Su lfur Fuel Strategy

The MANE-VU region, especially the northeast, is heavily reliant on distillate oil for home space heating, with more than with mo re than 4 million gallons used, according to 2006 estimates from the Energy Information Administration 46 . Likewise, the heavier residual oils are widely used by non-EGU sources , and to a lesser extent the EGU sector.
The sulfur content of distil late fuels currently averages above 2000 ppm (0.2percent). Although the sulfur content of residual oils varies by sour ce and across the region, it can exceed 2.0 percent. In 2002, combustion of di stillate and residual fuel in the MANE-VU region resulted in SO 2 emissions totaling approximately 380,000 tons.

As the second component of MANE-VU’s long term strategy, the member states agreed to pursue measures that would require the sale and use of fuel oils having reduced sulfur content. This strategy would be implemented in two phases:

1. Phase 1 would require reducing the sulfur content in disti llate (#1 and #2) fuel oils from current levels of 2,000 to 2,3000 ppm (0.20 to .23 percent) to a maximum of 500 ppm (0.05 percent) by weight . It would also restrict the sale of heavier blends of residual (#4 and # 5 and #6) fuel oils that have a sulfur content greater than 2,500 ppm (0.25 percent) and 5, ppm (0.5 percent) by weight, respectively.

2. Phase 2 would require further reducing the sulfur content of the distillate fraction from 500 ppm (0.05 percent) to 15 ppm ( 0.0015 percent) while k eeping the sulfur limits on residual oils at first-phase levels.

The two phases are to be introduced in seque nce with slightly di fferent timing for an
inner zone of the MANE-VU states 47 and the remainder of the MANE-VU states. While all MANE-VU states have agreed to pursue implementation of both phases to full effect by the end of 2018, it is possible that not ever y state can make a firm commitment to these measures today. States are expected to review the situation by the time of the first five-year regional haze progress report.

Reductions in sulfur dioxide emissions will occur as a direct consequence of the lowsulfur fuel strategy. For both phases combined, it is estimated that SO 2 emissions in the MANE-VU region will decline from 2002 levels by 168,222 tons per year for combustion of light distillates, and by 42,875 tons per ye ar for combustion of the heavier fuels. Together, these reductions represent a 35 percent decrea se in the projected 2018 SO 2 emissions inventory for non-E GU sources in the region.

NESCAUM analyzed both steps of the program separately, but it is the combined benefit of implementing the program that is relevant to the question of visibility improvement by
2018. To estimate the total 2018 emissions reductions from this strategy, MANE-VU applied the expected sulfur dioxide emi ssion reductions to all non-EGU sources burning #1, #2, #4, #5, or #6 fuel oil. These emission re ductions would result directly from the

46 U.S. Department of Energy, EIA, Ta ble F3a, at http://www.eia.doe.gov/emeu /states/sep_fuel/htm l/fuel_use_df.html.

47 The inner zone includes Delaware, Maryland, Ne w Jersey, New York, and possibly portions of eastern Pennsylvania

.

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lowering of fuel sulfur conten t 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 SO 2 emissions by 2018 will yield corre sponding 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 re presented in Figure 11- 1, which displays the estimated average change in 24-hr average PM 2.5 for the combined first and second phases of the low-sulfur fuel strategy as calcu lated by the CMAQ model.

Figure 11-1 Average Change in 24-hr PM 2.5 Due to Low Sulfur Fuel Strategies Relative to
OTB/OTW

(  g/m 3 )

Low Sulfur Fuel Oil Requirements are Reasonable: The MANE-VU Contribution Assessment documented source apportionment an alyses that linked vi sibility impairment

in MANE-VU Class I areas with SO 2 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), a nd 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.

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Four-Factor Analysis- L ow sulfur Fuel Oil Strategy

The MANE-VU Reasonable Progress Report discu ssed the four factors as they apply to low sulfur fuel use for industrial, commercial, and institutional boi lers and residential heating systems. MANE-VU’s Reasonable Pr ogress Report identified switching to lower
sulfur oil as an available SO 2 control option that woul d achieve 50 to 90 percent
reductions in SO 2 emissions from ICI Boilers. The re port also noted that home heating oil use generates an estimated 100,000 tons of SO 2 emissions in the Northeast each year,
and that SO 2 emissions would decline in proportion to reductions in fuel sulfur content. The following discussion summarizes informa tion concerning the four factors for the low-sulfur fuel strategy.

Costs of Compliance The MANE-VU Reasonable Progress Report noted that because of requirements for motor vehicle fuels, refineries have alrea dy 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 SO 2 removed by switching to lower sulfur fuel would range from $554 to $734 per ton (Converted from 2001 to 2006 dollars using a conversion factor of 1.1383). In some seasons and some locations, low sulfur diesel is actually cheaper than regular diesel fuel . (See Chapter 8 of the Reasonable Progress Report.)

The sulfur content of #4 and #6 fuels can also be cost-effectively reduced. Residual oil is essentially a by-product of the refining process, and is produced in several grades that can be blended to meet a specified fuel sulfur content limit. New York Harbor residual fuel prices for the week ende d March 21, 2008 ranged from a low of $71.38 a barrel for 2.00 and 2.2 percent sulfur fuel; to a high of $91.38 pe r barrel for 0.3 percen t sulfur fuel. Low

pour 48 fuel oil with 0.5 percent sulfur sold for $80.83 per barrel in this same period 49

.

While the costs for achieving the projected emi ssions reductions with the low-sulfur fuel strategy are somewhat dependent on market conditions, they are believed to be reasonable in comparison to costs of contro lling other sectors. Some MANE-VU states are proceeding with low-sulfur oil requirements much sooner than 2018; however, all of
the MANE-VU states concur that a low-su lfur oil strategy is both reasonable and achievable by 2018. MANE-VU ha s concluded that the cost of requiring lower sulfur
fuel is reasonable.

Time Necessary for Compliance MANE-VU’s Reasonable Progress Report indicate d that furnaces and boilers would not have to be retrofit and would not requir e expensive control technology to burn ULSD distillate fuel oil. Therefore, the time n ecessary for compliance would be determined by the availability of the fuel.

48 Low pour refers to a low-temperature pour point (or reduced viscosity at low temperature) for the fuel.

49 During this same period, residual oil with a fuel sulfur content limit of 0.7 percent and 1.0 percent traded at $75.13 and $72.63, respectively.

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The MANE-VU Reasonable Progress Report notes that, on a national scale, m ore ULSD is produced than both LSD and high sulfur fu el, and concludes that there is sufficient domestic infrastructure to produce adequate stocks of LSD and ULSD. The NESCAUM Low Sulfur Heating Oil Report 50 also observes that the fe deral rules for heavy-duty highway diesel fuel are flexible, so that if there is a shortage of 15 ppm fuel, the 15 to 500 ppm fuel could be used to relieve the s hortage. With this flexibility, the report
concludes that the like lihood of a fuel shortage in the s hort term due to use of ULSD for heating oil is diminished. The volatile natu re of heating supply and demand presents unique challenges to the fuel oil industry. The success of a low sulfur fuel oil program is predicated on meeting these challenges. The Northeast states are assessing a variety of business strategies and regulatory approach es that could be used to minimize any potential adverse supply and price impacts that could result from a regional 500 ppm sulfur standard for heating oil. Suppliers can increase pre-season reserves and look to increase imports from offshore refiners producing low sulfur product. Blending domestically produced biodiesel into heati ng oil offers opportunity to reduce imports, stabilize supplies and minimize supply-related price spikes.

Potential supply disruptions and price spikes for residual fuels were a particular concern
for several northern MANE-VU states. While the potential for disruptions in the supply of residual fuels is greater than that for distil late oil, these disrupti ons would affect only a
limited number of states duri ng extreme weather events.

MANE-VU has identified several mechanisms that could be implemented to address disruptions, including seasonal averaging and emergency waivers. A seasonal averaging approach would reduce potential supply constr aints by allowing the use of higher sulfur fuel during periods of peak demand (and limite d supply), and then requiring the increased
sulfur content of these fuels to be offset th rough the use of a lower sulfur fuel at other times. This approach would provide regulat ory certainty and great er flexibility during the winter months when fuel supplies may be subject to weather-related disruptions, but at a cost of increased recordkeeping a nd compliance monitoring. Since many states already have statutory authority to waive fu el sulfur limits for an emergency waiver,
states could also utilize their discreti onary powers to address short-term supply disruptions.

The strategy adopted by Maine and the other MANE-VU states proposes to phase in the required use of lower-sulfur fuels over the next 8 years, providing adequate time for full implementation.

Energy and Non-Air Quality Enviro nmental Impacts of Compliance According to MANE-VU’s Reasonable Progress Report, reducing the sulfur content of fuel oil would have a variety of beneficial consequences for boilers and furnaces using
this fuel. Low-sulfur distillate fuel is cl eaner burning and emits le ss particulate matter, thereby substantially reducing the rate of fouling of heating units and allowing longer time intervals between cleanings. The M ANE-VU report cites a study by the New York

50 “Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Costs and Implementation Issues”, December 31, 2005 by NESCAUM

.

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State Energ y Research and Development Authority (NYSERDA) showing that boiler deposits are reduced by a factor of two by lo wering the fuel sulfur content from 1,400 ppm to 500 ppm. The use low-sulfur oil could extend the useful life of a source by reducing the maintenance required because low-sulfur oil is less damaging to the combustion equipment. The report also notes th at decreasing sulfur le vels in fuel would enable manufacturers to develop more effi cient 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, SO 2 controls would also have benefici al environmental impacts by reducing acid deposition and helping to d ecrease concentrations of PM 2.5 . Reductions in PM 2.5 would potentially help nonattainment areas meet health-based National Ambient Air Quality Standards.

Remaining Useful Life of Any Potentially Affected Sources
Residential furnaces and boilers have finite life spans, but they do not need to be replaced
to burn low- or ultra-low-sulfur fuel. The Energy Research Center estimates that the average life expectancy of a re sidential heating oil boiler is 20-25 years. As noted above, use of low-sulfur fuel is less damaging to equipment and could therefore extend the
useful life of an oil-fired residential furnace or boiler.

Available information on the remaining useful life of ICI boilers indicates a wide range of life expectancies, depending on unit size, capacity factor 51 , and level of maintenance performed. The typical life expectancy of an ICI boiler ranges from 10 years to more than 30 years. As in the case of residentia l units, use of lower-sulfur fuels could extend the lifespan of an ICI boiler.

11.4.3 Targeted Strategy for Reducing SO 2 Emissions from EGU Stacks

EGUs are the single largest sector contribu ting to visibility im pairment at MANE-VU
Class I areas. SO 2 emissions from power plants con tinue to dominate the emissions inventory. Sulfate formed thr ough atmospheric processes from SO 2 emissions are responsible for over half the mass and approxi mately 70-80 percent of the extinction on the days of worst visibility (NESCAUM’s Contribution Assessment and Conceptual Model, Attachment A).

To ensure that EGU controls are targeted at those EGUs with the greatest impact on visibility at MANE-VU Class I areas, a mode ling analysis was conducted to identify the individual sources responsible for the greatest cont ributions to visibility impairment. Accordingly, MANE-VU developed a list of the 100 EGUs having the greatest impacts at each MANE-VU Class I area during 2002 The combined list for all seven MANE-VU
Class I areas identified a total of 167 distin ct emission points, with these stacks located throughout the Northeast, Midwes t and Southeast (Figure 11-2)

51 Capacity factor is defined as the actual amount of energy a boiler generates in one year divided by the total amount it could generate if it ran full time at full capacity.

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Figure 11-2 Location of 167 EGU Stacks Contributing th e Most to Visibili ty Impairment at
MANE-VU Class I Areas

After consultations with its member states and other RPOs MANE-VU requested a 90- percent reduction in SO 2 emissions from the top 167 st acks no later than 2018 (See the MANE-VU “Ask,” described in Section 3.4 of this SIP). NESCAUM’s preliminary modeling for MANE-VU showed that reducing SO 2 emissions from the targeted facilities by 90 percent would also produce measurable improvements in ambient 24-hour PM 2.5 concentrations. Assuming a control level equal to 10 pe rcent of the 2002 baseline emissions (i.e., 90 percent emission re duction), NESCAUM used CMAQ to model
sulfate concentrations in 2018 after implementation of controls. The modeled sulfate
values were then converted to estimates of PM 2.5 concentrations.

Figure 11-3 illustrates the reduction in fine pa rticle pollution in the Eastern U.S. that would result from implementing the targeted EGU SO 2 strategy. Improvements in PM 2.5

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concentrations would occur throughout the MA NE-VU region as well as for portions of the VISTAS and Midwest RPO regions, es pecially the Ohio River Valley.

Figure 11-3 Preliminary Estimate of Av erage Change in 24-hr PM 2.5 Due to 90 Percent

Reduction in SO 2 Emissions from 167 EGU St acks Affecting MANE-VU

Although the reductions are poten tially large, MANE-VU dete rmined, after consultation with affected states, that it was unreasonable to expect that the full 90-percent reduction
in SO 2 emissions would be achieved by 2018. Therefore, additional modeling was
conducted to assess the more realistic scenar io in which emissions would be controlled by the individual facilities and/or states to levels already projected to take place by that date. At some facilities, the actual emission reductions are anticipated to be greater or less than the 90 percent benchmark. For a de tailed description of this analysis, see Alpine Geophysics’ report for MARAMA entitled “Documentation of 2018 Emissions from Electric Generating Units in the Ea stern United States for MANE-VU’s Regional Haze Modeling, Revised Final Draft, April 21, 2008 (Attachment S). Targeted EGU SO 2 Emissions Reductions are Reasonable: MANE-VU identified specific EGU stacks that were significant contri butors to visibility degradation at MANEVU Class I areas in 2002 based on CALPU FF modeling analyses documented in the
Contribution Assessment. MANE-VU obtaine d information about existing and planned
controls on emissions from those stacks. Th ese analyses and the information on proposed EGU controls are presented in the MANE -VU Reasonable Progress Report, and the

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Contribution Assessm ent (specifically Att achment D),as well as in Section 8.0 (Emissions Inventory), and Section 12.0 (L ong Term Strategy) of this SIP.

Based on information gathered from the st ates and RPOs, MANE-VU anticipates that emissions from many of the specific EGU st acks will be controlled as a result of EPA’s Clean Air Interstate Rule (CAIR). Since CAIR is a cap and trade program, it is not possible to predict with certainty which of th e 167 stacks will in fact be controlled under
CAIR in 2018.

Four-Factor Analysis – Targeted EGU SO 2 Reduction Strategy

Costs of Compliance Technologies to control the precursors of regional haze are commercially available. 52

Because EGUs are the most signific ant stationary source of SO 2 , NO
x , and PM, they have been subject to extensive federal and state regulations to control all three pollutants. The technical feasibility of cont rol technologies has been su ccessfully proven for a large number of small (@100MW) to very large bo ilers (over 1,000 MW) using different types of coal used. Over the last few years, the co st data clearly indicate that many technologies provide substantial and cost-effective reductions.

Both wet and dry flue gas desulfurization (“sc rubbers”) are in wide commercial use in the U.S. for controlling SO 2 emissions from coal-fired pow er plants. The capital costs for new or retrofit wet or dry scrubbers ar e higher than the capital costs for NO

x and PM controls. Capital costs ranged from $180/kW for large units (larger than 600 MW) to as high as $350/kW for small units (200 to 300 MW). (See pages 2-22 of the NESCAUM report “Assessment of Control Technologies for BART Elig ible Sources,” March 2005, Attachment R). However, the last few year s have seen a general trend of decliningcapital costs due to vendor competition and technology maturation. Also, the costeffectiveness (in dollars per t on of emissions removed) is ve ry attractive because the high sulfur content of the coal burned by these uni ts results in a very large amount of SO 2 removed by the control devices. The typical co st-effectiveness is in the range of 200 to 500 dollars per ton of SO 2 removed, although the cost ri ses steeply for small units burning low-sulfur coals and operating at low ca pacity factors. For any unit, the overall
cost effectiveness is determined mo stly by the baseline pre-controlled SO 2 emission rate (or fuel sulfur content), size a nd capacity factor of the unit, as well as the capital cost of flue gas desulfurization (gener ally ranges from $150 to $200/Kw).

The MANE-VU Reasonable Progress Report review ed options for controlling coal-fired EGU boilers, including switching to lower-sulfu r coal, switching to natural gas, coal cleaning, and flue gas desulfur ization (FGD). The most eff ective control option (but not necessarily appropriate for all installations) is FGD, which can achieve up to a 95 percent
reduction in SO 2 emissions. The cost varies consid erably among units and was estimated

52 The information in this and the next paragraph comes from the “Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities,” March 2005 , prepared by NESCAUM, in partnership with MANE-VU.

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to range from as low as $170/ton to as hi gh as $5,700/ton. Table 11-6 summ arizes the
estimated SO 2 control costs on a dollar per ton of SO 2 removed basis.

Table 11-6 Estimated Cost Ranges for SO 2 Control Options for Coal-Fired EGU Boilers

(2006 dollars per ton of SO 2 removed)

To predict future em issions and further evaluate the costs of emission controls for electric generating units, MANE-VU and other RPOs ha ve followed the example of EPA in using the Integrated Planning Model (IPM®), an in tegrated economic and emissions model for EGUs. This model projects electricity supp lies based on various assumptions while at the same time developing least-co st solutions to electrical generating needs within the specified emissions targets. IPM also provides estimates of the costs of complying with various policy requirements.

EPA developed IPM version 2.1.9 and used this model to evaluate the impacts of CAIR and the Clean Air Mercury Rule (CAMR) 53 . Recently, EPA updated their input data and

53 CAMR was also vacated by the federal courts and is no longer in effect.

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developed IPM v3.0. However, because of tim e constraints, all MANE-VU modeling runs were based on EPA IPM v2.1.9 with change s made to the input assumptions. As stated previously, CAIR has recently been remanded to EP A and it is unknown at this time when EPA will propose a revised or new rule in accordance with the court’s July 11,
2008 decision.

The RPOs collaborated with each other to update EPA Base Case v.2.1.9 using more
current data about EGUs with more realis tic fuel prices, creating an IPM run called VISTAS PC_1f. The VISTAS IPM run is the ba sis for regional air quality modeling for regional haze SIPs in MANE-VU.

MANE-VU, through MARAMA, contracted with the consulting firm ICF International to prepare two new IPM runs 54 . The first modeling run, known as the MARAMA CAIR Base Case run, was based on the VISTAS PC_1f run and underlying EPA IPM v.2.1.9 with some updated information on fuel prices, co ntrol constraints, etc. This run also goes by the name MARAMA_5c. The second run, ca lled 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 informa tion used in the VISTAS run, but
assumed lower NO X emission caps and higher SO 2 retirement ratios.

Based on modeling results, MANE-VU estimat es that the marginal cost of SO 2 reductions (the cost of reducing an additiona l ton of emissions) ranges from $640/ton in 2008 to $1,392 ton in 2018. 55

Costs will vary for individual plants to re duce emissions by 90 percent, as recommended in the MANE-VU Ask. However, this strategy provides states with the flexibility to pursue controls on specific sources as a ppropriate and to control emissions from alternative sources, if necessar y, to meet the 90 percent targ et established in the Ask.

Given the significance of SO 2 emissions from specific EGU’s to visibility impairment in MANE-VU Class I areas, the MANE-VU Commissi oners, after weighing all factors- the availability of technology to reduce emissions, the estimated co st of controls, the costs of alternative measures, the flexibility to achieve alternative reductions if necessary, etc. -
concluded that the costs of reducing emissions from the identified key stacks was reasonable. Maine agrees with this conc lusion for base-load coal-fired units, but recognizes add-on controls may not be co st-effective for oil-fired peaking units.

Time Necessary for Compliance MANE-VU’s Reasonable Progress Report indicate s that, generally, sources are given a 2- to 4-year phase-in period to comply with new rules. Under Phase I of the NO

x SIP call, EPA provided a compliance date of about 3.5 years from the SIP submittal date. Most MACT standards allow a 3-year complia nce period. Under Phase II of the NO

x SIP Call,

54 See the report, Comparison of CAIR and CAIR+ Proposal using the Integrated Planning Model (IPM®), ICF Resources LLC, May 2007, Attachment U.

55 See Table 6, “Allowance Prices (Marginal Costs) of Emissions Reductions...” p. 9, ICF, May 2007,
Attachment U.

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EPA provided a 2-yea r compliance period fr om the SIP submittal date. The MANE-VU
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 Enviro nmental Impacts of Compliance The MANE-VU Reasonable Progress Report identified several energy and non-air quality impacts as a result of additional EGU controls. These included potential adverse impacts on fuel supplies if there were larg e-scale fuel switching, the triggering of NSR requirements, and the generation of wastewater and sludge from flue gas desulfurization systems. Conversely, additional controls for SO 2 , NOx, and ammonia would have beneficial environmental impacts by reduc ing mercury emissions, acid deposition and nitrogen deposition to water bodies and natural landscapes. Reductions would also result
in decreases in ambient levels of PM 2.5 with corresponding health benefits. The MANEVU states concluded that the energy and non-air quality impacts of additional EGU
controls are reasonable. Main e agrees with this conclusion

Remaining Useful Life of Any Potentially Affected Sources As noted in the MANE-VU Reasonable Progres s 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 perf ormed. Typical life e xpectancies range to 50 years or more. Additionally, implementa tion of air pollution regulations over the years has necessitated emission control retrof its that have increased the expected life spans of many EGUs. The lifetime of an EGU may be extended through repair, repowering, or other strategies if the unit is mo re economical to run than to replace with power from other sources. Extending facili ty lifetime may be particularly likely for a unit serving an area with limited transmissi on to bring in other power. The remaining
useful life of a unit should not be confused with the economic decision of whether or not to continue operating a unit or to re-power or replace it. The cost of environmental compliance is only one of many fact ors involved in such a decision.

11.4.4 Non-EGU SO 2 Emissions Reduction Strategy Outside the MANE-VU Region

In addition to the measures described above, (i.e., BART, low sulfur fuel within MANEVU, and targeted controls on specific E GUs), MANE-VU asked states in neighboring regional planning organizations to consider further non-EGU emissions reductions comparable to those achieved by states loca ted within the MANE-VU region through the application of MANE-VU’s low sulfur fuel strategy. Previous modeling indicated that the MANE-VU low sulfur fuel strategy would achieve a greater than 28 percent reduction
in non-EGU SO 2 emissions by 2018. After consu ltation 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 MR PO regions, implementation of measures capable of achieving SO 2 emission reductions equivale nt to MANE-VU’s 28 percent
reduction in non-EGU SO 2 emissions in 2018.

To model the impact of this strategy on vi sibility at MANE-VU Class I areas, MANEVU had to make reasonable assumptions abou t where the requested emissions reductions

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would occur in the VIST AS and MRPO st ates without knowing precisely how those
reductions would be realized. As a means to approximate a 28 percent reduction in nonEGU SO 2 emissions, the following reduc tions were modeled:

 For control measures in VISTAS and MRPO states:

 Coal-Fired ICI Boilers: SO 2 emissions were reduced by 60 percent

 Oil-Fired ICI boilers: SO 2 emissions were reduced by 75 percent

 ICI Boilers lacking fuel specification: SO 2 emissions were reduced by 50 percent

 For additional controls only in the VISTAS states: SO 2 emissions from other area oil-combustion sources were reduced by 75 percent (based on the same SCCs identified in MANE-VU’s oil strategies list)

This modeling scenario represen ts just one example of realis tic strategies that states
outside of MANE-VU could em ploy to meet the non-EGU SO 2 emissions reductions requested by MANE-VU.

A number of non-MANE-VU states have not in cluded, or may not include, the requested
28 ercent reduction in non-EGU SO 2 emissions in their initial SIPs. The MANE-VU states encourage EPA to hold these states responsible for satisf ying the MANE-VU Ask in the course of preparing their first five-y ear progress reports in order to meet the CAA national goal of remedying any existing visi bility impairment in Class I areas.

Non-EGU SO 2 Emission Reductions Measures Outside the MANE-VU Region are
Reasonable: After EGUs, ICI boilers and heater s are the next largest class of SO 2 emitters. ICI boilers are thus a logical c hoice among non-EGU sources for consideration
of additional SO 2 control measures.

ICI Boiler Control Options Air pollution reduction and c ontrol technologies for ICI boilers have advanced substantially over the past 25 years. Howeve r, according to the 1998 survey of industrial boilers by EPA (2004), only 2 percent of gas- fired boilers and 3 pe rcent of oil-fired boilers had installed any kind of air pollution c ontrol device. A larger percentage of coalfired boilers had installed ai r pollution control devices: specifically, 47 percent had installed some type of control device, mainlyto control particulate matter (PM). Postcombustion SO 2 controls were used by less than one percent of industrial boilers in 1998, with the exception of boilers firing petroleum coke (2 percen t of boilers firing petroleum coke had acid scrubbers). A small percen tage of industrial boilers had combustion controls in place in 1998, although since 1998, additional low-NO

X firing systems may
have been installed since that date.

Almost all SO 2 emission control technologies fall in the category of reducing SO 2 after its formation, as opposed to minimizing its fo rmation during combustion. The method of
SO 2 control appropriate for any i ndividual ICI boiler is depende nt upon the type of boiler, type of fuel, capacity utilizat ion, and the types and staging of other air pollution control

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devices. Ho wever, cost-effective emi ssions reduction technologies for SO 2 are available and are effective in reducing emissions from th e exhaust gas stream of ICI boilers. Postcombustion SO 2 control is accomplished by reacting the SO 2 in the gas with a reagent (usually calcium- or sodium-b ased) and removing the resultin g product (a sulfate/sulfite) for disposal or commercial use, depending on the technology used. SO 2 reduction technologies are commonly referred to as Flue Gas Desulfurization (FGD) and are usually described in terms of the proce ss conditions (wet versus dry), byproduct utilization (throwaway versus saleable) and reagent utiliz ation (once-through versus regenerable).

The exceptions to the nearly universal use of post-combustion controls are found in fuel switching, coal cleaning, and fluidized bed bo ilers, in which limestone is added to the
fuel in the combustion chamber. SO 2 control options for ICI boilers are outlined in Table 11-7. Further descriptions of these SO 2 control technology options are available in Chapter 4 of the MANE-VU Reasonable Progress Report (Attachment T).

The SO 2 removal efficiency of these controls va ries from 20 to 99+ percent, depending upon the fuel type and control strategy. For co al-fired boilers, opti ons include switching to low-sulfur coal, coal cleaning, wet FGD, dry FGD, and spray dryers. The overall SO 2 reductions vary from a low of 20 to 25 percen t for switching to low-sulfur fuel(s) to a high of 60 to 95 percent for wet FGD and sp ray dry FGD. The majority of control strategies, however, are capable of achievi ng a 60 percent or grea ter reduction. Thus, assuming that coal-fired ICI boilers adopt vary ing levels of controls, with most choosing a 50 to 70 percent reduction stra tegy and fewer choosing either the 20 percent or the 90 percent reduction strategy, the region-wide average is like ly to be in the range of a 60 percent reduction in SO 2 emissions. This assumption is validated by the data which documents that wet FGD systems represent 85 percent of the FGD systems in use in the United States and that FGD systems have an average SO 2 removal efficiency of 78 percent. MANE-VU’s modeling of a 60 percent reduction in SO 2 emission from coalfired ICI boilers is therefore reasonable.

For oil-fired boilers, options in clude switching to a lo wer sulfur fuel (e.g., oil or natural gas), dry FGD, and spray dryers. The overall SO 2 reductions vary from a low of 40 to 60 percent for dry FGD, to a high of 60 to 95 percent for spray dry FGD. For comparison, the MANE-VU low sulfur fuel strategy a ssumes a 50 to 90 percent reduction in SO 2 emissions from oil-fired ICI boi lers. Assuming a typical distri bution of control strategies chosen by the sources, MANE-VU’s modeling of an average 75 percent reduction in SO 2 emission from oil-fired ICI boilers is reasonable.

For ICI boilers in which a fuel was notspecified, a 50 pe rcent reduction in SO 2 emissions was assumed. ICI boilers in this categor y include those outside the MANE-VU region for which the current inventory did not specify the type of fuel burned. Because a response was not received from the MRPO, this assumption also encompasses some of the uncertainty regarding the implementa tion of MANE-VU’s non-EGU Ask. Given the paucity of data, a lower reduction in SO 2 emissions (50 percent) was assumed in this category than for coal- or oil-fired ICI boile rs. Implementation of one or more of the

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suggested S O 2 control options capable of achieving an average 50 percent SO 2 reduction at these sources is a reasonable assumption.
Table 11-7
Available SO 2 Control Options for ICI Boilers

Technology Description Applicability Performance

Switch to a Low Sulfur Coal (generally <1% sulfur) Replace high-sulfur

bituminous coal combustion
with lower-sulfur coal Potential control measure
for all coal-fired ICIs currently using coal with high sulfur content 50-80% reduction in SO 2 emissions by switching to a
lower-sulfur coal

Switch to Natural Gas (virtually 0% sulfur) Replace coal combustion with natural gas Potential control measure
for all coal-fired ICIs Virtually eliminate SO 2 emissions by switching to natural gas

Switch to a Lower Sulfur Oil Replace higher-sulfur
residual oil with lower-sulfur distillate oil. Alternatively, replace medium sulfur

distillate oil with ultra-low
sulfur distillate oil Potential control measure
for all oil-fired ICIs currently using higher
sulfur content residual or

distillate oils 50-80% reduction in SO 2 emissions by switching to a
lower-sulfur oil

Coal Cleaning Coal is washed to remove
some of the sulfur and ash prior to combustion Potential control measure
for all coal-fired ICI boilers 20-25% reduction in SO 2 emissions

Combustion Control A reactive material, such as limestone or bi-carbonate, is
introduced into the combustion chamber along
with the fuel Applicable to pulverized
coal-fired boilers and circulating fluidized bed

boilers 40%-85% reductions in SO 2 emissions

Flue Gas Desulfurization (FGD) - W et SO 2 is removed from flue gas by dissolving it in a lime or limestone slurry. (Other

alkaline chemical are sometimes used) Applicable to all coal-fired
ICI boilers 30-95%+ reduction in SO 2 emissions

Flue Gas Desulfurization (FGD) - Spray Dry A fine mist containing lime or

other suitable sorbent is injected directly into flue gas Applicable primarily for boilers currently firing low
to medium sulfur fuels 60-95%+ reduction in SO 2 emissions

Flue Gas Desulfurization (FGD) - Dry Powdered lime or other suitable sorbent is injected directly into flue gas Applicable primarily for boilers currently firing low
to medium sulfur fuels 40-60% reduction in SO 2 emissions

For emissions from other area oil-combus tion sources in the VISTAS region, an SO 2 reduction of 75 percent was assumed. This is equivalent to the MANE-VU low sulfur fuel strategy. The four fact or analysis of this 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-VU concludes that each of the stra tegies assumed for modeling purposes to meet the MANE-VU Ask of a 28 percent reduction in non-EGU
SO 2 emissions is reasonable. States should ha ve no difficulty in meeting this benchmark

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in ligh t of the control efficiencies that are attainable at reasonable costs with retrofit technologies that are availa ble for ICI boilers today.

Costs of Compliance
Industrial boilers have a wider range of sizes than EGUs and often operate over a wider range of capacities. Thus, cost estimates for the same technologies will generally span a relatively larger range, and costs for individu al boilers will depend on the capacity of the boiler and typical operating condi tions. In general, cost-eff ectiveness increases as boiler size and capacity factor (a measure of boiler utilization) increases.

MANE-VU’s Reasonable Progress Report (Attac hment T) provides emission control cost
estimates for ICI boilers in the range of $130 per ton to $11,000 per ton, a very wide range due to the variability of sources and control options in this category. 56 All costs presented below for emission controls on ICI boilers are borrowed from this report. Dollar amounts originated from EPA publicati ons cited in the report and have been converted to 2006 dollars using a conversi on factor from www.inflationdata.com.

o Cost of Fuel Switching: Although fuel switching can be a ve ry effective m eans of reducing SO 2 emissions (reductions of 50 to 99.9 percent are possible) , burning low-sulfur fuel may not be a technically feasible or economically practical SO 2 control alternative for every ICI coalfired boiler. Factors impacti ng applicability include the char acteristics of the plant and the particular type of fuel change being considered. Additionally, switching to a lower
sulfur coal can affect fu el handling systems, boiler performance, PM control effectiveness, and ash handling systems. Oil-fi red boilers switching to a lower sulfur fuel of the same grade (e.g., switching from #6 fuel oil at 2.0%S to #6 fuel oil at 0.5% S) do not typically encounter thes e issues; please see Section 11.4.2 for a discussion of the
costs and issues associated with sw itching to low sulfur fuel oil.

The costs of coal fuel switching, including s ubstitution or blending with a low-sulfur coal, can be attributed to tw o main reasons: the cost of low-sulfur coal compared to higher sulfur coal (inc luding coal’s heating value), and th e cost of any necessary boiler or coal handling equipment modifi cations. Many plants will be able to switch from highsulfur to low-sulfur bituminous coal w ithout serious difficulty, but switching from bituminous to sub-bituminous coal may requi re potentially significant investments and modifications to an existing plant. Even if a lower sulfur fuel is available, it may not be cost competitive if it must be transported l ong distances from the supplier or supplied in small quantities. It also may be more cost-effective to burn a higher sulfur fuel supplied by nearby suppliers and to use a post-combustion control device.

Switching from coal combustion to natural gas combustion virtually eliminates SO 2 emissions. It is technically feasible to switch from coal to natural gas, but the wide variation in natural gas process means that it may be uneconomical to consider this option for large ICIs due to the fuel quantity necessary and the price of natu ral gas. Natural gas

56 MANE-VU’s Reasonable Progress Report is entitled “Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I Areas” prepared by MACTEC for MARAMA, dated July 9, 2007.

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83 363 294 231

14 1,286 1,040 818

50 360 291 229

83 212 171 134 3.43%- sulfur
coal 85 is currently about twice tim es th e price of coal in terms of he ating value, but has been as high as seven times the price of coal in recent years.

o Cost of Coal Cleaning The World Bank, an organization which assists with economic and technological needs in developing countries, reports that the cost of physically cleani ng coal varies from $1 to $10 per ton of coal cleaned, depending on the coal quality, the cleaning process used, and the degree of cleaning desired. In most cases the costs were found to be between $1 and $5 per ton of coal cleaned. The effectivene ss of coal cleaning is typically a 20 to 25 percent reduction in SO 2 emissions. Coal cleaning also increases the heating value of the fuel by a small amount.

o Cost of Combustion Controls Dry sorbent injection (DSI) sy stems have lower capital a nd operation costs than postcombustion FGD systems because of the simplicity of the DSI design, lower water use requirements, and smaller land area requireme nts. Table 11-8 presents the estimated costs of adding DSI-based SO 2 controls to ICI boilers based fo r different boiler sizes, fuel types, and capacity factors.

o Cost of FGD Installation of post-combustion SO 2 controls in the form of FGD has several impacts on facility operations, maintenance, and waste handling procedures. FGD systems generally require substantial land area for construction of the absorber towers, sorbent tanks, and waste handling equipment. The facility costs therefore depend on the cost and availability of space for constr uction of the FGD system. Solid waste handling is another
factor that influences the cost of FGD control systems. Signi ficant waste material may be generated that requires disposal. These costs may be mitigated, however, by utilization of a forced oxidation FGD process that produces commercial-grade gypsum, which may be sold as a raw material for other commercial processes.

Table 11-8 Estimated Dry Sorbent Injection (DSI) Costs for ICI Boilers (2006 dollars)

152 100
MMBTU/hr 250
MMBTU/hr 1,000
MMBTU/hr

14 4,686 3,793 2,979

50 1,312 1,062 834

83 772 624 490

14 2,732 2,212 1,737

50 765 619 486

83 450 364 286

14 2,205 1,786 1,402

50 617 500 392 Cost Effectiveness ($/Ton of SO 2 )

Fuel SO 2 Reduction (%) Capacity Factor (%)

2%-sulfur coal

3.43%-sulfur
coal

2%-sulfur coal 40

40

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Table11-9 p resents the total estimated co st effectiveness of adding FGD-based SO 2 controls for different boiler sizes, fuel types, and capacity factors. There is no indication that these cost data include revenue from gyps um sales, which would partially offset the
costs of FGD controls.

Carbon dioxide is also emitted as a by-product of FGD, therefore impacts of increased
carbon emissions would need to be considered. CO 2 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, co sts related to increased carbon emissions from FGD cannot yet be assessed.

MANE-VU’s request for a 28 percent reduction in non-EGU SO 2 emissions allows states flexibility in determining which sources to cont rol, so that the most cost-effective control measures can be adopted and implemented over the next 10 years. Given the wide range of control options and costs available for th is purpose, MANE-VU has concluded that its request for a 28 percen t reduction in non-EGU SO 2 emissions is reasonable. Maine
concurs with this conclusion.

Time Necessary for Compliance For pre- and post-combustion SO 2 emission controls, engineer ing and construction lead times will vary between 2 and 5 years, dependi ng 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 descri bed, and states generally have a 2-year period for compliance with RACT rules.

Table 11-9
Estimated FGD Costs For ICI Boilers

(2006 dollars)

100

MMBTU/hr 250

MMBTU/hr 1,000

MMBTU/h r 14 3,781 2,637 1,817

50 1,379 1,059 828
83 1,006 814 676
14 4,571 3,150 2,119 50 1,605 1,207 928 83 1,147 906 744 14 4,183 2,786 1,601 50 1,290 899 567

83 843 607 407 14 3,642 2,890 1,909 50 1,116 875 601

83 709 563 398 14 4,797 3,693 2,426 50 1,415 1,106 751

83 892 705 492 14 10,843 8,325 5,424 Fuel SO 2 Reduction (%) Capacity Factor (%) Cost Effectiveness ($/Ton of SO 2 ) Technology

High-sulfur

coal 40

Lowersulfur coal 40 FGD (Dry)

FGD (Dry)

Coal 85

High-sulfur

coal 85 FGD (Spray dry)

FGD (Spray dry)

Lowersulfur coal FGD (W et) 40

Oil FGD (W et) 40

153 5 0 2,269 1,765 1,184
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For the purp oses of this review, it is assumed that a 2-year period after SIP submittal is adequate for the installation of pre-combusti on controls (fuel switchi ng or cleaning) and a 3-year period for the installation of post -combustion controls. MANE-VU has therefore
concluded that there is sufficient time betw een 2008 and 2018 for the affected states to adopt emission control requirements and for aff ected sources to install controls necessary to meet MANE-VU’s requested SO 2 emission reductions from non-EGU sources. Maine
concurs with this conclusion.

Energy and Non-Air Quality Enviro nmental Impacts of Compliance The primary energy impact of pre- or post-co mbustion control alternatives is a potential increase in electricity usage. Fuel switchi ng and cleaning do not si gnificantly affect the efficiency of the boiler itself, but require ad ditional energy to clean or blend coal. FGD systems typically operate with high-pressure drops across the control equipment, and therefore consume significant amounts of elec tricity to operate bl owers and circulation pumps. In addition, some combinations of FGD technology and plant configuration may require flue gas reheating to prevent physical damage to equipment, resulting in higher fuel usage.

The primary non-air environmental impacts of fu el switching derive from transportation of the fuel. Secondary environmental impact s derive from waste disposal and material handling operations (e.g. fugitive dust). For FGD systems, the generation of wastewater and sludge from the SO 2 removal process is a considera tion. Wastewater from the FGD systems will increase sulfate, metals, and solids loading at the receiving wastewater treatment facility, resulting in potential im pacts to operating cost, energy requirements, and effluent water quality. Processing of th e wastewater sludge can require energy for stabilization and/or dewatering, and transpor ting the sludge to the landfill has additional environmental impacts.

Fuel switching to a low-sulfur distillate fuel oil has a variety of be neficial 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 Devel opment Authority, (NYSERDA) 57 , lowering the fuel sulfur content from 1,400 ppm to 500 ppm will reduce boiler deposits by a factor of two. These reductions in buildup of deposits result in longer service interval s between cleanings.

Reducing SO 2 emissions from ICI boilers would have positive environmental and health impacts. SO 2 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 PM 2.5 , a significant contributor to premature morbidity and illness in individuals with heart or lung conditions.

57 Reference 10 in Attachment T.

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MANE-VU has concluded that the energy and non-air environm ental impacts of controlling SO 2 emissions from ICI boilers are justifie d in light of the beneficial impacts on regional haze, fine particulate air pollu tion, acid rain, and equipment operation, as
described above. Maine concurs with this conclusion.

Remaining Useful Life of Any Potentially Affected Sources Available information for remaining useful lif e estimates of ICI boilers indicates a wide range of operating time, depending on size of the unit, capacity factor, and level of maintenance performed. Typical life span s range from about 10 years up to over 30 years. However, the remaining useful life of a source is highly vari able; and ol der units are not likely to be retrofitted with expensive emission controls. Given the typical range of life expectancies of ICI boilers, the technical options available, and the flexibility that
non-MANE-VU states would have to meet the Ask, MANE has concluded that its request for a 28 percent reduction in non-EGU SO 2 emissions is reasonable. Maine concurs with
this conclusion.

11.5 Visibility Impacts of Addi tion al Reasonable Controls

MANE-VU’s evaluations included modeling to estimate the visibility effects of various
elements of the Maine/MANE-VU Ask. Th is modeling is desc ribed in NESCAUM’s report entitled “MANE-VU Modeling for R easonable Progress Goals,” February 2008, (Attachment P). NESCAUM also conducted more recent, revised modeling to assess the effects of all haze reduction strategies comb ined. The latter modeling is described in NESCAUM’s report entitled “ 2018 Visibility Projections,” March 2008, (Attachment Q). The following information about the effects of specific strategies is taken from these reports.

The NESCAUM modeling demonstrates that si gnificant visibility benefits will accrue from implementation of the additional re asonable control measures described in Subsection 11.4, above. Figures 11.3 and 11.4 desc ribe the results of this modeling. In the first of the two figures, the light yellow bars represent expected visibility at MANEVU Class I areas in 2018. Comparison of these values with the 2018 “glide slope” values (the plum-colored second bars from th e left) shows that all areas are expected to experience visibility improvements that meet or exceed the uniform rate of progress calculated for each area. The second figure s hows that, for the 20 percent of days having the best visibility, expected visibility in 2018 will be better than it is today at all
locations.

In conclusion, the reasonable progress goals for Class I areas proposed by the MANE-VU states are found to be consistent with the stated national goals of preventing further visibility degradation while making timely pr ogress toward achieving natural visibility conditions in Class I areas by 2064.

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Figure 11-3 Demonstration of Required and Reasonab le Visibility Pro gress for 20% Worst Visibility Days

V isibility Progress for 20% Worst Days

0 5 10 15 20 25 30 35

Acadia Brigantine Great Gulf Lye Brook MoosehornVisibility (deciviews)

2002 Baseline 2018 Glideslope 2018 Projected Progress Natural ( Visibilit y Im p rovements Must be Made at Reasonable Rate )

Figure 11-4 Demonstration of Required and Visibility Ma intenance for 20% Best Visibility Days

Visibility Progr ess For 20% Best Days

0 2 4 6 8 10 12 14 16

Acadia Brigantine Great Gulf Lye Brook MoosehornVisibility (deciviews)

2002 Baseline 2018 Projected Progress (Baseline Visibility Must be Maintained or Improved)

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### 12. Long Term Strategy

40 CFR Section 51.308(d)(3) requires the State of Maine to submit a long-term strategy that addresses regional haze visibility impairment for each mandatory Class I Federal area within and outside the State which may be affected by emissions from within Maine.
These Class I areas include: Acadia Na tional Park; Great Gulf Wilderness Area; Presidential Range-Dry River Wilderness; Moosehorn Wilderness and Roosevelt Campobello International Park. The long- term strategy must include enforceable emissions limitations, compliance schedules, an d 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, Re gional Planning and Consultation, Maine
consulted with states and tribes both with in and outside MANE-VU when developing the emission management strategies in this SI P. The following describes how Maine meets the long-term strategy requirements of the Regional Haze Rule.

Maine’s long term strategy includes enfo rceable emissions limitations, compliance schedules, and other measures necessary to achieve the reasonable progress goals
established in Section 11. Add itional measures may be reasonab le to adopt at a later date
after further considerat ion and review. In developing th is long-term stra tegy, Maine also considered the requirements of the Clean Air Act, Section 110(a)(2 )9D)(i)(ii), pertaining to interstate and international transport of pollutants. Maine has previously addressed this issue in its “Transport SIP Revision,” submitted to EPA on April 24, 2008. As that document observed, states must include pr ovisions in their implementation plans to prohibit any source or activity from emitting air pollutants in amounts that would interfere with another state’s ability to prev ent significant deteriorat ion of air quality and visibility. The long-term strategy presented he rein is designed to protect visibility in
Maine as well as in areas out side of Maine that are affected by Maine emissions.

12.1 Overview of the Long Term Strategy Development Process

The regional strategy developm ent process id entified reasonable measures that would reduce emissions contributing to visibility impairment at MANE-VU Class I areas by 2018 or earlier. The process for identifyi ng potential emission reduction measures and
the technical basis for the l ong term strategy is discusse d in the following sections.

As a MANE-VU member and participant, Maine supported a number of technical analyses that were developed to assist th e MANE-VU states in de ciding which regional haze control measures to pursue. These analyses are documented in the following reports:

 “Contributions to Regional Haze in th e Northeast and Mid-Atlantic United States” (also known as the Contribution Assessment), August 3, 2006, NESCAUM (Attachment A).

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 “Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning Model®” (also known as the CAIR + Report), May 30. 2007, ICF/MARAMA (Attachment U).

 “Assessment of Reasonable Progress fo r Regional Haze in MANE-VU Class I Areas” (also known as the Reasona ble 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 Op tions for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers , Cement Plants and Paper and Pulp Facilities,” March 7, 2005, NESCAUM (Attachment R).

12.2 The Regional Process for Id entifying Potential Strategies

MANE-VU reviewed a wide range of potential control m easur es to reduce regional haze at the affected Class I areas by the 2018 mile stone. The process of choosing a set of proposed regional haze control measures st arted in late 2005. The Ozone Transport Commission (OTC) selected a contracting firm to assist with the analysis of ozone and regional haze control measure options, and provi ded the contractor with a “master list” of some 900 potential control measures, ba sed on experience and previous state implementation plan work. With the help of an internal OTC control measure workgroup,
the contractor narrowed the list of availabl e regional haze control measures for further consideration by MANE-VU.

MANE-VU then developed an interim list of control measures for regional haze. The
identified control measures can be di vided into three ge neral categories:

 Beyond-CAIR sulfate reductions from el ectricity generati ng 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 combusti on, 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 (Attachmen t U) documents MANE-VU’s assessment of the costs of CAIR and provides a cost analysis for additional SO 2 and NO

x controls at
EGUs in the eastern United States. Th e Reasonable Progress Report documents the
assessment of control measures for EGUs a nd the other source categories selected for analysis. Further analysis is provided in the NESCAUM document entitled, “Assessment of Control Technology Options for BART-Elig ible Sources: Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and Pulp Facilities.”

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The beyond-CAIR EGU strategy quickly becam e central to th e MANE-VU long term strategy planning efforts, since EGU sulfate emissions are the largest contributor to visibility impairment at M ANE-VU Class I areas. Similarly, a low-sulfur oil strategy gained traction after a NESC AUM-initiated conference wi th refiners and fuel-oil suppliers concluded that such a strategy could fully implemented by 2018. Thus the lowsulfur heating oil and the oil- fired ICI boiler sector control measures merged into an overall strategy requiring the use of low-sulfur oil. Under this st rategy, low-sulfur oil would be required for all residential and co mmercial heating units and all ICI boilers burning #2, #4, or #6 fuel oils.

During MANE-VU’s internal consultation meeting in March 2007, member states
reviewed the interim list of c ontrol measures to make additional refinements. States determined, for example, that there may be too few coal-fired ICI boilers in the MANEVU states for that to be considered as a “r egional” strategy, but those sources could be controlled on a state-by-state basis. The MANE-VU members also decided that lime and cement kilns, of which there are few in the MANE-VU region, would best be handled via the BART determination process. Reside ntial wood burning and outdoor wood boilers
remained on the list for those states where lo calized visibility impacts are a consideration, even though emissions from these sources are primarily organic carbon and direct particulate mater. Finally, the MANE-VU memb ership decided that the issue of outdoor wood burning should be examined further by individual states, because of concerns related to enforcement and penetr ation of existing state regulations 58

.

12. 3 The Technical Basis for Strategy Development

40 CFR Section 51.308(d)(3)(iii) requires Main e to docum ent 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 th at the Maine emission reductions, when
coordinated with those of other States and Tribes, are sufficient to achieve reasonable progress goals in Class I areas affected by emissions originating in Maine.

The emission reductions necessary to meet reas onable progress goals in the Class I areas affected by Maine are described in the following documents:

 “Baseline and Natural Background Visibi lity Conditions—Considerations and Proposed Approach to the Calculation of Baseline and Natural Background Visibility Conditions at MANE- VU Class I Areas,” December 31, 2006, NESCAUM (Attachment G).

 “The Nature of the Fine Particle a nd Regional Haze Air Quality Problems in the MANE-VU Region: A Conceptu al Description,” November 2, 2006, NESCAUM (Attachment V).

58 Maine regulates outdoor burning activities through statute at 12 MRSA §9321 et seq. and through its 06- 096 CMR Chapter 102 Open Burning and 06-096 CMR Chapter 150 Control of Emissions From Outdoor
Wood Boilers rule.

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 “Contributions to Regional Haze in th e Northeast and Mid-Atlantic United States (also known as the Contri bution Assessment),” August 31, 2006, NESCAUM (Attachment A).

 “Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning Model® (also known as the CAIR + Report) May 30, 2007, ICF/MARAMA (Attachment U).

 “Assessment of Reasonable Progress fo r Regional Haze in MANE-VU Class I Areas” (called the Reasonable Progress Report), July 9, 2007, MACTEC/MARAMA) (Attachment T).

 “Five-Factor Analysis of BART-Eligible Sources: Survey of Options for Conducting BART Determinations,” June 1, 2007, NESCAUM (Attachment N).

 “Assessment of Control Technology Op tions for BART-Eligible Sources: Steam Electric Boilers, Industrial Boilers , Cement Plants and Paper and Pulp Facilities,” March 7, 2005, NESCAUM (Attachment R).

 “MANE-VU Modeling for Reasonable Pr ogress Goals: Model Performance Evaluation, Pollution Apportionment, and Control Measure Benefits,” February 7, 2008, NESCAUM (Attachment P).

 “2018 Visibility Projections,” Marc h 31, 2008, NESCAUM (Attachment Q).

In addition, Maine relied on analyses c onducted by neighboring RPOs, including the following documents, which are available upon reque st but are not incorp orated 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, Main e worked with the other members of MANE-VU and with the Ozone Transport Co mmission to evaluate a large number of potential emission reduction strategies covering a wide range of sources of SO 2 and other pollutants contributing to regional haze. 40 CFR 51.308(d)(3)(v) requires states to
consider several factors in de veloping their long-term strate gies. Operatin g within this framework and using the available informati on about emissions and potential impacts, the MANE-VU Reasonable Progress Workgroup selected the foll owing source categories for detailed analysis:

 Coal and oil-fired electric generating units, (EGUs);

 Point and area source industrial, commercial and institutional (ICI) boilers;

 Cement and lime kilns;

 Sources capable of using lo w-sulfur heating oil; and

 Residential wood combus tion and open burning.

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These efforts led to the s election of the emi ssion 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 em ission reductions from ongoing pollution control programs. In developing its Long Term Strategy, Maine considered emission control programs bei ng 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 al ready made by Maine and other states to implement air pollution control measures for EGU point sources, non-EGU point sources, and area sources, respectively. Th ese control measures are the very same
measures that were included in the 2018 emi ssions inventory and used in the modeling.
While these control measures were not desi gned expressly for the purpose of improving visibility, the pollutants they c ontrol include those that contri bute to visibility impairment
in MANE-VU Class I Areas.

MANE-VU’s 2018 “beyond on the way” (BOT W) emissions inventory accounts for emission controls already in place as well as emission controls that are not yet finalized but are likely to achieve additional re ductions by 2018. The BOTW inventory was developed based on the MANE-VU 2002 Vers ion 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 contro l measures that were developed for ozone SIPs that were not yet on the books in some states. For some states it also included
controls that were under consideration for Regional Haze SIPs that have not yet been adopted. More information may be found in the following documents:

 “ Development of Emissions Projections for 2009, 2012, and 2018 for NonEGU Point, Area, and Non-road Sources in the MANE-VU Region,” February 2007, MACTEC/MARAMA (Attachment J)

 “Documentation of 2018 Emissions from Electric Generating Units in Eastern U.S. for MANE-VU Regional Haze Modeling,” April 28, 2008, Alpine Geophysics/MARAMA (Attachment S)

 “MANE-VU Modeling for Reasonable Pr ogress Goals: Model Performance Evaluation, Pollution Apportionment, and C ontrol Measure Benefits,” February 7, 2008, NESCAUM (Attachment P)

 “2018 Visibility Projections,” Ma rch 31, 2008, NESCAUM (Attachment Q)

12.4.1 EGU Emissions Controls Expected by 2018

The following EGU emission reduction programs were included in the modeling used to develop the reasonable progress goals. These programs represent the greatest opportunities for reducing SO 2 emissions at Class I areas in the MANE-VU region and serve as the starting point for MANE-VU’s l ong-term strategy to mitigate regional haze.

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Clean Air In terstate Rule (CAIR) . This major federal rule has been remanded to EPA to correct deficiencies. The original CAIR im posed permanent caps on sulfur dioxide (SO 2 ) and nitrogen oxides (NO

x ) in the eastern United States by 2015. When fully effective, this program was expected to reduce SO 2 emissions in the CAIR region by up to 70 percent. The first phase of CAIR was im plemented on an interim basis in 2009, and EPA is expected to issue a revised CAIR rule in response to the remand in 2010 or 2011. To predict future emissions from EGUs after implementation of CAIR, MANE-VU used the Integrated Planning Model (IPM). 59 Adjustments to the IPM output were made to provide a more accurate representation of anticip ated controls at specific EGU sou documented in the Alpine Geophysics report list ed above. In making these adjustments, emission controls originating from the follo wing states and regional programs were
considered. rces as

Connecticut EGU Regulations : Connecticut adopted the following regulations governing
EGU emissions:

 Regulations of Connecticut State Ag encies (RCSA) section 22a-174- 19a , limiting
the SO 2 emission rate to 0.33 lb SO 2 /MMBtu for fossil fuel-fired EGUs greater than 15 MW that are also Title IV sources. (Implementation status - 2007).

 RCSA section 22a-174-22 , limiting the non-ozone seasonal NO X emission rate to
0.15 lb NO X /MMBtu for fossil fuel-fired EGUs greater than 15 MW. (Implementation status - 2007).

 Connecticut General St atutes section 22a-199 , limiting the mercury (Hg) emission rate to 0.0000006 lb Hg/MMBtu for all coal-fired EGUs or alternatively coal-fired EGUs can meet a 90% Hg em ission reduction. (Implementation status - 2008).

Delaware EGU Regulations : Delaware adopted the following regulations governing
EGU emissions:

1. Reg. 1144, Control of Stationary Generator Emissions , SO 2 , PM, VOC and NO

x emission control, state-wide, effective January 2006.

2. Reg. 1146, EGUs, Electric Generating Unit (EGU) Multi-Pollutant Regulation

, SO 2 and NO

x emission control, state-wide, effective December 2007. SO 2 reductions will be more than regulation specifies.

59 The IPM model runs also anticipated the implemen tation of EPA’s Clean Air Mercury Rule (CAMR), which was recently vacated by the courts. However, MANE-VU believes that the adjustments made to the predicted SO 2 emissions from EGUs will have a larger e ffect on the air quality modeling analysis
conducted for this SIP than will th e vacatur of the CAMR rule. The emission adjustments were based on
state’s comments on the actual levels of SO 2 controls expected to be insta lled in response to state-specific regulations and EPA’s CAIR rule. MANE-VU believes these adjustments improve the reliability of both the emission inventory and modeling results.

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3. Regulation No. 1148, Control of Stati onary Combustion Turbine Electric Generating Unit Emissions , requiring SO2, NO
x and PM 2.5 emission controls, state-wide, effective January 2007.

Delaware estimates that these regulations w ill result in the following emission reductions
for affected units: SO 2 emissions of 32,630 tons in 2002 will decline to 8,137 tons in 2018 (a 75 percent reduction); NO

x emissions of 8,735 tons in 2002 will decline to 3,740 tons in 2018 (a 57 percent reduction).

Also, Delaware anticipates the following reduc tions resulting from the consent decree with the Valero Refinery Delaware City, DE (formerly Motiva, Valero Enterprises). 2002
SO 2 levels of 29,747 tons will drop to 608 tons in 2018 (a 98 percent reduction). NO

x 2002 levels of 1,022 tons will fall to 102 tons in 2018 (a 90 percent reduction).

Maine EGU Regulations: Chapter 145 NO X Control Program, limits the NO X emission
rate to 0.22 lb NO X /MMBtu for fossil fuel-fired units greater than 25 MW built before 1995 with a heat input capacity between 250 and 750 MMBtu/hr, and which also limits
the NO X emission rate to 0.17 lb NO X /MMBtu for fossil fuel-fir ed units greater than 25 MW built before 1995 with a heat input capac ity greater than 750 MMBtu/hr. (effective 2007)

Massachusetts EGU Regulations : Based on the Massachusetts Department of
Environmental Protection’s 310 CMR 7.29, Emissions Standards for Power Plants, adopted in 2001, six of the larg est fossil fuel-fired power plants in Massachusetts must comply with emissions limitations for NO

x , SO 2 , mercury, and CO 2 . These regulations will achieve an approximately 50 percent reduction in NO

x emissions and a 50 - 75 percent reduction in SO 2 emissions compared to prev ious emissions. Depending upon the compliance path selected by the affected fac ilities, the facilities will comply with the output-based NO

x and SO 2 standards between 2004 and 2008. This regulation also limits the six grandfathered EGUs to a CO 2 emisison rate of 1,800 lb/MWh.

New Hampshire EGU Regulations : New Hampshire adopted the following regulations governing EGU emissions:

 Chapter Env-A 2900 capping NOx emissi ons at 3,644 tons NO X per year, SO 2 emissions at 7,289 tons SO 2 per year, and CO 2 emissions at 5,425,866 tons CO 2 per year for all existing fossil steam units by December 31, 2006.

 Chapter Env-A 3200 NOx Budget Trading Program limiting ozone season NO X emissions on all fossil fuel-fired EGUs greater than 15 MW to 0.15 lb/MMBtu, effective November 2, 2007.

New Jersey New Source Review Settlement Agreements : The New Jersey settlement agreement with PSEG required the following actions for specific EGUs:

 Bergen Unit #2 : Repower to combined cycle by December 31, 2002.

 Hudson Unit #2 : install Dry FGD or approved alternative technology by Dec. 31,

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2006 to control SO 2 emissions, and operate the cont rol technology at all times the unit operates to limit SO 2 emissions to 0.15 lb SO 2 /MMBtu; install SCR or approved alternative technology by May 1, 2007 to control NO X emissions and operate the control technology year-round to limit NO X emissions to 0.1 lb
NO
x /MMBtu; and install a baghouse or appr oved alternative technology by May 1,
2007 to control PM emissions and limit PM emissions to 0.015 lb PM/MMBtu.

 Mercer Unit #1 : install Dry FGD or approved alternative technology by Dec. 31,
2010 to control SO 2 emissions and operate the control technology at all times the unit operates to limit SO 2 emissions to 0.15 lb SO 2 /MMBtu, and install SCR or approved alternative technology by 2005 to control NO X emissions, and operate the control technology ozone season only in 2005 and year-round by May 1, 2006 to
limit NO X emissions to 0.13 lb NO X /MMBtu.

 For Mercer Unit #2 : install Dry FGD or approved alternative technology by Dec. 31, 2012 to control SO 2 emissions, and operate the c ontrol technology at all times the unit operates to limit SO 2 emissions to 0.15 lb SO 2 /MMBtu, and install SCR or approved alternative technology by 2004 to control NO X emissions, and operate the control technology ozone season only in 2004 and year-round by May 1, 2006 to
limit NO X emissions to 0.13 lb NO X /MMBtu.

The New Jersey settlement also requires co al with monthly aver age sulfur content no greater than 2% at un its operating an FGD.

New York EGU Regulations : New York adopted the fo llowing regulations governing
EGUs:

Title 6 NYCRR Parts 237, Acid Deposition Reduction NO
x Budget Trading Program,
limits NO X emissions on all fossil fuel-fired E GUs greater than 25 MW to a non-ozone season cap of 39,908 tons in 2007.

Title 6 NYCRR Parts 238, Acid Deposition Reduction SO 2 Budget Trading Program
limits annual SO 2 emissions from all fossil fuel-fired EGUs greater than 25 MW to an
annual SO 2 cap of 197,046 tons SO 2 /year, starting in 2007 and an annual SO 2 cap of 131,364 tons SO 2 /year starting in 2008.

North Carolina Clean Smokestacks Act : Enacted in 2002, this le gislation requires that coal-fired EGUs achieve a 77 percent cut in nitrogen oxide (NO

x ) emissions by 2009 and a 73 percent cut in sulfur dioxide (SO 2 ) emissions by 2013. This legislation also establishes annual caps on both SO 2 and NO

x emissions for the two primary utility companies in North Carolina, Duke Energy and Progress Energy. Th ese 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:

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 Santee Cooper : A 2004 consent agreement calls for Santee Cooper in South Carolina to install and commence opera tion of continuous emission control equipment for PM/SO 2 /NO

x emissions; comply with system-wide annual
PM/SO 2 /NO

x emissions limits; agree not to buy, sell or trade SO 2 /NO

x allowances allocated to Santee Cooper Sy stem as a result of said agreement; and to comply with emission unit limits of said agreement.

 TECO : Under a settlement agreement, by 2008, Tampa Electric in Florida will install permanent emissions-control e quipment to meet stringent pollution limits; implement a series of interim pollution reduction measures to reduce emissions while the permanent controls are designed and installed; and retire pollution emission allowances that Tampa Electric or others could use, or sell to others, to emit additional NO

x , SO 2 and PM.

 VEPCO : Virginia Electric and Power Co. agreed to spend $1.2 billion between by 2013 to elimin ate 237,000 tons of SO 2 and NO

x emissions each year from eight coal-fired electricity generating plants in Virginia and West Virginia.

 Gulf Power 7 : A 2002 agreement calls for Gulf Power to upgrade its operation
to cut NO
x emission rates by 61 percent at its Crist 7 generating plant by 2007 with major reductions beginning in earl y 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 conduc ted an analysis of various control measures as documented in “Development of Emission Projec tions for 2009, 2012, and 2018 for Non-EGU, Area, and Nonroad sources in the MANE-VU Region” (Attachment I). Control factors were applied to the 2018 MANE-VU inventory for non-EGUs to represent the following national, regi onal, or state control measures:

 NO
x SIP Call Phase I (NO

x Budget Trading Program) (except ME, NH and VT)

 NO
x SIP Call Phase II (except ME, NH and VT )

 NO
x RACT in 1-hour Ozone SIPs (already included in the 2002 inventory)

 NO
x OTC 2001 Model Rule for ICI Boilers

 2-, 4-, 7-, and 10-year MACT Standards

 Combustion Turbine and RICE MACT (NO

x co-benefits not includedassumed to be minimal)

 Industrial Boiler/Pr ocess Heater MACT 60

60 The inventory was prepared before the MACT for Industrial Boilers and Process Heaters was vacated. Control efficiency was assume d to be at 4 percent for SO 2 and 40 percent for PM.

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 EPA’s Refinery Enforcement Initiative (Fluid catalytic cracking units and fluid coking units; process heaters an d boilers; flare gas recovery; leak detection and repair; and benzene (wastewater))

In addition, states provided specific control measure info rmation about specific non-EGU sources or regulatory programs in their stat e. For example, several states developed
additional control measures in the course of their planning efforts to reduce ozone within the Ozone Transport Region (OTR). These control measures were included by MANEVU in their inventories used for regional haze modeling. (The affected states may or may not have committed to adopting these measures in their ozone SIPs). For specific states, the ozone reduction strategies includ ed in the modeling would reduce NO

x emissions from the following non-EGU point sources:

 Asphalt production plants in Connecticut, New Jersey, New York, and the District of Columbia;

 Cement kilns in Maine, Maryland, New York, and Pennsylvania; and

 Glass and fiberglass furnaces in Maryla nd, Massachusetts, New Jersey, New York and Pennsylvania.

For other regions, MANE-VU used emission i nventory 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 inco rporated into the modeling include the following consent agreements reflect ed in the VISTAS inventory:

 Dupont: A 2007 agreement calls for E. I. Dupont Nemours & Company’s James River plant to install dual ab sorption pollution c ontrol equipment by September 1, 2009, resulting in emissi on reductions of approximately 1,000
tons SO 2 annually. The James River plant is a non-EGU located in the state of Virginia.

 Stone Container: A 2004 agreement calls for the West Point Paper Mill in Virginia owned by Smurfit/Stone Containe r to control with a wet scrubber the
SO 2 emissions of the #8 Power Boiler. Th is control device should result in reductions of over 3,500 tons of SO 2 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 gene ral, MANE-VU developed the 2018 inventory for area sources by applying growth and control factors to the 2002 Version 3.0 inventory. Area source control factors were developed and incorporated in the modeling for the following national or regional control measures:

 OTC VOC Model Rules (Consumer Produc ts, Architectural and Industrial Maintenance Coatings, Portable Fuel Containers, Mobile Equipment Repair and Refinishing and Solvent Cleaning);

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 Residential Woodstove NSPS; and

 State-specific control stra tegies implemented since 2002.

The following additional control measures we re included in the 2018 analysis to reduce
VOC and NO

x emissions for the following area source categories for some states (as identified below):

 VOC control measures for adhesives a nd sealants (contro ls added in all MANE-VU states except VT);

 VOC control measures for emulsified and cutback asphalt paving (controls added in all MANE-VU states except ME, and VT);

 VOC control measures for consumer pr oducts (controls added in all MANEVU states except VT);

 VOC control measures for portable fuel containers (contr ols added in all MANE-VU states except VT); and;

 NO
x 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 re gions were obtained fr om those Region’s
RPOs. Some of the area source control meas ures listed above may have been developed by states for the primary purpose of reduci ng ozone within the Ozone Transport Region (OTR)- see Subsection 12.4.2 for information on ot her measures included in state’s ozone
SIPs.

12.4.4 Mobile Sources Cont rols Expected by 2018

For the on-road mobile source emission inve ntory, 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 1990 Clean Air Act (CAA) Amendments contain provisions that require passenger cars to capture refueling emissions. In 1994, EPA published the ORVR rule establishing standards for refueling emissions controls for passenger cars and lig ht 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 emi ssion standard of 0.20 grams per gallon of dispensed fuel, which was expected to yiel d a 95 percent reducti on of VOC emissions
over uncontrolled levels. The CAA authorizes EPA to allow state and local agencies to phase out Stage II programs, even in the worst nonattainment areas, once EPA has determined that onboard systems are in “widespread use”.

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Heavy Duty Diesel (2007) Engine Emis sion Standards for Trucks and Buses : EPA set
a PM em issions standard for new heavy-duty engines of 0.01 grams per brakehorsepower-hour (g/bhp-hr), to take full effect for diesel engines in the 2007 model year.
This rule also includes standards for NO

x and non-methane hydrocarbons (NMHC) of 0.20 g/bhp-hr and 0.14 g/bhp-hr , respectively. These NO

x and NMHC standards will be phased-in together between 2007 and 2010 for diesel engines. Sulfur in diesel fuel must be lowered to enable modern pollution-contro l technology to be effective on these trucks and buses. EPA began requiring the use of 500 ppm low sulfur diesel fuel in 1993. In 2006, the highway diesel sulfur content was lo wered to 15ppm (ultra low sulfur diesel).

Tier 2 Motor Vehicle Standards: Tier 2 is a fleet averagin g program, modeled after the
California LEV II standards. Manufacturers can produce vehicles with emissions ranging from relatively dirty to zero, but the mix of vehicles a manuf acturer sells each year must have average NO

x emissions below a specified value. Tier 2 standards became effective in the 2005 model year and are included in th e 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 NONROA D Model used to develop the nonroad
source emissions did not incl ude aircraft, commercial marine, and locomotives, MANEVU’s contractor, MACTEC, developed the in ventory for these source categories. Nonroad mobile source emissions for the 2018 emission inventory were calculated with
EPA’s NONROAD2005 emissions model as in corporated in the NMIM2005 (National Mobile Inventory Model) database. The NONROAD mode l accounts for the emissions
benefits associated with Fede ral non-road equipment emissions control measures such as the following:

 “Control of Air Pollution; Determinati on of Significance for Nonroad Sources
and Emissions Standards for New Nonroa d Compression Ignition Engines At or Above 37 Kilowatts,” 59 FR 31306, June 17, 1994.

 “Control of Emissions of Air Pollution Fr om Nonroad Diesel Engines,” 63 FR 56967, October 23, 1998.

 “Control of Emissions From Nonroa d Large Spark-Ignition Engines and Recreational Engines (Marine and La nd-Based); Final Rule,” 67 FR 68241, November 8, 2002.

 “Control of Emissions of Air Pollution Fr om 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 regions’ RPOs.

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12.5 Additional Reasonable Strategies

As required under 40 CFR Section 51.308(d )(3)(v), Maine and the other MANE-VU states applied a four-factor analysis to potential contro l m easures for the purpose of establishing reasonable progre ss goals (See Subsection 11.4 for a detailed description).
Reasonable measures include those that th e affected states have already committed themselves to implementing, as described in Subsection 12.4, above. In addition, the
MANE-VU states have identified other c ontrol measures that were found to be reasonable and were included in the modeling th at was used to set reasonable progress goals. (These additional m easures 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 progr ams and the additional reasonable control measures described below- comprise the l ong-term strategy for improving visibility at
MANE-VU Class I Areas.

Specifically, the MANE-VU long-term st rategy includes the following additional measures to reduce pollutants that cause regional haze:

 Timely implementation of BART requirements;

 A low sulfur fuel oil strategy in the in ner zone states (New Jersey, New York, Delaware, and Pennsylvania, or portions th ereof) to reduce the sulfur content of:

o Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 2012,

o #4 residual oil to 0.25 percent sulfur by weight by no later than 2012,

o #6 residual oil to 0.3 – 0 .5 percent sulfur by wei ght by no later than 2012,
and

o Further reduce the su lfur content of distillate oil to 15 ppm by 2016;

 A low sulfur fuel oil strategy in the ou ter zone states (the remainder of the MANE-VU region) to reduce the sulfur content of:

o Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 2014,

o #4 residual oil to 0.25 percent-0.50 per cent sulfur by weight by no later than 2018,

o #6 residual oil to no greater than 0.5 percent sulfur by weight by no later than 2018, and

o Further reduce the sulfur content of distillate oil to 15 ppm by 2018 depending on supply and availability;

 A 90 percent or greater reduc tion in sulfur dioxide (SO 2 ) emissions from each of the electric generating un it (EGU) stacks identified by MANE-VU (Attachment W) comprising a total of 167 stacks, dated June 20, 2007) as reasonably anticipated to cause or cont ribute to impairment of vi sibility in each mandatory Class I Federal area in the MANE-VU region. If it is infeasible to achieve that

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level of reduction from a unit, alternative measures will be pursued in such State;
and

 Continued evaluation of other control measures including energy efficiency, alternative clean fuels, and other measures to reduce SO 2 and nitrogen oxide (NO

x ) emissions from all coal-burning facilities by 2018 and new source performance standards for wood combustion.

This suite of additional control measures are those that the MANE-VU states have agreedto pursue for the purpose of mitigating regional haze. The corollary is that the MANEVU Class I states (Maine, New Hampshire, Vermont, and New Jersey) are asking states outside the MANE-VU region that contribute to visibility impa irment inside the region to pursue similar measures. The control measures that non-MANE-VU states choose to pursue may be directed toward the same emission source sector s identified by MANEVU for its own emission reductions, or they ma y be equivalent measures targeting other source sectors. Under the MANE-VU long-term strategy, states will be allowed until 2018 to pursue adoption and implementation of proposed control measures.

12.5.1 BART

Implementation of the BART provisions of the Regional Haze Rule (40 CFR 51.308(e))
is one of the reasonable stra tegies included in this SIP 61 . BART controls in Maine are
identified in Section 10 of this SIP.

To assess the benefits of implementing the BART provisions of the Regional Haze Rule for non-EGU facilities, NESCAUM included estimated reductions anticipated for BARTeligible facilities in the MANE-VU region in the final 2018 CMAQ modeling analysis, as described previously in Subsection 11.5 of this SIP. The mode ling assumed that 12 units at seven BART-eligible sources in MANE-VU w ould be controlled as a result of BART requirements alone. (see Table 12.1

Note that additional emission reductions will occur at many other BART-eligible
facilities within MANE-VU as a result of cont rols achieved by either programs that serve as BART but are not specifical ly identified as such (e.g., RACT ). While not specifically identified as being attributable to BART , these additional emission reductions were accounted for in the 2018 CMAQ modeling.

Additional visibility benefits are likely to result from the installation of new emissions controls at BART-eligible facilities that ar e located in neighboring RPOs. However, the MANE-VU modeling did not account for BA RT controls in other RPOs, and consequently, did not include the visibility improvements at MANE-VU Class I Areas that would likely result from such measures.

61 For EGU’s , EPA determined that CAIR would fu lfill the BART requirement for his sector.

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12.5.2 Low-Sulfur Oil Strategy

The important assumption underlying MANE-VU’ s low-sulfur fuel oil strategy is based on the production and use of home heating and fuel oils that contain 50% less sulfur for the heavier grades (#4 and #6 residual), and a minimum of 75% and maximum of 99.25% less sulfur in #2 fuel oil (also known as home hea ting oil, distillate, or diesel fuel) at an acceptably small increase in price to the end us er. As much as three-fourths of the total sulfur reductions achieved by this strategy come from using the low-sulfur #2 distillate for space heating in the residential and commerc ial sectors. The costs of these emission reductions are estimated at $550 to $750 per ton, as documented in the MANE-VU Reasonable Progress Report. While the costs of the low-sulfur fuel oil strategy vary depending on market conditions, they appear to be reasonable when measured against the costs of controlling other sectors.

Maine has already adopted a low sulfur fuel strategy. The 124 th Second Regular Session of the Maine Legislature (2010) adopted LD 1662, “An Act To Improve Maine's Air Quality and Reduce Regional Haze at Acadia National Park and Other Federally Designated Class I Areas,” which implements the MANE-VU low sulfur fuel strategy in Maine. This legislation esta blishes a statewide sulfur limit for distillate fuels of 50 ppm in 2016, and 15 ppm in 2018. For residual (#6) fu el oil, the statewide sulfur limit will be reduced to 0.5% in 2018. The legislati on also directs the De partment to undertake rulemaking (to be completed by 2014) to adop t rules that provide an opportunity for a
licensed air contamination source that holds a license on the e ffective date of the statute to apply for an equivalent alte rnative sulfur reducti on strategy to the resi dual fuel oil and distillate fuel requirements. The rules must provide for the achievement of equivalent sulfur emission reductions through other means, including, but not limited to, reductions in consumption of residual fuel oil and distillate fuel, early sulfur emission reductions from a baseline emissions inventory year of 2002, and conversions. LD 1662, as adopted by the Maine Legislature and signed by Governor Baldacci on April 5, 2010, is attached
in Attachment Z.

12.5.3 Targeted EGU Strategy

MANE-VU has identified emissions from the top 167 EGU emission points that contribute most to visibility impairment at MANE-VU Class I Areas (see Figure 12-1). Controlling emissions from these contributi ng facilities is crucial to mitigating haze pollution in wilderness areas and nationa l parks of the northeast states.

MANE-VU’s agreed regional approach for th e EGU source sector is to pursue a 90 percent control level on SO 2 emissions from the 167 identified stacks by 2018. MANEVU has concluded that pursuing th is 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 reduc tion level would include the effects of lower average reduction rates fr om dry scrubbing technol ogy, consistent with historic experience. The costs of SO 2 reductions will vary by unit. The MANE-VU Reasonable Progress Report (Attachment T) su mmarizes the various control methods and

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172 costs, which range from $170 to $5,700 per ton, depending on site-specific factors such as the size and type of unit, combustion tec hnology, and type of fuel used. Maine has one EGU identified in the MANE-VU analysis, Wy man Station Unit #4, which is located in located in Yarmouth, Maine. As a signatory to the MANE-VU statement of principles (Attachment D), Maine is committed to pursu e additional emission reductions at this facility through its low sulfur fuel oil progr am. Maine DEP believes that the use of lowsulfur fuel at this facility (in lieu of add-on controls) will provide the most cost-effective sulfur reductions, and that addi tional controls at this unit should be subsumed under the low-sulfur fuel strategy. For more detail on Maine’s implementation of the Targeted EGU Strategy, see Section 12.9, below.

Several states have implemented state-speci fic EGU emission reduction programs. These commitments, identified below, are include d in the long-term st rategy as reasonable measures to meet MANE-VU’s reasonable progress goals.

Maryland Healthy Air Act : Maryland adopted the following requirements governing
EGUs:

 For NO
x :

 Phase I (2009) sets unit specific annual caps (totaling 20,216 tons) and ozone season caps (totaling 8,900 tons).

 Phase II (2012) sets unit specific annual caps (totaling 16,667 tons) and ozone season caps (totaling 7,337 tons).

 For SO 2 :

 Phase I (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 I (2010) requires a 12-month ro lling average of a minimum of 80% removal efficiency.

 Phase II (2013) requires a: 12-month rolling average of a minimum of 90% removal efficiency.

The specific EGUs included are: Brandon Shores (Units 1 and 2), C.P.Crane (Units 1 and 2), Chalk Point (Units 1, and 2), Dickerson (U nits 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-statetrading of emission allowances, no inter-company trading and no banking from year-toyear were included in this analysis5/27/2010Draft For FLM ReviewTable 12-1Estimated Emissions fromNon-CAIR Unit BART-Eligible Facilities Located in MANE-VU Used in Final ModelingFacility NameUnitNameSCCCodePlant ID(from theMANE-VUInventory)Point ID(from theMANE-VUInventory)Facility TypeFuel2002Emissions(tons)2018Emissions(tons)MDEASTALCO ALUMINUM2830300101021-000528Metal Production15061356MDEASTALCO ALUMINUM2930300101021-000529Metal Production15061356MDLEHIGH PORTLANDCEMENT3930500606013-001239Portland Cement98MDLEHIGH PORTLANDCEMENT1630500915021-000316Portland Cement13211,189MDLEHIGH PORTLANDCEMENT1730500915021-000317Portland Cement976878MDWESTVACO FINE PAPERS210200212001-00112Paper and Pulp89231338MEWyman StationBoiler 3101004012300500135004EGUOil616308MESAPPI SomersetPowerBoiler #1102007992302500027001Paper and PulpOil/WoodBark/ProcessGas28841442MEIP JayPowerBoiler #2102004012300700021002Paper and PulpOil3086°1543MEIP JayPowerBoiler #1102004012300700021001Paper and PulpOil2964°1482NYKODAK PARK DIVISIONU00015102002038261400205U00015ChemicalManufacturer2379814216NYLAFARGE BUILDINGMATERIALS INC41000305007064012400001041000Portland Cement148004440°1999 emissions1735/27/2010
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Figure 12-1 167 EGU Stacks Affecting MANE-VU Class I area(s)

Massachusetts EGU Regulations : Based on the Massachusetts Department of Environmental Protection’s 310 CMR 7.29, Emissions Standards for Power Plants, adopted in 2001, six of the larg est fossil fuel-fired power plants in Massachusetts must comply with emissions limitations. For mercury (Hg), 6 facilities must comply with: 85% Hg reduction or 0.0075 lbs Hg/GWh in 2008 and 90% Hg reduction or 0.0025 lbs 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 Salem Harbor (Units 1, 2, 3 and 4).

New Hampshire EGU Laws and Regulations : New Hampshire amended the following laws and regulations governing EGU emissions:

 RSA 125-O requires the insta llation of scrubbers on Merr imack Station (Units 1 and 2) by July 1, 2013 to control SO 2 and mercury emissions. This law allows
State-level SO 2 credits for over- or early- compliance.

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 Env-A 2900 sets limits for NO

x , SO 2 , and CO 2 emissions by December 31, 2006 for all existing fossil EGUs.

New Jersey Hg MACT Rule : Under this rule, all coal-f ired EGUs will have a mercury removal efficiency of 90%. (Some SO 2 reductions may occur as a result of this mercury rule.)

Consent Agreements in the VISTAS Region : The following consent agreements in the
VISTAS states were reflected in the emi ssions inventories used for those states:

 East Kentucky Power Cooperative : A July 2, 2007 consent agreement between the EPA and East Kentucky Power Cooperati ve requires the util ity to reduce its
emissions of SO 2 by 54,000 tons per year a nd its emissions of NO

x by 8,000 tons per year, by installing an d operating selective catal ytic reduction (SCR) technology; low-NO

x burners, and PM and mercury Continuous Emissions Monitors at the utility’s Spurlock, Dale and Cooper Plants. According to the EPA, total emissions from the plants will decrease between 50 and 75 percent
from 2005 levels. As with all federal c onsent decrees, EKPC is precluded from using reductions required under other pr ograms, such as CAIR, to meet the reduction requirements of the consent decr ee. EKPC is expected to spend $654 million to install pollution controls.

 American Electric Power: Under this ag reement, American Electric Power will spend $4.6 billion dollars for emission c ontrols at sixteen plants located in Indiana, Kentucky, Ohio, Virginia and We st Virginia. These control measures will eliminate 72,000 tons of NO

x emissions each year by 2016 and 174,000 tons
of SO 2 emissions each year by 2018.

12.6 Source Retirement and Replacement Schedules

40 CFR Section 51.308(d)(3)(v)(D) requires Main e to consider source retirement and replacement schedules in developing reasona ble progress goals. Source retirement and replacement were considered in devel oping the 2018 emission inventory described previously in Subsection 11.2, Reasonable Prog ress 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 Im pacts of Construction Activities

40 CFR Section 51.308(d)(3)(v)(B) requires Maine to consider measures to mitigate the impacts of construction activ ities on regional haze. M ANE-VU’s consideration of measures to mitigate the impacts of constr uction activities is documented in “Technical Support Document on Measures to Mitigate the Visibility Impacts of Construction Activities in the MANE-VU Region,” Draf t, October 20, 2006, MARAMA (Attachment X).

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The construction industry is already subject to requirem ents for contro lling pollutants that contribute to visibility impairment. For ex ample, EPA’s off-road engine standards and low sulfur fuel requirements result in re ductions of PM and precursor emissions (SO 2 and
NO
x ) from construction vehicles.

At the state level, Maine cu rrently regulates emissions of fugitive dust through its 06-096 CMR Chapter 101, Visible Emissions rules, which establishes opacity limits for emissions from several categories of air contaminant sources, including fugitive
emissions from construction activ ities. Maine also regulates emissions from both on-road
vehicles and construction activities through its 06-096 CMR Chapter 127 New Motor Vehicle Emission Standards rules (new mo tor vehicle emission standards), the 06-096 CMR Chapter 147 Diesel-Powered Motor Vehi cle Emission Standards rules (opacity standards), and the 06-096 CMR General Pe rmit Regulations for Nonmetallic Mineral Processing Plants rules. Non-road vehicl es are subject to fe deral regulations.

MANE-VU’s Contribution Assessment (Attachme nt B) found that, from a regional haze perspective, crustal material generally does not play a major role at MANE-VU Class I Areas. On the 20 percent best visibility days during the 2000-2004 baseline period, crustal material accounted for 6 to 11 percent of the particle-related light extinction at MANE-VU Class I Areas. On the 20 percen t worst visibility days, however, the ratio was reduced to between 2 and 3 percent. Fu rthermore, the crustal fraction is largely made up of pollutants of natura l origin (e.g., soil or sea salt) that are not targeted under the Regional Haze Rule. Nevertheless, the cr ustal fraction at any given location can be heavily influenced by the proximity of constr uction activities; and construction activities occurring in the immediate vicinity of M ANE-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 eval uated in the first regional haze progress report.

12.7.2 Agricultural and Forestry Smoke Management

40 CFR Section 51.308(d)(3)(v)(E) requires Ma ine to consider smoke management techniques related to agricult ural and forestry management in developing its long-term strategy. MANE-VU’s analysis of smoke management in th e context of regional haze SIPs is documented in “Technical Support Document on Agricultural and Forestry Smoke Management in the MANE-VU Region,” September 1, 2006, MARAMA (Attachment Y).

As noted in this report, fires used for resour ce management are of far less significance to the total inventory of fine-par ticle pollutant emissions than other sources of wood smoke in the region. The largest wood smoke source categories, with respect to PM2.5 emissions, are residential wood combustion ( 73 percent); open burni ng (15 percent); and industrial, commercial and institutional w ood combustion (9 percent). Unwanted fires involving buildings and wild lands make up only a minor fraction of wood burning emissions and cannot be reasonably addressed in this SIP. Fires that are covered under

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sm oke management plans, incl uding agricultural and prescrib ed forest burning, constitute less than one percent of total wood smoke emissions in MANE-VU 62

.

Moreover, smoke emissions from all sources represent only a minor fraction of fineparticle mass that is the cause of regiona l haze. MANE-VU’s Contribution Assessment (Attachment A) found that elemental carbon, the main ingredient of smoke, contributed only 3 to 4 percent of fine particle mass on days of worst and best visibility. Additionally, elemental carbon absorbs light more readily than it scatters light. It is
therefore reasonable to concl ude that smoke emissions from controlled agricultural and forestry burning contribute, on average, only a small fraction of one pe rcent of total light extinction on days of both good and poor visibi lity. Maine has no information to indicate that this situation would change significantly over the next decade.

12.7.3 Control of Residential and Co mmercial Wood Co mbustion Emissions

As noted in Section 8, resi dential wood combustion is re sponsible for 25 percent of primary fine particulate emissions in the MANE-VU region, and is a significant contributor to regional haze. Maine has adopt ed regulations to a ddress emissions from outdoor wood and pellet boilers, an out door wood boiler replacement and buy-back program, and a woodstove replacement buy-back program.

The Chapter 150 Control of Emissions from Outdoor Wood Boilers Rule

In June 2007, the Maine Legislature adopted the EPA Phase I partic ulate emission limit
of 0.60 lbs/MMBtu/hr heat i nput as the standard for new outdoor wood-fired hydronic heaters (OWHH), also known as outdoor wood boilers, sold in Maine beginning April 1, 2008. Beginning April 1, 2010 new OWHH sold in Maine are required to meet a more stringent particulate emission standard of 0.32 lbs/MMBTU heat output (Phase II).

06-096 CMR Chapter 150 Control of Emissi ons from Outdoor Wood Boilers, which incorporated the OWHH particulate emissi on standards adopted by the Legislature, became effective November 1, 2007, and also established setback, stack height, particulate emission limits, and fuel re quirements for outdoor wood boilers (See Attachment BB). Chapter 150 was subsequently amended 63 to control the sale, installation, use, and si ting of outdoor wood boilers that co mbust biomass pellets as fuel. Maine is submitting this rule to EPA for in corporation into the Regional Haze SIP.

The Chapter 160, Outdoor Wood Boiler Re placement 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 commissione r to be used by the Department to upgrade, purchase and replace outdoor wood boilers that create a nuisance condition as defined in the

62 For example, PM2.5 and PM10 emissions from agricultural burning and forestry management activities account for only 0.139% and 0.157% of total wood smoke emissi ons (Source: 2002 MANE-VU Modeling Inventory Version 3.0).

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Departm ent’s rules or threat to public health or safety, and directed the Department to develop a rule that includes, but not limite d to, criteria for determining whether an
outdoor wood boiler constitutes a nuisance conditi on or threat to public health or safety and is eligible for use of the fund, compensa tion criteria and amounts and procedures for
certification and verification of removal and possible replacement of eligible outdoor
wood boilers.

Pursuant to this legislation, the Depa rtment adopted the 06-096 CMR Chapter 160, Outdoor Wood Boiler Replacement and Buy Back Program rules, which establish a replacement and buy back program to remove nuisance outdoor wood boilers that were installed prior to February 1, 2008 and repla ce them with approved heating appliances. The Department will maintain a list of nuisance outdoor wood boilers and prioritize them for the program based on the th reat to public health and safe ty and proximity to neighbors and sensitive populations. To receive compensation, th e owner of the outdoor wood boiler must have explored all possible remedi es, including increasing the stack height and setback distances to neighbors and potential re trofits to eliminate the nuisance conditions. Compensation may include the cost of instal lation and disposal and shall not exceed $15,000.

The Residential Wood Stove Replacement Fund

On April 8, 2010, the Maine Legislature enact ed 38 MRSA §610-D, which established a residential woodstove replacement program in the Maine Department of Environmental Protection. Under this program , eligible participants will be able to receive funding toward the purchase of new cleaner-burning residential heating appliances to replace older wood stoves that are not certified by the EPA lower emitting residential heating appliances, such as EPA certified wood, pellet or vented gas stoves. The Department will be establishing eligibility criteria for program participation, benefits, and approved methods for replacement and dispos al of non-certified wood stoves.

12.8 Estimated Effects of the Long -Term Strategy on Visibility

40 CFR 51.308(d)(3)(v)(G) requires Maine to consider, in developing its long-term strategy, the anticipated net eff ect on visibility due to proj ected changes in point, area and mobile source emissions over the period addressed by the long-term strategy. NESCAUM conducted modeling to evaluate the expected improvements to visibility at affected Class I Areas by 2018 as a cons equence of implementing MANE-VU’s longterm strategy. Those visibility improvemen ts will result, in part, from the efforts identified in this SIP to reduce emissions that originate in Maine.

All Class I states affected by emissions originating in Maine have (or will have) established reasonable progre ss goals for 2018 for each of their Class I Areas. The control measures included in this SIP represent the reasonable efforts of Maine, in conjunction with the efforts of other MANE -VU states, toward achieving the reasonable progress goals established by the affected states.

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Based on th e most recent MANE-VU modeling, the proposed control measures will
reduce sulfate levels at affected Class I Ar eas by about one-third on the worst visibility days and by 6 to 31 percent on the best visi bility days by 2018. Nitrate and elemental
carbon levels will also show substantial reduc tions across all areas for both bets and worst days, while smaller reductions in organi c carbon will occur. Small increases are predicted for the fine soil component of regi onal 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 th e modeling for the baseline and future years 64

. No changes were predicted for sea salt because the model does not track this component.

The 2000-2004 visibility readings at affected Class I areas provide the baseline against which future visibility readings will be measured to assess progress deriving from implementation of Maine’s Regional Haze SIP and those of the other MANE-VU states. To determine baseline visibility for a ffected Class I areas, the 2000-2004 IMPROVE monitoring data was used to calculate the aver age deciview values for the 20 percent best visibility days and the 20 percent worst vi sibility days over that period. Thus, the 20 percent best day and 20 percent worst day valu es represent average visibility conditions for the top and bottom quintiles.

To create the series of visibi lity graphs which follow, 2018 vi sibility estimates were made in accordance with EPA modeling guidance. First, 2002 daily average baseline concentrations were multiplied by their corre sponding relative reduc tion factors to obtain 2018 projected concentrations for each day. The 2018 projected concentrations were then used to derive daily visibi lity in deciviews. As a fina l step, the deciview values for the 20 percent of days having best visibility were averaged, and the process repeated for the 20 percent of days having worst visibili ty. The resulting averages represent the projected upper and lower quin tiles of visibility in 2018.

The following is provided to assist with inte rpretation of the line graphs in Figures 12. 2 through 12.7. Note that lower deciview values indicate better visibility.

 The irregular blue line ( 

# ~ ) represents the 20 percent best visibility average value as determined from monitoring data for each year of the period 2001-2005.

 The irregular red line ( 

# ~ ) represents the 20 percent worst visibility average value as determined from monitoring data for each year of the period 2001-2005.

 The straight orange line (

__ ) represents the 20 percent best visibility average value as determined from monitoring data for the 5-year period of 2000-2004. (This line represents the 20 percent best visibility baseline condition .)

 The straight blue line (

__ ) represents the 20 percent worst visibility average value as determined from monitoring data for the 5-year period of 2000-2004. (This line represents the 20 percent worst visibi lity baseline condition .)

64 Specifically, the fire emissions invent ory used in VISTAS for the base year relied on an earlier version of fire emissions data than the one used for the 2018 inventory.

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 The straight broken line (

···· ) is a continuation of the 20 percent best visibility baseline, representing the 20 percent best visibility condition as it would be with no further degradation or im provement.

 The straight green line (

__ ) represents the 20 percent worst visibility values that establish the uniform rate of progres s for the period 2004-2064. (This line is
sometimes referred to as the uniform progress line , or “glide slope.” It was created by linear interpola tion between the 20 percent worst visibility baseline value in 2004 and the 20 percent worst vi sibility value under na tural conditions in 2064. If visibility improvements match th is rate of progress, actual visibility will return to natural conditions in 2064).

 The light-green dash (

--- ) shown at 2064 represents th e theoretical 20 percent best visibility value under natural conditio ns (i.e., no anthropogenic emissions).

 The purple star ( * ) represents the 20 pe rcent best visibility value in 2018 after implementation of MANE-VU’s long-term strategy, as predicted by the CMAQ model. (This value is a reasonable progress goal .)

 The blue star ( * ) represents the 20 percent wors t visibility value in 2018 after implementation of MANE-VU’s long-term strategy, as predicted by the CMAQ model. (This value is a reasonable progress goal .)

Figures 12-2 through 12-4 are line graphs showing anticipated visibility improvements
for the MANE-VU Class I Areas affected by emissions origin ating in Maine. Figures 12- 2 and 12-3 illustrate the predic ted visibility improvement at Acadia National Park and Moosehorn National Wildlife Refuge/Roosevel t Campobello Internat ional Park by 2018 resulting from the implementation of the long -term strategy (See the blue cross mark). This improvement is compared to the Uniform Rate of Progress for affected Class I areas (see green sloping line). Note that the blue cross mark is belo w than the green line as it passes over the 2018 date marked at the bottom of the chart. This indicates that the
control measures identified in this SIP provide visibility improvements exceeding the uniform rate of progress for reaching natural visibility in 2064. The lower number of deciviews means better visibility.) Figure 12-4 demonstrates that Great Gulf Wilderness Class I area in New Hampshire, which is significantly affected by Maine emissions, is also projected to meet or exceed the unif orm rate of progress goal for 2018. All Class I areas affected by Maine emissions are also pr ojected to have no degradation from current baseline best visibility.

12.9 Implementation of the Region al Haz e Strategies in Maine

40 CFR Section 51.308(d)(3)(ii) of the Re gional Haze Rule requires Maine to demonstrate that its implementation plan in cludes all measures necessary to obtain the
emission reductions needed to meet the reasonable progress goals. The modeling analysis referenced in S ubsection 12.8 (Figures 12-2 through 12-4) above, which demonstrates that Maine’s long-term strategy is sufficient to meet reasonable progress

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goals, is predicated on Maine (and othe r MANE-VU) states reducing their SO 2 emissions as a result of a number of emission control programs.

Figure 12-2 Projected Visibility Improvement at Acad ia National Park Based On 2018 Best and Final Projections

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

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Figure 12-4 Projected Visibility Improveme nt at Grea t Gulf Wilderness Based on Most Recent Projections for 2018

As previously noted, Maine has adopted, and will implement, the following measures as part of its long-term strategy to meet the reasonable progress goals:

1. A low sulfur fuel oil strategy in accordance with the MANE-VU statement providing
SO 2 reductions for Wyman Station, ICI boi lers, and residential heating units;

2. Timely implementation of BART require ments yielding a 50 percent or greater
reduction in SO 2 emissions from Maine sources subject to BART;

3. A program to reduce SO 2 emissions at the Wyman Station #4 boiler by at least 84 percent from uncontrolled levels; and

4. A comprehensive program to reduce wood smoke emissions from outdoor wood and pellet boilers, woodstoves a nd other wood-burning devices.

12.9.1 The Maine Low Sulfur Oil Program

The Maine Low Sulfur Oil Program, as en acted by Public Law Chapter 604, (See Attachment Z), instituted the fo llowing restrictions on fuel su lfur content for residual (#4, #5, and #6) and distillate oil:

(1) Beginning January 1, 2018; a person may not use residual oil with a su lfur content greater than 0.5% by weight;

(2) Beginning January 1, 2016, a person may not use distillate oil with a sulfur content greater than 0.005 % by weight; and

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(3) Beginning January 1, 2018, a person m ay not use distillate oil with a sulfur content greater than 0.0015 % by weight.

In addition to the low sulfur requirements fo r distillate and residual oil, the program
contains two elements not included in th e MANE-VU Low Sulfur Oil Strategy. These
elements include:

1) An exemption from the low sulfur content limits for sources using distillate fuel for manufacturing purposes; and

2) Equivalent alternative sulfur reduction application. The Department of Environmental Protection is required to adopt major substantive rules 65 that provide an opportunity for a licensed air co ntamination 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 lim ited to, reductions in consumption of residual fuel oil and distillate fuel, early sulfur emission reductions from a baseline emissions inventory year of 2002 and conversions to alternative fuels. Approved alternate sulfur re duction strategies must be in effect by January 1,
2018.

The Distillate Fuel Exemption The Department does not believe that th e low sulfur content limit exemption for manufacturing purposes will have a signi ficant impact on the emission reductions afforded by this strategy for 2018 and beyond. While the exemption allows the continued use of high-sulfur 66 distillate oil at severa l manufacturing facilities , there are structural impediments to the actual use of these fuels. First, since there is only a limited potential market for high-sulfur distillate 67 the Department believes that this fuel will not be readily available, and will likely be more expensive than the mo re widely-used 15 ppm
distillate. Distributors and w holesalers of distillate fuels have noted that supplying highsulfur distillate to a limited market introdu ces additional costs to their industry in the form of segregated storage and transportati on/delivery systems, since even incidental contamination (co-mingling) can lead to non-compliance issues.

Very small amounts of higher sulfur product ca n contaminate ultra low sulfur distillate, as illustrated in Figure 12-5, below. Since le ss than 7 gallons of high sulfur distillate can
contaminate an entire truck load of ultra-low sulfur distillate fuel, segregated storage and transportation/delivery systems are proba bly the only mechanism that can assure compliance with federal and state ULSD requirements for the petroleum marketing industry. Given the low demand, and additi onal storage, trans portation and delivery costs, the Department does not believe that high sulfur distillate fuel will be widely used by the manufacturing sect or in 2018 and later.

65 Rules must be adopted and submitted to the Maine Legislature for approval by January 1, 2014.

66 Containing 2,000-5,000 ppm sulfur.

67 All other users of distillate (diesel) fuel in Maine w ill be subject to the 15 ppm sulfur limits (including general use and space heating at manufacturing facilities).

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Figure 12-5 Contamination of Ultra Low Sulfur Distillate (Diesel) Fuel

Fuel Type Amount of non-ULSD added to 7,500 gallons of ULSD 7 gallons (0.1%) 37 gallons (0.5%) 75 gallons (1%) 500-ppm Fuel +0.5 ppm +2.5 ppm + 5.0 ppm 2,000 ppm Fuel +2.0 ppm +10.0 ppm + 20.0 ppm 5,000 ppm Fuel +5.0 ppm + 25.0 ppm +50.0 ppm

As noted above, Maine believes that future (2018) use of distillate fuel by the manufacturing sector will be limited due to co st and compliance concerns. Nevertheless, projected 2018 SO 2 emissions for Maine have been ad justed to address this exemption, and its impact on non-EGU point source emissi ons, as discussed in Section 12.10, below.

The Equivalent Alternative Sulfur Reduction Application Under this provision of the Maine low su lfur oil program, the Department of
Environmental Protection is required to adopt rules pr oviding an opportunity for a
licensed source that holds an air emission licen se to apply for an e quivalent alternative sulfur reduction strategy to the residual fuel oil and distilla te fuel requirements. Since these rules will require sulfur emission reductio ns that are equivalent to the use of 0.5%
sulfur residual or 0.0015% sulf ur distillate fuel, there will be no net change to the predicted SO 2 emission reductions provided by this strategy. The Department will be working with EPA to develop these rules, and will submit them for inclusion into the SIP.

12.9.2 BART in Maine

As required by 40 CFR §51.308(e), the Maine Regional Haze SIP includes emission limitations representing Best Available Retr ofit Technology (BART) and schedules for compliance with BART for each BART-elig ible source that may reasonably be anticipated to cause or contribu te to any impairment of visibi lity in any mandatory Class I Federal area. Maine’s implementation of th e BART requirements is fully discussed in
Section 10.

12.9.3 The Targeted EGU Strategy in Maine

As noted in section 12.5.3, above, MANE-VU’s agreed regional approach for the EGU source sector is to pursue a 90 percent control level on SO 2 emissions from the 167 identified stacks by 2018. Maine has one EGU identified in the MANE-VU analysis; FPL Energy (FPLE) Wyman Station Unit #4.

FPLE Wyman Station is an 850-megawatt electri c generating facility located on Cousins Island in Yarmouth, Maine. The facility cons ists of four generati on units, all of which
fire #6 residual fuel oil. The fifth unit is a smaller oil-fired auxiliary boiler which provides building heat and auxi liary steam, and the sixth unit is an emergency backup diesel generator that provides electricity for use on-site.

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Unit #4 is powered by a Foster W heeler boiler with a maximum design heat input of 6290 MMBtu/hr, firing #6 and #2 fuel oil. This unit is equipped with 30 front wall fired burners capable of firing up to 41,333 gal/hr. Boiler #4 was manufactured in 1974 and installed in 1975, and therefore is subject to the New Source Performance Standards (NSPS) Subpart D, but not Subpart Da. Unit #4 is a peaking unit, and operated at an average annua l capacity factor of less than 10 percent
between 2002 and 2009 68 , with annual SO 2 emissions of 1,170 tpy in 2002.

Although flue gas desulfurization (FGD) through the use of a wet, semi-dry or dry scrubber is technically feasible, this t echnology is cost prohibitive due to the lowcapacity factor of this unit and site-specific restrictions. In lieu of requiring add-oncontrols, Maine will be utilizing its low-sulfur fuels program to implement the MANEVU Targeting EGU Strategy at this unit. The Maine Low Sulfur Fuel Program will require the use of low-sulfur fuel containing no more than 0.5% sulfur beginning January 1, 2018, providing an 84 percent reduction fr om baseline (3.0% sulfur) fuel.

Maine is also committing to further analyze the visibility benefits that would be provided by the use of 0.3% sulfur fuel, and to require the use of this fuel (or an equivalent emissions rate) no later than January 1, 2018, if necessary to meet the reasonable progress goals at Class I areas in Main e or any other Class I area si gnificantly affected by Maine emissions. Maine is committing to undertake th is analysis no later than January 1, 2013 as part of its 5-year period ic implementation plan revision.

12.9.4 Wood Smoke Emission Reductions Strategies in Maine

Strategies to reduce wood smoke emissions in Maine will also provide significant reductions in regional haze. As deta iled in Section 12.7.3, Maine has adopted a comprehensive suite of programs designe d to reduce wood smoke emissions from outdoor wood and pellet boilers and residen tial wood stoves. Since the visibility improvements provided by these programs were not modeled as part of the MANE-VU process, Maine has included these pr ograms in its Regional Haze SIP as SIP enhancements, or strengthening measures. The 06-096 CMR Chapter 150 Control of Emissions from Outdoor Wood Boilers (Attachme nt BB), is included for incorporation in the Maine Regional Haze SIP.

12.10 Maine’s Share of Emission Reductions

Im plementation of the long-term strategy will produce significant reductions in Maine’s emissions inventory by the end of the firs t planning period, or 2018. Changes to the emissions inventory will also occur as a re sult of population growth; changes in land use and transportation; development of industrial, energy, and natural resources; and other air pollution measures not directly relate to regional haze. However, it is the expected
reductions in SO 2 emissions that will have the greates t effect on visibility improvement at MANE-VU Class I Areas; and t hose reductions will be largely due to the implementation of the control measures developed in this SIP.

68 For comparison, the nationwide capacity factor for coal-fired generation in 2008 was 72.2 percent.

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As noted in Subsection 12.9 (above) the em i ssion controls incl uded in the Maine Regional Haze SIP are generally consiste nt with those modeled in MANE-VU’s development of reasonable progress goals for Maine and the other MANE-VU Class 1 states (see Section 11.2, above). However, since the Maine Low Sulfur Oil Program and efforts to reduce emissions at Wyman Stati on Unit #4 differ slightly from the programs and emission reductions modeled as reasonable progress goals, Maine must demonstrate that its long-term strategy will achieve the reasonable pr ogress goals established by the Regional Haze SIP.

In an effort to demonstrate that the long-term strategy established by this SIP will achieve the modeled reasonable progress goals, Maine undertook a more refined analysis of its projected 2018 SO 2 emissions that is based on the 2008 Maine DEP Point Source Inventory. 69 The Maine analysis updated projected SO 2 emissions for point sources that included only the reductions provided by the use of 0.5% sulfur residual oil as implemented by the Maine Low Sulfur Fuel Program. 70 While this approach is necessarily very conservative, and does not capture all of the re ductions 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 goa ls. The documentation for this effort and the updated Maine 2018 Projected Point Source Inventory are contained in Attachment
AA.

After accounting for all facili ties that ceased operation and/ or surrendered their air emission licenses between 2001 and 2009 (25 so urces) and accounting for the reductions provided by the use of 0.5% residual fuel, Ma ine’s updated 2018 projected point source emissions were 8,445 tpy for all point s ources (EGU and non-EGU combined); well below the 19,888 tpy utilized in the MANE-VU reasonable progress modeling.

Table 12-3, below, illustrates the M ANE-VU 2002 (baseline) and MANE-VU 2018 (modeling) inventories for Maine, along with the Maine updated 2018 [projected
inventories. The emission i nventory for Maine projects changes to point, area and mobile source inventories by the end of the first implementation period resulting from population growth; industrial, energy and natural reso urces development; land management; and air pollution control. Table 12-4 compar es the percentage reductions (SO 2) for the MANEVU region and Maine for each source category. The implementation of the Long Term Strategy will reduce Maine’s SO 2 emissions by 73.4 percent, as compared to the compared to the projected reduction of 67.5 percent in the MANE-VU region. Further information on Maine’s emissions inventory, in cluding other pollutants that contribute to visibility impairment, is available in Section 8.0, Emissions Inventory, and in
Attachments I and AA.

69 Since the Maine long-term strategies for non-point sources do not differ from those modeled, it is not necessary to update other source categories at this point in time.

70 The Department’s analysis did not include any reductions from the use of ULSD (15 ppm) at point

sources.
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Table 12-3
SO 2 Emissions from Point, Area and Mobile Sources in Maine (tpy)

Source Category MANE-VU
2002
Baseline MANE-VU
2018 Modeling Maine (Updated)
2018 Projected
On-Road Mobile 1,804 894 894

Non-Road Mobile 917 82 82

EGU Point 9,299 6,806
Non-EGU Point 14,412 13,082 8,445

Area 13,149 1,127 1,127

TOTAL 39,581 21,991 10,548

Table 12-4
SO 2 Emissions from Point, Area and Mob ile Sources in the MANE-VU Region and
in Maine (tpy)

Source Category MANE-VU Region
Percent
Reduction
2002-2018 Maine
Percent
Reduction
2002-2018

On-Road Mobile 78.2 50.5

Non-Road Mobile 84.9 91.1

EGU Point 77.6 Non-EGU point 65.4 64.4

Area 54.8 91.4

TOTAL 67.5 73.4

12.10 Emission Limitations and Compliance Schedules

40 CFR 51.308(d)(v)(C) requires Maine to esta blish emission limitations and compliance
schedules to meet reasonab le progress goals. Emissi on limitations and compliance schedules are in place for th e 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 in clude emission limitations and compliance schedules for all BART-eligible sources. The Maine Low Sulfur Fuel Program, implementing the MANE-VU low sulfur fuel st rategy and the targeted EGU strategy in Maine was enacted by the Maine Legislatur e on March 25, 2010, and signed into law by

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Governor Jo hn Baldacci on April 5, 2010. As noted in Section 12.9.3, Maine is committing to further analyze the visibility be nefits that would be provided by the use of 0.3% sulfur fuel, and to require the use of th is fuel (or an equivalent emissions rate) no later than January 1, 2018, if n ecessary to meet the reasonable progress goals at Class I areas in Maine or any other Class I area si gnificantly affected by Maine emissions. Maine is committing to undertake this analysis no later than January 1, 2013 as part of its 5-year periodic implem entation plan revision.

12.11 Enforceability of Emission Limitations and Control Measures

40 CFR 51.308(d)(3)(v)(F) requires Maine to ensure that em ission limitations and control measures used to meet reasonable progress goa ls are enforceable. All control measures incorporated into law or codifi ed in administrative rules will be enforceable. Any facility subject to state or federal permit requirements, including BART-eligible and V facilities, will be required to comply with the speci fic permit conditions that reference the applicable provisions of those laws and rules.

In Maine, the authority to create rules, issu e permits and enforce laws related to regional
haze is established in Title 38 Maine Revi sed Statutes Annotated (MRSA), Chapter 2, Department of Environmental Protection, Subc hapter 1, Organization and Powers and in Title 38 MRSA, Chapter 4, Protection and Im provement of Air. Under 38 MRSA Chapter 2 and Chapter 4, the Department is authorized to enforce the state’s air laws and regulations, establish a permit program, accept and administer grants, and exercise all incidental powers necessary to carry out the its statutory obligations.

Sections of Maine law of particular re levance to the regional haze SIP are:

 Title 38 Maine Revised Statutes Annotat ed (MRSA) section 581, Declaration of findings and intent, which declares the Legislature’s intent to:

“exercise the police power of the State in a coordinated state-wide program to control present and future s ources of emission of air c ontaminants to the end that air polluting activities of every type s hall be regulated in a manner that reasonably insures the continued health, sa fety and general welfare of all of the citizens of the State”

 38 MRSA section 585. Establishment of emission standards, which states:

“The board may establish and may amend standards, herein called "emission standards", limiting and regulating in a just and equitable manner the amount and type of air contaminants which may be emitted to the ambient air within a region. Such emission standards shall be designed to prevent air pollution and to achieve and maintain the ambient air quality standards within the region in which applicable”

 38 MRSA section585, Establishment of emission standards, which states:

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“The board may establish and amend regulations to implement ambient air quality standards and emission standards. Th ese regulations shall be designed to
achieve and maintain ambient a ir quality standards and emission standards within any region and prevent air pollution”

 38 MRSA section 590, Licensing, wh ich states, in relevant part :

“1. License required. After ambient ai r 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 t hat region any air contamination source or emit any air contaminants in that region w ithout an air emission license from the department”

 38 MRSA sections 347-A, 347-C, and 349, which provide for the enforcement of all SIP measures; and

 38 MRSA section 353-A, which establishes annual air emission license fees and 38 MRSA section 353A (1) A, which establishes an annual fee surcharge for emissions of hazardous air pollutants.

The Maine regulations also provide for en forceable emission control measures and compliance schedules to meet the applicable requirements of the Clean Air Act and rules promulgated by EPA. The following regulations are of particular re levance to the Maine Regional Haze SIP:

06-096 CMR Chapter 100 Definitions Regulation 06-096 CMR Chapter 101 Visible Emissions Regulation 06-096 CMR Chapter 102 Open Burning Regulation 06-096 CMR Chapter 103 Fuel Burning Equi pment Particulate Emission Standard 06-096 CMR Chapter 104 Incinerator Particulate Emission Standard 06-096 CMR Chapter 105 General Process Source Particulate Emission Standard 06-096 CMR Chapter 106 Low Sulfur Fuel 06-096 CMR Chapter 109 Emergency Episode Regulation 06-096 CMR Chapter 110 Ambient Air Quality Standards 06-096 CMR Chapter 114 Classification of Air Quality Control Regions 06-096 CMR Chapter 115 Major and Minor Source Air Emission License Regulations 06-096 CMR Chapter 116 Prohibi ted Dispersion Techniques 06-096 CMR Chapter 117 Source Surveillance 06-096 CMR Chapter 121 Emission Testi ng of Resource Recovery Facilities 06-096 CMR Chapter 126 Capture E fficiency Test Procedures 06-096 CMR Chapter 127 New Motor Vehicle Emission Standards 06-096 CMR Chapter 138 Reasonably Available Control Technology for Facilities that Emit Nitrogen Oxides 06-096 CMR Chapter 140 Part 70 Air Emission License Regulations 06-096 CMR Chapter 145 NOx Control Program 06-096 CMR Chapter 146 Diesel-Powered Motor Vehicle Emission Standards

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06-096 CMR Chapter 148 Em issions from Smaller-Scale Electric Generating

Resources 06-096 CMR Chapter 149 General Permit Re gulation for Nonmetallic Mineral Processing Plants 06-096 CMR Chapter 150 Control of Em issions from Outdoor Wood Boilers 06-096 CMR Chapter 160 Outdoor Wood Boiler Replacement and Buy Back Program

The Maine regulations provide for enfo rceable emission control measures and compliance schedules to meet the applicable requirements of the clean Air Act and rules promulgated by EPA. The Maine rules also define the State’s air emission licensing (permit) program for stationary sources to ensure that nationa l ambient air quality
standards are achieved.

12.12 Prevention of Significant Deterioration

Prevention of Significant Deterioration (PSD ) requirements for new major stationary sources and major modifications (emitting > 50 tons of any air contaminant) are implemented in Maine through the 06-096 CMR Chapter 100 Definitions Regulation which was approved into the SIP on October 15, 1996 71 , the 06-096 CMR Chapter 113 Growth Offset Regulation which was approved into the SIP on February 14, 1996 72 , and the 06-096 CMR Chapter 115 Major and Minor Source Air Emission License Regulations which were approved into the SIP by EPA on February 14, 1996. 73

, 74 PSD is applicable to all major sources (or exis ting sources making a major modification), triggering significance thresholds, located in an area that is in attainment with the National Ambient Air Quality Standards or unclassified. One of the intentions of the PSD program is to protect air quality in na tional parks, wilderness areas, and other areas of special natural, scenic, or historic value. The PSD permitting process requires a technical air quality analysis and additional analyses to assess the potential impacts on soils, vegetation and visibility.

The required procedures for evaluating the impacts of a proposed PSD source on air quality and visibility are provided in Section 7 of Maine’s 06-096 CMR Chapter 115 Major and Minor Source Air Emission License Regulations. The Ambient Air Quality Impact Analysis must demonstrate that the ne w allowable emissions will not result in an exceedence of the remaining increments for SO 2 , NO 2 or PM 10 in any Class I area. The applicant must also demonstrate “that the in crease in allowable emissions will not cause an adverse impact on visibility in any sensit ive area or in any Class I area, and will not interfere with reasonable progress toward th e remedying of existing man-made visibility impairment in a sensitive area. The analysis must be submitted to the Department and the

71 61 FR 53639

72 61 FR 5694

73 61 FR 5694

74 Although these rules have been amended several tim es since being incorporated into the SIP, these revisions did not change any of the major source permitting requirements relevant to PSD, and the current state regulations are consistent with the SIP-approved versions for the purposes of implementing the PSD requirements.

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appropriate Federal land Manager at least 60 days prior to the close of the public comment period on the source or m odification. In this manner, new major sources and existing sources making major modifications will be constructed in a manner that will not degrade air quality or visibility. The PSD permitting program is an integral part of Maine’s long-term strategy for m eeting its regional haze goals.

12.13 Reasonably Attributable Visibility Impairment

40 CFR Section 51.302 (c) provides for general plan requirements in cases where the
affected FLM has notified the State that Reas on ably Attributable Visibility Impairment (RAVI) exists in a Class I Ar ea in the state. There are no RAVI sources in the MANEVU region.

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### 13. Comprehensive Periodic Im plementation Plan Revisions

40 CFR Section 51.308(f) requires a State/ Tribe to revise its regional haze implementation plan and submit a plan re vision to EPA by July 31, 2018 and every ten years thereafter. In accord ance with the requirements li sted in 40 CFR Section 51.308(f) of the federal rule for regional haze, Maine commits to revising and submitting this regional haze implementation plan by July 31, 2018 and every ten years thereafter.

In addition, 40 CFR Section 51.308(g) require s 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 a ddressed 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 late r than December 17, 2012

.

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### 13. Determination of the Adequacy of the Existing Plan

As required by 40 CFR Section 51.308(h), depending on the findings of the five-year progress report, required unde r 40 CFR Section 51.308 (g), Maine commits to taking one of the following actions at the same time th e State submits the 5-year progress report:

(1) If the State determines that the exis ting implementation plan requires no further
substantive revision in order to achieve esta blished goals for visibility improvement and emissions reductions, the State will provide to the Administ rator a negativ e declaration that further revision of the existing implementation plan is not needed.

(2) If the State determines that the implementa tion plan is or may be inadequate to ensure reasonable progress due to emissions from sour ces 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 th e regional planning process for the purpose of developing additional strategies to address the plan's
deficiencies.

(3) If the State determines that the implementa tion 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 availabl e information, to the Administrator.

(4) If the State determines that the implementa tion plan is or may be inadequate to ensure reasonable progress due to emissions from sources within the State, the State will revise its implementation plan to address the plan's deficiencies within one year.

The findings of the five-year progress report will determine which action is appropriate and necessary.

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### References

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Environ. Sci. Technol

. , 32, 2706-2714, 1998.

Byun D.W., and J.K.S. Ching. Science Algorithms of the EPA Models-3 Community Multiscale Air Quality (CMAQ) Modeling System . EPA/600/R-99/030. March
1999.

Davidson, C., Strader, R., Pandis, S., and Robinson, A., Preliminary Proposal to MARAMA and NESCAUM: Development of an Ammonia Emissions Inventory for the Mid-Atlantic States and New England . Carnegie Mellon Universit y, Pittsburgh, PA. 7-Jan. 1999.

Duyzer, J., “Dry Deposition of Ammonia a nd Ammonium Aerosols over Heathland,” J. Geophys. Res., 99(D9):18,757 – 18,763, 1994.

EarthTech, 2004, http://src.com/calpuff/calpuff1.htm

EPA 2005, http://www.epa.gov/ttn/chief/eiinformation.html

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EPA National Emission Standards for Hazardous Air Pollutants for Industrial/ Commercial/Ins titutional Boilers and Process Heaters

, http://cascade.epa.gov/Right Site/dk_public_collection_de tail.htm?ObjectType=dk_docke t_collection&cid=OAR-2002-0058&ShowList=ite ms&Action=view (Accessed February 25, 2004).

EPA, National Air Quality and Emission Trends Report, 1998 , EPA 454/R-00-003,
available online: http://www.epa.gov/oar/aqtrnd98/ , 2000a.

EPA, National Air Pollutant Trends, 1900 – 1998 , EPA 454/R-00-002, available online: http://www.epa.gov/ttn/chie f/trends/trends98/trends98.pdf , 2000b.

MARAMA 2004, http://www.marama.org/visibility/2002%20NEI/index.htm l

NESCAUM, “Development of an Improved Ammonia Emissions Inventory for the United States,” December 2001b.

NESCAUM, “Regional Haze and Vi sibility in the Northeast and Mid-Atlantic States,” January 2001a.

SAI. User’s Guide to the Regional Modeling System for Aerosols and Deposition (REMSAD), Version 7. ICF Consulting/SAI, San Francisco, CA. 2002

Strader, R., Anderson, N., and Davidson, C., Development of an Ammonia Inventory for
the Mid-Atlantic States and New En gland, Progress Report, October 18, 2000 , available
online: http://marama.org/rt_cente r/MARAMAprogress10-18-00.pdf , 2000.

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1961