used are described in Section 3 of Appendix   REF _Ref191969187 \r \h  N
.  MACTEC applied growth factors to the 2002 baseline area source
inventory using state-supplied data where available or by using the EGAS
5.0 growth factor model.  MACTEC also accounted for the appropriate
control strategies in the future year projections.

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, and lawn and garden equipment.  For the majority of
non-road mobile sources, emissions are estimated using the EPA’s
NONROAD model.  Aircraft, railroad locomotives, and commercial marine
vessels are not included in the NONROAD model, and their emissions are
estimated using applicable references and methodologies.  Again, Pechan
prepared the 2002 baseline modeling inventory using the state and local
CERR submittals as a starting point.  Details on the preparation of the
2002 baseline non-road inventory are described in Chapter IV of Appendix
  REF _Ref198002744 \r \h  M .

Future year non-road mobile source emissions were projected for the
MANE-VU region by MACTEC.  The methodologies that were used are
discussed in Section 4 of Appendix   REF _Ref191969187 \r \h  N .  In
summary, MACTEC used EPA’s NONROAD2005 non-road vehicle emissions
model as contained in EPA’s National Mobile Inventory Model.  Since
calendar year is an explicit input into the NONROAD model, future year
emissions for non-road vehicles could be calculated for the applicable
projection years.  For the non-road vehicle types that are not included
in the NONROAD model (i.e. aircraft, locomotives, and commercial marine
vessels), MACTEC used the 2002 baseline inventory and the 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 factors.  Since the future years for the
CAIR projections did not directly match those required for the purposes
of ozone, particulate matter, and regional haze analyses (i.e., 2009,
2012, and 2018), MACTEC used linear interpolation to develop factors for
the required future years.

On-Road Mobile Sources

The on-road emissions source category is comprised of those vehicles
that are meant to travel on public roadways, including cars, trucks,
buses, and motorcycles.  The basic methodology used for on-road mobile
source calculations is to multiply vehicle-miles-traveled (VMT) data by
emission factors developed using EPA’s MOBILE6 motor vehicle emission
factors model.  Unlike the other emissions source categories, the
on-road mobile category requires that SMOKE model inputs be prepared,
rather than emissions data in SMOKE/IDA format that the other categories
require.  Therefore, for the 2002 baseline inventory, Pechan prepared
the necessary VMT and MOBILE6 inputs in SMOKE format.

Projected on-road mobile source inventories were developed by NESCAUM
for the MANE-VU region for ozone, particulate matter, and Regional Haze
SIP purposes.  As with the other emissions source categories, projected
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 VMT data and MOBILE6 model inputs for the applicable calendar
years.  Using the inputs supplied by the MANE-VU member states, NESCAUM
compiled and generated the required SMOKE/MOBILE6 emissions model
inputs.  Further details regarding the on-road mobile source projection
can be found in Appendix   REF _Ref218496233 \r \h  O , Development of
MANE-VU Mobile Source Projection Inventories for SMOKE/MOBILE6
Application.

Biogenic Emission Sources

For the purposes of the 2002 baseline modeling emissions inventory,
biogenic emissions were calculated for the modeling domain by the New
York State Department of Environmental Conservation (NYSDEC).  NYSDEC
used the BEIS Version 3.12 as contained within the SMOKE emissions
processing model.  Biogenic emissions estimates were made for CO,
nitrous oxide (NO) and VOC.  Further details about the biogenic
emissions processing can be found in NYSDEC’s Technical Support
Document 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, November 20, 2006.  Biogenic
emissions were assumed to remain constant for the future analysis years.

Summary of MANE-VU 2002 and 2018 Emissions Inventory

  REF _Ref191279648 \h  \* MERGEFORMAT  Table 6  and Table 7 summarize
the emissions inventories for the MANE-VU region compiled for 2002 and
projected for 2018.  The amount of pollutants (in tons per year) emitted
from the various source categories is presented.  This information was
useful in setting reasonable progress goals by states containing Class I
areas (Section 9) and in determining the long-term strategy (Section 10)
to address the contribution of Massachusetts to regional haze in Class 1
areas.

Table   SEQ Table \* ARABIC  6 : MANE-VU 2002 Emissions Inventory
Summary (tons)

 	VOC	NOx	CO	PM2.5	PM10	NH3	SO2

Point	97,300	673,660	367,645	55,447	89,150	6,194	1,907,634

Area	1,528,141	262,477	1,325,853

	332,729

	1,455,311	249,795	316,357

On-Road Mobile	789,560	1,308,233	11,749,819	22,107	31,561	52,984	40,091

Non-Road Mobile	572,751	431,631	4,553,124	36,084	40,114	287	57,257

Biogenics	2,575,232	28,396	274,451	-	-	-	-

TOTAL	5,562,984	2,704,397	18,260,892	446,367	1,616,136	309,260	2,321,339

Source: Pechan, 2006. "Technical Support Document for 2002 MANE-VU SIP
Modeling Inventories, Version 3." November 20, 2006. Appendix   REF
_Ref198002744 \r \h  \* MERGEFORMAT  M

Table   SEQ Table \* ARABIC  7 : MANE-VU 2018 Emissions Inventory
Summary (in tons)

 	VOC	NOx	PM2.5	PM10	NH3	SO2

Point	114,290	374,952	93,267	128,483	11,136	598,520

Area 	1,334,038	263,031	243,321	720,462	341,746	129,656

On-Road Mobile	269,981	303,955	9,189	9,852	66,476	8,757

Non-Road Mobile	380,076	271,181	23,933	27,055	360	8,643

Biogenics	2,575,232	28,396	-	-	-	-

TOTAL	4,673,617	1,241,515	369,710	885,852	419,718	745,576

Source: MACTEC, 2007. "Development of Emission Projections for 2009,
2012, and 2018 for non-EGU Point, Area, and Nonroad Sources in the
MANE-VU Region." February 28, 2007.  Appendix   REF _Ref191969187 \r \h
\* MERGEFORMAT  N

EGU Point Emissions: VISTAS_PC_1f  IPM Run, Appendix   REF _Ref197835294
\r \h  \* MERGEFORMAT  W

Summary of Massachusetts 2002 Base and 2018 Projected Emissions and
Reductions

  REF _Ref196790899 \h  \* MERGEFORMAT  Table 8  presents the
Massachusetts inventories for the 2002 base year and for the 2018
projected emissions and expected reductions.  The MANE-VU 2002 and 2018
emission summary and reductions, derived from   REF _Ref191279648 \h
Table 6  and Table 7, also are presented for comparison.   REF
_Ref196790899 \h  Table 8  shows that Massachusetts’ overall projected
reduction of total regional haze pollutants between 2002 and 2018 is 38
percent.  This is closely comparable to MANE-VU’s overall reduction of
36 percent for the same period.  Thus, actions taken to reduce
Massachusetts’ emissions are projected to meet the objectives of the
MANE-VU Reasonable Progress Goals.

Table   SEQ Table \* ARABIC  8 : Massachusetts 2002 Base Year and 2018
Projected Emissions and Reductions (in tons)

	VOC	NOx	CO	SO2	PM10	PM2.5	NH3	RH TOTAL

MA 2002 BASE YEAR

POINT > 1 TPY1	                5,647 	              45,590
    21,403 	              101,049 	             5,852
4,161 	             1,526

	AREA2	            159,753 	               34,371
137,278 	              25,585 	          191,369 	         43,203
    16,786

	ON-ROAD MOBILE3	               57,186 	            143,368
1,039,100 	                 4,399 	             3,408
2,410 	            5,499

	OFF-ROAD MOBILE4	              56,749 	              42,769
     461,514 	                  3,791 	              3,531
3,226 	                  28

	BIOGENICS5	             113,957 	                 1,257
   11,594 	 - 	 - 	 - 	 -

	MA 2002 ANTHROPOGENIC	    279,335 	    266,098 	    1,659,295
134,824 	   204,160 	   53,000 	   23,839

	MA 2002 WITH  BIOGENICS	    393,292 	    267,355 	    1,670,889
134,824 	   204,160 	   53,000 	   23,839 	   1,076470

MA 2018 PROJECTED YEAR

POINT > 1 TPY6	               10,902 	              40,458
   27,286 	              55,878 	              9,137 	            6,827
             1,622

	AREA7	            134,963 	               36,199
125,205 	                  1,804 	           82,027 	          31,237
        19,552

	ON-ROAD MOBILE8	               17,056 	               22,813
     515,460 	                  1,937 	                 893
   840 	             5,817

	OFF-ROAD MOBILE9	              36,306 	              27,040
   546,373 	                    442 	             2,246
2,052 	                  36

	BIOGENICS10	             113,958 	                 1,257
    11,594 	 - 	 - 	 - 	 -

	MA 2018 ANTHROPOGENIC	     199,227 	      126,510 	    1,214,324
 60,061 	    94,303 	   40,956 	   27,027

	MA 2018 WITH BIOGENICS	      313,185 	     127,767 	    1,225,918
  60,061 	    94,303 	   40,956 	   27,027 	     663,299

MA 2002-2018 REDUCTION	               80,107 	            139,588
         444,971 	              74,763 	         109,857
12,044 	           (3,188)	       413,171

MA 2002-2018 REDUCTION %	20.4%	52.2%	26.6%	55.5%	53.8%	22.7%	-13.4%
38.4%

MANEVU 2002 WITH BIOGENICS11	 5,562,984 	 2,704,397 	  18,260,892
2,321,339 	 1,616,136 	 446,367 	 309,260 	   12,960,483

MANEVU 2018 WITH BIOGENICS11	  4,673,617 	   1,241,515 	  13,728,087
  745,576 	  885,852 	  369,710 	   419,718 	 8,335,988

MANEVU 2002-18 REDUCTION %	16.0%	54.1%	24.8%	67.9%	45.2%	17.2%	-35.7%
35.7%

 1. VOC & NOx Point emissions are from MA 2002 Base Year Inventory with
cut-offs at >10 TPY.  Because CO, SO2, PM10, PM2.5 and NH3 Point
emissions

     cut-off was 100 TPY for the MA 2002 Inventory, Massachusetts used
MANE-VU's Point emissions that were counted down to 1 TPY.  MANE-VU

     used EPA-NEI, in which EPA 'gap-filled' and augmented the Primary
PM10 and PM2.5 emissions to include condensables (which most states do
not report).

     This is explained in EPA's Point Source Inventory Documentation:
http://www.epa.gov/ttn/chief/net/2002inventory.html (EI QA and Data
Augmentation)

 2. Area Source 2002 emissions from MA 2002 Base Year Inventory.  MA
original Area fuel SO2 was 54,924 TPY and was revised to 25,585 TPY.

     This revision was due to a change in the assumed sulfur content,
but was not included in MANE-VU Version 3 inventory; hence the original
value was modeled.

 3. From Pat Davis (MARAMA) April 25 2006 e-mail attachments 'V3 2002
MANEVU OnRoad Source filed in ks/MANEVU-Projections.

 4. From MACTEC 2009-12-18 Projections, Tables 4.2a to 4.8c, Feb.07
http://marama.org/visibility/Inventory%20Summary/FutureEmissionsInventor
y.htm

 5. 2002 emissions- MA 2002 Base Year Emission Inventory -Originally
from Pat Davis 4/25/2006 e-mail attachment "V3 2002 MANE-VU Biogenic
Sources"

 6. Non-EGU from MACTEC 2009, 2012 & 2018 Projections Report Tables 5-6
to 5-12, Feb.2007 http://marama.org/visibility/inventory%20Summary/

      Future/EmissionsInventory.htm. EGU projections from MACTEC FTP
Website & http://marama.org/visibility/EI-Projects/index.html

	      StateLevelSummarym02.xls Emissions 08/04/2005.

 7. From MARAMA/MACTEC 2009, 2012 & 2018 Projections Report Tables 5-17
to 5-23, Feb.2007. SO2 and other pollutants were adjusted for the
effects

      of RPG Low Sulfur %. Pat Davis 3/28/08 e-mail attachment: 2108
Best & Final-All-Pollutants-Emiss-032808.xls. Julie McDill 3/17/2008
e-mail re RPG.

 8. From Pat Davis e-mail Mar-11-2008 NESCAUM 2018 MOBILE6.2 annual
runs. File:ks/RH-SIP-Mobile-2018-sum-MV.

 9. From MACTEC 2009-12-18 Projections, Tables 4.2a to 4.8c, Feb.07
http://marama.org/visibility/Inventory%20Summary/FutureEmissionsInventor
y.htm

10. From MA 2002 Base Year Emission Inventory -originally from Pat Davis
4/25/2006 e-mail attachment "V3 2002 MANE-VU Biogenic Sources"

11. From MANE- VU Draft SIP Inventory Template Section 7.6, October
2007. From MACTEC 2/07 "Development Emissions Projections 2009, 2012 &
2018

     & Julie McDill's (MARAMA) 3/17/08 e-mail with revised 2018 SO2
emissions due to RPG low sulfur %.

Understanding the Sources of Visibility-Impairing Pollutants

This section explores the origins, quantities, and roles of
visibility-impairing pollutants emitted in the eastern United States and
Canada that contribute significantly to regional haze at MANE-VU’s
mandatory Class I areas.

Visibility-Impairing Pollutants

The pollutants primarily responsible for fine particle formation, and
thus contributing to regional haze, include SO2, NOx, VOCs, NH3, PM10,
and PM2.5.  The MANE-VU Contribution Assessment (Appendix   REF
_Ref191968764 \r \h  \* MERGEFORMAT  A ), finalized in August 2006,
reflects a conceptual model in which sulfate emerges as the most
important single constituent of haze-forming fine particle pollution and
the principle cause of visibility impairment across the Northeast
region.  Sulfate alone accounts for anywhere from one-half to two-thirds
of total fine particle mass on the 20 percent haziest days at MANE-VU
Class I sites.  This translates to about two-thirds to three-fourths of
visibility extinction on those days.  Organic carbon was shown to be the
second largest contributor to haze.  As a result of the dominant role of
sulfate in the formation 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 SO2
control measures in the eastern United States.

Visibility extinction is a measure of the ability of particles to
scatter and absorb light. Extinction is expressed in units of inverse
mega-meters (Mm-1).    REF _Ref199911487 \h  \* MERGEFORMAT  Figure 18
shows the dominance of sulfate (bottom yellow bar) in visibility
extinction calculated from 2000-2004 baseline data.

Figure   SEQ Figure \* ARABIC  18 : Contributions to PM2.5 Extinction at
Seven Class I Sites

Contributing States and Regions

The MANE-VU Contribution Assessment used various modeling techniques,
air quality data analysis, and emissions inventory analysis to identify
source categories and states that contribute to visibility impairment in
MANE-VU Class I areas.  With respect to sulfate, based on estimates from
four different techniques, the Contribution Assessment estimated that
emissions from within MANE-VU in 2002 were responsible for about 25-30
percent of the sulfate at MANE-VU and nearby Class I areas. (Emissions
from other regions, Canada, and outside the modeling domain also were
important).    REF _Ref194726328 \h  \* MERGEFORMAT  Table 9  shows the
results of one of the four methods of assessing state-by-state
contributions to sulfate impacts (the REMSAD model).  This table
highlights the importance of emissions from outside the MANE-VU region.
Note that percentage contributions differ between methods.

Table   SEQ Table \* ARABIC  9 : Percent of Annual Average Modeled
Sulfate Due to Emissions from Listed States

Contributing States or Areas

Acadia, Maine

(%)

Brigantine, New Jersey

(%)

Dolly Sods, West Virginia

(%)	Great Gulf and Presidential Range Dry River, New Hampshire

(%)

Lye Brook, Vermont

(%)

Moosehorn

and Roosevelt Campobello,Maine

(%)

Shenandoah, Virginia

(%)

Connecticut	0.76	0.53	0.04	0.48	0.55	0.56	0.08

Delaware	0.96	3.20	0.30	0.63	0.93	0.71	0.61

District of Columbia	0.01	0.04	0.01	0.01	0.02	0.01	0.04

Maine	6.54	0.16	0.01	2.33	0.31	8.01	0.02

Maryland	2.20	4.98	2.39	1.92	2.66	1.60	4.84

Massachusetts	10.11	2.73	0.18	3.11	2.45	6.78	0.35

New Hampshire	2.25	0.60	0.04	3.95	1.68	1.74	0.08

New Jersey	1.40	4.04	0.27	0.89	1.44	1.03	0.48

New York	4.74	5.57	1.32	5.68	9.00	3.83	2.03

Pennsylvania	6.81	12.84	10.23	8.30	11.72	5.53	12.05

Rhode Island	0.28	0.10	0.01	0.11	0.06	0.19	0.01

Vermont	0.13	0.06	0.00	0.41	0.95	0.09	0.01

MANE-VU 	36.17	34.83	14.81	27.83	31.78	30.08	20.59

Midwest RPO	11.98	18.16	30.26	20.10	21.48	10.40	26.84

VISTAS	8.49	21.99	36.75	12.04	13.65	6.69	33.86

Other	43.36	25.02	18.18	40.03	33.09	52.83	18.71

Figures 19 and 20 are from the Contribution Assessment and show another
method used to identify and rank states’ contributions to sulfate at
MANE-VU and nearby Class I areas using 2002 data.  This simple technique
for deducing the relative impact of emissions from specific point
sources on a specific receptor site involves calculating the ratio of
annual emissions (Q) to source-receptor distance (d).  This Q/d ratio is
then multiplied by a factor designed to account for the effects of
prevailing winds and to convert units.  The use of this technique is
explained in the Contribution Assessment.

Based on the results of the Q/d technique, Figures 19 and 20 show the
resulting rankings across a set of northern and southern Class I areas
in or near MANE-VU.  Figure 19 covers the four northern Class I areas in
MANE-VU (Lye Brook, Great Gulf, Acadia, and Moosehorn).  Figure 20
covers one Class I area in the southern part of MANE-VU (Brigantine) as
well as two neighboring Class I areas in the VISTAS region (Dolly Sods
and Shenandoah).  Massachusetts ranks tenth in annual average sulfate
contributions to Northeast Class I areas in Figure 19 and 23rd for the
Mid-Atlantic Class I areas in Figure 20.  For more details about the
methods used to identify contributing states and regions, please see the
Contribution Assessment.  Note the importance of emissions from Canada
and from various states outside of the MANE-VU region.

Figure   SEQ Figure \* ARABIC  19 : Ranked state percent sulfate
contributions to Northeast Class I receptors based on emissions divided
by distance (Q/d) results

Figure   SEQ Figure \* ARABIC  20 : Ranked state percent sulfate
contributions to Mid-Atlantic Class I receptors based on emissions
divided by distance (Q/d) results

The ranking of emission contributions to visibility impairment in the
MANE-VU Class I areas by methods such as these has direct relevance to
the consultation process described previously in Section 3.  Using
results from the REMSAD model, MANE-VU applied the following three
criteria to identify states and regions for the purposes of consultation
on regional haze:

Any state/region that contributed 0.1 (g/m3 sulfate or greater on the 20
percent worst visibility days in the base year (2002)

Any state/region that contributed at least 2 percent of total sulfate
observed on the 20 percent worst visibility days in 2002

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

For the purposes of deciding how broadly to consult, the MANE-VU States
settled on the second of the three criteria: any state/region that
contributed at least 2 percent of total sulfate observed on the 20
percent worst visibility days in 2002.

In the following seven figures, states and regions meeting the three
listed criteria are identified graphically for seven Class I areas:
Shenandoah and Dolly Sods are Class I areas in the VISTAS region that
are impacted by emissions from MANE-VU states; the other five Class I
areas are in MANE-VU.  Note that the IMPROVE monitor at Great Gulf also
represents the Presidential Range - Dry River Wilderness, and the
IMPROVE monitor at Moosehorn also represents Roosevelt Campobello
International Park.  Each figure has three components:

On the left is a single bar graph of the IMPROVE-monitored PM2.5 mass
concentration ((g/m3) by constituent species for the baseline years
2000-2004.  The bottom (yellow) portion of the bar represents the
measured sulfate concentration.

The middle component of each figure provides a bar graph of the 2002
total sulfate contribution of each state or region as estimated by
REMSAD.

Finally, the right segment contains three maps showing which states meet
the criteria described above.  The three arrows from the bar graph in
the middle component indicate the cut-offs for state inclusion in the
maps in the right segment.

Connecticut, Rhode Island, Vermont, and the District of Columbia were
not identified as being among the political or regional units
contributing at least 2 percent of sulfate at any of the seven Class I
areas.  However, as participants in MANE-VU, those entities have agreed
to pursue adoption of regional control measures aimed at visibility
improvement on the haziest days and prevention of visibility degradation
on the clearest days.

Based on the MANE-VU Contribution Assessment, emissions from
Massachusetts contribute to visibility degradation in the following
Class I areas:  Acadia National Park, Great Gulf Wilderness, Lye Brook
Wilderness, Presidential Range/Dry River Wilderness, Moosehorn
Wilderness, and Roosevelt/Campobello International Park.    REF
_Ref202755715 \h  \* MERGEFORMAT  Figure 21 ,   REF _Ref202755752 \h
\* MERGEFORMAT  Figure 26 , and   REF _Ref218497188 \h  Figure 27 ,
respectively, illustrate that emissions from Massachusetts do not
contribute greater than 0.1 (g/m3 sulfate or 2% of sulfate to the
Brigantine, Shenandoah, and Dolly Sods Class I areas.

Figure   SEQ Figure \* ARABIC  21 : Modeled 2002 Contributions to
Sulfate by State at Brigantine

Figure   SEQ Figure \* ARABIC  22 : Modeled 2002 Contributions to
Sulfate by State at Lye Brook

Figure   SEQ Figure \* ARABIC  23 : Modeled 2002 Contributions to
Sulfate by State at Great Gulf and Presidential Range/Dry River
Wilderness

Figure   SEQ Figure \* ARABIC  24 : Modeled 2002 Contributions to
Sulfate by State at Acadia

Figure   SEQ Figure \* ARABIC  25 : Modeled 2002 Contributions to
Sulfate by State at Moosehorn and Roosevelt Campobello International
Park

Figure   SEQ Figure \* ARABIC  26 : Modeled 2002 Contributions to
Sulfate by State at Shenandoah

Figure   SEQ Figure \* ARABIC  27 : Modeled 2002 Contributions to
Sulfate by State at Dolly Sods

Emissions Sources and Characteristics

The major pollutants responsible for regional haze are SO2, NOX, VOCs,
NH3, PM10, and PM2.5.  The following is a description of the sources
(e.g., point, area, and mobile) and characteristics of pollutant
emissions contributing to haze in the eastern United States.  Emissions
data and graphics presented in this section are taken from the MANE-VU
2002 Baseline Emissions Inventory, Version 2.0 (note that the more
recent MANE-VU 2002 Baseline Emissions Inventory, Version 3.0, released
in April 2006, has superseded Version 2.0 for modeling purposes).
Although the emissions inventory database also includes carbon monoxide
(CO), this primary pollutant is not considered here because it does not
contribute to regional haze.

In addition to the MANE-VU inventory, useful emissions inventories
include the 1996 EPA National Emissions Trends database (NET) and the
1999 National Emissions Inventory (NEI). Trends among the three
emissions inventories – NET 1996, NEI 1999, and MANE-VU 2002 – are
highlighted in the text and graphics presented below.

Sulfur Dioxide (SO2)

SO2 is the primary precursor pollutant for sulfate 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, SO2
emissions are an obvious target for reducing regional haze in the
eastern United States.  Combustion of coal and, to a lesser extent, of
certain petroleum products accounts for most anthropogenic SO2
emissions.  In fact, in 1998 a single source category, coal-burning
power plants, was responsible for two-thirds of total SO2 emissions
nationwide (Appendix   REF _Ref218496886 \r \h  P ).  REF _Ref191279164
\h  \* MERGEFORMAT  Figure 28  shows SO2 emissions trends in the MANE-VU
states extracted from the NEI for the years 1996, 1999, and from the
2002 MANE-VU inventory. Most of the states show declines in year 2002
annual SO2 emissions as compared to 1996 emissions.  The decline can be
attributed to implementation of the second phase of the EPA Acid Rain
Program, which in 2000 further reduced allowable emissions and extended
emissions limits to more power plants.

Figure   SEQ Figure \* ARABIC  28 : Trends in Annual Sulfur Dioxide
Emissions by State

Figure 29 shows the percent contribution from different source
categories to overall, annual 2002 SO2 emissions in the MANE-VU states.
The chart shows that point sources dominate SO2 emissions, which
primarily consist of stationary combustion sources for generating
electricity, industrial energy, and heat.  Smaller stationary combustion
sources called “area sources” (primarily commercial and residential
heating, and smaller industrial facilities) are another important source
category in the MANE-VU states.  By contrast, on-road and non-road
mobile sources make only a relatively small contribution to overall SO2
emissions in the region (Appendix   REF _Ref218496886 \r \h  P ).

Figure   SEQ Figure \* ARABIC  29 : 2002 Sulfur Dioxide Emissions (SO2)
by State

Bar Graph: Percentage Fractions of the Four Source Categories

       (-o-) Line Graph: Total State Annual Emissions (106 tpy)

Volatile Organic Compounds (VOCs)

Existing emissions inventories generally refer to volatile organic
compounds (VOCs) for hydrocarbons whose volatility in the atmosphere
makes them particularly important from the standpoint of ozone
formation.  From a regional haze perspective, there is less concern with
the volatile organic gases emitted directly to the atmosphere and more
with the secondary organic aerosol (SOA) that the VOCs form after
condensation and oxidation processes.  Thus the VOC inventory category
is of interest primarily because of the organic carbon component of
PM2.5.

After sulfate, organic carbon (OC) generally accounts for the next
largest share of fine particle mass and particle-related light
extinction at northeastern Class I sites.  The term organic carbon
encompasses a large number and variety of chemical compounds that may
come directly from emission sources as a part of primary PM or may form
in the atmosphere as secondary pollutants.  The organic carbon present
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 vegetation.  Recent efforts to reduce
manmade organic carbon emissions have been undertaken primarily to
address summertime ozone formation in urban centers.  Future efforts to
further reduce organic carbon emissions may be driven by programs that
address fine particles and visibility.  Massachusetts will continue to
evaluate methods to reduce the contribution of organic carbon emissions
to regional haze; however, significant visibility improvements will not
occur until sulfate-dominated visibility impairment has been reduced.

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 atmosphere.  Thus, the organic carbon contribution to
visibility impairment at most Class I sites in the East is likely to
include manmade pollution transported from a distance and from nearby
sources, and biogenic emissions, especially terpenes, from coniferous
forests

As shown in   REF _Ref191279294 \h  \* MERGEFORMAT  Figure 30 , the VOC
emissions 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 vehicles, as well as evaporative
emissions from transportation fuels.  VOC emissions also may originate
from a variety of area sources (including solvents, architectural
coatings, and dry cleaners) and from some point sources (e.g.,
industrial facilities and petroleum refineries).

Biogenic VOCs may play an important role within the rural settings
typical of Class I sites. The oxidation of hydrocarbon molecules
containing seven or more carbon atoms is generally the most significant
pathway for the formation of light-scattering organic aerosol particles.
 Smaller reactive hydrocarbons that may contribute significantly to
urban smog (ozone) are less likely 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 hydrocarbons, including biogenic emissions (Appendix   REF
_Ref218496886 \r \h  P ).  In short, further work is needed to
characterize the organic carbon contribution to regional haze in the
Northeast and Mid-Atlantic states and to develop emissions inventories
that will be of greater value for visibility planning purposes.

Figure   SEQ Figure \* ARABIC  30 : 2002 Volatile Organic Carbon (VOC)
Emissions by State

Bar Graph: Percentage Fractions of the Four Source Categories

       (-o-) Line Graph: Total State Annual Emissions (106 tpy)

Oxides of Nitrogen (NOX)

NOx emissions contribute to visibility impairment in the eastern U.S. by
forming light-scattering nitrate particles.  Nitrate generally accounts
for a substantially smaller fraction of fine particle mass and related
light extinction than sulfate and organic carbon at northeastern Class I
sites.  Notably, nitrate may play a more important role at urban sites
and in the wintertime.  In addition, NOx may have an indirect effect on
summertime visibility by virtue of its role in the formation of ozone,
which in turn promotes the formation of secondary organic aerosols
(Appendix   REF _Ref218496886 \r \h  P ).

Figure 31 shows NOx emissions in the MANE-VU region at the state level.
Since 1980, nationwide emissions of NOx from all sources have shown
little change.  In fact, emissions increased by 2 percent between 1989
and 1998.  This increase is most likely due to industrial sources and
the transportation sector, since power plant combustion sources had
implemented modest emissions reductions during the same time period.
Most states in the MANE-VU region experienced declining NOX emissions
from 1996 through 2002.  Exceptions include Massachusetts, Maryland, New
York, and Rhode Island, which show an increase in NOx emissions in 1999
before declining in 2002 to levels below 1996 emissions.  For
Massachusetts, the increase in NOx emissions from 1996 to 1999 was due
largely to increases in emissions from off-road and stationary point
sources.  The subsequent decline in NOx emissions from 1999 to 2002 is
mainly attributable to controls in the on-road mobile category,
including Enhanced Inspection and Maintenance (I/M) and California Low
Emission Vehicle (CA-LEV) programs.  There also were significant
reductions in the stationary point source category, mainly power plants,
that are attributable to NOx RACT.

Figure   SEQ Figure \* ARABIC  31 : Trends in Annual Nitrogen Oxide
(NOx) Emissions by State

Power plants and mobile sources generally dominate state and national
NOx emissions inventories.  Nationally, power plants account for more
than one-quarter of all NOx emissions, amounting to over six million
tons.  The electric sector plays an even larger role, however, in parts
of the industrial Midwest where high NOx emissions have a particularly
significant power plant contribution.  By contrast, mobile sources
dominate the NOx inventories for more urbanized Mid-Atlantic and New
England states to a far greater extent, as shown in Figure 32.  In these
states, on-road mobile sources represent the most significant NOx source
category.  Emissions from non-road mobile sources, primarily
diesel-fired engines, also represent a substantial fraction of the
inventory.  While there are fewer uncertainties associated with
available NOx 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
(Appendix   REF _Ref218496886 \r \h  P ).

Figure   SEQ Figure \* ARABIC  32 : 2002 Nitrogen Oxide (NOx) Emissions
by State

Bar Graph: Percentage Fractions of the Four Source Categories

       (-o-) Line Graph: Total State Annual Emissions (106 tpy)

Primary Particle Matter (PM10 and PM2.5)

Directly emitted or “primary” particles include both filterable and
condensable particulates.  These are distinct from secondary particles
that form in the atmosphere through chemical reactions involving
precursor pollutants like SO2 and NOX.  Both primary and secondary
particles can contribute to regional haze.  For regulatory purposes, a
distinction is made between particles with an aerodynamic diameter less
than or equal to 10 micrometers and smaller particles with an
aerodynamic diameter less than or equal to 2.5 micrometers (i.e.,
primary PM10 and PM2.5, respectively).  Figure 33 and Figure 34 show
PM10 and PM2.5 emissions for the MANE-VU states for the years 1996,
1999, and 2002.  Most states show a steady decline in annual PM10
emissions over this time period, with the exception of Maine.  By
contrast, emission trends for primary PM2.5 are more variable.  For
Massachusetts, both PM10 and PM2.5 emissions increased from 1996 to
1999, then declined to 2002.  Similar to trends in NOx emissions, the
increase was due largely to increases in emissions from off-road and
stationary point sources.  The subsequent decline in PM emissions from
1999 to 2002 is mainly attributable to controls in the on-road mobile
category, including Enhanced I/M and CA-LEV.  There also were
significant reductions in the stationary point source category, mainly
power plants, that are attributable to NOx RACT.

Figure   SEQ Figure \* ARABIC  33 : Trends in Primary Coarse Particle
(PM10) Emissions by State

Figure   SEQ Figure \* ARABIC  34 : Trends in Primary Fine Particle
(PM2.5) Emissions by State

Crustal sources are significant contributors of primary PM emissions.
This category includes fugitive dust emissions from construction
activities, paved and unpaved roads, and agricultural tilling.
Typically, monitors estimate PM10 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 estimated emission rates for fine particles using
these types of measurement techniques and observed concentrations of
crustal matter in the ambient air at downwind receptor sites suggest
that physical or chemical processes remove a significant fraction of
crustal material relatively quickly.  As a result, it rarely entrains
into layers of the atmosphere where it can transport to downwind
receptor locations.  Because of this discrepancy between estimated
emissions and observed ambient concentrations, modelers typically reduce
estimates of total PM2.5 emissions from all crustal sources by applying
a factor of 0.15 to 0.25 to the total PM2.5 emissions before including
it in modeling analyses.

From a regional haze perspective, crustal material 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
particle-related light extinction at MANE-VU Class 1 sites.  On the 20
percent worst-visibility 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 Regional Haze Rule.  Of course, the crustal fraction
can be influenced by certain human activities, such as construction,
agricultural practices, and road maintenance (including wintertime
salting), and thus to the extent that these types of activities are
found to affect visibility at northeastern Class I sites, control
measures targeted at crustal material may prove beneficial.

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 addition, a few areas in the Northeast, such as
New Haven, Connecticut and Presque Isle, Maine, have some experience
with the control of dust and road-salt as a result of regulatory
obligations stemming from their past non-attainment status with respect
to the National Ambient Air Quality Standard (NAAQS) for PM10.

Current emissions inventories for the entire MANE-VU area indicate
residential wood combustion represents 25 percent of primary fine
particulate emissions in the region.  This implies that rural sources
can play an important role in addition to the contribution from the
region’s many highly populated urban areas.  An important
consideration in this regard is that residential wood combustion occurs
primarily in the winter months, while managed burning activities occur
largely in other seasons.  Managed burning includes agricultural and
prescribed fires, as well as use of naturally ignited fires to achieve
resource benefits and slash burning of logging debris (which is
prohibited in Massachusetts).  Particulate emissions from managed burns
can be limited by confining burning activities to times when favorable
meteorological conditions can efficiently disperse the emissions.

Wood smoke impacting MANE-VU Class I areas is more local in origin than
sources of SO2, except for major transport events.    REF _Ref194726558
\h  Figure 35  below is from the MANE-VU Contribution Assessment
(Appendix A; see Appendix B) and represents the results of source
apportionment and trajectory analyses.  It illustrates that the impacts
of wood smoke on MANE-VU Class I areas are more likely due to emissions
from within MANE-VU and Canada.  The green-highlighted portion of the
map depicts the wood smoke source region in the Northeast states.  The
stars on the map represent air monitor sites (including those at several
Class I areas) whose data sets were determined to be useful to the
modeling analysis used to attribute wood smoke impacts.

The MANE-VU Technical Support Document on Agricultural and Forestry
Smoke Management in the MANE-VU Region (Appendix   REF _Ref197851758 \r
\h  \* MERGEFORMAT  Q ) concluded that fire from land management
activities (agricultural, prescribed, and slash burning, and managed
wildfires) was not a major contributor to regional haze in MANE-VU Class
I areas, and that the majority of emissions from fires were from
residential wood combustion.

Although data are currently lacking, Massachusetts is concerned about
the growing use of residential wood stoves by homeowners seeking
alternatives to petroleum-based fuels for home heating.  Recent,
localized problems with smoke emissions from outdoor wood boilers
(wood-fired hydronic heaters) led MassDEP to promulgate regulations that
tighten requirements on the sale, installation, and use of these
devices.  MassDEP will keep close watch on smoke emissions from the
residential sector to determine whether additional control measures on
this source category may be necessary in the next few years.

Figure   SEQ Figure \* ARABIC  35 : Wood Smoke Source Regional
Aggregations

NE: ACAD, PMRC, LYBR

MA: WASH, SHEN, JARI

SE: GRSM, MACA

  REF _Ref204413763 \h  Figure 36  and   REF _Ref191279547 \h  \*
MERGEFORMAT  Figure 37  show that area and mobile sources dominate
primary PM emissions.  (The NEI inventory categorizes residential wood
combustion and some other combustion sources as area sources.)  The
relative contribution of point sources is larger in the primary PM2.5
inventory than in the primary PM10 inventory since the crustal component
(which consists mainly of larger or “coarse-mode” particles)
contributes mostly to overall PM10 levels.  At the same time, pollution
control equipment commonly installed at large point sources is usually
more efficient at capturing coarse-mode particles.

Figure   SEQ Figure \* ARABIC  36 : 2002 Primary PM10 Emissions by
State

Bar Graph: Percentage Fractions of the Four Source Categories

       (-o-) Line Graph: Total State Annual Emissions (106 tpy)

Figure   SEQ Figure \* ARABIC  37 : 2002 Primary PM2.5 Emissions by
State

       Bar Graph: Percentage Fractions of the Four Source Categories

                    (-o-) Line Graph: Total State Annual Emissions (106
tpy)

Ammonia Emissions (NH3)

Because ammonium sulfate [(NH3)2SO4]and ammonium nitrate (NH3NO3) are
significant contributors to atmospheric light scattering and fine
particle mass, knowledge of ammonia emission sources is important to the
development of effective regional haze reduction strategies.  According
to 1998 estimates, livestock agriculture and fertilizer use accounted
for approximately 86 percent of all ammonia emissions to the atmosphere.
 However, better ammonia inventory data is needed for the photochemical
models used to simulate fine particle formation and transport in the
eastern United States.  States were not required to include ammonia in
their air emissions data collection efforts until fairly recently (see
Consolidated Emissions Reporting Rule, 67 FR 39602; 6/10/2002), and so
it will take time for the quality of ammonia inventory data to match the
quality of the data for the other criteria pollutants.

Ammonium ion (formed from ammonia emissions to the atmosphere) is an
important constituent of airborne particulate matter, typically
accounting for 10–20 percent of total fine particle mass.  Reductions
in ammonium ion concentrations can be extremely beneficial because a
more-than-proportional reduction in fine particle mass can result.
Ansari and Pandis showed that a 1 (g/m3 reduction in ammonium ion could
result in up to a 4 (g/m3 reduction in fine particulate matter.
Decision makers, however, must weigh the benefits of ammonia reduction
against the significant role it plays in neutralizing acidic aerosol.

To address the need for improved ammonia inventories, MARAMA, NESCAUM,
and EPA funded researchers at Carnegie Mellon University (CMU) in
Pittsburgh to develop a regional ammonia inventory.  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 framework 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 and can make updates easily, allowing additional
ammonia sources to be added or emissions factors to be replaced as
better information becomes available.10

Figure 38 shows that estimated ammonia emissions were fairly stable in
the 1996 NEI, 1999 NEI, and 2002 Version 3 MANE-VU inventories for
MANE-VU states, with some slight increases observed for most states in
MANE-VU.  This apparent increase in emissions from 1999 to 2002 is due
to a difference in the models used to generate the emissions data.  1999
emissions were generated using an EPA model, whereas the 2002 emissions
were generated using the CMU ammonia model described above.  The CMU
ammonia model incorporates categories such as humans, house pets, wild
animals, fertilizers, soils, and miscellaneous animals that are not
incorporated into the EPA model.

Area and on-road mobile sources dominate ammonia emissions (Figure 39).
Specifically, emissions from agricultural sources and livestock
production account for the largest share of estimated ammonia emissions
in the MANE-VU region, except in the District of Columbia.  The two
remaining sources with a significant emissions contribution are
wastewater treatment systems and gasoline exhaust from highway vehicles.

Figure   SEQ Figure \* ARABIC  38 : Trends in Ammonia Emissions by State

Figure   SEQ Figure \* ARABIC  39 : 2002 NH3 Emissions by State

Bar Graph: Percentage Fractions of the Four Source Categories

(-o-) Line Graph: Total State Annual Emissions (106 tpy)

Best Available Retrofit Technology

In the Regional Haze Rule, EPA included provisions designed specifically
to reduce emissions of visibility-impairing pollutants from large
sources that, because of their age, were exempted from new source
performance standards (NSPS) established under the Clean Air Act.  These
provisions, known as Best Available Retrofit Technology, or BART, are
located at 40 CFR 51.308(e).

Massachusetts is required by 40 CFR 51.308(e) to submit an
implementation plan containing emission limits representing BART and
schedules for compliance with BART for each eligible source that may
reasonably be anticipated to cause or contribute to any impairment of
visibility in any mandatory Class I Federal area.  This requirement
applies unless Massachusetts demonstrates that an emission trading
program or other alternative will achieve greater reasonable progress
toward natural visibility conditions.

BART requirements apply to 26 specified major point source categories,
including power plants, industrial boilers, paper and pulp plants,
cement kilns, and other large stationary sources.  To be considered
BART-eligible, emission units from these specified categories must have
commenced operation or come into existence in the 15-year period prior
to August 7, 1977 (the date of passage of the 1977 Clean Air Act
Amendments, which first required new source performance standards).  In
addition, the cumulative “potential to emit” levels of all
BART-eligible units at a facility must be at least 250 tons per year of
any visibility-impairing pollutant.  Visibility-impairing pollutants
include, but are not limited to, sulfur dioxide (SO2), nitrogen oxides
(NOx), particulate matter less than or equal to 10 microns in diameter
(PM10), volatile organic chemicals (VOCs), and ammonia.

BART Overview

The BART program is intended to reduce visibility-impairing emissions of
the pollutants from large stationary sources that were not required to
meet certain emission control requirements at the time the CAA was
amended in 1977.  Under Section 169A, States must consider five
statutory factors when determining BART control requirements for
BART-eligible units:

Cost of compliance,

Energy and non-air quality environmental impacts of compliance,

Existing pollution control technology in use at the source,

Remaining useful life of the source, and

Degree of improvement in visibility reasonably anticipated from use of
BART.

In July 2005, EPA adopted the final BART rule.  Under the final rule,
the BART program requires states to develop an inventory of sources
within each state that could be subject to control.  Specifically, the
rule:

Outlined methods to determine if a source is “reasonably anticipated
to cause or contribute to haze;”

Defined the methodology for conducting a BART control analysis;

Provided presumptive control limits for electricity generating units
(EGUs) larger than 750 Megawatts (i.e. “presumptive BART”);

Provided a justification for the use of the Clean Air Interstate Rule
(CAIR) as BART for CAIR state EGUs.

Beyond the specific elements listed above, EPA provided the states with
a great degree of flexibility in how they choose to implement the BART
program.

As set forth in 40 CFR 51.308(e)(2), states may choose to implement or
require participation by BART sources in an emissions trading program or
an alternative measure that will achieve greater reasonable progress
than BART implementation at all sources subject to BART.  In addition,
if such alternative measure has been designed primarily to meet a
Federal or State requirement other than BART, a more simplified approach
can be used to demonstrate that the alternative measure will make
greater reasonable progress than implementing BART alone.

BART-Eligible Sources in Massachusetts

Massachusetts identified its BART-eligible sources using the methodology
in the Guidelines for Best Available Retrofit Technology (BART)
Determinations under the Regional Haze Rule, 40 CFR Part 51, Appendix Y.
 Seventeen sources were found to be eligible for BART and are listed in
Table 10. These include nine electric generating units (EGUs), four
industrial/commercial/ institutional (ICI) boilers/chemical processing
plants, one municipal waste combustor (MWC), and three petroleum storage
facilities.

Table   SEQ Table \* ARABIC  10 : BART-Eligible Facilities in
Massachusetts

I.D.	Source	Units	Type

1190012	Boston Generating - New Boston	Unit 1	EGU

1190128	Boston Generating – Mystic	Unit 7	EGU

1190491	Braintree Electric	Unit 3	EGU

1200061	Dominion - Brayton Point	Units 1, 2, 3, and 4	EGU

1190194	Dominion - Salem Harbor	Unit 4	EGU

1190092	Harvard University - Blackstone	Units 11 and 12	EGU

1200054	Mirant - Canal Station	Units 1 and 2	EGU

1190093	Mirant - Kendall LLC	Units 1 and 2	EGU

1200067	Taunton Municipal Light Plant

(TMLP) - Cleary Flood	Units 8 and 9	EGU

1190175	Eastman Gelatin	Units 1, 2, 3 and 4	ICI Boilers/Chemical
Processing

1190138	General Electric Aircraft - Lynn	Unit 3	ICI Boilers/Chemical
Processing

420086	Solutia	Units 9 and 10	ICI Boilers/Chemical Processing

1190507	Trigen - Kneeland St	Unit 3	ICI Boilers/Chemical Processing

1197654	Wheelabrator – Saugus	Units 1 and 2	Municipal Incinerator

1190484	Exxon Mobil – Everett	All Process Units	Petroleum Storage

1190487	Global Petroleum – Revere	All Process Units	Petroleum Storage

1190483	Gulf Oil – Chelsea	All Process Units	Petroleum Storage

Determination of which BART-eligible sources are subject to BART

Massachusetts is a member of the Mid-Atlantic/Northeast Visibility Union
(MANE-VU).  As part of the consultation process among MANE-VU states a
policy decision was made by the MANE-VU Board in June 2004 that all
BART-eligible sources are subject to BART.  As such, no BART exemptions
will be given, meaning all BART-eligible sources are included in the
BART review process.

Pollutants Covered by BART

As allowed under BART, Massachusetts has determined that SO2, NOx and PM
are the contributing visibility-impairing pollutants most appropriate to
target under its BART approach.  Massachusetts did not include either
VOCs or ammonia because of the lack of tools to estimate emissions and
subsequently to model VOCs and ammonia, and because Massachusetts is
aggressively addressing VOCs through its ozone SIPs.  This conclusion is
consistent with discussions in the MANE-VU consultation process.
Therefore, Massachusetts did not further consider BART for the three
petroleum storage facilities identified in Table 10 above.

Modeling of BART Visibility Impacts

MANE-VU conducted modeling analyses of BART-eligible sources using
CALPUFF in order to provide a regionally-consistent foundation for
assessing the degree of visibility improvement which could result from
installation of BART controls (see Attachment R).

MANE-VU modeled BART visibility impacts using 2002 emissions of SO2,
NOx, and PM10 from all BART-eligible units in the region, including all
BART-eligible sources in Massachusetts.  The NWS and MM5 meteorological
platforms were both used to model each BART-eligible unit’s maximum
24-hr, 8th highest 24-hr, and annual average impact at the Class I area
most heavily impacted, as well as the total impact from all BART sources
on each Class I area.  These visibility impacts were modeled relative to
20 percent best days, 20 percent worst days, and annual average natural
background conditions.  For the purposes of this analysis, MANE-VU
examined the 24-hr maximum visibility impact relative to the 20 percent
best days.  In accordance with EPA guidance, which allows the use of
either estimates of the 20 percent best or annual average natural
background visibility conditions as the basis for calculating the
deciview difference that individual sources would contribute for BART
modeling purposes, MANE-VU opted to use the more conservative best
conditions estimates approach because it is more protective to the
region.

In addition to modeling the maximum potential improvement from BART,
MANE-VU also determined that 98 percent of the cumulative visibility
impact from all MANE-VU BART eligible sources corresponds to a maximum
24-hr impact of 0.22 dv from the NWS-driven 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 than 0.1 dv impact are unlikely to
warrant additional controls under BART.

Visibility Impacts of Massachusetts BART-Eligible Sources

The results of CALPUFF modeling using MM5 and NWS meteorological
platforms for Massachusetts BART-eligible facilities (excluding VOC
sources) are found in Table 11 and Table 12, respectively.  These
results display facility-wide impacts on the worst day at the site
experiencing the largest impact relative to the 20 percent best natural
background conditions.

Table   SEQ Table \* ARABIC  11 : CALPUFF Visibility Modeling Results
using MM5 Platform

	MM5- Impact on Worst Day Relative to 20 Percent Best Natural Conditions
(delta deciview; ddv)

Facility	Class I Site	Total	SO4	NO3	PM10

Dominion - Brayton Point	Acadia	11.152	9.740	3.354	0.031

Mirant - Canal Station	Acadia	6.643	6.018	1.310	0.000

Mystic Station	Moosehorn Wilderness	1.023	0.943	0.117	0.002

Dominion - Salem Harbor	Moosehorn Wilderness	0.982	0.886	0.151	0.001

Trigen - Kneeland Station	Acadia	0.146	0.023	0.127	0.001

Wheelabrator-Saugus	Acadia	0.250	0.026	0.232	0.000

General Electric Aircraft - Lynn	Acadia	0.239	0.148	0.092	0.000

TMLP - Cleary Flood	Acadia	0.103	0.028	0.076	0.003

Mirant - Kendall	Acadia	0.095	0.015	0.082	0.000

Harvard University - Blackstone	Acadia	0.060	0.039	0.027	0.001

New Boston	Presidential Range	0.044	0.000	0.044	0.000

Braintree Electric	Acadia	0.031	0.004	0.029	0.000

Eastman Gelatin	Acadia	0.029	0.002	0.026	0.000

Solutia	Presidential Range	0.003	0.000	0.003	0.000

Table   SEQ Table \* ARABIC  12 : CALPUFF Visibility Modeling Results
using NWS Platform

	NWS- Impact on Worst Day Relative to 20 Percent Best Natural Conditions
(ddv)

Facility	Class I Site	Total	SO4	NO3	PM10

Dominion - Brayton Point	Moosehorn Wilderness	7.200	6.206	1.754	0.026

Mirant - Canal Station	Acadia  	3.485	3.251	0.427	0.000

Mystic Station	Moosehorn Wilderness	0.660	0.556	0.108	0.003

Dominion - Salem Harbor	Acadia  	0.545	0.488	0.108	0.001

Trigen - Kneeland Station	Lye Brook Wilderness	0.097	0.005	0.092	0.002

Wheelabrator - Saugus	Lye Brook Wilderness	0.183	0.004	0.179	0.000

General Electric Aircraft - Lynn	Acadia  	0.159	0.118	0.085	0.000

TMLP – Cleary Flood	Moosehorn Wilderness	0.061	0.022	0.037	0.002

Mirant - Kendall	Lye Brook Wilderness	0.059	0.003	0.057	0.000

Harvard University - Blackstone	Acadia  	0.034	0.023	0.010	0.001

New Boston	Lye Brook Wilderness	0.028	0.000	0.027	0.001

Eastman Gelatin	Acadia  	0.025	0.002	0.024	0.000

Braintree Electric	Moosehorn Wilderness	0.014	0.002	0.012	0.000

Solutia	Acadia  	0.003	0.000	0.003	0.000

Overview of Massachusetts BART-Eligible Sources

There are three categories of BART-eligible sources in Massachusetts
that emit SO2, NOx, and PM:  a “cap out” source, sources with de
minimis visibility impacts, and sources that contribute significantly to
visibility impairment.

“Cap Out” Source

BART eligibility is limited to sources in one of 26 source categories
that had units installed and operating between 1962 and 1977 with the
current cumulative potential to emit more than 250 tons per year of a
visibility impairing pollutant.  EPA guidance allows BART-eligible
sources to adopt a federally enforceable permit limit to permanently
limit emissions of visibility impairing pollutants to less than 250 tons
per year, thereby “capping-out” of BART.   General Electric – Lynn
has actual emissions of visibility impairing pollutants of fewer than
250 tons per year and was BART-eligible only because its potential
emissions exceed the statutory BART threshold of 250 tons per year.
MassDEP has issued a permit to General Electric – Lynn establishing
caps of less than 250 tpy for NOx and SO2 emissions from Unit 3 in order
to cap-out of BART requirements (Appendix BB); PM10 potential emissions
already are less than 250 tpy.  Therefore, General Electric – Lynn
Unit 3 is no longer BART-eligible.

Sources with De Minimis Impacts on Visibility

According to the 2005 Regional Haze Rule, once a 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 contribute to any visibility impairment in a Class I area.
MANE-VU has identified a set of sources whose potential “degree of
visibility improvement” is so small (<0.1 ddv) that no reasonable
weighting could justify additional controls under BART. (Note that the
cumulative impact of all of these MANE-VU sources combined is lower than
EPA’s guidance, which states that the threshold for determining
whether a source “contributes” to visibility impairment should be
≤0.5 dv.)  A description of this modeling can be found in Appendix R,
Section 4.1, and the modeling results can be found in Appendices R-1 and
R-2.  MANE-VU has termed these sources to have a “de minimis
visibility impact.”

For Massachusetts, sources meeting this criterion are listed in Table
13.  Trigen – Kneeland has been added to this list, despite its
modeled impact of 0.146 ddv (0.127 ddv from NO3) using the MM5 modeling
platform, due to two significant errors in the 2002 input data used by
MANE-VU to screen facilities for their impact on visibility.  First,
Units 1-4 were included in the modeling when only Unit 3 is
BART-eligible.  Second, the 2002 modeled NOx emissions from Unit 3 were
396 tons, rather than the actual 96 tons of NOx emissions.
Massachusetts believes that modeling using the corrected 2002 NOx
emissions from Trigen - Kneeland would indicate a total visibility
impact of <0.1 ddv; therefore Trigen – Kneeland is being considered a
source with de minimis impact on visibility.

Table   SEQ Table \* ARABIC  13 : Massachusetts Sources with De Minimis
Visibility Impact

I.D.	Source	Type

1190491	Braintree Electric	EGU

1190092	Harvard University - Blackstone	EGU

1190093	Mirant - Kendall LLC	EGU

1190012	New Boston	EGU

1190175	Eastman Gelatin 	ICI Boilers/Chemical Process

420086	Solutia	ICI Boilers/Chemical Process

1190507	Trigen – Kneeland	ICI Boilers

MassDEP has determined that the visibility improvement that would be
achieved by the installation of BART controls at these sources does not
justify the installation of such controls.

Sources that Contribute to Visibility Impairment

Massachusetts BART-subject sources with greater than a de minimis impact
on visibility include three coal-fired EGUs (Brayton Point Units 1-3),
seven oil-fired EGUs (Brayton Point Unit 4, Canal Station Units 1-2,
Mystic Station Unit 7, Salem Harbor Unit 4, and Cleary Flood Units 8 and
9) and two MWC units (Wheelabrator – Saugus).  An overview of these
sources is contained in Table 14.

It should be noted that all of these sources are subject to MassDEP
pollution control requirements that limit SO2 and NOx.  All of the these
sources, except Cleary Flood and Wheelabrator-Saugus, are subject to 310
CMR 7.29, Emissions Standards for Power Plants, which MassDEP adopted in
2001 to control the emissions of NOx, SO2, mercury, and carbon dioxide
from the state’s largest EGUs.  In addition, these sources, as well as
Cleary Flood, are subject to MassDEP’s NOx RACT rules and ozone season
MassCAIR control program, 310 CMR 7.32.  Wheelabrator-Saugus is subject
to 310 CMR 7.08(2): Municipal Waste Combustors and 310 CMR 7.19(9) (NOx
RACT for Municipal Waste Combustor Units).

The Regional Haze Rule allows Massachusetts to either make individual
BART determinations or to implement an alternative that will achieve
greater reasonable progress toward natural visibility conditions.
Massachusetts has developed a BART determination for the Wheelabrator
units and has adopted an alternative to BART for the remaining EGU BART
sources.

Table   SEQ Table \* ARABIC  14 : Overview of BART-Eligible EGUs & MWCs

Source Type	Source	Unit	Subject to Presumptive BART?	Primary Fuel
Secondary Fuel(s)	Unit Type	Built Year

EGU	Brayton Point	1	yes	Coal (1.5%S)	Natural Gas, Residual Oil
Tangentially-fired	1963

EGU	Brayton Point	2	yes	Coal (1.5%S)	Natural Gas, Residual Oil
Tangentially-fired	1964

EGU	Brayton Point	3	yes	Coal (1.5%S)	Natural Gas, Residual Oil	Dry
bottom wall-fired boiler	1969

EGU	Brayton Point	4	yes	Residual Oil	Natural Gas	Dry bottom wall-fired
boiler	1974

EGU	Canal Station	1	yes	Residual Oil	Diesel Oil	Dry bottom wall-fired
boiler	1970

EGU	Canal Station	2	yes	Residual Oil	Diesel Oil,       Natural Gas	Dry
bottom wall-fired boiler	1976

EGU	Mystic Station	7	yes	Residual Oil	Natural Gas	Tangentially-fired
1974

EGU	Salem Harbor	4	yes	Residual Oil	 	Dry bottom wall-fired boiler	1972

EGU	Cleary Flood	8	no	Residual Oil	Diesel Oil	Dry bottom wall-fired
boiler	1966

EGU	Cleary Flood	9	no	Natural Gas	Diesel Oil,      Residual Oil	Other
boiler	1976

MWC	Wheelabrator - Saugus	1	no	Municipal Solid Waste	Mass burn waterwall
boiler	1975

MWC	Wheelabrator - Saugus	2	no	Municipal Solid Waste	Mass burn waterwall
boiler	1975

BART Determination for Wheelabrator - Saugus

Massachusetts has one BART-eligible incinerator, Wheelabrator –
Saugus, which contains two mass burn incinerators with water wall
boilers, each rated at 325 MMBtu/hr heat input.  Each boiler can produce
up to 195,000 lbs/hr of steam at 650 psi and 850º F.  Both incinerator
units are BART-eligible, with reported combined 2002 emissions of 84
tons of SO2 and 721 tons of NOx

Wheelabrator – Saugus is subject to MassDEP’s 1995 NOx Reasonably
Available Control Technology (RACT) regulation, 310 CMR 7.19(9).
Wheelabrator – Saugus also is subject to more stringent NOx emissions
limitations in MassDEP’s Municipal Waste Combustor regulation, 310
CMR.7.08(2), which was promulgated in 1998 (and amended in 2001) to
implement EPA’s 1995 Emissions Guidelines for existing large (greater
than 250 tons) Municipal Waste Combustors pursuant to Sections 111(d)
and 129 of the federal Clean Air Act.  Section 129 requires that these
guidelines must be based on Maximum Achievable Control Technology
(MACT).  In 2006, EPA revised its Emissions Guidelines for large
Municipal Waste Combustors, lowering the PM emission guidelines (as well
as for other non-BART relevant pollutants), but leaving the SO2 and NOx
emissions guidelines unchanged.   In 2012, MassDEP plans to propose
revisions to 310 CMR 7.08(2) to adopt the lowered 2006 Emissions
Guidelines.   In addition, MassDEP has committed in its 2008 Ozone SIP
to conduct additional analysis as to whether existing NOx controls still
constitute RACT, and will consider including more stringent NOx
limits in 310 CMR 7.19 when it proposes revisions to 310 CMR 7.08(2)
in 2012.  Wheelabrator – Saugus will be required to comply with any
more stringent emissions limits included in 310 CMR 7.08(2) and 310 CMR
7.19.

NOx

Wheelabrator has NOx control equipment for both units that includes
low-NOx burners and Selective Non-Catalytic Reduction (SNCR).
MassDEP’s NOx emission limit under 310 CMR 7.08(2)(f)3 is 205 ppm (by
volume at 7 percent oxygen dry basis, 24-hr daily arithmetic average).
Compliance is determined by continuous emissions monitors (CEMs).
MassDEP’s regulatory limit is consistent with EPA’s Emissions
Guidelines (both 1995 and 2006).  However, MassDEP believes that the
capabilities of current NOx control technologies can achieve emissions
lower than EPA’s MACT.

At MassDEP’s request, Wheelabrator performed furnace gas temperature
profiling and conducted SNCR optimization testing to determine the
capability of further reducing NOx emissions while minimizing ammonia
slip (see Appendix Z).  The optimization test results indicate that a
reduced NOx emissions target of 185 ppm (dry, 7% O2) at current boiler
operating loads of approximately 150,000 lbs/hr could be achieved with
the existing SNCR system.  Based on MassDEP’s review of Wheelabrator
– Saugus’ existing control technologies, MassDEP determined that the
NOx emissions rate target of 185 ppm (30-day average) for each of
Wheelabrator’s units represents BART.  MassDEP issued a modified
Emission Control Plan Final Approval for Wheelabrator with the BART NOx
limit in March 2012 (Appendix JJ).

As described in Tables 11 and 12, Wheelabrator – Saugus’ visibility
impacts on Class I areas based on 2002 emissions was 0.232 ddv and 0.179
ddv, depending on the modeling platform, which are close to MANE-VU’s
de minimis level (0.1 ddv) and are well below EPA’s threshold guidance
of 0.5 ddv for determining whether a source “contributes” to
visibility impairment.  Therefore, no detailed visibility modeling was
performed to determine the benefit of achieving the lower NOx emission
rate, although  MassDEP expects a modest visibility improvement to
result from a lower NOx emission rate.

Additional technologies and costs were not evaluated because MassDEP
believes that low-NOx burners and SNCR are state of the art for
municipal waste combustors, and through optimization can achieve a NOx
emissions limit lower than the current federal MACT limit.

SO2

Wheelabrator’s existing control technology for SO2 emissions includes
a spray dry absorber (SDA) with lime slurry injection.  Wheelabrator’s
permitted SO2 emission limit under 310 CMR 7.08(2)(f)2 is 29 ppm (by
volume at 7 percent oxygen dry basis) or 75 percent reduction by weight
from uncontrolled SO2 levels.  Compliance is based on a 24-hour
geometric mean.  MassDEP’s regulatory limit is consistent with EPA’s
Emissions Guidelines (both 1995 and 2006).

CALPUFF modeling suggests that visibility impacts from 2002 SO2
emissions from Wheelabrator - Saugus are below 0.1 ddv on the worst day
at any Class I area (see Tables 11 and 12).  MassDEP has determined that
further controls for SO2 are not warranted given the additional cost
required to install supplementary SO2 controls because Wheelabrator
already has control equipment equivalent to MACT and the degree of
visibility improvement that could be achieved (<0.1 ddv) is de minimis.

PM

Each of Wheelabrator’s units are equipped with 10-module fabric
filters (baghouses) and are subject to 310 CMR 7.08 (2)(f)2 limits for
PM of 27 mg/dscm or less at 7 percent oxygen (dry basis). This emissions
limit is consistent with EPA’s 1995 Emissions Guidelines for MWCs.  In
2006, EPA lowered the Emissions Guideline for PM to 25 mg/dscm.  MassDEP
has determined that a PM emissions rate of 25 mg/dscm for each of
Wheelabrator’s units represents BART.  MassDEP has determined that a
PM emissions limit lower than 25 mg/dscm is not warranted given the
additional cost required to install supplementary PM controls because
Wheelabrator already has control equipment equivalent to MACT and the
degree of visibility improvement that could be achieved is de minimis.
MassDEP issued a modified Emission Control Plan Final Approval for
Wheelabrator with the 25 mg/dscm PM emission rate in March 2012
(Appendix JJ).

Energy and Non-air Quality Impacts

There are no significant energy and non-air quality impacts associated
with the proposed BART for Wheelabrator-Saugus.  One environmental
benefit of a lower NOx emissions limit, in addition to improved
visibility, is the impact on acid deposition in Massachusetts and
Northern New England.  Reductions in ambient concentrations of NOx will
reduce acid deposition as well as excess nitrogen deposition, thereby
reducing the acidification of lakes, streams and soils and material
damage to buildings, and the eutrophication of inland and coastal
waters.

Remaining Useful Life

As a member of MANE-VU, Massachusetts has determined that a
BART-eligible source that is found to have reasonable control options
available to it should either control emissions from that BART-eligible
source prior to July 1, 2013, or accept a federally enforceable permit
limitation or retirement date prior to adoption of this SIP.

Schedule for BART determination and Federal Enforceability

40 CFR 51.308(e)(1)(iv) requires that BART controls must be in operation
for each applicable source no later than five years after EPA SIP
approval and must be federally enforceable. MassDEP has issued an
Emissions Control Plan Final Approval pursuant to 310 CMR 7.08(2) that
requires Wheelabrator to comply with the BART NOx and PM emissions
limits in 2012.  Because 310 CMR 7.08(2) is included in the
federally-approved Massachusetts State Plan for Municipal Waste
Combustors, the  Emission Control Plan Final Approval for Wheelabrator
is federally enforceable.

Alternative to BART for EGUs

EPA’s Regional Haze Rule at 40 CFR 51.308(e)(3) gives states the
authority to implement an alternative measure that achieves greater
reasonable progress towards improving visibility at Class I areas than
source-specific Best Available Retrofit Technology (BART).  A state can
establish a BART benchmark (i.e., emissions reductions that would result
from the application of source-specific BART), and then can compare the
emissions reductions achieved from the alternative measure with the
emissions reductions that would be achieved from the BART benchmark.  If
the reductions from the alternative measure are greater than the BART
benchmark, the state can assume that the alternative measure results in
greater reasonable progress than BART.

MassDEP has adopted an alternative to BART that covers all of the
BART-eligible electric generating units (EGUs) plus all additional coal-
and oil-fired EGUs subject to MassDEP’s regulation 310 CMR 7.29,
Emissions Standards for Power Plants.  This includes the BART-eligible
EGUs (Brayton Point Units 1–4, Canal Station Units 1–2, Mystic Unit
7, Salem Harbor Unit 4, and Cleary Flood Units 8–9), plus additional
units subject to 310 CMR 7.29, which include Salem Harbor Units 1–3,
Mt. Tom Station Unit 1, and Somerset Power Unit 8.  MassDEP’s
alternative to BART includes the following measures:

Existing regulation 310 CMR 7.29, Emissions Standards for Power Plants,
which establishes NOx and SO2 emissions rates (as well as mercury
emission rates and carbon dioxide caps) for certain EGUs.

The retirement of Somerset Power.

Permit restrictions for Brayton Point, Salem Harbor, and Mt. Tom Station
that limit/retire SO2 and/or NOx emissions.

Existing regulation 310 CMR 7.19, Reasonably Available Control
Technology (RACT) for Sources of Oxides of Nitrogen NOx, which
establishes NOx emission rates for various sources, including EGUs.

Amended regulation 310 CMR 7.05, Fuels All Districts, which requires
EGUs that burn residual oil to limit the sulfur content to 0.5% by
weight beginning July 1, 2014.

As demonstrated below, MassDEP’s alternative to BART will achieve
greater emission reductions of SO2 and NOx than would be achieved
through the installation and operation of BART alone.  The following
sections establish a BART benchmark, provide estimated emission
reductions that will be achieved by the alternative to BART measures
listed above, and show that reductions from these alternative measures
exceed reductions from the application of BART alone.

BART benchmark

Massachusetts has used a most-stringent-case BART as the BART benchmark,
based on EPA’s Guideline for BART Determinations and the MANE-VU
Workgroup recommended emissions limits for SO2 and NOx, which take into
consideration the currently available cost-effective SO2 and NOx control
technologies for EGUs.

EPA’s Guideline for BART Determinations (40 CFR 51, Appendix Y)
establishes presumptive SO2 emission limits for 750 megawatt (MW) and
larger power plants.  Four facilities (Brayton, Canal, Mystic, and Salem
Harbor) are greater than 750 MW, while Cleary Flood is below 750 MW.
Seven of the BART-eligible units are primarily oil-fired, while Brayton
Point Units 1, 2, and 3 are primarily coal-fired.

For each oil-fired EGU at a 750 MW or larger power plant, regardless of
size, EPA recommends that, for SO2 control purposes, states evaluate
limiting the sulfur content of the fuel oil burned to 1 percent or less
by weight.  For NOx control purposes at power plants with a generating
capacity in excess of 750 MW currently using SNCR or SCR for part of the
year, EPA suggests that use of such controls year round is BART.

For each uncontrolled coal-fired EGU greater than 200 MW at a 750 MW or
larger power plant, EPA recommends SO2 control levels of either 95% or
0.15 lbs/MMBtu.  For NOx, EPA recommends using selective non-catalytic
reduction (SNCR) or selective catalytic reduction (SCR) year round.  For
coal-fired EGUs operating without post-combustion NOx controls, EPA
provides presumptive NOx emission rates differentiated by boiler design
and type of coal burned.

As part of the regional consultation process, the MANE-VU BART Workgroup
established recommended BART emission limits for various types of
sources (see Appendix R, Five-Factor Analysis of BART-Eligible Sources).
 Table 15 includes the MANE-VU BART Workgroup recommended BART emission
limits for non-CAIR EGUs.  (The BART-eligible units in Massachusetts are
considered non-CAIR EGUs because Massachusetts was not subject to the
CAIR SO2 and NOx annual programs.)  The MANE-VU BART workgroup’s
recommended BART emission limits are the same as EPA’s recommended
limits for SO2 for coal, but are more stringent than the EPA recommended
limits for SO2 for oil and for NOx.  Therefore, Massachusetts used the
MANE-VU recommended emission limits to establish the BART benchmark.

Table   SEQ Table \* ARABIC  15 : MANE-VU BART Workgroup Recommended
BART Emission Limits for SO2 and NOx for non-CAIR EGUs

	SO2	NOx

	95% control or 0.15 lb/MMBtu (coal) and 0.33 lbs/MMBtu (oil)

	o In NOx SIP call area,

extend use of controls to

year-round, and

o 0.1 – 0.25 lbs/MMBtu,

depending on boiler and fuel type

Massachusetts’ Alternative BART Program for SO2

MassDEP’s Alternative to BART for SO2 relies on:

310 CMR 7.29, Emissions Standards for Power Plants, which establishes
SO2 emissions standards for certain EGUs.

Permit restrictions for Mt. Tom Station, Brayton Point, and Salem Harbor
that disallow the use of 310 CMR 7.29 SO2 Early Reduction Credits and
federal Acid Rain Allowances for compliance with 310 CMR 7.29.

An annual cap of 300 tons of SO2 for Salem Harbor Unit 2, and a shutdown
of Units 3 and 4 beginning June 1, 2014.

The retirement of Somerset Power in 2010.

Amended regulation 310 CMR 7.05, Fuels All Districts, which requires
EGUs that burn residual oil to limit the sulfur content to 0.5% by
weight beginning July 1, 2014.

Each is described below:

310 CMR 7.29, Emissions Standards for Power Plants:  MassDEP’s
existing regulation 310 CMR 7.29 (Appendix DD) establishes a
facility-wide rolling 12-month SO2 emissions rate of 3.0 pounds per
megawatt-hour and a monthly average emissions rate of 6.0 pounds per
megawatt-hour.  This regulation allows the use of 310 CMR 7.29 SO2 Early
Reduction Credits (on a 1 ton credit to 1 ton excess emission basis) and
the use of federal Acid Rain SO2 Allowances (on a 3 ton allowance to 1
ton excess emission basis) for compliance with the 3.0 pounds per
megawatt-hour emissions rate.  310 CMR 7.29 applies to Brayton Point,
Canal Station, Mt. Tom Station, Mystic, Salem Harbor, and Somerset
Power.

Mt. Tom Station:  On May 15, 2009, MassDEP issued an amended Emission
Control Plan Final Approval (Appendix EE) for Mt. Tom Station that
prohibits the use of 310 CMR 7.29 SO2 Early Reduction Credits and
federal Acid Rain Allowances for compliance with 310 CMR 7.29.

Brayton Point:  On April 12, 2012, MassDEP issued an Amended Emission
Control Plan Final Approval (Appendix GG) that prohibits the use of
Early Reduction Credits and federal Acid Rain Allowances for compliance
with 310 CMR 7.29 after June 1, 2014.

Salem Harbor:  On March 27, 2012, MassDEP issued a Final Amended
Emission Control Plan (ECP) Approval (Appendix FF) that prohibits the
use of 310 CMR 7.29 SO2 Early Reduction Credits and federal Acid Rain
Allowances for compliance with 310 CMR 7.29, after June 1, 2014.  The
ECP also establishes an annual cap of 300 tons of SO2 for Salem Harbor
Unit 2 and the shutdown of Units 3 and 4 effective June 1, 2014.

Somerset Power Retirement:  Somerset Power ceased operating in 2010, and
on June 22, 2011, MassDEP issued a letter (Appendix HH) that revoked all
air approvals and permits for the facility and deemed all pending permit
applications withdrawn.

310 CMR 7.05 Fuels All Districts:  MassDEP’s 310 CMR 7.05, Fuels All
Districts (Appendix II) requires EGUs that burn residual oil to limit
the sulfur content to 0.5% by weight beginning July 1, 2014.

Analysis of Alternative BART Program for SO2

Table 16 shows the BART benchmark estimated SO2 emissions for the
BART-eligible units, which were calculated by multiplying the MANE-VU
BART workgroup recommended BART SO2 emission rates in lbs/MMBtu (see
Table 15 above) by each unit’s 2002 heat input in MMBtu.  The BART
benchmark results in a estimated emissions reduction of 50,752 tons of
SO2 from 2002 emissions.

Table   SEQ Table \* ARABIC  16 : BART Benchmark for SO2

BART Eligible Facility	Unit	2002 SO2 Emissions (Tons)	2002 Heat Input
(MMBtu)	MANE-VU Recommended SO2 BART Emission Rate (lbs/MMBtu)	BART
Benchmark Estimated SO2 Emissions (Tons)

Brayton Point 	1	9,254	17,000,579	0.15	1,275

Brayton Point 	2	8,853	15,896,795	0.15	1,192

Brayton Point 	3	19,450	36,339,809	0.15	2,725

Brayton Point	4	2,037	4,787,978	0.33	790

Canal Station 	1	13,066	27,295,648	0.33	4,504

Canal Station 	2	8,948	19,440,919	0.33	3,208

Cleary Flood 	8	39	92,567	0.33	15

Cleary Flood 	9	68	2,123,819	0.33	350

Mystic 	7	3,727	15,172,657	0.33	2,503

Salem Harbor 	4	2,886	6,137,412	0.33	1,013

 Total	 	68,328	 	 	17,576

	SO2 Reduction	50,752

Table 17 shows the Alternative to BART estimated SO2 emissions, which
were calculated by multiplying MassDEP’s 310 CMR 7.05 SO2 emission
rates in lbs/MMBtu by the 2002 heat input in MMBtu, multiplying the 310
CMR 7.29 SO2 rolling 12-month emissions rate in lbs/MWh by the 2002
megawatt-hours electrical generation, and accounting for permit
restrictions in effect at Mt. Tom Station, Brayton Point, and Salem
Harbor, as well as the retirement of Somerset Power.  The Alternative to
BART results in a estimated emissions reduction of 54,986 tons from 2002
emissions, which is 4,234 tons more than the estimated emissions
reductions from the BART benchmark.

Table   SEQ Table \* ARABIC  17 :  Alternative to BART for SO2

Facility	Unit	2002 SO2 Emissions (Tons)	2002 Heat Input (MMbtu) or
Generation (MWh)	Alternative BART Emission Rate (lbs/MMBtu or lbs/MWh)
Alternative BART Estimated SO2 Emissions (Tons)

Brayton Point 	1	9,254	1,951,839	3.0	2,928

Brayton Point 	2	8,853	1,855,515	3.0	2,783

Brayton Point 	3	19,450	4,294,957	3.0	6,442

Brayton Point 	4	2,037	4,787,978	0.56	1,341

Canal Station	1	13,066	27,295,648	0.56	7,643

Canal Station 	2	8,948	19,440,919	0.56	5,443

Cleary Flood 	8	39	92,567	0.56	25

Cleary Flood 	9	68	2,123,819	0.56	595

Mount Tom 	1	5,282	1,047,524	3.0	1,571

Mystic 	7	3,727	15,172,657	0.56	4,248

Salem Harbor 	1	3,425	631,606	3.0	947

Salem Harbor 	2	2,821	527,939	Cap	300

Salem Harbor 	3	4,999	974,990	Retired	0

Salem Harbor 	4	2,886	6,137,412	Retired	0

Somerset 	8	4,399	8,910,087	Retired	0

 Total	 	89,254	 	 	34,268

	SO2 Reduction	54,986

40 CFR 51.308(e)(3) provides a process for determining whether an
alternative measure makes greater reasonable progress than would be
achieved through the installation and operation of BART.  If the
geographic distribution of emissions reductions is similar between an
alternative measure and BART, the comparison of the two measures may be
made on the basis of emissions alone.  The alternative measure may be
deemed to make greater reasonable progress than BART if it results in
greater emissions reductions than requiring sources subject to BART to
install, operate and maintain BART.  In this case, the Alternative to
BART achieves greater emissions reductions than BART and the geographic
distribution of emissions reductions is nearly identical since all of
the units subject to BART are included in the Alternative to BART.

Massachusetts’ Alternative BART Program for NOx

MassDEP’s Alternative to BART for NOx relies on:

310 CMR 7.29, Emissions Standards for Power Plants, which establishes
NOx emissions rates for certain EGUs.

An annual cap of 276 tons of NOx for Salem Harbor Unit 1 and an annual
cap of 50 tons of NOx for Unit 2, and a shutdown of Units 3 and 4
beginning June 1, 2014.

The retirement of Somerset Power in 2010.

310 CMR 7.19, Reasonably Available Control Technology (RACT) for Sources
of Oxides of Nitrogen NOx, which establishes NOx emissions standards for
various sources, including EGUs.

Each is described below:

310 CMR 7.29, Emissions Standards for Power Plants: MassDEP’s existing
regulation 310 CMR 7.29 establishes a rolling 12-month average NOx
emission rate of 1.5 lbs/MWh and a monthly average emission rate of 3
lbs/MWh.  310 CMR 7.29 applies to Brayton Point, Canal Station, Mt. Tom
Station, Mystic, Salem Harbor, and Somerset Power.

Salem Harbor:  On March 27, 2012, MassDEP issued a Final Amended
Emission Control Plan (ECP) Approval (Appendix FF) that requires an
annual cap of 276 tons of NOx for Salem Harbor Unit 1 and an annual cap
of 50 tons of NOx for Unit 2, and a shutdown of Units 3 and 4 beginning
June 1, 2014.

Somerset Power Retirement:  Somerset Power ceased operating in 2010, and
on June 22, 2011, MassDEP issued a letter (Appendix HH) that revoked all
air approvals and permits for the facility and deemed all pending permit
applications withdrawn.

310 CMR 7.19, Reasonably Available Control Technology (RACT) for Sources
of Oxides of Nitrogen NOx:  MassDEP’s existing regulation 310 CMR 7.19
establishes NOx emissions rates for various stationary sources,
including EGUs.  Under 310 CMR 7.19, Cleary Flood Units 8 and 9 are
subject to a NOx emission rate of 0.28 lbs/MMBtu.  Mystic Unit 7 is
subject to a NOx emission rate of 0.25 lbs/MMBtu.  Mystic also is
subject to 310 CMR 7.29 on a facility-wide basis; however, Mystic Unit 7
could exceed the 310 CMR 7.29 NOx rate of 1.5 lbs/MWh while the facility
as a whole complies with the rate because the other units at Mystic are
natural gas-fired with low NOx emissions, and therefore the 310 CMR 7.19
unit-specific NOx rate of 0.25 lbs/MMBtu is the controlling factor for
Unit 7.

Analysis of Alternative BART Program for NOx

Table 18 shows the BART benchmark estimated NOx emissions for the
BART-eligible units, which were calculated by multiplying the lowest
MANE-VU BART workgroup recommended BART emission rate of 0.1 lb/MMBtu
(from Table 15 above) by the 2002 heat input in MMBtu.  The BART
benchmark results in estimated emissions reductions of 12,820 tons of
NOx from 2002 emissions.

Table   SEQ Table \* ARABIC  18 : BART Benchmark for NOx

BART-Eligible Facility	Unit	2002 NOx Emissions (Tons)	2002 Heat Input
(MMBtu)	MANE-VU Recommended BART NOx Emission Rate (lbs/MMBtu)	BART
Benchmark Estimated NOx Emissions (Tons)

Brayton Point 	1	2,513	17,000,579	0.10	850

Brayton Point 	2	2,270	15,896,795	0.10	795

Brayton Point 	3	7,335	36,339,809	0.10	1,817

Brayton Point	4	552	4,787,978	0.10	239

Canal Station 	1	3,339	27,295,648	0.10	1,365

Canal Station 	2	2,260	19,440,919	0.10	972

Cleary Flood 	8	12	92,567	0.10	5

Cleary Flood 	9	161	2,123,819	0.10	106

Mystic 	7	805	15,172,657	0.10	759

Salem Harbor 	4	787	6,137,412	0.10	307

 Total	 	20,034	 	 	7,214

	NOx Reduction	12,820

Table 19 shows the Alternative to BART estimated NOx emissions, which
were calculated by multiplying MassDEP’s 310 CMR 7.29 NOx emission
rate in lbs/megawatt hour (MWh) and 310 CMR 7.19 NOx emission rate in
lbs/MMbtu by the 2002 electricity generation in MWh and 2002 heat input
in MMBtu, respectively, and accounting for permit restrictions in effect
at Salem Harbor and the retirement of Somerset Power.  The Alternative
to BART results in estimated emission reductions of 13,117 tons from
2002 emissions. The estimated NOx reductions from the Alternative to
BART are 297 tons more than estimated reductions from BART alone.

Table   SEQ Table \* ARABIC  19 :  Alternative to BART for NOx

Facility	Unit	2002 NOx Emission (Tons)	2002 Heat Input (MMBtu) or
Generation (MWh)	Alternative BART Emission Rate (lbs/MMBtu or lbs/MWh)
Alternative BART Estimated NOx Emissions (Tons)

Brayton Point 	1	2,513	1,951,839	1.5	1,464

Brayton Point 	2	2,270	1,855,515	1.5	1,392

Brayton Point 	3	7,335	4,294,957	1.5	3,221

Brayton Point 	4	552	401,305	1.5	301

Canal Station	1	3,339	2,945,578	1.5	2,209

Canal Station 	2	2,260	1,910,079	1.5	1,433

Cleary Flood 	8	12	92,567	0.28	13

Cleary Flood 	9	161	2,123,819	0.28	297

Mount Tom 	1	1,969	1,047,524	1.5	786

Mystic 	7	805	15,172,657	0.25	1,897

Salem Harbor 	1	920	631,606	Cap	276

Salem Harbor 	2	755	527,939	Cap	50

Salem Harbor 	3	1,331	974,990	Retired	0

Salem Harbor 	4	787	508,342	Retired	0

Somerset 	8	1,445	8,910,087	Retired	0

 	 	26,455	 	 	13,338

	NOx Reduction	13,117

As with SO2, the Alternative to BART achieves greater NOx emission
reductions than BART and the geographic distribution of NOx emissions
reductions is nearly identical since all of the units subject to BART
are included in the Alternative to BART.

BART for PM10 Emissions

MassDEP has made source-by-source BART determinations for PM10 emissions
from its BART EGUs.  An overview of 2002 and 2009 PM10 emissions and PM
controls at the EGU BART sources is contained in Table 20.
Collectively, these facilities emitted 1,531 tons of PM10 in 2002 that
diminished visibility in New England Class I areas by 0.032-0.037
deciviews (ddv).  Through installation of controls, these facilities
have significantly reduced PM emissions, so that in 2009 these
facilities emitted a total of 109 tons of PM10.

CALPUFF modeling of 2002 PM emissions at these facilities shows an
impact that was well below 0.1 ddv on the worst day at affected Class I
areas, for each unit and cumulatively, which is the level MANE-VU has
identified that the degree of visibility improvement is so small (<0.1
ddv) that no reasonable weighting could justify additional controls
under BART.  The visibility impact would be even lower today based on
the emissions reductions achieved since 2002 as shown in Table 20.
MassDEP considered MANE-VU’s evaluation of PM control options;
however, MassDEP has determined that no additional controls are
warranted for primary PM10 because controls have been added to all but
one of the facilities, and the additional cost of further control is not
justified since there would be no significant visibility improvement.

Table   SEQ Table \* ARABIC  20 : Massachusetts PM10 BART Sources,
Emissions and Controls

I.D.	Source	Unit	PM10 ddv	2002 PM10 Emissions (tpy)	2009 PM10 Emissions
(tpy)	PM Controls	PM Emission Limits lbs/MMBtu as of 2009

1200061	Brayton Point	1	0.031, 0.026	386	39	Fabric Filter Baghouse	0.08

1200061	Brayton Point	2

Fabric Filter Baghouse	0.08

1200061	Brayton Point	3

Fabric Filter Baghouse (Planned)	0.08

1200061	Brayton Point	4	0.000, 0.000	6	0	ESP	0.03

1200054	Canal Station	1	0.000, 0.000	672	60	ESP	0.02

1200054	Canal Station	2

ESP	0.02

1190128	Mystic Station	7	0.002, 0.003	131	4	ESP	0.05

1190194	Salem Harbor	4	0.001, 0.001	316	0	ESP	0.04

1200067	Cleary Flood	8	0.003, 0.002	20	6	 None	0.12

1200067	Cleary Flood	9

 None

 	0.12

Reasonably Attributable Visibility Impairment

40 CFR 51.302(c) provides for general plan requirements in cases where
the affected Federal

Land Manager has notified the state that Reasonably Attributable
Visibility Impairment

(RAVI) exists in a Class I Area in the state.  Based on the modeling
conducted by MANE-VU

and consultations with Federal Land Managers, there are no RAVI sources
in Massachusetts or the other MANE-VU states.

Reasonable Progress Goals

For each Class I area within a State/Tribe, 40 CFR Section 51.308(d)(1)
requires the State/Tribe to establish reasonable progress goals
(expressed in deciviews) that provide for reasonable progress towards
achieving natural visibility.  EPA released guidance on June 7, 2007 to
use in setting reasonable progress goals.  The goals must provide
improvement in visibility for the most impaired days and ensure no
degradation in visibility for the least impaired days over the SIP
period.  The State/Tribe also must provide an assessment of the number
of years it would take to attain natural visibility conditions if
improvement continues at the rate represented by the reasonable progress
goals.

Under 40 CFR Section 51.308(d)(1)(iv), consultation is required in
developing reasonable progress goals. The rule states:

In developing each reasonable progress goal, the State must consult with
those States which may reasonably be anticipated to cause or contribute
to visibility impairment in the mandatory Class I Federal area. In any
situation in which the State cannot agree with another such State or
group of States that a goal provides for reasonable progress, the State
must describe in its submittal the actions taken to resolve the
disagreement. In reviewing the State's implementation plan submittal,
the Administrator will take this information into account in determining
whether the State's goal for visibility improvement provides for
reasonable progress towards natural visibility conditions.

In developing the reasonable progress goal, the Class I State/Tribe also
must consider four factors (cost of compliance, time needed for
compliance, energy and non-air quality environmental impacts, and
remaining useful life of any affected source).  The State/Tribe also
must show that it considered the uniform rate of progress and the
emission reduction measures needed to achieve reasonable progress for
the period covered by the implementation plan, and if the state proposes
a rate of progress slower than the uniform rate of progress, assess the
number of years it would take to attain natural conditions if visibility
improvement continues at the rate proposed.

Because Massachusetts does not contain any Class I areas, it did not
determine reasonable progress goals but did consult with states it
impacts.  Massachusetts consulted with Maine, New Hampshire, and
Vermont, which have Class I areas impacted by emissions from sources
within Massachusetts.  Massachusetts agrees with the reasonable progress
goals established by these states through the MANE-VU planning process
for their Class I areas.

As a benchmark to aid in developing reasonable progress goals, MANE-VU
compared baseline visibility conditions to natural visibility conditions
at each MANE-VU Class I area.  The difference between baseline and
natural visibility conditions for the 20 percent worst days was used to
determine the uniform rate of progress that would be needed during each
implementation period in order to attain natural visibility conditions
by 2064.  Table 21 presents baseline visibility, natural visibility, and
required uniform rate of progress for the MANE-VU Class I areas affected
by emissions from sources within Massachusetts.  Visibility values are
expressed in deciviews (dv), where each single-unit deciview decrease
would represent a barely perceptible improvement in visibility.

Table   SEQ Table \* ARABIC  21 : Uniform Rate of Progress Calculation
(all values in deciviews)

Class I Area	2000-2004

Baseline

Visibility

(20% Worst

Days)	Natural

Visibility

(20% Worst

Days)	Total

Improvement

Needed by

2018	Total

Improvement

Needed by

2064	Uniform

Annual Rate of

Improvement

Acadia National Park	22.9	12.4	2.4	10.5	0.174

Moosehorn Wilderness and

Roosevelt Campobello

International Park

21.7

12.0

2.3

9.7

0.162

Great Gulf Wilderness and

Presidential Range - Dry River

Wilderness

22.8

12.0

2.5

10.8

0.180

Lye Brook Wilderness	24.5 	11.7	3.0	12.8	0.212

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.

The reasonable progress goals established for each of the Class I areas
are expected to provide greater visibility improvements than the uniform
rate of progress shown in Table 21.  A summary of the reasonable
progress goals are shown in Tables 22 and 23.

Table   SEQ Table \* ARABIC  22 : Reasonable Progress Goals - 20% Worst
Days (all values in deciviews)

Visibility Condition	2000-2004 Baseline Visibility	2018 Reasonable
Progress Goal	Visibility Improvement by 2018	Natural Visibility

Acadia National Park	22.9	19.4	3.5	12.4

Moosehorn Wilderness Area/ Roosevelt Campobello International Park

21.7

19.0

2.7

12.0

Great Gulf Wilderness	22.8	19.1	3.7	12.0

Presidential Range – Dry River Wilderness	22.8	19.1	3.7	12.0

Lye Brook Wilderness	24.4	20.9	3.5	11.7

Table   SEQ Table \* ARABIC  23 : Reasonable Progress Goals - 20% Best
Days (all values in deciviews)

Visibility Condition	2000-2004 Baseline Visibility	2018 Reasonable
Progress Goal	Visibility Improvement by 2018	Natural Visibility

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

Great Gulf Wilderness	7.7	7.2	0.5	3.7

Presidential Range – Dry River Wilderness	7.7	7.2	0.5	3.7

Lye Brook Wilderness	6.4	5.5	0.9	2.8

Long-Term Strategy

40 CFR Section 51.308(d)(3) requires Massachusetts to submit a long-term
strategy that addresses regional haze visibility impairment for each
mandatory Class I Federal area within and outside the state that may be
affected by emissions from within the state.  The long-term strategy
must include enforceable emissions limitations, compliance schedules,
and other measures necessary to achieve the reasonable progress goals
established by states where the Class I areas are located.  Consultation
between states affecting and/or containing Class I areas must be
performed to develop coordinated emission management strategies.  The
state must demonstrate that it has included all measures necessary to
obtain its share of the emission reductions needed to meet the progress
goal for the area.  If the state has participated in a regional planning
process, the state must include measures needed to achieve its
obligations agreed upon through that process.

This section describes the long-term strategy that Massachusetts will
pursue to address visibility impairment for each of the following Class
I areas that are affected by emissions from within Massachusetts: Acadia
National Park, Great Gulf Wilderness, Lye Brook Wilderness, Presidential
Range/Dry River Wilderness, Moosehorn Wilderness, and
Roosevelt/Campobello International Park.

The long-term strategy includes enforceable emissions limitations,
compliance schedules, and other measures necessary to achieve the
reasonable progress goals established for the Class I areas.  To the
extent that it is practicable, Massachusetts commits to adopting these
measures before submitting a report on reasonable progress to EPA in
2013.  Additional measures may be reasonable to adopt at a later date
after further consideration and review.

Overview of the Long-Term Strategy Development Process

As a participant in MANE-VU, Massachusetts supported a regional approach
towards deciding which control measures to pursue for regional haze
based on technical analyses documented in the following reports:

Contributions to Regional Haze in the Northeast and Mid-Atlantic United
States (called the Contribution Assessment, Appendix   REF _Ref191968764
\r \h  \* MERGEFORMAT  A ),

Five-Factor Analysis of BART-Eligible Sources: Survey of Options for
Conducting BART Determinations (Appendix R),

Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning
Model® (called the CAIR+ Report, Appendix S),

Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I
Areas (called the Reasonable Progress Report, Appendix T), and

Assessment of Control Technology Options for BART-Eligible Sources:
Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and
Pulp Facilities (Appendix U).

The regional strategy development process identified reasonable measures
that would reduce emissions contributing to visibility impairment at
Class I areas affected by emissions from within the MANE-VU region by
2018 or earlier.  The technical basis for the long-term strategy is
discussed in the following section, which describes the process of
identifying potential emission reduction strategies.

MANE-VU reviewed a wide range of potential control measures to reduce
emissions from sources contributing to visibility impairment in affected
Class I areas.  The process by which MANE-VU arrived at a set of
proposed regional haze control measures to pursue for the 2018 milestone
started in late 2005 in conjunction with efforts to identify measures to
reduce ozone pollution.  The Ozone Transport Commission (OTC) selected a
contracting firm to assist with the analysis of ozone and regional haze
control measure options.  OTC provided the contractor with a “master
list” of some 900 potential control measures, based on experience and
previous state implementation plan work.  With the help of an internal
OTC control measure workgroup, the contractor also identified available
regional haze control measures for MANE-VU’s further consideration.

MANE-VU then developed an interim list of control measures, which for
regional haze included: beyond-CAIR sulfate reductions from EGUs,
low-sulfur heating oil (residential and commercial), and controls on ICI
boilers (both coal and oil-fired), lime and cement kilns, residential
wood combustion, and outdoor burning (including outdoor wood boilers).

The next step in the regional haze control measure selection process was
to further refine the interim list.  The CAIR+ Report (Appendix   REF
_Ref197852454 \r \h  S ) documents the analysis of the cost of
additional SO2 and NOx controls at EGUs in the Eastern U.S.  The
Reasonable Progress Report (Appendix   REF _Ref197852975 \r \h  T )
documents the assessment of control measures for EGUs and the other
source categories selected for analysis.  Further analysis is provided
in the NESCAUM document entitled, “Assessment of Control Technology
Options for BART-Eligible Sources: Steam Electric Boilers, Industrial
Boilers, Cement Plants and Paper and Pulp Facilities” (Appendix   REF
_Ref197852974 \r \h  \* MERGEFORMAT  0 ).

The beyond-CAIR EGU strategy continued to stay on the list since EGU
sulfate emissions have, by far, the largest impact on visibility in the
MANE-VU Class I areas.  Likewise, a low-sulfur oil strategy gained
support after a NESCAUM-initiated conference with refiners and fuel-oil
suppliers concluded that such a strategy could realistically be
implemented in the 2014 timeframe.  The low-sulfur heating oil and the
oil-fired ICI boiler sector control measures merged into an overall
low-sulfur oil strategy for distillate and residual oils for both the
residential and commercial heating and oil-fired ICI boiler source
sectors.

During MANE-VU’s internal consultation meeting in March 2007, member
states reviewed the interim list of control measures to make further
refinements.  States determined, for example, that there are too few
coal-fired ICI boilers in the MANE-VU states to be considered a
“regional” control strategy, but could be a sector pursued by
individual states.  They also determined that control of lime and cement
kilns, of which there are few in the MANE-VU region, would likely be
handled in each state’s BART determination process.  Residential wood
burning and outdoor wood boilers remained a strategy for those states
where localized visibility impacts may be of concern even though
emissions from these sources are primarily organic carbon and direct
particulate matter.  Finally, outdoor wood burning also was determined
to be better left as a sector to be examined and controlled further by
individual states, due to issues of enforceability and penetration of
existing state regulations.

Technical Basis for Strategy Development

40 CFR Section 51.308(d)(3)(iii) requires states to document the
technical basis for the state’s apportionment of emission reductions
necessary to meet reasonable progress goals in each Class I area
affected by the state’s emissions.  Massachusetts relied on technical
analyses developed by MANE-VU to demonstrate that its emission
reductions, when coordinated with those of other states, are sufficient
to achieve reasonable progress goals in Class I areas affected by
Massachusetts.

The emission reductions necessary to meet reasonable progress goals in
each Class I area affected by Massachusetts are summarized in the
following sections of this SIP and are described in the following
documents:

Contributions to Regional Haze in the Northeast and Mid-Atlantic United
States (called the Contribution Assessment, Appendix   REF _Ref191968764
\r \h  \* MERGEFORMAT  A )

Baseline and Natural Background Visibility Conditions—Considerations
and Proposed Approach to the Calculation of Baseline and Natural
Background Visibility Conditions at MANE-VU Class I Areas (Appendix
REF _Ref191968946 \r \h  \* MERGEFORMAT  E )

MANE-VU Modeling for Reasonable Progress Goals: Model Performance
Evaluation, Pollution Apportionment, and Control Measure Benefits
(Appendix   REF _Ref201032634 \r \h  \* MERGEFORMAT  F )

2018 Visibility Projections (Appendix   REF _Ref201032635 \r \h  \*
MERGEFORMAT  G )

Five-Factor Analysis of BART-Eligible Sources: Survey of Options for
Conducting BART Determinations (Appendix   REF _Ref201033142 \r \h  \*
MERGEFORMAT  R )

Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning
Model® (called the CAIR+ Report, Appendix   REF _Ref197852454 \r  \*
MERGEFORMAT  S )

Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I
Areas (called the Reasonable Progress Report) (Appendix   REF
_Ref197852975 \r  \* MERGEFORMAT  T )

Assessment of Control Technology Options for BART-Eligible Sources:
Steam Electric Boilers, Industrial Boilers, Cement Plants and Paper and
Pulp Facilities (Appendix   REF _Ref197852974 \r  \* MERGEFORMAT  0 )

The Nature of the Fine Particle and Regional Haze Air Quality Problems
in the MANE-VU Region:  A Conceptual Description (Appendix   REF
_Ref197834028 \r \h  \* MERGEFORMAT  V )

In addition, Massachusetts relied on analyses conducted by neighboring
RPOs, including the following documents, which are available upon
request but are not incorporated into this SIP:

VISTAS Reasonable Progress Analysis Plan by VISTAS, dated September 18,
2006

Reasonable Progress for Class I Areas in the Northern Midwest-Factor
Analysis, by EC/R, dated July 18, 2007

Massachusetts worked with other members of the Ozone Transport
Commission and MANE-VU, as described in Section 2, to consider a wide
variety of potential emission reduction strategies covering a wide range
of sources of SO2 and other pollutants contributing to regional haze.
40 CFR 51.308(d)(1) requires states to consider several factors in
developing their long-term strategies.  Using available information
about emissions and potential impacts, the MANE-VU Reasonable Progress
Workgroup selected the following source categories for detailed
analysis:

Coal and oil-fired electric generating units (EGUs);

Point and area source industrial, commercial and institutional boilers;

Cement kilns;

Lime kilns;

The use of low-sulfur heating oil; and

Residential wood combustion and open burning.

These efforts led to the selection of the emission reduction strategies
presented in this SIP.

2018 Emission Reductions Due to Ongoing Air Pollution Controls

40 CFR Section 51.308(d)(3)(v)(A) requires states to consider emission
reductions from ongoing pollution control programs.  In developing its
long-term strategy, Massachusetts considered emission control programs
being implemented between the 2002 baseline period and 2018, as
discussed below.  Many of the emission reduction programs represent
commitments already made by Massachusetts and other states to implement
air pollution control measures for EGU point sources, non-EGU point
sources, and area sources, respectively.  These control measures are the
same measures that were included in the 2018 emissions inventory and
used in the modeling.  While these control measures were not designed
expressly for the purpose of improving visibility, the pollutants they
control include those that contribute to visibility impairment in
MANE-VU Class I Areas.

MANE-VU’s 2018 “beyond on the way” (BOTW) emissions inventory
accounts for emission controls that are already in place, as well as
those that are not yet finalized but are likely to achieve additional
reductions by 2009.  The BOTW inventory was developed based on the
MANE-VU 2002 Version 3.0 inventory and the MANE-VU 2018 on the books/on
the way (OTB/OTW) inventory.  Inventories used for other RPOs also
reflect anticipated emissions controls that will be in place by 2018.
The inventory is termed “beyond on the way” because it includes
control measures that were developed for ozone SIPs that are 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.  Given the uncertainty inherent in the BOTW emissions
inventory due to lack of enforceability, Massachusetts is continuing to
evaluate these measures to determine whether they are reasonable to
adopt and implement by 2018 and expects to make that determination in
the progress report it will submit in 2013.

More information may be found in the following documents:

MANE-VU Modeling for Reasonable Progress Goals: Model Performance
Evaluation, Pollution Apportionment, and Control Measure Benefits
(Appendix   REF _Ref201032634 \r \h  \* MERGEFORMAT  F )

2018 Visibility Projections (Appendix   REF _Ref201032635 \r \h  \*
MERGEFORMAT  G )

Development of Emissions Projections for 2009, 2012, and 2018 for
Non-EGU Point, Area, and Non-road Sources in the MANE-VU Region
(Appendix   REF _Ref191969187 \r \h  \* MERGEFORMAT  N )

Documentation of 2018 Emissions from Electric Generating Units in the
Eastern U.S. for MANE-VU’s Regional Haze Modeling (Appendix   REF
_Ref197835294 \r  \* MERGEFORMAT  W )

EGU Emissions Controls Expected by 2018

The following EGU emission reduction programs were included in the
modeling used to develop the reasonable progress goals and as the basis
for the long-term strategy:

Clean Air Interstate Rule (CAIR). The CAIR program was intended to
permanently cap emissions of SO2 and NOx in the eastern United States by
2015 and reduce SO2 emissions in the CAIR region by more than 70 percent
and NOx emissions by more than 60 percent from 2003 levels.  However,
CAIR was vacated by the U.S. Court of Appeals on July 11, 2008.  A
subsequent remand to EPA for remedy occurred on December 23, 2008.  CAIR
remained in place through 2011.    On August 8, 2011, EPA promulgated
the Cross State Air Pollution Rule, effective beginning January 1, 2012.
The IPM® model was used to predict future emissions from EGUs after
implementation of CAIR.  All MANE-VU Class I states used CAIR as a basis
for modeling progress towards the reasonable progress goals in their
Regional Haze SIPs.  For the short-term, this modeling is still valid.
MANE-VU will incorporate the details of EPA’s CSAPR into future
modeling.

Modifications to the output of IPM® made to better represent
anticipated controls are described in the report Documentation of 2018
Emissions from Electric Generating Units (Appendix   REF _Ref197835294
\r  \* MERGEFORMAT  W ). Controls considered in making these
modifications include the following:

Connecticut EGU Regulations: Connecticut adopted the following
regulations governing EGU emissions:

Regulations of Connecticut State Agencies (RCSA) section 22a-174- 19a,
limiting the SO2 emission rate to 0.33 lb SO2/MMBtu for fossil
fuel-fired EGUs greater than 15 MW that also are Title IV sources.
(Implementation status - 2007)

RCSA section 22a-174-22, limiting the non-ozone seasonal NOx emission
rate to 0.15 lb NOx/MMBtu for fossil fuel-fired EGUs greater than 15 MW.
(Implementation status - 2007)

Connecticut General Statutes section 22a-199, limiting the mercury (Hg)
emission rate to 0.0000006 lb Hg/MMBtu for all coal-fired EGUs, or
alternatively coal-fired EGUs can meet a 90% Hg emission reduction.
(Implementation status - 2008)

Delaware EGU Regulations:  Delaware adopted the following regulations
governing EGU emissions:

Reg. 1144, Control of Stationary Generator Emissions, SO2, PM, VOC and
NOx emission control, Statewide, Effective January 2006.

Reg. 1146, EGUs, Electric Generating Unit (EGU) Multi-Pollutant
Regulation, SO2 and NOx emission control, Statewide, Effective December
2007. SO2 reductions will be more than regulation specifies.

Regulation No. 1148, Control of Stationary Combustion Turbine Electric
Generating Unit Emissions, SO2, NOx, and PM2.5 emission control,
Statewide, Effective January 2007.

Delaware estimates that these regulations will result in the following
emission reductions for affected units:

SO2 2002 levels of 32,630 tons to 8,137 tons in 2018 (75 percent
decrease)

NOx 2002 levels of 8,735 tons to 3,740 tons in 2018 (57 percent
decrease)

Delaware Consent Decree:  Valero Refinery Delaware City, DE (formerly
Motiva, Valero Enterprises). 2002 SO2 levels of 29,747 tons will
decrease to 608 tons in 2018 (98 percent decrease). NOx 2002 levels of
1,022 tons will decrease to 102 tons in 2018 (90 percent decrease).

Maine EGU Regulations:  Maine adopted the following regulations
governing EGU emissions:

	Chapter 145 NOx Control Program, which limits the NOx emission rate to
0.22 lb NOx/MMBtu for fossil fuel-fired units greater than 25 MW built
before 1995 with a heat input capacity between 250 and 750 MMBtu/hr and
also limits the NOx emission rate to 0.15 lb NOx/MMBtu for fossil
fuel-fired units greater than 25 MW built before 1995 with a heat input
capacity greater than 750 MMBtu/hr. (Implementation - 2007)

Massachusetts EGU Regulations:  Massachusetts adopted 310 CMR 7.29,
Emissions Standards for Power Plants, in 2001, which:

Applies to six of the largest fossil fuel-fired power plants in
Massachusetts, including Brayton Point (Units 1, 2, 3, 4), Mystic (Units
4, 5, 6, 7, 81, 82, 93, and 94), NRG Somerset (Units 8), Mount Tom (Unit
1), Canal Station (Units 1 and 2), and Salem Harbor (Units 1, 2, 3, and
4).

Limits SO2 emissions to 6.0 lbs/MWh each month and 3.0 lbs/MWh as a
rolling average incorporating allowances and early reduction credits.

 Limits NOx emissions to 3.0 lbs/MWh each month and 1.5 lbs/MWh as a
rolling average.

Limits mercury (Hg) emissions to 85% Hg reduction or 0.0075 lbs Hg/GWh
in 2008 and 90% Hg reduction or 0.0025 lbs Hg/GWh in 2012.

Limits CO2 emissions to 1,800 lbs CO2/MWh.

These regulations will achieve an approximately 50 percent reduction in
NOx emissions and 50 - 75 percent reduction in SO2 emissions.

New Hampshire EGU Regulations: New Hampshire adopted the following
regulations governing EGU emissions:

Chapter Env-A 2900, which caps NOx emissions on all existing fossil
steam units to 3,644 tons NOx per year, SO2 emissions on all existing
fossil steam units to 7,289 tons SO2 per year, and CO2 emissions on all
existing fossil steam units to 5,425,866 tons CO2 per year.
(Implementation - 2007)

Chapter Env-A 3200, which limits NOx emissions on all fossil fuel-fired
EGUs greater than 15 MW to 0.15 lb NOx/MMBtu. (Implementation - 2007)

New Jersey New Source Review Settlement Agreements:  The New Jersey
settlement agreement with PSEG required the following actions:

Repower Bergen Unit #2 to combined cycle by December 31, 2002.

For Hudson Unit #2, install Dry FGD or approved alternative technology
by Dec. 31, 2006 to control SO2 emissions and operate the control
technology at all times the unit operates to limit SO2 emissions to 0.15
lb SO2/MMBtu; install SCR or approved alternative technology by May 1,
2007 to control NOx emissions and operate the control technology
year-round to limit NOx emissions to 0.1 lb NOx/MMBtu; and install a
baghouse or approved alternative technology by May 1, 2007 to control PM
emissions and limit PM emissions to 0.015 lb PM/MMBtu.  The settlement
also requires coal with a monthly average sulfur content no greater than
2% at units operating an FGD.

For Mercer Unit #1: install Dry FGD or approved alternative technology
by Dec. 31, 2010 to control SO2 emissions and operate the control
technology at all times the unit operates to limit SO2 emissions to 0.15
lb SO2/MMBtu and install SCR or approved alternative technology by 2005
to control NOx emissions and operate the control technology ozone season
only in 2005 and year-round by May 1, 2006 to limit NOx emissions to
0.13 lb NOx/MMBtu.  The settlement also requires coal with a monthly
average sulfur content no greater than 2% at units operating an FGD.

For Mercer Unit #2: install Dry FGD or approved alternative technology
by Dec. 31, 2012 to control SO2 emissions and operate the control
technology at all times the unit operates to limit SO2 emissions to 0.15
lb SO2/MMBtu and install SCR or approved alternative technology by 2004
to control NOx emissions and operate the control technology ozone season
only in 2004 and year-round by May 1, 2006 to limit NOx emissions to
0.13 lb NOx/MMBtu.  The settlement also requires coal with a monthly
average sulfur content no greater than 2% at units operating an FGD.

New York EGU Regulations: New York adopted the following regulations
governing EGU emissions:

Part 237, which limits NOx emissions from all fossil fuel-fired EGUs
greater than 25 MW to a non-ozone season cap of 39,908 tons in 2007 and
annual SO2 emissions from all fossil fuel-fired EGUs greater than 25 MW
to an annual cap of 197,046 tons SO2/year starting in 2007 and an annual
cap of 131,364 tons SO2/year starting in 2008.

North Carolina Clean Smokestacks Act: Under the act, enacted in 2002,
coal-fired power plants (EGUs) in North Carolina must achieve a 77
percent cut in NOx emissions by 2009 and a 73 percent cut in SO2
emissions by 2013.  This legislation establishes annual caps on both SO2
and NOx emissions for the two primary utility companies in North
Carolina, Duke Energy and Progress Energy.  These reductions must be
made in North Carolina, and allowances are not saleable.

Consent Agreements in the VISTAS region:  The impacts of the following
consent agreements in the VISTAS states were reflected in the emissions
inventory used for those states:

Santee Cooper: A 2004 consent agreement calls for Santee Cooper in South
Carolina to install and commence operation of continuous emission
control equipment for PM/SO2/NOx emissions; comply with system-wide
annual PM/SO2/NOx emissions limits; agree not to buy, sell or trade
SO2/NOx allowances allocated to Santee Cooper System as a result of said
agreement; and to comply with emission unit limits of said agreement.

TECO: Under a settlement agreement, by 2008, Tampa Electric in the state
of Florida will install permanent emissions control equipment to meet
stringent pollution limits; implement a series of interim
pollution-reduction measures to reduce emissions while the permanent
controls are designed and installed; and retire pollution emission
allowances that Tampa Electric or others could use, or sell to others,
to emit additional NOx, SO2 and PM.

VEPCO: Virginia Electric and Power Co. agreed to spend $1.2 billion
between by 2013 to eliminate 237,000 tons of SO2 and NOx 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 NOx emission rates by 61 percent at its Crist 7
generating plant by 2007 with major reductions beginning in early 2005.
The Crist plant is a significant source of nitrogen oxide emissions in
the Pensacola Florida area.

Non-EGU Point Source Controls Expected by 2018

Control factors were applied to the 2018 MANE-VU inventory to represent
the following national, regional, and state control measures:

NOx SIP Call Phase I (NOx Budget Trading Program)

NOx SIP Call Phase II

NOx RACT in 1-hour Ozone SIPs

NOx OTC 2001 Model Rule for ICI Boilers

2-, 4-, 7-, and 10-year MACT Standards

Combustion Turbine and RICE MACT

Industrial Boiler/Process Heater MACT

EPA’s Refinery Enforcement Initiative

In addition, states provided specific control measure information about
specific sources or regulatory programs in their state.  MANE-VU used
the state-specific data to the extent it was available.

For other regions, MANE-VU used inventories developed by the RPOs for
those regions, including VISTAS Base G2, MRPO’s Base K, and CenRAP’s
emissions inventory.  (Emissions for CenRAP states in the MANE-VU
modeling domain were taken from the VISTAS Base G2 inventory.)  Non-EGU
source controls incorporated into the modeling include the following
consent agreements reflected in the VISTAS inventory:

Dupont: A 2007 agreement calls for E. I. Dupont Nemours & Company’s
James River plant to install dual absorption pollution control equipment
by September 1, 2009, resulting in emission reductions of approximately
1,000 tons SO2 annually. The James River plant is a non-EGU located in
the state of Virginia.

Stone Container: A 2004 agreement calls for the West Point Paper Mill in
Virginia owned by Smurfit/Stone Container to control with a wet scrubber
the SO2 emissions of the #8 Power Boiler.  This control device should
result in reductions of over 3,500 tons of SO2 in 2018.

Area Source Controls Expected by 2018

For area sources within MANE-VU, Massachusetts relied on MANE-VU’s
Version 3.0 Emissions Inventory for 2002.  In general, the 2018
inventory for area sources was developed by MANE-VU applying growth and
control factors to the 2002 Version 3.0 inventory.  Area source control
factors were developed for the following national and regional control
measures:

OTC VOC Model Rules (Consumer products, architectural and industrial
maintenance coatings, portable fuel containers, mobile equipment repair
and refinishing, and solvent cleaning)

Federal On-board Vapor Recovery

New Jersey Post-2002 Area Source Controls

Residential Woodstove NSPS

The following additional control measures were included in the 2018
analysis to reduce VOC emissions for the following area source
categories for some states (as identified below):

NOx measures (natural gas, No. 2 fuel oil, No. 4 and 6 fuel oil, and
coal; only in CT, NJ, and NY);

VOC measures: adhesives and sealants (all MANE-VU states except VT);

emulsified and cutback asphalt paving (all MANE-VU states except DE, ME,
and VT);

consumer products (all MANE-VU states except VT); and

portable fuel containers (all MANE-VU states except VT).

As noted above, the inventory information used for other regions was
obtained from those regions’ RPOs.

Onroad Mobile Source Controls Expected by 2018

For the onroad mobile source emission inventory, Massachusetts relied on
MANE-VU’s Version 3.0 emissions inventory that included the following
emission control measures in MANE-VU states:

Heavy Duty Diesel (2007) Engine Standard:  EPA set a PM emissions
standard for new heavy-duty engines of 0.01 grams per
brake-horsepower-hour (g/bhp-hr), to take full effect for diesel engines
in the 2007 model year.  This rule also includes standards for NOx and
non-methane hydrocarbons (NMHC) of 0.20 g/bhp-hr and 0.14 g/bhp-hr,
respectively.  These NOx 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-control technology to be effective on
these trucks and buses.  EPA will require a 97 percent reduction in the
sulfur content of highway diesel fuel from its current level of 500
parts per million (low-sulfur diesel, or LSD) to 15 parts per million
(ultra-low sulfur diesel, or ULSD).

Tier 2 Motor Vehicle Standards:  Tier 2 is a fleet averaging program,
modeled after the California LEV II standards.  Manufacturers can
produce vehicles with emissions ranging from relatively dirty to zero,
but the mix of vehicles a manufacturer sells each year must have average
NOx emissions below a specified value.  Tier 2 standards became
effective in the 2005 model year and are included in the assumptions
used for calculating mobile source emissions inventories used for 2018.

Large Spark Ignition and Recreational Vehicle Rule:  EPA has adopted new
standards for

emissions of NOx, hydrocarbons (HC), and carbon monoxide (CO) from
several groups of previously unregulated nonroad engines.  Included in
these are large industrial spark-ignition engines and recreational
vehicles.  Nonroad spark-ignition engines are those powered by gasoline,
liquid propane, or compressed natural gas rated over 19 kilowatts (kW)
(25 horsepower).  These engines are used in commercial and industrial
applications, including forklifts, electric generators, airport baggage
transport vehicles, and a variety of farm and construction applications.
 Nonroad recreational vehicles include snowmobiles, off-highway
motorcycles, and all terrain vehicles.  These rules were initially
effective in 2004 and were assumed to be fully phased-in by 2012.

Nonroad Sources Controls Expected by 2018

Massachusetts used Version 3.0 of the MANE-VU 2002 Emissions Inventory.
Since the NONROAD Model used to develop the nonroad source emissions did
not include aircraft, commercial marine, and locomotives, MANE-VU’s
contractor, MACTEC, developed the inventory for these categories.
Nonroad mobile source emissions for the 2018 emission inventory were
calculated with EPA’s NONROAD2005 emissions model as incorporated in
the NMIM2005 (National Mobile Inventory Model) database.  The NONROAD
model accounts for the emissions benefits associated with Federal
non-road equipment emissions control measures such as the following:

 “Control of Air Pollution; Determination of Significance for Nonroad
Sources and Emissions Standards for New Nonroad Compression Ignition
Engines At or Above 37 Kilowatts,” 59 FR 31306, June 17, 1994.

“Control of Emissions of Air Pollution From Nonroad Diesel Engines,”
63 FR 56967, October 23, 1998.

“Control of Emissions From Nonroad Large Spark-Ignition Engines and
Recreational Engines (Marine and Land-Based); Final Rule,” 67 FR
68241, November 8, 2002.

“Control of Emissions of Air Pollution From Nonroad Diesel Engines and
Fuel; Final Rule,” April, 2004. This rule sets standards that will
reduce emissions by more than 90 percent from nonroad diesel equipment
and reduce sulfur levels by 99 percent from current levels in nonroad
diesel fuel starting in 2007.  This step will apply to most nonroad
diesel fuel in 2010 and to fuel used in locomotives and marine vessels
in 2012.

As noted above, the inventory information used for other regions was
obtained from those regions’ RPOs.

Additional Controls Analyzed as Part of Ozone SIPs

Additional control measures were considered by several states as part of
ozone planning.  These control measures were included in the inventory
used for regional haze modeling analysis.  The states may or may not
have committed to adopting these measures in the ozone SIP.  For
specific states, the measures included in this analysis reduce emissions
for the following pollutants and non-EGU point source categories due to
strategies developed for purposes of reducing ozone in the Ozone
Transport Region (OTR):

NOx measures:

Asphalt production plants in CT, DC, NJ, and NY

Cement kilns in ME, MD, NY, PA

Glass and fiberglass furnaces in MD, MA, NJ, NY, PA

VOC measure: adhesives and sealants application (all MANE-VU states
except NJ and VT)

These measures were included in the “Beyond on the Way” inventory
for the states identified.

The following additional control measures were included in the 2018
analysis to reduce VOC emissions for the following area source
categories for some states (as identified below):

NOx measures (natural gas, No. 2 fuel oil, No. 4 and 6 fuel oil, and
coal) (Only CT, NJ, and NY)

VOC measures: adhesives and sealants (except VT)

emulsified and cutback asphalt paving (except ME and VT)

consumer products (except VT)

portable fuel containers (except VT)

Additional Reasonable Strategies

In developing reasonable progress goals as required by 40 CFR
51.308(d)(1), Massachusetts and the MANE-VU states identified specific
emission control measures - beyond those which individual states or RPOs
have already made commitments to implement - that would be reasonable to
undertake as part of a concerted strategy to mitigate regional haze.
The proposed additional control measures were incorporated into the
regional strategy adopted by MANE-VU on June 20, 2007, to meet the
reasonable progress goals established by the Class I states.  The basic
elements of this strategy are described in the MANE-VU “Ask” (see
below).  States targeted for coordinated actions toward achieving these
goals include all of the MANE-VU states plus Georgia, Illinois, Indiana,
Kentucky, Michigan, North Carolina, Ohio, South Carolina, Tennessee,
Virginia and West Virginia.

In addition to proposed emission controls in the U.S., the MANE-VU Class
I states determined that it was reasonable to include anticipated
emission reductions in Canada in the modeling used to set reasonable
progress goals.  This determination was based on evaluations conducted
before and during the consultation process.  Specifically, the modeling
accounts for six coal-burning EGUs in Canada having a combined output of
6,500 MW that are scheduled to be shut down and replaced by nine natural
gas turbine units with selective catalytic reduction (SCR) by 2018.

Rationale for Determining Reasonable Controls

40 CFR 51.308(d)(1)(i)(A) requires that, in establishing reasonable
progress goals for each Class I area, the State must consider the costs
of compliance, the time necessary for compliance, the energy and non-air
quality environmental impacts of compliance, and the remaining useful
life of any potentially affected sources.  The SIP must include a
demonstration showing how these factors were taken into consideration in