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Massachusetts Regional Haze

State Implementation Plan

August 9, 2012
Page ii
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Executive Summary

The federal Clean Air Act, in sections 169A and 169B, contains requirements for the protection of 

visibility in 156 national parks, forests and wilderness areas that have been federally designated as Class 

I areas and include some of our nation’s most treasured public lands. Unfortunately, enjoyment of the 

scenic vistas in these pristine areas is significantly impaired by regional haze. In the eastern U.S., the 

average visual range has decreased from 106 miles (under natural conditions) to 24 - 44 miles today. 

In 1999, the U.S. Environmental Protection Agency (EPA) issued regulations known as the Regional Haze Rule, 

which requires states to develop State Implementation Plans to reduce haze-causing pollution to improve 

visibility in Class I areas. The overall goal of the regional haze program is to restore natural visibility conditions 

at Class I areas by 2064. 

Regional haze is caused by fine particle pollution that impairs visibility over a large region by scattering 

or absorbing light. Fine particle pollution also adversely impacts human health, especially for children, 

the elderly, and people with heart or respiratory conditions. The Massachusetts Department of 

Environmental Protection (MassDEP) has prepared this State Implementation Plan (SIP) to address 

Massachusetts sources that contribute to regional haze.

Class I Areas

Although Massachusetts has no Class I areas, emissions from Massachusetts sources contribute to 

visibility degradation in Class I areas in several other states. These include Lye Brook Wilderness Area 

(Vermont), Great Gulf Wilderness Area (New Hampshire), Presidential Range-Dry River Wilderness 

Area (New Hampshire), Acadia National Park (Maine), Moosehorn Wildlife Refuge (Maine), and 

Roosevelt Campobello International Park (Maine/Canada).

In the first round of SIPs, states with Class I areas must set reasonable progress goals for 2018 for 

improving visibility in their Class I areas. States affecting Class I areas (including Massachusetts) must 

submit SIPs with long-term strategies for meeting the 2018 reasonable progress goals. SIPs also must 

include control measures for certain existing sources placed into operation between 1962 and 1977 

(known as Best Available Retrofit Technology or BART). States must update their SIPs in 2018 and 

every 10 years thereafter and must evaluate progress every 5 years. 

Regional Planning Efforts
Page iv

EPA established five regional planning organizations across the nation to coordinate regional haze 

efforts. Massachusetts is a member of one of these regional organizations, the Mid-Atlantic Northeast 

Visibility Union (MANE-VU), comprised of Mid-Atlantic and Northeast states, tribes, and federal 

agencies. Massachusetts developed this SIP by participating in a regional planning process coordinated 

by MANE-VU. Together, the MANE-VU members established baseline and natural visibility

conditions, determined the primary contributors to regional haze, identified reasonable progress goals 

and long-term strategies, and facilitated a consultation process with states, other regional planning 

organizations, and federal land managers. 

As a MANE-VU member state, Massachusetts adopted the “Statement of MANE-VU Concerning a 

Request for a Course of Action by States Within MANE-VU Toward Assuring Reasonable Progress” at 

the MANE-VU Board meeting on June 7, 2007. This Statement outlines a strategy for reducing regional 

haze at MANE-VU Class I areas for the first ten-year planning period and forms the basis for the actions 

Massachusetts has included in this SIP. 

Elements of Massachusetts’ SIP for Regional Haze 

In accordance with 40 CFR 51.308(b), Massachusetts submits this SIP to meet the requirements of 

EPA’s Regional Haze Rule. This SIP addresses the core requirements of 40 CFR 51.308(d). These actions 

include: 

Best Available Retrofit Technology - EPA’s Regional Haze Rule requires the control of emissions from 

certain stationary sources placed into operation between 1962 and 1977 through the implementation of 

Best Available Retrofit Technology (BART) or an alternative to BART that achieves greater emission 

reductions. Massachusetts identified 5 electric generating unit (EGU) facilities, 1 municipal waste 

combustor, and 1 industrial boiler as BART-eligible facilities whose 2002 emissions (the baseline year 

for this SIP) contributed significantly to visibility impairment. For the EGUs, Massachusetts has 

adopted an Alternative to BART program that achieves greater emissions reductions than source-bysource BART. For the municipal waste combustor, Massachusetts has made a source-specific BART 

determination. For the industrial boiler, no BART determination is needed since the facility has 

accepted an emissions cap that makes it no longer BART-eligible. 

Targeted EGU strategy - MANE-VU identified 167 EGU stacks at power plants whose sulfur dioxide 

(SO2) emissions significantly impaired visibility at one or more MANE-VU Class I areas, including 

stacks at 5 Massachusetts power plants. Massachusetts agreed to reduce SO2 emissions from these 

specific power plants stacks by 90 percent from 2002 levels by 2018, or to pursue equivalent, alternative 

measures. Each of these EGUs already has reduced SO2 emissions due to Massachusetts air quality 

regulations. Based on MassDEP’s existing regulations, and additional reductions that will result from 

MassDEP’s Alternative to BART, EPA’s Mercury and Air Toxics Standard, and EGU closures, 

MassDEP estimates that SO2 emissions in 2018 will be up to 87% lower than 2002 emissions.
Page v

Sulfur in Fuel Oil - MANE-VU determined that states could cost-effectively achieve significant 

reductions in SO2 emissions by requiring lower sulfur content fuel oils, including #2 distillate oil (home 

heating oil) and #4 and #6 residual oils (used in power plants and industrial and commercial boilers). 

Refineries already have made significant capital investments to produce low and ultra-low sulfur diesel, 

which is the same product as #2 distillate oil, and lower sulfur residual oils also are readily available. 

To implement the regional MANE-VU low sulfur fuel oil strategy, MassDEP has adopted regulations 

that lower allowable sulfur content in fuel oils, ultimately achieving 15 parts per million sulfur for #2 oil 

and 0.5 percent sulfur by weight for #4 and #6 residual oils by 2018. 

The regulatory and technical basis for this proposed SIP is found in Sections 1 – 7. The prescriptive elements of 

this proposed SIP – BART, reasonable progress goals, and long-term strategy – are found in Sections 8 – 10. 
Page vi

Table of Contents

Executive Summary..................................................................................................................................iii

Table of Contents.....................................................................................................................................vi

List of Figures...........................................................................................................................................xi

List of Tables........................................................................................................................................... xiv

List of Appendices.................................................................................................................................. xvi

Acronyms and Abbreviations................................................................................................................. xix

1. BACKGROUND AND OVERVIEW OF THE FEDERAL REGIONAL HAZE REGULATION.....................................1

1.2. The Basics of Haze ............................................................................................................................1

1.3. Regulatory Framework.....................................................................................................................2

History of Federal Regional Haze Rule .............................................................................................4

State Implementation Plan...............................................................................................................6

2. REGIONAL PLANNING AND STATE/TRIBE AND FEDERAL LAND MANAGER COORDINATION......................7

2.2. Regional Planning .............................................................................................................................7

2.3. Mid-Atlantic/Northeast Visibility Union (MANE-VU).......................................................................8

2.4. Class I Areas Within MANE-VU.........................................................................................................9

2.5. Area of Influence for MANE-VU Class I Areas ............................................................................... 10

2.6. Massachusetts Impact on MANE-VU Class I Areas........................................................................ 11

2.7. Regional Haze Planning after the Remand of CAIR....................................................................... 12

2.8. Regional Consultation and the “Ask” ............................................................................................ 13

2.9. Meeting the “Ask” – MANE-VU States.......................................................................................... 17

2.10. Meeting the “Ask” – Massachusetts............................................................................................. 18

2.11. Meeting the “Ask” – States Outside of MANE-VU ........................................................................ 18

2.12. Technical Ramifications of Differing Approaches.......................................................................... 19
Page vii

2.13. Federal Land Manager Coordination............................................................................................. 19

3. ASSESSMENT OF BASELINE AND NATURAL CONDITIONS ......................................................................22

3.2. Calculation Methodology .............................................................................................................. 22

3.3. MANE-VU Baseline and Natural Visibility...................................................................................... 24

4. MONITORING STRATEGY.....................................................................................................................26

4.2. IMPROVE Program Objectives....................................................................................................... 26

4.3. Monitoring Information for Massachusetts.................................................................................. 26

4.4. Monitoring Information for MANE-VU Class I Areas Impacted by Emissions from Massachusetts

....................................................................................................................................................... 27

Acadia National Park, Maine ......................................................................................................... 27

Great Gulf Wilderness Area, New Hampshire............................................................................... 29

Presidential Range - Dry River Wilderness, New Hampshire .......................................................... 30

Lye Brook Wilderness, Vermont.................................................................................................... 31

Moosehorn Wilderness Area, Maine ............................................................................................ 34

Roosevelt/Campobello International Park, New Brunswick, Canada ........................................... 35

5. MODELING .........................................................................................................................................38

5.2. Meteorology.................................................................................................................................. 39

5.3. Emissions Data Preparations......................................................................................................... 40

5.4. Model Platforms............................................................................................................................ 42

CMAQ ............................................................................................................................................ 42

REMSAD......................................................................................................................................... 42

CALGRID......................................................................................................................................... 43

CALPUFF ........................................................................................................................................ 43

6. EMISSIONS INVENTORY.......................................................................................................................44

6.2. Baseline and Future Year Emission Inventories for Modeling ...................................................... 44

MANE-VU Regional Baseline Inventory......................................................................................... 45
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Massachusetts Baseline Inventory................................................................................................ 45

Future Year Emission Control Inventories..................................................................................... 47

6.3. Emission Processor Selection and Configuration.......................................................................... 48

6.4. Inventories for Specific Source Types ........................................................................................... 48

Stationary Point Sources............................................................................................................... 49

6.5. Electric Generating Units............................................................................................................... 49

6.6. Non-EGU Point Sources................................................................................................................. 50

Stationary Area Sources................................................................................................................ 50

Non-Road Mobile Sources............................................................................................................. 51

On-Road Mobile Sources............................................................................................................... 51

Biogenic Emission Sources ............................................................................................................ 52

6.7. Summary of MANE-VU 2002 and 2018 Emissions Inventory........................................................ 52

6.8. Summary of Massachusetts 2002 Base and 2018 Projected Emissions and Reductions.............. 54

7. UNDERSTANDING THE SOURCES OF VISIBILITY-IMPAIRING POLLUTANTS..............................................58

7.2. Visibility-Impairing Pollutants ....................................................................................................... 58

Contributing States and Regions................................................................................................... 59

7.3. Emissions Sources and Characteristics.......................................................................................... 69

Sulfur Dioxide (SO2) ....................................................................................................................... 70

Volatile Organic Compounds (VOCs)............................................................................................. 72

Oxides of Nitrogen (NOX)............................................................................................................... 75

Primary Particle Matter (PM10 and PM2.5)..................................................................................... 78

Ammonia Emissions (NH3)............................................................................................................. 87

8. BEST AVAILABLE RETROFIT TECHNOLOGY ............................................................................................91

8.2. BART Overview.............................................................................................................................. 91

8.3. BART-Eligible Sources in Massachusetts....................................................................................... 92
Page ix

8.4. Determination of which BART-eligible sources are subject to BART ............................................ 94

8.5. Pollutants Covered by BART.......................................................................................................... 95

8.6. Modeling of BART Visibility Impacts.............................................................................................. 95

8.7. Visibility Impacts of Massachusetts BART-Eligible Sources........................................................... 96

8.8. Overview of Massachusetts BART-Eligible Sources....................................................................... 98

“Cap Out” Source .......................................................................................................................... 98

Sources that Contribute to Visibility Impairment ....................................................................... 100

8.9. BART Determination for Wheelabrator - Saugus........................................................................ 102

8.10. Alternative to BART for EGUs...................................................................................................... 105

8.11. BART for PM10 Emissions ............................................................................................................. 115

8.12. Reasonably Attributable Visibility Impairment........................................................................... 116

9. REASONABLE PROGRESS GOALS ........................................................................................................117

10. LONG-TERM STRATEGY .....................................................................................................................121

10.2. Overview of the Long-Term Strategy Development Process...................................................... 121

10.3. Technical Basis for Strategy Development.................................................................................. 123

10.4. 2018 Emission Reductions Due to Ongoing Air Pollution Controls............................................. 125

EGU Emissions Controls Expected by 2018 ................................................................................. 125

Non-EGU Point Source Controls Expected by 2018 .................................................................... 130

Area Source Controls Expected by 2018 ..................................................................................... 131

Onroad Mobile Source Controls Expected by 2018 .................................................................... 132

Nonroad Sources Controls Expected by 2018............................................................................. 133

Additional Controls Analyzed as Part of Ozone SIPs................................................................... 133

10.5. Additional Reasonable Strategies................................................................................................ 134

Rationale for Determining Reasonable Controls......................................................................... 135

MANE-VU Statement of June 20, 2007 ....................................................................................... 138
Page x

Best Available Retrofit Technology ............................................................................................. 139

Low-Sulfur Fuel Oil Strategy ........................................................................................................ 140

Targeted EGU Strategy ................................................................................................................ 143

10.6. Source Retirement and Replacement Schedules........................................................................ 151

10.7. Measures to Mitigate the Impacts of Construction Activities .................................................... 151

10.8. Agricultural and Forestry Smoke Management .......................................................................... 152

Regulation of Outdoor Hydronic Heaters.................................................................................... 152

10.9. Estimated Impacts of Long-Term Strategy on Visibility .............................................................. 153

Additional Measures Included in Best and Final Modeling......................................................... 153

Visibility Impacts of Additional Reasonable Controls from Best and Final Modeling ................. 154

10.10. Massachusetts’ Share of Emissions Reduction ........................................................................... 158

10.11. Emission Limitations and Compliance Schedules........................................................................ 159

10.12. Enforceability of Emission Limitations and Control Measures.................................................... 159

10.13. Prevention of Significant Deterioration ...................................................................................... 159
Page xi

List of Figures

Figure 1: Locations of Federally Protected Mandatory Class I Areas.........................................................................4

Figure 2: US EPA Designated Regional Planning Organizations .................................................................................7

Figure 3: Class I Areas within MANE-VU.....................................................................................................................9

Figure 4: Map of CAIR States................................................................................................................................... 12

Figure 5: MANE-VU Principles for Regional Haze Planning ..................................................................................... 13

Figure 7: Acadia National Park on Clear and Hazy Days.......................................................................................... 29

Figure 6: Map of Acadia National Park Showing ..................................................................................................... 28

Figure 8: Map of Great Gulf and Presidential Range - Dry River Wilderness Areas Showing IMPROVE Monitor 

Location ................................................................................................................................................................... 29

Figure 9: Great Gulf Wilderness Area on Clear and Hazy Days............................................................................... 30

Figure 10: Location of Lye Brook Wilderness Monitor............................................................................................ 32

Figure 11: Lye Brook Wilderness Area on Clear and Hazy Days.............................................................................. 32

Figure 12: Map of the Baring and Edmunds Divisions of the Moosehorn National Wildlife Refuge Showing the 

IMPROVE Monitor Location..................................................................................................................................... 34

Figure 13: Moosehorn Wilderness Area on a Clear and a Hazy Day ....................................................................... 35

Figure 14: Map of Roosevelt/Campobello International Park ................................................................................ 35

Figure 15: Roosevelt/Campobello International Park on Clear and Hazy Days ...................................................... 37

Figure 16: Modeling domains used in MANE-VU air quality modeling studies with CMAQ................................... 40

Figure 17: Examples of processed model-ready emissions: a) SO2 from Point, b) NO2 from Area, c) NO2 from Onroad, d) NO2 from Non-road, e) ISOP from Biogenic, f) SO2 from all source categories........................................ 41

Figure 18: Contributions to PM2.5 Extinction at Seven Class I Sites......................................................................... 58

Figure 19: Ranked state percent sulfate contributions to Northeast Class I receptors based on emissions divided 

by distance (Q/d) results......................................................................................................................................... 60
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Figure 20: Ranked state percent sulfate contributions to Mid-Atlantic Class I receptors based on emissions 

divided by distance (Q/d) results ............................................................................................................................ 62

Figure 21: Modeled 2002 Contributions to Sulfate by State at Brigantine............................................................. 65

Figure 22: Modeled 2002 Contributions to Sulfate by State at Lye Brook.............................................................. 66

Figure 23: Modeled 2002 Contributions to Sulfate by State at Great Gulf and Presidential Range/Dry River 

Wilderness............................................................................................................................................................... 66

Figure 24: Modeled 2002 Contributions to Sulfate by State at Acadia................................................................... 67

Figure 25: Modeled 2002 Contributions to Sulfate by State at Moosehorn and Roosevelt Campobello 

International Park.................................................................................................................................................... 67

Figure 26: Modeled 2002 Contributions to Sulfate by State at Shenandoah ......................................................... 68

Figure 27: Modeled 2002 Contributions to Sulfate by State at Dolly Sods............................................................. 68

Figure 28: Trends in Annual Sulfur Dioxide Emissions by State .............................................................................. 70

Figure 29: 2002 Sulfur Dioxide Emissions (SO2) by State ........................................................................................ 72

Figure 30: 2002 Volatile Organic Carbon (VOC) Emissions by State ....................................................................... 75

Figure 31: Trends in Annual Nitrogen Oxide (NOx) Emissions by State................................................................... 76

Figure 32: 2002 Nitrogen Oxide (NOx) Emissions by State...................................................................................... 78

Figure 33: Trends in Primary Coarse Particle (PM10) Emissions by State ................................................................ 79

Figure 34: Trends in Primary Fine Particle (PM2.5) Emissions by State.................................................................... 79

Figure 35: Wood Smoke Source Regional Aggregations ......................................................................................... 83

Figure 36: 2002 Primary PM10 Emissions by State................................................................................................... 86

Figure 37: 2002 Primary PM2.5 Emissions by State.................................................................................................. 87

Figure 38: Trends in Ammonia Emissions by State.................................................................................................. 89

Figure 39: 2002 NH3 Emissions by State.................................................................................................................. 89

Figure 40: Average Change in 24-hr PM2.5 Due to Low Sulfur Fuel Strategies Relative to OTB/OTW (g/m3)..... 143

Figure 41: 167 Targeted EGU Stacks Affecting MANE-VU Class I Areas................................................................ 144
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Figure 42: Average Change in 24-hr PM2.5 due to 90 Percent Reduction in SO2 Emissions from 167 EGU Stacks 

Affecting MANE-VU............................................................................................................................................... 145

Figure 43: Projected Visibility Improvement at Acadia National Park Based on 2018 Visibility Projections........ 155

Figure 44: Projected Visibility Improvement at Great Gulf Wilderness Area Based on 2018 Visibility Modeling 156

Figure 45: Projected Visibility Improvement at Lye Brook Wilderness Area Based on 2018 Visibility Modeling. 156

Figure 46: Projected Visibility Improvement at Moosehorn Wilderness Area Based on 2018 Visibility Modeling 

............................................................................................................................................................................... 158
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List of Tables

Table 1: MANE-VU Members .....................................................................................................................................8

Table 2: States that Contribute to Visibility Impairment at One or More of the MANE-VU Class I Areas of Acadia, 

Moosehorn, Roosevelt-Campobello, Great Gulf, Presidential Range-Dry River, Lye Brook, and Brigantine.......... 10

Table 3: Class I Federal Areas Affected by Emissions from Massachusetts............................................................ 11

Table 4: IMPROVE Monitors for MANE-VU Class I Areas........................................................................................ 22

Table 5: Summary of Baseline Visibility and Natural Visibility Conditions for the 20 Percent Best and 20 Percent 

Worst Visibility Days at MANE-VU Class I Areas...................................................................................................... 24

Table 6: MANE-VU 2002 Emissions Inventory Summary (tons).............................................................................. 52

Table 7: MANE-VU 2018 Emissions Inventory Summary (in tons).......................................................................... 54

Table 8: Massachusetts 2002 Base Year and 2018 Projected Emissions and Reductions (in tons) ........................ 54

Table 9: Percent of Annual Average Modeled Sulfate Due to Emissions from Listed States.................................. 59

Table 10: BART-Eligible Facilities in Massachusetts................................................................................................ 94

Table 11: CALPUFF Visibility Modeling Results using MM5 Platform ..................................................................... 97

Table 12: CALPUFF Visibility Modeling Results using NWS Platform ...................................................................... 97

Table 13: Massachusetts Sources with De Minimis Visibility Impact.................................................................... 100

Table 14: Overview of BART-Eligible EGUs & MWCs............................................................................................. 102

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

............................................................................................................................................................................... 107

Table 16: BART Benchmark for SO2 ....................................................................................................................... 109

Table 17: Alternative to BART for SO2 ............................................................................................................... 110

Table 18: BART Benchmark for NOx....................................................................................................................... 113

Table 19: Alternative to BART for NOx.................................................................................................................. 114

Table 20: Massachusetts PM10 BART Sources, Emissions and Controls................................................................ 115

Table 21: Uniform Rate of Progress Calculation (all values in deciviews)............................................................. 118
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Table 22: Reasonable Progress Goals - 20% Worst Days (all values in deciviews)................................................ 119

Table 23: Reasonable Progress Goals - 20% Best Days (all values in deciviews) .................................................. 119

Table 24: Summary of Results from the Four-Factor Analysis.............................................................................. 137

Table 25: Massachusetts Targeted EGUs.............................................................................................................. 148
Page xvi

List of Appendices

A. Contributions to Regional Haze in the Northeast and Mid-Atlantic United States: MidAtlantic/Northeast Visibility Union (MANE-VU) Contribution Assessment. NESCAUM, August 2006.

B. Final Interim Principles for Regional Planning. MANE-VU, June 2006.

C. Statement(s) of the Mid-Atlantic/Northeast Visibility Union (MANE-VU) Concerning a Request for a 

Course of Action by States/EPA Within/Outside MANE-VU Toward Assuring Reasonable Progress. 

MANE-VU, June 7, 2006.

D. Federal Land Manager and EPA Comments and State Responses on Pre-Public Hearing Draft 

Massachusetts Regional Haze SIP (Appendices D-1 – D5), Public Comments and State Responses on 

Public Hearing Draft SIP (Appendices D6 – D15), and Public Comments and State Responses on Public 

Hearing Draft SIP Revision (Appendices D16 – D31).

E. 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. 

NESCAUM, December 2006.

F. MANE-VU Modeling for Reasonable Progress Goals: Model Performance Evaluation, Pollution 

Apportionment, and Control Measure Benefits. NESCAUM, February 2008.

G. 2018 Visibility Projections. NESCAUM, March 2008.

H. Meteorological Modeling Using Penn State/NCAR 5th Generation Mesoscale Model (MM5). NYSDEC 

TSD-1a, February 2006.

I. Emissions Processing for the Revised 2002 OTC Regional and Urban 12 km Base Case Simulations. 

NYSDEC TSD-1c, September 2006.

J. CMAQ Model Performance and Assessment, 8-Hr OTC Ozone Modeling. NYSDEC TSD-1e, February 

2006.

K. Eight Hour Ozone Modeling using the SMOKE/CMAQ system. NYSDEC TSD-1d, February 2006.

L. Modeling Protocol for the OTC CALGRID Screening-Level Modeling Platform for the Evaluation of 

Ozone. NHDES, May 2007.

M. Technical Support Document for 2002 MANE-VU SIP Modeling Inventories, Version 3. E.H. Pechan & 

Associates for MANE-VU, November 2006.

N. Development of Emissions Projections for 2009, 2012, 2018 for Non-EGU Point, Area, and Nonroad 

Sources in the MANE-VU Region. MACTEC, February 2007.
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O. Development of MANE-VU Mobile Source Projection Inventories for SMOKE/MOBILE6 Application. 

NESCAUM, June 2006.

P. Regional Haze and Visibility in the Northeast and Mid-Atlantic States. NESCAUM, January 2001.

Q. Technical Support Document on Agricultural and Forestry Smoke Management in the MANE-VU 

Region. MANE-VU, September 2006.

R. Five Factor Analysis of BART Eligible Sources: Survey of Options for Conducting BART Determinations. 

NESCAUM, June 2007.

R-1. CalPuff BART Modeling Results (MM5)

R-2. CalPuff BART Modeling Results (NWS)

S. Comparison of CAIR and CAIR Plus Proposal using the Integrated Planning Model®. ICF, May 2007.

T. Assessment of Reasonable Progress for Regional Haze in MANE-VU Class I Areas. MACTEC, July 2007.

T-1. Addendum for Residual Oil. MANE-VU, April 2011.

U. Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, Industrial 

Boilers, Cement Plants and Paper and Pulp Facilities. NESCAUM, March 2005.

V. The Nature of the Fine Particle and Regional Haze Air Quality Problems in the MANE-VU Region: A 

Conceptual Description. NESCAUM, November 2006. 

W. Documentation of 2018 Emissions from Electric Generating Units in the Eastern U.S. for MANE-VU’s 

Regional Haze Modeling. Alpine Geophysics, April 2008.

X. Technical Support Document on Measures to Mitigate the Visibility Impacts of Construction Activities in 

the MANE-VU Region. MANE-VU, October 2006.

Y. Low Sulfur Heating Oil in the Northeast States: An Overview of Benefits, Costs, and Implementation 

Issues. NESCAUM, December 2005.

Z. SNCR Optimization Report, Wheelabrator Saugus Inc., WTE Units 1 & 2, Two 750 TPD MSW 

Combustors. Fuel Tech, January 2010.

AA. Public Health Benefits of Reducing Ground-level Ozone and Fine Particle matter in the Northeast U.S. – A 

Benefits Mapping and Analysis Program (BenMAP) Study. NESCAUM, January 2008.

BB. Approval of General Electric Aviation NOx Reasonably Available Control Technology (RACT) Modified 

Emission Control Plan. MassDEP, March 2011.

CC. 310 CMR 7.26(50) through (54): Outdoor Hydronic Heaters. MassDEP, December 2008.
Page xviii

DD. 310 CMR 7.29, Emissions Standards for Power Plants. MassDEP

EE. Mt. Tom Station - Amended Emission Control Plan Final Approval. MassDEP, May 2009.

FF. Salem Harbor – Amended Emission Control Plan Final Approval. MassDEP, March 2012.

GG. Brayton Point – Amended Emission Control Plan Final Approval. MassDEP, April 2012.

HH. Somerset Power – Letter Revoking Permits. MassDEP, June 2011.

II. 310 CMR 7.05: Fuels All Districts. MassDEP, August 2012.

JJ. Wheelabrator-Saugus – Emission Control Plan Modified Final Approval. MassDEP, March 2012 
Page xix

Acronyms and Abbreviations

ACAD1 Acadia National Park IMPROVE monitor

BART Best Available Retrofit Technology

BEIS-3 Biogenic Emission Inventory System (3 version 0.9)

BOTW Beyond on the Way (controls)

BTU British Thermal Unit

CAA Clean Air Act

CAIR Clean Air Interstate Rule

CALGRIDCalifornia Grid Model

CEED Center for Energy and Economic Development

CENRAP Central Regional Air Planning Association

CERR Consolidated Emission Reporting Rule

CFR Code of Federal Regulations

CMAQ Community Multi-scale Air Quality Modeling System

CO Carbon Monoxide

dv Deciview

EGU Electric Generating Unit

EPA Environmental Protection Agency

FLM Federal Land Manager

GCVTC Grand Canyon Visibility Transport Commission

GRGU1 Great Gulf Wilderness Area IMPROVE monitor; also monitors Presidential Range/Dry River Wilderness 

Area

HAP Hazardous Air Pollutant

ICI Industrial/Commercial/Institutional

IMPROVE Interagency Monitoring of Protected Visual Environments

IPM Integrated Planning Model
Page xx

LADCO Lake Michigan Air Directors Consortium

LYBR1 Lye Brook Wilderness Area IMPROVE monitor

MassDEP Massachusetts Department of Environmental Protection

MANE-VU Mid-Atlantic/Northeast Visibility Union

MARAMA Mid-Atlantic Regional Air Management Association

MM5 Mesoscale Meteorological Model

MMBtu Million British Thermal Units

MOOS1 Moosehorn Wilderness Area IMPROVE monitor; also monitors Roosevelt/Campobello International Park

MOBILE6.2 EPA’s On-Road Mobile Source Emissions Estimation Model

MRPO Midwest Regional Planning Organization

MW Megawatt

MWh Megawatt Hour

MWC Municipal Waste Combustor

N/A Not Applicable

NAAQS National Ambient Air Quality Standards

NCAR National Center for Atmospheric Research

NEI National Emissions Inventory

NET National Emissions Trend

NESCAUM Northeast States for Coordinated Air Use Management

NH3 Ammonia

NOx Oxides of Nitrogen

NONROAD EPA’s Non-Road Emissions Estimation Model 2005 Version

NSPS New Source Performance Standards

NTI National Toxics Inventory

NYSDEC New York State Department of Environmental Conservation

NWS National Weather Service
Page xxi

OC Organic Carbon

OTC Ozone Transport Commission

OTB/W On the Books/On the Way (controls)

PM2.5 Fine Particulate Matter; particles with an aerodynamic diameter less than or equal to a nominal 2.5

micrometers

PM10 Particles with an aerodynamic diameter less than or equal to a nominal 10 micrometers

QA Quality Assurance

RACT Reasonably Available Control Technology

REMSADRegional Modeling System for Aerosols and Deposition

RFP Reasonable Further Progress

RH Regional Haze

RPO Regional Planning Organization

SIP State Implementation Plan

SLAMS/ State & Local Air Monitoring System and

NAMS National Air Monitoring System

SCC Source Category Code

SMOKE Sparse Matrix Operator Kernel Emissions

SMP Smoke Management Plan

SOA Secondary Organic Aerosol

SO2 Sulfur Dioxide

TPY Tons per year

TSC Technical Support Committee (of MANE-VU)

TSD Technical Support Document

USEPA United States Environmental Protection Agency

UMD University of Maryland

VIEWS Visibility Information Exchange Web System

VISTAS Visibility Improvement State and Tribal Association of the Southeast
Page xxii

VOC Volatile Organic Compound

WRAP Western Regional Air Partnership
Page 1

1.BACKGROUND AND OVERVIEW OF THE FEDERAL 

REGIONAL HAZE REGULATION

1.2. The Basics of Haze 

Regional haze is visibility impairment caused by the cumulative emission of air pollutants from numerous 

sources over a wide geographic area. The primary cause of regional haze is the scattering and absorption of 

light by fine particles. Fine particle air pollution also adversely impacts human health, especially the respiratory 

and cardiovascular systems of people at increased risk, including children, the elderly, and people with heart or 

respiratory conditions. 

Regional haze obscures views in pristine areas such as national parks, forests and wilderness areas (156 of which 

have been designated Federal Class I areas). In parks in the eastern U.S., the average visual range has decreased 

from 106 miles (under natural conditions) to 24- 44 miles today. 

Visibility impairment can be quantified using three different, but mathematically related measures: visual range 

(i.e., how far one can see); light extinction per unit distance (e.g., Mm-1)

1

; and deciviews (dv), a useful metric for 

measuring increments of visibility change that are just perceptible to the human eye. Each can be estimated 

from the ambient concentrations of individual particle constituents, taking into account their unique lightscattering (or absorbing) properties, and making appropriate adjustments for relative humidity. Assuming 

natural conditions, visibility in the Northeast and Mid-Atlantic is estimated to be about 106 miles, which 

corresponds to 23 Mm-1or 8 dv. Under current polluted conditions in the region, average visibility ranges from

24 miles in the south to 44 miles in the north; these values correspond to 103 Mm-1to 55 Mm-1or 23 to 17 dv, 

respectively. On the worst 20 percent of days, visibility impairment in Northeast and Mid-Atlantic Class I areas 

ranges from 21.7 to 29 dv (a visual range of about 30 to 14 miles).

The fine particles that commonly cause hazy conditions in the eastern U.S. are primarily composed of sulfate, 

nitrate, organic carbon, elemental carbon (soot), and crustal material (e.g., soil dust, sea salt, etc.). Sulfate, 

nitrate, and organic carbon are secondary pollutants that form in the atmosphere from precursor pollutants, 

primarily sulfur dioxide (SO2), nitrogen oxides (NOx), and volatile organic compounds (VOCs), respectively. 

Sulfate, formed from SO2 emissions, is the dominant contributor to fine particle pollution throughout the 

eastern U.S. and therefore most eastern regional control efforts are directed at reducing SO2 emissions.

 

1

In units of inverse length. An inverse megameter (Mm-1) is equal to one over one thousand kilometers.
Page 2

1.3. Regulatory Framework

In amendments to the Clean Air Act (CAA) in 1977, Congress added Section 169 (42 U.S.C. 7491) setting forth the 

following national visibility goal:

Congress hereby declares as a national goal the prevention of any future, and the remedying of 

any existing, impairment of visibility in mandatory Class I Federal areas which impairment results 

from man-made air pollution.

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

criteria: 

 all national parks greater than 6000 acres,

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

 one international park.

In 1980, Bradwell Bay, Florida, and Rainbow Lake, Wisconsin, were excluded for purposes of visibility protection 

as federal Class I areas. Today, 156 national park and wilderness areas remain as Class I visibility protection 

areas (Figure 1).

Over the following years, modest steps were taken to address the visibility problems in Class I areas. The control 

measures taken mainly addressed “plume blight” from specific pollution sources and did little to address 

regional haze issues in the Eastern United States. 

When the CAA was amended in 1990, Congress added Section 169B (42 U.S.C. 7492), authorizing further 

research and regular assessments of the progress made. In 1993, the National Academy of Sciences concluded 

that “current scientific knowledge is adequate and control technologies are available for taking regulatory action 

to improve and protect visibility.”

In addition to authorizing creation of visibility transport commissions and setting forth their duties, Section 

169B(f) of the CAA mandated creation of the Grand Canyon Visibility Transport Commission (GCVTC) to make 

recommendations to the U.S. Environmental Protection Agency (EPA) for the region affecting the visibility of the 

Grand Canyon National Park. The GCVTC submitted its report to EPA in June 1996, following four years of 
Page 3

research and policy development. This report, as well as the many research reports prepared by the 

Commission, contributed invaluable information to EPA in its development of regulations for visibility 

improvement.
Page 4

Figure 1: Locations of Federally Protected Mandatory Class I Areas

History of Federal Regional Haze Rule

The federal requirements that states must meet to achieve national visibility goals are contained in 

Title 40: Protection of Environment, Part 51 – Requirements for Preparation, Adoption, and Submittal Of 

Implementation Plans, Subpart P – Protection of Visibility (40 CFR 51.300-309). Known more simply as the 

Regional Haze Rule, these regulations were adopted on July 1, 1999, and went into effect on August 30, 1999. 

The rule seeks to address the combined visibility effects of various pollution sources over a large geographic 

region. This wide-reaching pollution net means that many states – even those without Class I Areas – are 

required to participate in haze reduction efforts. The specific requirements for States’ Regional Haze State

Implementation Plans (SIPs) are set forth in 40 CFR 51.308, Regional Haze Program Requirements.
Page 5

In consultation with the states and tribes, EPA designated five Regional Planning Organizations (RPOs) 2to assist 

with the coordination and cooperation needed to address the haze issue. The Mid-Atlantic / Northeast states, 

including the District of Columbia, formed the Mid-Atlantic / Northeast Visibility Union (MANE-VU).3

EPA’s adoption of the Regional Haze Rule was challenged by the American Corn Growers Association. On May 

24, 2002, the U.S. Court of Appeals, D.C. District Court, ruled on the challenge and remanded to EPA the Best 

Available Retrofit Technology (BART) provisions of the rule, but denied industry’s challenge to the haze rule’s 

goals of natural visibility and no degradation requirements. On June 15, 2005, EPA finalized a rule addressing 

the court’s remand. 

On February 18, 2005, the Appeals Court issued another ruling vacating the Regional Haze Rule in part and 

sustaining it in part. For more information see Center for Energy and Economic Development v. EPA, # 03-1222, 

(D.C. Cir. Feb. 18, 2005; “CEED v. EPA”). In this case, the court granted a petition challenging provisions of the 

Regional Haze Rule governing the optional emissions trading program for certain Western States and Tribes (the 

WRAP Annex Rule). 

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

1. Revised the regulatory text in 40 CFR 51.308(e)(2)(i) in response to the CEED court’s remand to remove 

the requirement that the determination of BART “benchmark” be based on cumulative visibility 

analyses, and to clarify the process for making such determinations, including the application of BART 

presumptions for Electric Generating Units (EGUs) as contained in Appendix Y to 40 CFR 51.

2. Added new regulatory text in 40 CFR 51.308(e)(2)(vi) to provide minimum elements for cap and trade 

programs in lieu of BART.

3. Revised regulatory text in 40 CFR 51.309 to reconcile the optional framework for certain Western States 

and Tribes to implement the recommendations of the Grand Canyon Visibility Transport Commission 

with the CEED decision.

 

2

A description of the RPOs is contained in the Regional Planning Section of this SIP.

3

A description of MANE-VU and a full list of its members are described in the Regional Planning Section of this SIP.
Page 6

State Implementation Plan

In accordance with 40 CFR 51.308(b), Massachusetts submits this SIP to meet the requirements of EPA’s 

Regional Haze Rule. This SIP addresses the core requirements of 40 CFR 51.308(d). In addition, this SIP addresses 

requirements pertaining to regional planning and state/tribe and Federal Land Manager (FLM) coordination and 

consultation.

Pursuant to 40 CFR 51.308(d)(4)(v), Massachusetts also commits to making periodic updates to the 

Massachusetts emissions inventory (Section 6). Massachusetts proposes to complete these updates to coincide 

with the progress reports.

40 CFR 51.308(f) requires Massachusetts to submit revisions to its Regional Haze SIP every ten years. The first 

milestone for reasonable progress is 2018. Massachusetts commits to submitting a revision to its Regional Haze 

SIP by July 31, 2018.

40 CFR 51.308(g) requires Massachusetts to submit a report to EPA every 5 years that evaluates progress toward 

the reasonable progress goal for each Class I area located within the state and each mandatory Class I area 

located outside the state that may be affected by emissions from within the state. Massachusetts commits to 

submitting the first progress report in 2013. 

Finally, pursuant to 40 CFR 51.308(h), Massachusetts will submit a determination of adequacy of its Regional 

Haze SIP whenever a progress report is submitted.
Page 7

2.REGIONAL PLANNING AND STATE/TRIBE AND FEDERAL 

LAND MANAGER COORDINATION

2.2. Regional Planning

In 1999, EPA and affected states/tribes agreed to create five Regional Planning Organizations (RPOs) to facilitate 

interstate coordination on Regional Haze SIPs. Figure 2 shows a map of the five RPOs: MANE-VU (MidAtlantic/Northeast Visibility Union), VISTAS (Visibility Improvement State and Tribal Association of the 

Southeast), MRPO (Midwest Regional Planning Organization), CenRAP (Central Regional Air Planning 

Association), and WRAP (Western Regional Air Partnership). As part of regional planning, the RPOs and states 

and tribes within each RPO are required to consult on the development of emission management strategies. 

Figure 2: US EPA Designated Regional Planning Organizations
Page 8

2.3. Mid-Atlantic/Northeast Visibility Union (MANE-VU)

MANE-VU’s work is managed by the Ozone Transport Commission (OTC) and carried out by the OTC, the MidAtlantic Regional Air Management Association (MARAMA), and the Northeast States for Coordinated Air Quality 

Management (NESCAUM). Members of MANE –VU are listed in Table 1. The states and tribes, along with 

federal agencies and professional staff from OTC, MARAMA and NESCAUM, are members of the various 

committees and workgroups established by MANE-VU. Policy decisions are made by the MANE-VU Board of 

Directors, composed of senior staff from each member state, tribe, or agency.

Table 1: MANE-VU Members

Connecticut Pennsylvania 

Delaware Penobscot Nation

District of Columbia Rhode Island 

Maine St. Regis Mohawk Tribe

Maryland Vermont 

Massachusetts U.S. Environmental Protection Agency*

New Hampshire U.S. National Park Service*

New Jersey U.S. Fish and Wildlife Service*

New York U.S. Forest Service*

* Non-voting member 

Since its inception on July 24, 2001, MANE-VU established an active committee structure to address both 

technical and non-technical issues related to regional haze. One of the primary committees is the Technical 

Support Committee (TSC), charged with assessing the nature and magnitude of the regional haze problem within 

MANE-VU, interpreting the results of technical work, and reporting on such work to the MANE-VU Board. It has 

three standing working groups, broken down by topic area: Emissions Inventory, Modeling, and 

Monitoring/Data Analysis Workgroups. The TSC has evolved to function as a valuable sounding board for all the 

technical projects and processes of MANE-VU and has established a process to ensure that important regional 

haze-related projects are completed in a timely fashion and members are kept informed of all MANE-VU tasks 

and duties. 
Page 9

The second primary committee is the Communications Committee, charged with developing approaches to 

inform the public about the regional haze problem in the region and making any recommendations to the 

MANE-VU Board to facilitate that goal. It oversaw the development of MANE-VU’s newsletter and outreach 

tools, both for stakeholders and for the public, regarding regional issues within MANE-VU.

Policy decisions are made by the MANE-VU Board. MANE-VU established a Policy Advisory Group to provide 

advice to decision-makers on policy questions. Federal Land Managers, EPA, states, and tribes are represented 

on the Policy Advisory Group, which met on an as-needed basis.

2.4. Class I Areas Within MANE-VU

MANE-VU contains seven Federal Class I areas in four states (Figure 3). Massachusetts does not contain any 

Class I areas.

Figure 3: Class I Areas within MANE-VU
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2.5. Area of Influence for MANE-VU Class I Areas

40 CFR 51.308(d)(3) of the Regional Haze Rule requires states to determine their respective contribution to 

visibility impairment at Class I areas. Through source apportionment modeling (more fully described in Section 

7), MANE-VU has identified and evaluated the major contributors to regional haze at MANE-VU Class I areas as 

well as Class I areas in nearby RPOs. The complete findings are contained in a report produced by the Northeast 

States for Coordinated Air Quality Management (NESCAUM) entitled, “Contributions to Regional Haze in the 

Northeast and Mid-Atlantic United States,” otherwise known as the Contribution Assessment (Appendix A). 

Based on that work, MANE-VU concluded that it was appropriate to define an area of influence including all of 

the states participating in MANE-VU, plus other states that modeling indicated contributed at least 2 percent of 

the sulfate ion at MANE-VU Class I areas in 2002. MANE-VU identified the states in Table 2 as causing or 

contributing to visibility impairment in one or more of the following Class I areas: Acadia National Park, 

Brigantine Wildlife Refuge, Great Gulf Wilderness Area, Lye Brook Wilderness Area, Moosehorn Wildlife Refuge, 

Presidential Range-Dry River Wilderness Area, and Roosevelt-Campobello International Park.

Table 2: States that Contribute to Visibility Impairment at One or More of the MANE-VU Class I Areas of 

Acadia, Moosehorn, Roosevelt-Campobello, Great Gulf, Presidential Range-Dry River, Lye Brook, and 

Brigantine

State RPO

Connecticut MANE-VU

Delaware MANE-VU

Maine MANE-VU

Maryland MANE-VU

Massachusetts MANE-VU

New Hampshire MANE-VU

New Jersey MANE-VU

New York MANE-VU

Pennsylvania MANE-VU

Rhode Island MANE-VU
Page 11

Vermont MANE-VU

Georgia VISTAS

Kentucky VISTAS

North Carolina VISTAS

South Carolina VISTAS

Tennessee VISTAS

Virginia VISTAS

West Virginia VISTAS

Illinois MRPO

Indiana MRPO

Michigan MRPO

Ohio MRPO

2.6. Massachusetts Impact on MANE-VU Class I Areas

Emission sources within Massachusetts had measurable impacts on visibility at Class I areas within MANE-VU in 

the 2002 baseline year. The magnitude of these impacts is described in detail in Section 7 and MANE-VU’s 

Contribution Assessment (Appendix A). Table 3 lists the Class I areas affected by emissions sources in 

Massachusetts. 

Table 3: Class I Federal Areas Affected by Emissions from Massachusetts

Class I Federal Area State

Acadia National Park Maine

Moosehorn Wildlife Refuge Maine

Roosevelt Campobello International Park Maine/Canada

Great Gulf Wilderness Area New Hampshire

Presidential Range-Dry River Wilderness Area New Hampshire

Lye Brook Wilderness Area Vermont
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2.7. Regional Haze Planning after the Remand of CAIR

On March 10, 2005, EPA issued the Clean Air Interstate Rule (CAIR). This important federal rule was designed to 

achieve major permanent reductions in SO2 and NOx emissions in the eastern United States through a cap-andtrade system using emission allowances. CAIR would permanently cap emissions originating in 28 eastern states 

and the District of Columbia (Figure 4). Although Massachusetts was only designated as a participating CAIR 

state for the ozone season, this program would have greatly affected future air quality in the state.

According to EPA’s CAIR website, SO2 emissions in the affected states would be reduced by more than 70 

percent and NOx emissions by more than 60 percent from 2003 levels upon full implementation of CAIR (see 

http://www.epa.gov/cair/). 

Figure 4: Map of CAIR States

On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit found that CAIR violated basic 

provisions of the Clean Air Act. The court vacated CAIR in its entirety and remanded it to EPA in order to 

promulgate a new rule consistent with the court’s opinion. EPA appealed the decision amid widespread concern 

that, despite its flaws, some form of CAIR was preferable to the sudden regulatory void created by the Court’s 

decision. Upon reconsideration, on December 23, 2008, the Court stayed the vacatur of CAIR but maintained

the remand to EPA to promulgate a new rule consistent with the Court’s July 11, 2008, opinion.

Because CAIR formed the regulatory underpinnings for most of the emission reductions that were to produce 

visibility improvements in mandatory Class I areas, the vacatur of CAIR would have represented a major 
Page 13

difficulty for the individual states in attempting to comply with the Regional Haze Rule. While all eastern states 

have depended in varying degree on CAIR in the preparation of their regional haze SIPs, some Southeast states 

have relied almost entirely on CAIR to demonstrate compliance with the rule. The vacatur of CAIR also called 

into question the validity of MANE-VU’s (and other RPOs’) emission inventories and air quality modeling studies 

already completed for the member states’ Regional Haze SIPs.

The CAIR Phase I requirements remained in place through 2011. On August 8, 2011, EPA published the CrossState Air Pollution Rule (CSAPR) to replace CAIR. CSAPR requires 28 states in the eastern half of the United 

States to significantly improve air quality by reducing SO2 and NOx emissions from power plant emissions that 

cross state lines and contribute to ground-level ozone and fine particle pollution in other states. Massachusetts 

is not included in CSAPR.

Future emission controls under CSAPR are similar to those as CAIR originally would have obtained. Therefore, 

Massachusetts expects that future emissions and air quality levels are likely to be not very different from values 

predicted by MANE-VU’s completed modeling, even though that modeling was based on implementation of 

CAIR as it was before CSAPR. Consequently, the long-term strategy developed for Massachusetts’ SIP represents

a reasonable starting point from which to go forward with measures to improve visibility at MANE-VU’s Class I 

Areas. These measures will be reviewed at the mid-point review in 2013 in consultation with Class I states, who 

may at that time reassess their reasonable progress goals. 

2.8. Regional Consultation and the “Ask”

40 CFR Section 51.308(d)(3)(i) requires Massachusetts to consult with other states/tribes to develop coordinated 

emission management strategies. Massachusetts consulted with other states and tribes through participation in 

the MANE-VU and inter-RPO processes that developed the technical information necessary for the development 

of coordinated strategies. 

On May 10, 2006, MANE-VU adopted the Inter-RPO State/Tribal and FLM Consultation Framework. A full copy 

of MANE-VU’s Final Interim Principles for Regional Planning can be found in Appendix B. That document sets

forth the principles listed in Figure 5. MANE-VU states and tribes applied these principles to the regional haze 

consultation and SIP development processes. Issues addressed included regional haze baseline assessments, 

natural background levels, and development of reasonable progress goals – described at length in later sections 

of this SIP.

Figure 5: MANE-VU Principles for Regional Haze Planning

1) All State, Tribal, RPO, and Federal participants are committed to continuing dialogue and information sharing in order to create 

understanding of the respective concerns and needs of the parties. 
Page 14

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

3) States alone have the authority to undertake specific measures under their SIP. This inter-RPO framework is designed solely to 

facilitate needed communication, coordination, and cooperation among jurisdictions, but does not establish binding obligation on 

the part of participating agencies. 

4) There are two areas which require State-to-State and/or State-to-Tribal consultations (“formal” consultations): (i) development of 

the reasonable progress goal for a Class I area, and (ii) development of long-term strategies. While it is anticipated that the formal 

consultation will cover the technical components that make up each of these policy decision areas, there may be a need for the 

RPOs, in coordination with their State and Tribal members, to have informal consultations on these technical considerations. 

5) During both the formal and informal inter-RPO consultations, it is anticipated that the States and Tribes will work collectively to 

facilitate the consultation process through their respective RPOs, when feasible. 

6) Technical analyses will be transparent, when possible, and will reflect the most up-to-date information and best scientific 

methods for the decision needed within the resources available. 

7) The State with the Class I area retains the responsibility to establish reasonable progress goals. The RPOs will make reasonable 

efforts to facilitate the development of a consensus between the State with a Class I area and other States affecting that area. In 

instances where the State with the Class I area cannot agree with such other States that the goal provides for reasonable 

progress, actions taken to resolve the disagreement must be included in the State’s regional haze implementation plan (or plan 

revisions) submitted to the EPA Administrator as required under 40 CFR §51.308(d)(1)(iv). 

8) All States whose emissions are reasonably anticipated to contribute to visibility impairment in a Class I area must provide the 

Federal Land Manager (“FLM”) agency for that Class I area with an opportunity for consultation, in person, on their regional haze 

implementation plans. The States/Tribes will pursue the development of a memorandum of understanding to expedite the 

submission and consideration of the FLM’s comments on the reasonable progress goals and related implementation plans. As 

required under 40 CFR §51.308(i)(3), the plan or plan revision must include a description of how the State addressed any FLM 

comments. 

9) States/Tribes will consult with the affected FLMs to protect the air resources of the State/Tribe and Class I areas in accordance 

with the FLM coordination requirements specified in 40 CFR §51.308(i) and other consultation procedures developed by 

consensus. 

10) The consultation process is designed to share information, define and document issues, develop a range of options, solicit 

feedback on options, develop consensus advice if possible, and facilitate informed decisions by the Class I States. 

11) The collaborators, including States, Tribes and affected FLMs, will promptly respond to other RPO’s/States’/Tribes’ requests for 

comments.

The following points highlight many of the ways MANE-VU member states and tribes have cooperatively 

addressed regional haze:

 Budget Prioritization: MANE-VU developed a process to coordinate MARAMA, OTC, and NESCAUM staff 

in developing budget priorities, project rankings, and the eventual federal grant requests. 

 Issue Coordination: MANE-VU established a conference call and meeting schedule for each of its 

committees and workgroups. In addition, MANE-VU Air Directors regularly discussed pertinent issues. 
Page 15

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

 Capacity Building: To educate its staff and members, MANE-VU included technical presentations on 

conference calls and organized workshops with nationally recognized experts. Presentations on data 

analysis, BART work, inventory topics, modeling, control measures, etc., were an effective education and 

coordination tool.

 Routine Operations: MANE-VU staff at OTC, MARAMA, and NESCAUM established a coordinated 

approach to budgeting, grant deliverables/due-dates, workgroup meetings, inter-RPO feedback, etc.

In addition to having a set of guiding principles for consultation, MANE-VU needed a consistent technical basis 

for emission control strategies to reduce regional haze to meet the reasonable progress goals for 2018. After 

much research and analysis, on June 20, 2007, MANE-VU adopted the following pair of documents, which provide 

the technical basis for consultation among the interested parties and define the basic strategies for controlling

pollutants that cause visibility impairment at Class I areas in the eastern United States. Together, these 

documents are known as the MANE-VU “Ask” (Appendix C).

 “Statement of the Mid-Atlantic / Northeast Visibility Union (MANE-VU) Concerning a Course of Action 

within MANE-VU toward Assuring Reasonable Progress,” and

 “Statement of the Mid-Atlantic / Northeast Visibility Union (MANE-VU) Concerning a Request for a 

Course of Action by States outside of MANE-VU toward Assuring Reasonable Progress.”

The consultations among MANE-VU states and other states/tribes and provinces occurred through much of 

2007. Documentation of consultation meetings and calls between MANE-VU Class I States and states/tribes 

both within and outside MANE-VU can found on the MANE-VU website at 

www.otcair.org/manevu/consultations.asp?fview=2. A summary of the consultation process follows.

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

o At this meeting, MANE-VU members reviewed requirements for regional haze plans, preliminary 

modeling results, work being done to prepare the MANE-VU report on reasonable progress 

factors, and control strategy options under review.

 MANE-VU Intra-State Consultation, June 7, 2007

o At this meeting the MANE-VU Class I states adopted a statement of principles, and all MANE-VU 

members discussed draft statements concerning reasonable controls within and outside of 

MANE-VU. Federal Land Managers also attended the meeting, which was open to stakeholders.
Page 16

 MANE-VU Conference Call, June 20, 2007

o On this call, the MANE-VU states concluded discussions of statements concerning reasonable 

controls within and outside MANE-VU and agreed on the statements called the MANE-VU “Ask,” 

including a statement concerning controls within MANE-VU, a statement concerning controls 

outside MANE-VU, and a statement requesting a course of action by EPA. Federal Land 

Managers also participated in the call. Upon approval, all statements as well as the statement 

of principles adopted on June 7 were posted and publicly available on the MANE-VU web site. 

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

o On this call, the MANE-VU / New Hampshire “Ask” was presented to states in other RPOs, RPO 

staff, and Federal Land Managers, and an opportunity was provided to request further 

information. This call was intended to provide information to facilitate informed discussion at 

follow-up meetings.

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

o This meeting was held at LADCO offices in Chicago, Illinois and was attended by representatives 

of MANE-VU and MRPO states, as well as staff. The meeting provided an opportunity to 

formally present the MANE-VU “Ask” to MRPO states and to consult with them regarding the 

reasonableness of the requested controls. Federal Land Manager agencies also attended the 

meeting.

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

o This meeting was held at State of Georgia offices in Atlanta and was attended by representatives 

of MANE-VU and VISTAS states, as well as staff. The meeting provided an opportunity to 

formally present the MANE-VU “Ask” to VISTAS states and to consult with them regarding the 

reasonableness of the requested controls. Federal Land Manager agencies also attended the 

meeting.

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

o This call was a follow-up to the meeting held on August 6 in Chicago and provided an 

opportunity to further clarify what was being asked of the MRPO states, including explanation of 

the flexibility in the “Ask.” Both MRPO and MANE-VU staff agreed to work together to facilitate 

discussion of further controls on ICI boilers and EGUs.

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

o This call allowed MANE-VU members to clarify their understanding of the “Ask” and to provide 

direction to modeling staff as to how to interpret the “Ask” for purposes of estimating visibility 

impacts of the requested controls.

 MANE-VU Air Directors’ Conference Call, March 31, 2008
Page 17

o On this call, NESCAUM presented the results of the final 2018 modeling and described the 

methods used to represent the impacts of the measures agreed to by the Class I States. Federal 

Land Manager agencies also participated in this call.

2.9. Meeting the “Ask” – MANE-VU States

The member states of MANE-VU have stated their intention to meet the terms of the “Ask” in their SIPs. The 

“Ask” for member states commits each state to pursue the adoption and implementation of the following 

emission management strategies, as appropriate and necessary:

 timely implementation of BART requirements; and

 a low sulfur fuel oil strategy in the inner zone States (New Jersey, New York, Delaware and Pennsylvania, 

or portions thereof) to reduce the sulfur content of: distillate oil to 0.05 percent sulfur by weight (500 

ppm) by no later than 2012, of #4 residual oil to 0.25 percent sulfur by weight by no later than 2012, of 

#6 residual oil to 0.3 – 0.5 percent sulfur by weight by no later than 2012, and to further reduce the 

sulfur content of distillate oil to 15 ppm by 2016; and

 a low sulfur fuel oil strategy in the outer zone States (the remainder of the MANE-VU region) to reduce 

the sulfur content of distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 2014, of #4 

residual oil to 0.25 – 0.5 percent sulfur by weight by no later than 2018, and of #6 residual oil to no 

greater than 0.5 percent sulfur by weight by no later than 2018, and to further reduce the sulfur content 

of distillate oil to 15 ppm by 2018, depending on supply availability; and

 A 90 percent or greater reduction in sulfur dioxide (SO2) emissions from each of the top 100 electric 

generating units (EGUs) identified by MANE-VU (comprising a total of 167 stacks) as reasonably 

anticipated to cause or contribute to impairment of visibility in each mandatory Class I Federal area in 

the MANE-VU region. If it is infeasible to achieve that level of reduction from a unit, alternative 

measures will be pursued in such State; and 

 continued evaluation of other control measures including energy efficiency, alternative clean fuels, and 

other measures to reduce SO2 and nitrogen oxide (NOx) emissions from all coal-burning facilities by 

2018 and new source performance standards for wood combustion. These measures and other 

measures identified will be evaluated during the consultation process to determine if they are 

reasonable and cost-effective.
Page 18

Massachusetts supports the SIPs of each of its fellow MANE-VU states provided that these SIPs incorporate 

these commitments.

2.10. Meeting the “Ask” – Massachusetts

As a MANE-VU member state, Massachusetts also adopted the “Ask” at the MANE-VU Board meeting 

on June 7, 2007. Massachusetts is meeting the terms of this agreement by implementing an 

alternative to BART as described in Section 8, and by ensuring reductions in SO2 emissions from the 

Massachusetts Targeted EGU stacks, implementing low-sulfur fuel oil regulations, and implementing 

controls on outdoor wood-fired boilers as described in Section 10. Massachusetts also will pursue 

other reasonable and cost-effective measures as needed.

2.11. Meeting the “Ask” – States Outside of MANE-VU

For consulting states outside the MANE-VU region, the MANE-VU “Ask” requests the pursuit of the adoption and 

implementation of the following control strategies, as appropriate and necessary:

 timely implementation of BART requirements;

 A 90 percent or greater reduction in sulfur dioxide (SO2) emissions from each of the top 100 electric 

generating units (comprising a total of 167 stacks) impacting any mandatory Class I Federal area in the 

MANE-VU region, or an equivalent SO2 reduction within each State;

 the application of reasonable controls on non-EGU sources resulting in a 28 percent reduction in nonEGU SO2 emissions, relative to on-the-books, on-the-way 2018 projections used in regional haze 

planning, by 2018, which is equivalent to the projected reductions MANE-VU will achieve through its low 

sulfur fuel oil strategy;

 continued evaluation of other measures including measures to reduce SO2 and nitrogen oxide (NOx) 

emissions from all coal-burning facilities by 2018 and promulgation of new source performance 

standards for wood combustion. These measures and other measures identified will be evaluated 

through consultation processes to determine if they are reasonable.
Page 19

Massachusetts recognizes that non-MANE-VU states may choose not to adopt the MANE-VU “Ask” due to 

associated costs, conflicts, and relative lack of benefit within their jurisdictions. During consultations, some nonMANE-VU states were considering not pursuing reductions beyond CAIR controls and other measures pertaining 

to BART. EPA’s CSAPR will provide reductions similar to CAIR and it is hoped that states in the mid-west and 

southeast RPOs will adopt other additional controls. Ultimately, the approvability of all states’ SIPs will be 

determined by EPA. 

2.12. Technical Ramifications of Differing Approaches

MANE-VU states intended to develop a modeling platform that was common in terms of meteorology and 

emissions with each of the other nearby RPOs. The RPOs worked diligently to form a common set of emissions 

with similar developmental assumptions. Even with the best of intentions, it became difficult to keep up with 

each RPO’s updates and corrections. Each rendition of emissions inventory improved its quality, but because 

each update made to one RPO’s emissions meant that the other RPOs needed to incorporate the updates into 

the full emission set for all the RPOs and then reprocess them, there was a continuous modeling effort where 

each one outdated the last. Because each rendition put previous modeling efforts out of date, and a single 

modeling run could take more than a month to complete, inventory updates contributed to SIP delays. The 

emission inventory conflicts were excessively time consuming and caused most states to miss the official SIP 

filing date of December 17, 2007.

The RPOs also took differing perspectives on which version of the EGU dispatching model (Integrated Planning 

Model or IPM) to use. At the beginning of the process, IPM version 2.1.9 was available and EPA agreed to its use 

for emissions preparation. Since then, IPM version 3.0 became available and it became EPA’s preferred version 

since it had updated fuel costs. MRPO adopted IPM v3.0 for its use, but VISTAS stayed with IPM v2.1.9. Rather 

than develop non-comparative datasets for its previous IPM analyses, MANE-VU also stayed with IPM v2.1.9. 

Therefore, of the three eastern RPOs, differing emissions assumptions eventually worked their way into the final 

set of modeling assumptions. 

MANE-VU’s best and final modeling not only considers on-the-way/on-the-books emissions programs for 2018 

(listed in Section 10), but also includes additional reasonable controls in its region, including those contained in 

the MANE-VU “Ask”. It should be noted that other RPOs may not have included such measures in their final 

modeling. In these cases, the modeling results of states in these RPOs will be inconsistent with meeting the 

terms of the MANE-VU “Ask” – a situation that may not be adequately addressed in their SIPs. These 

inconsistencies will need to be resolved by EPA. 

2.13. Federal Land Manager Coordination

Massachusetts will continue to coordinate and consult with the Federal Land Managers (FLMs) during the 

development of future progress reports and plan revisions, as well as during the implementation of programs 

having the potential to contribute to visibility improvement in the Class I areas.
Page 20

Section 51.308(i) of the Regional Haze Rule requires coordination between states/tribes and the FLMs. 

Opportunities have been provided by MANE-VU for FLMs to review and comment on each of the technical 

documents developed by MANE-VU and included in this SIP. Massachusetts has provided agency contacts to the 

FLMs as required. In the development of this Plan, the FLMs were consulted in accordance with the provisions 

of 51.308(i)(2). 

MassDEP provided previous drafts of this SIP, or portions thereof, to FLMs and EPA for review and comment on

November 25, 2008 and July 31, 2009, and published the draft SIP for public hearing and comment on January 

11, 2011. MassDEP also published a draft SIP revision for public hearing and comment on February 17, 2012. 

MassDEP provided the FLMs an opportunity for consultation, in person and at least 60 days prior to holding a 

public hearing on the SIP. The comments submitted by the FLMs were both general and specific. The reviewing 

agencies found Massachusetts’ draft Regional Haze SIP to be well written and comprehensive. The uncertainty 

surrounding CAIR and discrepancies in modeling (especially inclusion of the MANE-VU Ask) between MANE-VU 

and other RPOs were identified as broad topics for further discussion through the consultation process. 

Comments of a specific nature were focused primarily on requesting additional information in support of initial 

BART analyses. In accordance with 40 CFR 51.308(i)(3), MassDEP has addressed comments from FLMs regarding 

the SIP in Appendix D of this plan, as well as comments submitted by EPA. 

Section 51.308(i)(4) requires procedures for continuing consultation between states/tribes and FLMs on the 

implementation of the visibility protection programs. In particular, consultations will be conducted with the 

designated visibility protection program coordinators for the National Park Service, the U. S. Fish and Wildlife 

Service, and the U.S. Forest Service. MassDEP will consult periodically with the FLMs as necessary on the status 

of the following implementation items:

1. Implementation of emissions strategies identified in the SIP as contributing to achieving improvement in 

the worst-day visibility.

2. Summary of major new source permits issued.

3. Status of Massachusetts actions to meet commitments for completing any future assessments or 

rulemakings on sources identified as likely contributors to visibility impairment, but not directly 

addressed in the most recent SIP revision. 

4. Any changes to the status of the monitoring strategy or monitoring stations that may affect tracking of 

reasonable progress. 

5. Work underway for preparing the 5-year review and / or 10-year revision.
Page 21

6. Items for FLMs to consider or provide support for in preparation for any visibility protection SIP revisions 

(based on the 5-year review or the 10-year revision schedule). 

7. Summaries of discussions (meetings, emails, other records) covered in ongoing communications 

between MassDEP and FLMs regarding implementation of the visibility program. 
Page 22

3.ASSESSMENT OF BASELINE AND NATURAL CONDITIONS

Under the Clean Air Act, the Regional Haze SIPs must contain measures to make reasonable progress toward the 

goal of achieving natural visibility. Section 51.308(d)(2) of EPA’s Regional Haze Rule requires each state 

containing a Class I area to determine baseline and natural visibility conditions for their Class I area in 

consultation with FLMs and states identified as containing sources whose emissions contribute to visibility 

impairment in Class I areas. Comparing baseline conditions to natural visibility conditions determines the 

uniform rate of progress that must be considered as states set reasonable progress goals for each Class I area. 

The requirement to assess baseline and natural conditions within Class I Areas is a responsibility of the state 

containing those areas. Massachusetts does not contain any Class I Areas; however, assessment of baseline and 

natural visibility conditions for MANE-VU Class I Areas is included here as reference.

3.2. Calculation Methodology

The Interagency Monitoring of Protected Visual Environments (IMPROVE) program was established in 1985 to 

provide the data needed to assess current visibility conditions, track changes in visibility, and help determine the 

causes of visibility impairment in Class I Areas (see Section 4 for more detailed information about IMPROVE). 

IMPROVE data was used to calculate baseline and natural conditions for MANE-VU Class I areas.

The IMPROVE monitors listed in Table 4 provide data that are representative of Class I Areas in MANE-VU. As 

described in the Monitoring Section (Section 4) of this SIP, Massachusetts accepts IMPROVE designation of these 

sites as representative of Class I areas in accordance with 40 CFR 51.308(d)(2)(i).

Table 4: IMPROVE Monitors for MANE-VU Class I Areas

Class I Area IMPROVE Site

Location 

(latitude and 

longitude) State

Acadia National Park ACAD1 44.38, -68.26 Maine

Moosehorn Wilderness Area MOOS1 45.13, -67.27 Maine

Roosevelt/Campobello International Park MOOS1 45.13, -67.27 Maine

Great Gulf Wilderness Area GRGU1 44.31, -71.22 New Hampshire

Presidential Range/Dry River Wilderness GRGU1 44.31, -71.22 New Hampshire
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Lye Brook Wilderness Area LYBR1 43.15, -73.13 Vermont

Brigantine Wilderness Area BRIG1 39.47, -74.45 New Jersey

Source: VIEWS (http://vista.cira.colostate.edu/views/), prepared on 7/06/06

In September 2003, EPA issued guidance for the calculation of natural background and baseline visibility 

conditions. The guidance provides a default method and describes certain refinements that states may wish to

evaluate to tailor these estimates to a specific Class I area if it is poorly represented by the default method. At 

that time, MANE-VU calculated natural visibility for each of the MANE-VU Class I areas using the default method 

for the 20 percent best and worst visibility days. MANE-VU also evaluated ways to refine the estimates. 

Potential refinements included: increasing the multiplier used to calculate impairment attributed to carbon, 

adjusting the formula used to calculate the 20 percent best and worst visibility days, and accounting for visibility 

impairment due to sea salt at coastal sites. However, MANE-VU found that these refinements did not 

significantly improve the accuracy of the estimates, and MANE-VU states desired a consistent approach. 

Therefore, default estimates were used with the understanding that this would be reconsidered when better 

scientific knowledge warranted. 

Once the technical analysis was complete, MANE-VU provided an opportunity to comment to federal agencies 

and stakeholders. The proposed approach was posted on the MANE-VU website on March 17, 2004 and a 

stakeholder briefing was held on the same day. Comments were received from the Electric Power Research 

Institute, the Midwest Ozone Group, the Appalachian Mountain Club, the National Parks Conservation 

Association, the National Park Service, and the US Forest Service. 

Several comments supported the proposal and other comments addressed four main topics: the equation used 

to calculate visibility, the statistical technique used to estimate the 20 percent best and worst visibility days, the 

inclusion of transboundary effects and fires, and the timing of when new information should be included. All 

comments were reviewed and summarized by MANE-VU. The MANE-VU Board was briefed on comments and 

proposed response options.

The MANE-VU position on natural background conditions was issued in June 2004, and stated that, 

“Refinements to other aspects of the default method (e.g., refinements to the assumed distribution or 

treatment of Rayleigh extinction, inclusion of sea salt, and improved assumptions about the chemical 

composition of the organic fraction) may be warranted prior to submission of SIPs depending on the degree to 

which scientific consensus is formed around a specific approach...”
Page 24

In 2006, the IMPROVE Steering Committee adopted an alternative reconstructed extinction equation to revise 

certain aspects of the default method. The aspects revised were scientifically well understood, and the 

Committee determined that revisions improved the performance of the equation at reproducing observed 

visibility at Class I sites. 

In 2006, NESCAUM conducted an assessment of the default and alternative approaches for calculation of 

baseline and natural background conditions at MANE-VU Class I areas. (See the MANE-VU document, 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 E.) Corresponding 

visibility improvement targets for 2018 using each approach also were presented in the document (see Table 3-3 

of Appendix E). Results suggest that the alternative approach leads to very similar uniform rates of progress in 

New England with slightly greater visibility improvement required in the Mid-Atlantic region relative to the 

default approach. Based on that assessment, in December 2006, MANE-VU recommended adoption of the 

alternative reconstructed extinction equation for use in SIPs. MANE-VU will continue to participate in further 

research efforts on this topic and will reconsider the calculation methodology as scientific understanding 

evolves.

3.3. MANE-VU Baseline and Natural Visibility

The IMPROVE program has calculated the 20 percent best and 20 percent worst baseline (2000-2004) and 

natural visibility conditions using the EPA-approved alternative method described above for each MANE-VU 

Class I Area. The data are posted on the Visibility Information Exchange Web System (VIEWS) operated by the 

regional planning organizations. The information can be accessed at http://vista.cira.colostate.edu/views/ and 

is summarized in Table 5 below. Units are expressed in deciviews, a log function of the light scattering and 

absorption extinction coefficient, as required by 40 CFR 51.308(d)(2). Generally, a one deciview change in the 

haze index is likely to be perceptible under ideal conditions regardless of background visibility conditions. 

Displayed are the five-year average baseline visibility values for the period 2000-2004, natural visibility levels, 

and the difference between baseline and natural visibility values for each of the MANE-VU Class I areas. The 

difference columns (best and worst) are of particular interest because they describe the magnitude of visibility 

impairment attributable to manmade emissions, which are the focus of the Regional Haze Rule.

The five-year averages for 20 percent best and worst visibility were calculated in accordance with 40 CFR 

51.308(d)(2), as detailed in NESCAUM’s Baseline and Natural Background document found in Appendix E.

Table 5: Summary of Baseline Visibility and Natural Visibility Conditions for the 20 Percent Best and 20 

Percent Worst Visibility Days at MANE-VU Class I Areas
Page 25

Class I Area(s)

2000-2004 Baseline

(deciviews)

Natural Conditions

(deciviews)

Difference

Best (deciviews)

20%

Worst 20%

Best

20%

Worst 20%

Best

20%

Worst 20%

Acadia National Park 8.8 22.9 4.7 12.4 4.1 10.5

Moosehorn Wilderness and

Roosevelt Campobello International Park

9.2 21.7 5.0 12.0 4.1 9.7

Great Gulf Wilderness and

Presidential Range - Dry River Wilderness 4

7.7 22.8 3.7 12.0 3.9 10.8

Lye Brook Wilderness 6.4 24.5 2.8 11.7 3.6 12.7

Brigantine Wilderness 14.3 29.0 5.5 12.2 8.8 16.8

Source: VIEWS (http://vista.circa.colostate.edu/views/), prepared on 6/22/2007

 

4

Based on 4-year average for 2001-2004 (data collection in 2000 was for summer only).
Page 26

4.MONITORING STRATEGY 

Section 51.308(d)(4) of EPA’s Regional Haze Rule requires a monitoring strategy for measuring, characterizing, 

and reporting of regional haze visibility impairment that is representative of Class I areas within a state, and 

allows compliance with this requirement to be met through participation in the Interagency Monitoring of 

Protected Visual Environments (IMPROVE) program.

In the mid-1980’s, the IMPROVE program was established to measure visibility impairment in mandatory Class I 

areas throughout the United States. The monitoring sites are operated and maintained through a formal 

cooperative relationship between EPA, National Park Service, U.S. Fish and Wildlife Service, Bureau of Land 

Management, and U.S. Forest Service. In 1991, several additional organizations joined the effort: State and 

Territorial Air Pollution Program Administrators, the Association of Local Air Pollution Control Officials (which 

now goes by The National Association of Clean Air Agencies), Western States Air Resources Council, Mid-Atlantic 

Regional Air Management Association, and Northeast States for Coordinated Air Use Management.

4.2. IMPROVE Program Objectives

The IMPROVE program provides scientific documentation of the visual air quality of America’s wilderness areas 

and national parks. Many individuals and organizations – land managers, industry planners, scientists (including 

university researchers), public interest groups, and air quality regulators – use the data collected at IMPROVE 

sites to understand and protect the visual air quality resources in Class I areas. Major objectives of the IMPROVE 

program include:

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

 Identify chemical species and emission sources responsible for existing anthropogenic visibility impairment,

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

 Provide regional haze monitoring representing all visibility-protected federal Class I areas where practical, as 

required by EPA’s Regional Haze Rule.

4.3. Monitoring Information for Massachusetts

Section 51.308(d)(4)(iii) of the Regional Haze Rule requires for a state with no Class I areas, such as 

Massachusetts, the inclusion of procedures by which monitoring data and other information are used in 

determining the contribution of emissions from within the state to regional haze visibility impairment at Class I 

areas outside the state. Massachusetts’ contribution is documented in the contribution assessment analysis 

completed by NESCAUM entitled, Contributions to Regional Haze in the Northeast and Mid-Atlantic States 

(Contribution Assessment) found in Appendix A. The NESCAUM study used various tools and techniques to 
Page 27

assess the contributions of individual states and regions to visibility degradation in Class I areas within and 

outside MANE-VU.

Massachusetts agrees that NESCAUM is providing quality technical information by using the IMPROVE program 

data and the Visibility Information Exchange Web System (VIEWS) site. Information about the use of the default 

and alternative approaches to the calculation of baseline and natural background conditions can be found in 

Section 3 of this SIP.

Massachusetts does not contain any Class I Areas; therefore no monitoring plan is required under Section 

51.308(d)(4) or Section 51.30 of the Regional Haze Rule. Massachusetts does, however, have three IMPROVE 

monitors that were used in the regional haze modeling: Cape Cod (CACO), Martha’s Vineyard (MAVI), and 

Quabbin summit (QURE). The CACO IMPROVE monitor is located at Cape Cod National Seashore in Truro and is 

operated and maintained by the National Park Service. It is located near MassDEP’s monitoring site at latitude 41:58 

and longitude -70:01. The QURE IMPROVE monitor is located at the Quabbin Reservoir in Ware, at latitude 42:17 and 

longitude –72:20, and is operated and maintained by MassDEP. The MAVI IMPROVE monitor is located on Martha’s 

Vineyard and is operated by the Wampanoag Tribe of Gay Head (Aquinnah). Massachusetts commits to continuing 

these monitoring programs and to working with the National Park Service, Wampanoag Tribe, and EPA towards this 

end.

The following information is for monitoring within Class I areas determined to be impacted by Massachusetts 

sources by the Contribution Assessment contained in Appendix A.

4.4. Monitoring Information for MANE-VU Class I Areas Impacted by Emissions from 

Massachusetts

Acadia National Park, Maine 

The IMPROVE monitor for Acadia National Park (ACAD1) is located at park headquarters near Bar Harbor, Maine, 

at elevation 157 meters, latitude 44.38 ̊, and longitude -68.26 ̊ (see Figure 6). This monitor is operated and 

maintained by the National Park Service. Massachusetts considers the ACAD1 site as adequate for assessing 

reasonable progress toward visibility goals at Acadia National Park, and no additional monitoring sites or 

equipment are necessary at this time. 
Page 28

Acadia National Park IMPROVE Site

Created by Tom Downs, MEDEP 4/17/07

IMPROVE MONITOR LOCATION

ACADIA NATIONAL PARK

LEGEND

http://www.maine.gov/dep/air/meteorology/images/Acadia.jpg

Figure 6: Map of Acadia National Park Showing

Location of IMPROVE Monitor
Page 29

IMPROVE MONITOR 

Figure 7: Acadia National Park on Clear and Hazy Days

 

http://www.hazecam.net/class1/acadia.html

Great Gulf Wilderness Area, New Hampshire

The IMPROVE monitor for the Great Gulf Wilderness (GRGU1) is located at Camp Dodge in the mid-northern 

area of Greens Grant in the White Mountain National Forest. The monitor site lies just east and south of where 

Route 16 crosses the Greens Grant / Martins Location boundary, south of Gorham, New Hampshire, at elevation 

454 meters, latitude 44.31 ̊, and longitude of -71.22 ̊ (see Figure 8). This monitor, which also represents the 

Presidential Range - Dry River Wilderness (see Figure 8), is operated and maintained by the U.S. Forest Service. 

Massachusetts considers the GRGU1 site as adequate for assessing reasonable progress toward visibility goals at 

the Great Gulf Wilderness, and no additional monitoring sites or equipment are necessary at this time.

Figure 8: Map of Great Gulf and Presidential Range - Dry River Wilderness Areas Showing IMPROVE 

Monitor Location
Page 30

http://www.maine.gov/dep/air/meteorology/images/NHclass1.jpg

Figure 9: Great Gulf Wilderness Area on Clear and Hazy Days

http://www.wilderness.net/

Presidential Range - Dry River Wilderness, New Hampshire

The IMPROVE monitor for the Presidential Range - Dry River Wilderness is also the monitor for Great Gulf 

Wilderness (GRGU1), as described above. Massachusetts considers the GRGU1 site as adequate for assessing 

reasonable progress toward visibility goals at the Presidential Range - Dry River Wilderness, and no additional 

monitoring sites or equipment are necessary at this time.

Presidential Range - Dry River Wilderness in Autumn
Page 31

http://www.wilderness.net

Lye Brook Wilderness, Vermont 

The IMPROVE monitor for the Lye Brook Wilderness (LYBR1) is located on Mount Equinox at the windmills in 

Manchester, Vermont, at elevation 1015 meters, latitude 43.15 ̊, and longitude of -73.13 ̊ (see Figure 10). The 

monitor does not lie within the wilderness area but is situated on a mountain peak across the valley to the west 

of the wilderness area. The IMPROVE site and the Lye Brook Wilderness are at similar elevations. The monitor 

is operated and maintained by the U.S. Forest Service. Massachusetts considers the LYBR1 site as adequate for 

assessing reasonable progress toward visibility goals at the Lye Brook Wilderness, and no additional monitoring 

sites or equipment are necessary at this time.
Page 32

Figure 10: Location of Lye Brook Wilderness Monitor

http://www.wilderness.net/index.cfm?fuse=NWPS&sec=stateView&state=NH&map=menhvt

Figure 11: Lye Brook Wilderness Area on Clear and Hazy Days

IMPROVE MONITOR SITE
Page 33

http://www.hazecam.net/class1/lye.html
Page 34

Moosehorn Wilderness Area, Maine 

The IMPROVE monitor for the Moosehorn Wilderness (MOOS1) is located near McConvey Road, about one mile 

northeast of the National Wildlife Refuge Baring (ME) Unit Headquarters, at elevation 78 meters, latitude 45.13 ̊, 

and longitude -67.27 ̊ (see Figure 12). This monitor also represents the Roosevelt Campobello International Park 

in New Brunswick, Canada. The monitor is operated and maintained by the U.S. Fish & Wildlife Service. 

Massachusetts considers the MOOS1 site as adequate for assessing reasonable progress toward visibility goals at 

the Moosehorn Wilderness, and no additional monitoring sites or equipment are necessary at this time.

Figure 12: Map of the Baring and Edmunds Divisions of the Moosehorn National Wildlife Refuge Showing 

the IMPROVE Monitor Location

 source: The Refuge Manager at Moosehorn Wilderness
Page 35

Figure 13: Moosehorn Wilderness Area on a Clear and a Hazy Day

source: Martha Webster, Maine Department of Environmental Protection – Bureau of Air Quality

Roosevelt/Campobello International Park, New Brunswick, Canada

The IMPROVE monitor for Roosevelt Campobello International Park is also the monitor for the Moosehorn 

Wilderness (MOOS1), as described above. Massachusetts considers the MOOS1 site as adequate for assessing 

reasonable progress toward visibility goals at Roosevelt Campobello International Park, and no additional 

monitoring sites or equipment are necessary at this time.

Figure 14: Map of Roosevelt/Campobello International Park 
Page 36

http://www.maine.gov/dep/air/meteorology/images/rcip.jpg
Page 37

Figure 15: Roosevelt/Campobello International Park on Clear and Hazy Days

source: Chessie Johnson, Roosevelt Campobello International Park Commission
Page 38

5.MODELING

Section 51.308(d)(3)(iii) of the Regional Haze Rule requires states to document the technical basis, including 

modeling, monitoring and emissions information, on which the state is relying to determine its apportionment 

of emissions reduction obligations necessary for achieving reasonable progress in each Class I area it affects.

Air quality modeling to assess regional haze has been done cooperatively between Massachusetts and its 

regional planning organization, MANE-VU, with major modeling efforts being conducted by NESCAUM5and 

screening modeling being conducted by the New Hampshire Department of Environmental Services.

6

These 

modeling efforts include emissions processing, meteorological input analysis, and chemical transport modeling 

to conduct regional air quality simulations for calendar year 2002 and several future periods, including the 

primary target period for this SIP, calendar year 2018. Modeling was conducted in order to assess contribution 

from upwind areas, as well as Massachusetts’ contribution to Class I areas in downwind states. Further, the 

modeling evaluated visibility benefits of control measures being considered for achieving reasonable progress 

goals and establishing a long-term emissions management strategy for MANE-VU Class I areas.

The modeling tools utilized for these analyses include the following:

 The Fifth-Generation Pennsylvania State University/National Center for Atmospheric Research (NCAR) 

Mesoscale Model (MM5) was used to derive the required meteorological inputs for the air quality 

simulations.

 The Sparse Matrix Operator Kernel Emissions (SMOKE) emissions modeling system was used to process and 

format the emissions inventories for input into the air quality models.

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

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

 The California Grid Model (CALGRID) and its associated EMSPROC6 emissions processor were used to screen 

specific control strategies.

 The California Puff Model (CALPUFF) was used to assess the contribution of individual states’ emissions to 

sulfate levels at selected Class I receptor sites.

 

5

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

6

Along with the VTDEP and MDEQ.
Page 39

Each of these tools has been evaluated and found to perform adequately. The pertinent SIP modeling 

underwent full performance testing and the results were found to meet the specifications of EPA modeling 

guidance.

For more details on the regional haze modeling, please refer to the NESCAUM report MANE-VU Modeling for 

Reasonable Progress Goals, Model Performance Evaluation, Pollution Apportionment, and Control Measure 

Benefits (Appendix F). The detailed modeling approach for the best and final 2018 projected scenario can be 

found in the NESCAUM report 2018 Visibility Projections (Appendix G).

5.2. Meteorology

The meteorological inputs for the air quality simulations were developed by the University of Maryland (UMD) 

using the MM5 meteorological modeling system. Meteorological inputs were generated for 2002 to correspond 

with the baseline emissions inventory and analysis year. The MM5 simulations were performed on a nested grid 

as illustrated in Figure 16. As shown in the figure, the modeling domain is comprised of a 36-km, 145 x 102 

continental grid and a nested 12-km, 172 x 172 grid encompassing the eastern United States and parts of 

Canada. In cooperation with the New York State Department of Conservation (NYSDEC), an assessment was 

made to compare the MM5 predictions with observations from a variety of data sources, including: 

 surface observations from the National Weather Service (NWS) and the Clean Air Status and Trends 

Network (CASTNet), 

 wind-profiler measurements from the Cooperative Agency Profilers (CAP) network,

 satellite cloud image data from the UMD Department of Atmospheric and Oceanic Science, and 

 precipitation data from the Earth Observing Laboratory at NCAR. This assessment was performed for 

the period covering May through September 2002. 

Further details regarding the MM5 meteorological processing and the modeling domain can be found in 

Appendix H, NYSDEC’s Meteorological Modeling Using Penn State/NCAR 5th Generation Mesoscale Model and 

Appendix F, NESCAUM’s MANE-VU Modeling for Reasonable Progress Goals.
Page 40

Figure 16: Modeling domains used in MANE-VU air quality modeling studies with CMAQ. 

Outer (blue) domain grid is 36 km and inner (red) domain is 12 km grid. The gridlines are shown at 180 km intervals (5x5 for 

36 km cells/15×15 for 12 km cells).

5.3. Emissions Data Preparations

Emissions data were prepared for input into the CMAQ and REMSAD air quality models using the SMOKE 

emissions modeling system. SMOKE supports point, area, mobile (both on-road and non-road), and biogenic 

emissions. The SMOKE emissions modeling system uses flexible processing to apply chemical speciation as well 

as temporal and spatial allocation to the emissions inventories. SMOKE incorporates the Biogenic Emission 

Inventory System (BEIS) and EPA’s MOBILE6 motor vehicle emission factor model to process biogenic and onroad mobile emissions, respectively. Vector-matrix multiplication is used during the final processing step to 

merge the various emissions components into a single model-ready emissions file. Examples of processed 

emissions outputs are shown in Figure 17.

Further details on the SMOKE processing that was done in support of the air quality simulations is provided in 

Appendix H and Appendix I, NYSDEC’s Emission Processing for the Revised 2002 OTC Regional and Urban 12 km 

Base Case Simulations. Additional details on the emission inventory preparation can be found in Section 6.
Page 41

Figure 17: Examples of processed model-ready emissions: a) SO2 from Point, b) NO2 from Area, c) NO2 

from On-road, d) NO2 from Non-road, e) ISOP from Biogenic, f) SO2 from all source categories
Page 42

5.4. Model Platforms

Two regional-scale air quality models, CMAQ and REMSAD, were used for the air quality simulations that directly 

supported the Regional Haze SIP effort. CMAQ was developed by EPA and was used to perform the primary SIPrelated modeling. The CMAQ modeling simulations also were an important tool for the 8-hour ozone SIP 

process. REMSAD was developed by ICF Consulting/Systems Applications International with support from EPA. 

REMSAD was used by NESCAUM to perform a source apportionment analysis. All of the air quality simulations 

that were used in the SIP efforts were performed on the 12-km eastern modeling domain shown in Figure 16

above.

NESCAUM performed a model performance evaluation for PM2.5 species, aerosol extinction coefficient, and the 

haze index, which is provided in Appendix F. NYSDEC also performed a model performance analysis to evaluate 

CMAQ model predictions against observations of ozone, PM2.5, and other chemical species, which is contained in 

Appendix J, CMAQ Model Performance and Assessment, 8-Hr OTC Ozone Modeling.

CMAQ

The CMAQ air quality simulations were performed cooperatively between five modeling centers, including 

NYSDEC, the New Jersey Department of Environmental Protection (NJDEP) in association with Rutgers 

University, the Virginia Department of Environmental Quality (VADEQ), UMD, and NESCAUM. NYSDEC also 

performed an annual 2002 CMAQ simulation on the 36-km domain shown in Figure 16; this simulation was used 

to derive the boundary conditions for the inner 12-km eastern modeling domain. Boundary conditions for the 

36-km simulations were obtained from a run of the GEOS-Chem (Goddard Earth Observing System) global 

chemistry transport model that was performed by researchers at Harvard University. The technical options that 

were used in performing the CMAQ simulations are described in detail in Appendix K, NYSDEC’s Eight-Hour

Ozone Modeling using the SMOKE/CMAQ system. Further technical details regarding the CMAQ model and its 

execution are also provided in Appendix F.

REMSAD

The REMSAD modeling simulations were used to satisfy the haze rule requirement that a pollution 

apportionment be performed to assess contribution to visibility improvement by geographic region or source 

sector. REMSAD’s species tagging capability makes it an important tool for this purpose. This allowed for a 

rough estimation of the total contribution from elevated point sources in each state to simulated sulfate 

concentrations at eastern receptor sites. Using identical emission and meteorological inputs to those prepared 

for the Integrated SIP (CMAQ) platform, REMSAD was used to simulate the annual average impact of each 

state’s SO2 emission sources on the sulfate fraction of PM2.5 over the northeastern United States using the same 

12-km eastern modeling domain as shown in Figure 16. Appendix F further describes the REMSAD model and its 

application to the Regional Haze SIP efforts. 
Page 43

CALGRID

In addition to the SIP-quality modeling platforms described above, an additional modeling platform was 

developed for use as a screening tool to evaluate additional control strategies or to perform sensitivity analyses. 

The CALGRID model was selected as the basis for this platform. CALGRID is a grid-based photochemical air 

quality model that is designed to be run in a Windows environment. In order to make the CALGRID model the 

best possible tool to supplement the SIP-quality CMAQ and REMSAD modeling, the current version of the 

CALGRID platform was set up to be run with the same set of inputs as the SIP-quality models. The CALGRID air 

quality simulations were run on the same 12-km eastern modeling domain that was used for CMAQ and 

REMSAD. This model’s performance was relative to the performance of the already evaluated CMAQ and 

REMSAD models and was thus determined to perform adequately.

Conversion utilities were developed to re-format the meteorological inputs, the boundary conditions, and the 

emissions for use with the CALGRID modeling platform. Pre-merged SMOKE emissions files were obtained from 

the modeling centers and re-formatted for input into EMSPROC6, the emissions pre-processor for the CALGRID 

modeling system. EMSPROC6 allows the CALGRID user to adjust emissions temporally, geographically, and by

emissions category for control strategy analysis. The pre-merged SMOKE files that were obtained from the 

modeling centers were broken down into the biogenic, point, area, non-road, and on-road emissions categories. 

These files by component were then converted for use with EMSPROC6, thus giving CALGRID users the flexibility 

to analyze a wide variety of emissions control strategies. Additional information on the CALGRID modeling 

platform can be found in Appendix L, NHDES’ Modeling Protocol for the OTC CALGRID Screening-Level Modeling 

Platform for the Evaluation of Ozone.

CALPUFF

CALPUFF is a non-steady-state Lagrangian puff model that simulates the dispersion, transport, and chemical 

transformation of atmospheric pollutants. Two parallel CALPUFF modeling platforms were developed by the 

Vermont Department of Environmental Conservation (VTDEC) and the Maryland Department of the 

Environment (MDE). The VTDEC CALPUFF modeling platform utilized meteorological observation data from the 

National Weather Service (NWS) to drive the CALMET meteorological model. The MDE platform utilized the 

same MM5 meteorological inputs that were used in the modeling done in support of the ozone and Regional 

Haze SIPs. These two platforms were run in parallel to evaluate individual states’ contributions to sulfate levels 

at Northeast and Mid-Atlantic Class I areas. The CALPUFF modeling effort is described in detail in Appendix A.
Page 44

6. EMISSIONS INVENTORY

Section 51.308(d)(4)(v) of the Regional Haze Rule requires a statewide emission inventory of pollutants that are 

reasonably anticipated to cause or contribute to visibility impairment in any mandatory Class I area. The 

inventory must include emissions for a baseline year, future (projected) year, and the most recent year for 

which data are available. Massachusetts’ baseline year is 2002. The pollutants inventoried by Massachusetts 

for 2002 include volatile organic compounds (VOCs), nitrogen oxides (NOx), carbon monoxide (CO), sulfur 

dioxide (SO2), fine particles (PM2.5), coarse particles (PM10), and ammonia (NH3). The emission inventory consists 

of the following source categories: stationary point, area, on-road mobile, off-road mobile, and biogenics. These 

source categories are discussed further below and in Section 7. 

6.2. Baseline and Future Year Emission Inventories for Modeling

Section 51.308(d)(3)(iii) of EPA’s Regional Haze Rule requires Massachusetts to identify the baseline emission 

inventory on which strategies are based. The baseline inventory is used to assess progress in making emissions 

reductions. Based on EPA guidance entitled, 2002 Base Year Emission Inventory SIP Planning: 8-hour Ozone, 

PM2.5, and Regional Haze Programs, which identifies 2002 as the anticipated baseline emission inventory year 

for regional haze, MANE-VU and Massachusetts used 2002 as the baseline year. Future year inventories were 

developed for the years 2009 and 2018 based on the 2002 base year. These future year emission inventories 

include emissions growth due to projected increases in economic activity, as well as the emissions reductions 

due to the implementation of control measures. In many instances, states already have submitted their 2002 

base year SIP inventories to EPA due to their planning obligations under the ozone and/or PM programs. 

Massachusetts submitted its 2002 inventory to EPA on January 31, 2008.

Emission inventories are not static documents, but are constantly revised and updated to reflect the input of 

better emission estimates as they become available. Therefore, even though the 2002 “SIP” inventories and the 

2002 “modeling” inventories both represent emissions from 2002, they may contain slightly different emission 

estimates due to the different time frames they were made available, and the different purposes each serves. 

Accurate baseline and future emissions inventories are crucial to the analyses required for the Regional Haze SIP

process. These emissions inventories were used to drive the air quality modeling simulations that were 

performed to assess the visibility improvement of potential control measures. Air quality modeling also was 

used to perform a pollution apportionment, which evaluates the contribution to visibility impairment by 

geographic region and by emission sector. In order to be used in the air quality modeling simulations, the 

baseline and future year emissions inventories were processed with SMOKE emissions pre-processor for 

subsequent input into CMAQ and REMSAD air quality models that were described in Section 5.
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MANE-VU Regional Baseline Inventory

The starting point for the 2002 baseline emissions inventory was the 2002 inventory submittals that were made 

to EPA by state and local agencies as part of the Consolidated Emissions Reporting Rule (CERR). With contractor 

assistance (E.H. Pechan & Associates), MANE-VU coordinated and quality assured the 2002 inventory data, and 

prepared it for input into the SMOKE emissions model. The 2002 emissions from non-MANE-VU areas within 

the modeling domain were obtained from other Regional Planning Organizations for their corresponding areas. 

These RPOs included VISTAS, MWRPO, and CenRAP.

The 2002 baseline inventory went through several iterations. Work on Version 1 of the 2002 MANE-VU 

inventory began in April 2004, and the final inventory and SMOKE input files were finalized during January 2005. 

Work on Version 2 (used from April through September 2005) involved incorporating revisions requested by 

some MANE-VU state/local agencies on the point, area, and on-road categories. Work on Version 3 (used from 

December 2005 through April 2006) included additional revisions to the point, area, and on-road categories as 

requested by some states. Thus, the Version 3 inventory for point, area, and on-road sources was built upon 

Versions 1 and 2. This work also included development of the biogenic inventory. In Version 3, the non-road 

inventory was completely redone because of changes that EPA made to the NONROAD2005 non-road mobile 

emissions model. 

Version 3 of the 2002 base year emissions inventory was used in the regional air quality modeling simulations. 

Further description of the data sources, methods, and results for this version of the 2002 baseline inventory is 

presented in a technical support document, Appendix M. Emissions inventory data files are available on the 

MARAMA website at www.marama.org/visibility/EI_Projects/index.html. 

After release of Version 3.0 of the MANE-VU 2002 inventory, Massachusetts revised its inventory of area source 

heating oil emissions due to two changes. First, the sulfur percent used to derive the emissions factors was 

adjusted from 1.0 to 0.3 because the Massachusetts draft 2002 SO2 emissions methodology for commercial and 

residential distillate fuel used the EPA default sulfur content of 1% instead of the correct 0.3% value that was 

implemented in 2001 according Massachusetts regulation 310 CMR 7.05(1) and (2). Second, the latest DOE-EIA 

2002 fuel use data was used instead of the previous version used in 2001. These two changes significantly 

altered the 2002 SO2 emissions for area source heating oil combustion. Massachusetts provided revised 2002 PE 

and EM tables, which MACTEC used in preparing the 2009/2012/2018 projection inventories. 

Massachusetts Baseline Inventory

Massachusetts submitted to EPA in January 2008 its comprehensive 2002 Base Year Emissions Inventory that

serves as a baseline for its 8-Hour Ozone, Carbon Monoxide (CO), and Regional Haze SIPS. The 2002 Inventory 

was estimated for a typical summer day for the ozone precursors VOC, NOx and CO. CO also was estimated for a 
Page 46

typical winter day for the CO SIP. Annual emissions were estimated for VOCs, NOx, CO, SO2, PM2.5, PM10, and 

NH3, as required as a baseline for this Regional Haze SIP. 

The complete MA 2002 Base Year Inventory is part of the Massachusetts 8-Hour Ozone Attainment Demonstration 

SIP and is available on MassDEP’s web site at: http://www.mass.gov/dep/air/priorities/sip.htm. It contains an 

extensive narrative explaining the methodology for the development of the inventory and the extensive data 

files supporting the emission estimates.

Massachusetts originally submitted emissions inventory data electronically to the EPA National Emissions 

Inventory (NEI) system and subsequently made revisions as a result of Quality Assurance (QA) procedures. The 

point source submittal included detailed facility level information, activity data down to the segment level, and 

annual VOCs, NOx, CO, SO2, PM2.5, PM10, and NH3 emissions. Massachusetts also electronically submitted area 

source activity data, emission factors, temporal factors, control factors, annual emissions for all pollutants, and 

typical summer day (VOC, NOx and CO) and winter day (CO only) emissions. Emissions data for point and area 

sources were submitted to EPA in its required NEI format.

For on-road and off-road mobile emissions, Massachusetts estimated typical summer and winter day emissions 

in the 2002 Base Year Inventory. However, for annual emissions Massachusetts relied on MANE-VU contractors 

to perform the twelve monthly model runs from EPA’S MOBILE6.2 for on-road emissions and the NONROAD 

model for off-road emissions. In order to estimate annual emissions from on-road mobile sources, 

Massachusetts submitted to the MANE-VU contractor the necessary MOBILE6.2 inputs such as monthly 

temperature and I/M scenarios together with other transportation parameters such as daily vehicle miles 

travelled, vehicle registration data, and speeds by county roadway class. Massachusetts also provided 

temperature and other inputs to MANE-VU contractors for running the NONROAD model in order to estimate 

annual emissions. The resulting on-road mobile and off-road mobile annual emissions generated by the MANEVU contractor were used in the 2002 Base Year Emissions Inventory.

EPA estimated 2002 Biogenic emissions for all counties in the US using its Biogenic Emissions Inventory System 

(BEIS-3) and Massachusetts used these summer day and annual emissions in the 2002 Base Year Emission 

Inventory for VOC, NOx, and CO.

The emissions data submitted to EPA-NEI was accessed, analyzed, and summarized by the MANE-VU contractors 

and modelers initially as part of the QA process and modeling for 8-hour Ozone and Regional Haze. 
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A summary of the Massachusetts 2002 Base Year Emission Inventory is presented in Table 8, which is contained 

in Section 6.5. The 2018 projected Massachusetts emissions in Table 8 were adapted from a MANE-VU summary 

based on growth and control factors from 2002. 

Future Year Emission Control Inventories 

A technical support document for the future year inventories is included in Appendix N and explains the data 

sources, methods, and results for future year emission forecasts for three years, five emission sectors, three

emission control scenarios, seven pollutants, and eleven states plus the District of Columbia. The following is a 

summary of the future year inventories that were developed:

 Projection years: 2009, 2012, and 2018;

 Emission source sectors: point-source electric generating units (EGUs), point-source non-electric 

generating units (non-EGUs), area sources, non-road mobile sources, and on-road mobile sources.

 Emission control scenarios:

- A combined on-the-books/on-the-way (OTB/OTW) control strategy accounting for emission control 

regulations already in place as of June 15, 2005, as well as some emission control regulations 

that were not yet finalized, but were expected to achieve additional emission reductions by 

2009; and

- A beyond-on-the-way (BOTW) scenario to account for controls from potential new regulations 

that may be necessary to meet attainment and other regional air quality goals, mainly for ozone.

- An updated scenario (sometimes referred to as “best and final”) to account for additional 

potentially reasonable control measures. For the MANE-VU region, these include: SO2

reductions at a set of 167 EGU stacks that were identified as contributing to visibility impairment 

at northeast Class I areas; implementation of a low-sulfur fuel strategy for non-EGU sources; and 

implementation of a BART strategy for BART-eligible sources not controlled under other 

programs.

(Note: Refer to Section 10, Long-Term Strategy, for detailed descriptions of specific control strategies, 

including the uncertainty inherent in OTB and BOTW strategies)

 Pollutants: ammonia, carbon monoxide (CO), oxides of nitrogen (NOX), sulfur dioxide (SO2), volatile 

organic compounds (VOCs), fine particulate matter (PM2.5, sum of filterable and condensable 

components), and coarse particulate matter (PM10, sum of filterable and condensable components).

 States: Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New 

York, Pennsylvania, Rhode Island, and Vermont, plus the District of Columbia (all members of the MANEVU region).
Page 48

6.3. Emission Processor Selection and Configuration

The SMOKE Processing System is principally an emissions processing system, as opposed to a true emissions 

inventory preparation system, in which emissions estimates are simulated from “first principles.” This means 

that, with the exception of mobile and biogenic sources, its purpose is to provide an efficient, modern tool for 

converting emissions inventory data into the formatted emissions files required for a photochemical air quality 

model. (SMOKE does generate emissions for on-road mobile and biogenic emissions, however, by driving the 

MOBILE6 and BEIS emissions models.)

Inside the MANE-VU region, the modeling inventories were processed by NYSDEC and NESCUAM using the 

SMOKE (Version 2.1) processor to provide inputs for the CMAQ model. A detailed description of all SMOKE 

input files such as area, mobile, fire, point and biogenic emissions files, and the SMOKE model configuration are 

provided in Appendix K.

6.4. Inventories for Specific Source Types

There are five emission source classifications in the emissions inventory:

 stationary point 

 stationary area

 non-road mobile

 on-road mobile

 biogenic 

Stationary point sources are large sources that emit greater than a specified tonnage per year. Stationary area 

sources are those whose emissions from individual sources are relatively small, but due to the large number of 

these sources the collective emissions could be significant (i.e., dry cleaners, service stations, agricultural 

sources, fire emissions, etc.). Non-road mobile sources are equipment that can move, but do not use the 

roadways (i.e., lawn mowers, construction equipment, railroad locomotives, aircraft, etc.) On-road mobile 

sources are automobiles, trucks, and motorcycles that use the roadway system. The emissions from these 

sources are estimated by vehicle type and road type. Biogenic sources are natural sources like trees, crops, 

grasses, and the natural decay of plants. For stationary point sources, emissions data is tracked at the facility 

level. For all other source types, emissions are summed on the county level. All emissions were prepared for 

modeling in accordance with EPA guidance.
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Stationary Point Sources

Point source emissions are emissions from large individual sources. Generally, point sources have permits to 

operate and their emissions are individually calculated based on source specific factors on a regular schedule. 

The largest point sources are inventoried annually. These are considered to be major sources having emissions 

of ≥ 50 to100 tons per year (tpy) of a criteria pollutant, ≥ 10 tpy of a single hazardous air pollutant (HAP) or ≥ 25 

tpy of total HAPs. Emissions from smaller stationary point sources in Massachusetts also are calculated 

individually, but less frequently, on a triennial basis. Point sources are grouped into EGU sources and other nonEGU industrial point sources.

6.5. Electric Generating Units

The base year inventory for EGU sources used 2002 continuous emissions monitoring (CEM) data reported to 

EPA in compliance with the Acid Rain program or 2002 hourly emission data provided by stakeholders. These 

data provide hourly emissions profiles that can be used in the modeling of SO2 and NOx emissions from these 

large sources. Emission profiles are used to estimate emissions of other pollutants (volatile organic compounds, 

carbon monoxide, ammonia, and fine particles) based on measured emissions of SO2 and NOx.

Future year inventories of EGU emissions for 2009 and 2018 were developed using the IPM model to forecast 

growth in electric demand and replacement of older, less efficient and more polluting power plants with newer, 

more efficient and cleaner units. While the output of the IPM model predicts that a certain number of older 

plants will be replaced by newer units to meet future electricity growth and state-by-state NOx and SO2 caps, 

Massachusetts did not directly rely upon the closure of any particular plant in establishing the 2018 inventory 

upon which the reasonable progress goals were set. 

The IPM model results are not the basis upon which to reliably predict plant closures. Preliminary modeling was 

thus performed with unchanged IPM 2.1.9 model results. However, prior to the Best and Final Modeling 

(Appendix G), future year EGU inventories were modified.

First, IPM predictions were reviewed by MANE-VU permitting and enforcement staff. In many cases, staff felt

that the IPM shutdown predictions were unlikely to occur. In particular, IPM predicted that many oil-fired EGUs 

in urban areas would be shutdown. Similar source information was solicited from states in both VISTAS and 

MRPO. As a result of this model validation, the IPM modeling output was adjusted before the Best and Final 

modeling (Appendix G) to reflect staff knowledge of specific plant status in MANE-VU, VISTAS, and MRPO states. 

Where EGU operating status was contrary to what was predicted by IPM modeling, the future year emissions 

inventory was adjusted to reflect the operation of those plants expected by state staff.
Page 50

Second, as a result of inter- and intra- RPO consultations, MANE-VU agreed to pursue certain control measures 

as described in the Long-Term Strategy section. For EGUs, the agreed upon approach was to reduce emissions 

from 167 stacks located in MANE-VU, MRPO and VISTAS by 90 percent, as described further in the Long-Term 

Strategy.

6.6. Non-EGU Point Sources

The primary basis for the 2002 baseline non-EGU emissions were those that were reported by state and local 

agencies for the CERR. As described above, MANE-VU’s contractor, E.H. Pechan & Associates (Pechan) 

coordinated the QA of the inventory and prepared the necessary files for input into the SMOKE emissions 

model. Further information on the preparation of the MANE-VU 2002 baseline point source modeling emissions 

inventory can be found in Chapter II of the Technical Support Document for 2002 MANE-VU SIP Modeling 

Inventories (Appendix M).

Projected non-EGU point source emissions were developed for the MANE-VU region by MACTEC Federal 

Programs, Inc. under contract to MARAMA. The specific methodologies that were used are described in 

Appendix N, Development of Emissions Projections For 2009, 2012, and 2018 For NonEGU Point, Area, and 

Nonroad Source In the MANE-VU Region. MACTEC used state-supplied growth factor data where available to 

project future year emissions. Where state-supplied data was not available, MACTEC used EPA’s Economic 

Growth and Analysis System Version 5.0 (EGAS 5.0) to develop applicable growth factors for the non-EGU 

component. MACTEC also incorporated the applicable federal and state emissions control programs to account 

for the expected emissions reductions that will take place under the OTB/OTW and BOTW scenarios.

Stationary Area Sources

Stationary area sources include sources whose individual emissions are relatively small but due to the large 

number of these sources, their collective emissions are significant. Some examples include dry cleaners, service 

stations, and the combustion of fuels for heating. Area source emissions are estimated by multiplying an 

emission factor by some known indicator of collective activity, such as fuel use, number of households, or 

population.

The area source emissions inventory submittals made for the CERR became the basis for the area source portion 

of the 2002 baseline inventory. Similar to the point source category, Pechan, on behalf of MANE-VU, prepared 

the area source modeling inventory using the CERR submittals as a starting point. Pechan quality assured the 

inventory and augmented it with additional data, including MANE-VU-sponsored inventories for categories such 

as residential wood combustion and open burning. Detailed information on the preparation of the MANE-VU 

2002 baseline area source modeling emissions inventory can be found in Chapter III of Appendix M.
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Similar to non-EGU point sources, future year area source emissions were projected for the MANE-VU region by 

MACTEC. The specific methodologies used are described in Section 3 of Appendix 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 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 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 
Page 52

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 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.

6.7. Summary of MANE-VU 2002 and 2018 Emissions Inventory

Table 6 and Table 7 summarize the emissions inventories for the MANE-VU region compiled for 2002 and 

projected for 2018.7The 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 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

NonRoad 

Mobile

572,751 431,631 4,553,124 36,084 40,114 287 57,257

 

7

Tables 6-8 are based upon the 2002 MANE-VU Regional Baseline Inventory, version 3. See Appendix M for details.
Page 53

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 M
Page 54

Table 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 N

EGU Point Emissions: VISTAS_PC_1f IPM Run, Appendix W 

6.8. Summary of Massachusetts 2002 Base and 2018 Projected Emissions and Reductions 

Table 8 presents the Massachusetts inventories for the 2002 base year8and for the 2018 projected emissions 

and expected reductions. The MANE-VU 2002 and 2018 emission summary and reductions, derived from Table 

6 and Table 7, also are presented for comparison. 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 8: Massachusetts 2002 Base Year and 2018 Projected Emissions and Reductions (in tons)

VOC NOx CO SO2 PM10 PM2.5 NH3 RH TOTAL9

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 

 

 1,039,100 

 

 3,408 2,410 

 

 

8 Massachusetts 2002 Baseline Emission Inventory. Available online: http://www.mass.gov/dep/air/priorities/aqdata.htm

9

Excludes CO, which is not a regional haze pollutant.
Page 55

143,368 4,399 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
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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/FutureEmissionsInventory.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/ 
Page 57

 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/FutureEmissionsInventory.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 %.
Page 58

7.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.

7.2. 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 A), finalized in August 

2006, reflects a conceptual model in which sulfate emerges as the most important single constituent of hazeforming 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). Figure 18 shows the dominance of sulfate (bottom yellow bar) in visibility 

extinction calculated from 2000-2004 baseline data.

Figure 18: Contributions to PM2.5 Extinction at Seven Class I Sites
Page 59

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). 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 9: Percent of Annual Average Modeled Sulfate Due to Emissions from Listed States10

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

 

10 Percentages based on 2002 annual average sulfate impact estimated with REMSAD model as described in MANE-VU 

Contribution Assessment Chapter 4 and summarized on page 8-2 of the Contribution Assessment (Appendix A).
Page 60

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 19: Ranked state percent sulfate contributions to Northeast Class I receptors based on emissions 

divided by distance (Q/d) results
Page 61

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

CanadaPAOHINNYMIW

V

ILG

A

M

A

KYNCV

A

MDALTNTXM

O

FLWINJMESCNHDEKSMNIACTOKMSLANEVTA

R

RIDC

Annual A

verage C

ontribution (g/m3 S

O

4)

Acadia

Great Gulf

Lye Brook

Moosehorn

MA
Page 62

Figure 20: Ranked state percent sulfate contributions to Mid-Atlantic Class I receptors based on emissions 

divided by distance (Q/d) results

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

OHPAW

V

NCCanadaM

D

INV

A

K

Y

G

A

NYILTNMIALNJTXFLDESCM

O

WIM

A

MSKSMNO

K

IALACTNHA

R

NEMED

C

RIVT

A

n

n

u

al A

v

era

g

e

C

o

ntrib

utio

n (μ

g/m

3

S

O

4)

Brigantine

Dolly Sods

Shenandoah

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:

1. Any state/region that contributed 0.1 g/m3sulfate or greater on the 20 percent worst visibility days in 

the base year (2002)

2. Any state/region that contributed at least 2 percent of total sulfate observed on the 20 percent worst 

visibility days in 2002

3. 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.

MA
Page 63

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.
Page 64

Figure 21, Figure 26, and Figure 27, respectively, illustrate that emissions from Massachusetts do not contribute 

greater than 0.1 g/m3sulfate or 2% of sulfate to the Brigantine, Shenandoah, and Dolly Sods Class I areas.
Page 65

Figure 21: Modeled 2002 Contributions to Sulfate by State at Brigantine

Brigantine

20% Worst Days

0

5

10

15

20

25

Brigantine

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Brigantine

CA NA DA

CENRAP

SE_BC

W_BC

N_BC

V T

RI

ME

DC

MS

CT

NH

MA

WI

NY

A L

IL

SC

MI

KY

TN

IN

NJ

DE

GA

WV

MD

V A

NC

OH

PA

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

g/m3

#

#

#
Page 66

Figure 22: Modeled 2002 Contributions to Sulfate by State at Lye Brook

Lye Brook 

20% Worst Days

0

2

4

6

8

10

12

14

16

Lye Brook

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Lye Brook

CANADA

CENRAP

SE_BC

W_BC

N_BC

DC

RI

MS

ME

CT

V T

NH

WI

DE

SC

A L

NJ

IL

MA

TN

GA

MI

KY

V A

IN

NC

MD

WV

NY

OH

PA

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

g/m3

#

#

#

Figure 23: Modeled 2002 Contributions to Sulfate by State at Great Gulf and Presidential Range/Dry River 

Wilderness

Great Gulf 

20% Worst Days

0

2

4

6

8

10

12

Great Gulf

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Great Gulf

CANADA

CENRAP

SE_BC

W_BC

N_BC

DC

MS

V T

RI

ME

CT

DE

A L

NJ

WI

SC

TN

V A

IL

MD

GA

NH

KY

NC

MI

WV

IN

MA

NY

PA

OH IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

g/m3

#

#

#
Page 67

Figure 24: Modeled 2002 Contributions to Sulfate by State at Acadia

Acadia 

20% Worst Days

0

2

4

6

8

10

12

Acadia

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Acadia

CA NA DA

CENRAP

SE_BC

W_BC

N_BC

DC

MS

VT

RI

AL

DE

WI

CT

TN

GA

SC

NJ

VA

IL

KY

MD

MI

NC

NH

IN

WV

ME

NY

PA

OH

MA

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

g/m3

#

#

#

Figure 25: Modeled 2002 Contributions to Sulfate by State at Moosehorn and Roosevelt Campobello 

International Park

Moosehorn 

20% Worst Days

0

2

4

6

8

10

12

Moosehorn

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Moosehorn

CA NA DA

CENRAP

SE_BC

W_BC

N_BC

MS

DC

VT

RI

AL

CT

WI

DE

SC

TN

GA

NJ

VA

MI

IL

KY

NH

MD

NC

IN

WV

ME

NY

OH

PA

MA

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

g/m3

#

#

#
Page 68

Figure 26: Modeled 2002 Contributions to Sulfate by State at Shenandoah

Shenandoah 

20% Worst Days

0

2

4

6

8

10

12

14

16

18

20

Shenandoah

Sulfate Nitrate EC OC Sea Salt Soil

IMPROVE mass 00-04

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Shenandoah

CANADA

CENRAP

SE_BC

W_BC

N_BC

VT

RI

ME

DC

MS

NH

CT

MA

NJ

DE

SC

WI

AL

TN

IL

GA

NY

NC

MI

MD

VA

KY

IN

WV

PA

OH Threshold options

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

REMSAD 2002 Contribution to Sulfate

#

#

#

g/m3

Figure 27: Modeled 2002 Contributions to Sulfate by State at Dolly Sods
Page 69

Dolly Sods 

20% Worst Days

0

2

4

6

8

10

12

14

16

18

20

Dolly Sods

Sulfate Nitrate EC OC Sea Salt Soil

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

Dolly Sods

CANA DA

CENRAP

SE_BC

W_BC

N_BC

RI

V T

ME

DC

CT

NH

MA

MS

DE

NJ

WI

NY

MD

SC

MI

IL

V A

A L

TN

NC

GA

IN

KY

PA

WV

OH

0.1 μg/m3 Sulfate

2 % of Sulfate

Top 10 States

IMPROVE mass 00-04 REMSAD 2002 Contribution to Sulfate Threshold options

#

#

#

g/m3

7.3. 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)11. Trends among the three emissions 

 

11 EPA's Emission Factor and Inventory Group (EFIG) / Office of Air and Radiation (OAR) / Office of Air Quality Planning and 

Standards (OAQPS) / Emissions, Monitoring and Analysis Division (EMAD) prepares a national database of air emissions 

information with input from numerous state and local air agencies, from tribes, and from industry. This database contains 

information on stationary and mobile sources that emit criteria air pollutants and their precursors, as well as hazardous air 

pollutants (HAPs). The database includes estimates of annual emissions, by source, of air pollutants in each area of the 

country on an annual basis. The NEI includes emission estimates for all 50 states, the District of Columbia, Puerto Rico, and 

the Virgin Islands. Emission estimates for individual point or major sources (facilities), as well as county-level estimates for 

area, mobile, and other sources, are available currently for years 1985 through 2005 for criteria pollutants, and for years 

1996 and 2005 for HAPs. Data from the NEI help support air dispersion modeling, regional strategy development, setting 
Page 70

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 P).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 inventory12. 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 28: Trends in Annual Sulfur Dioxide Emissions by State

 

regulations, air toxics risk assessment, and tracking trends in emissions over time. For emission inventories prior to 1999, 

the National Emission Trends (NET) database maintained criteria pollutant emission estimates, and the National Toxics 

Inventory (NTI) database maintained HAP emission estimates. Beginning with 1999, the NEI began preparing criteria and 

HAP emissions data in a more integrated fashion to take the place of the NET and the NTI.

12 EPA (2005) http://www.epa.gov/ttn/chief/eiinformation.html and MARAMA (2004) 

http://www.marama.org/visibility/2002%20NEI/index.html 
Page 71

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

NEI 1996

NEI 1999 V3

MANE-VU 2002 V3

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 P).
Page 72

Figure 29: 2002 Sulfur Dioxide Emissions (SO2) by State

0%

25%

50%

75%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

0.0

0.2

0.4

0.6

0.8

1.0

1.2

million t/y

AREA NONROAD ONROAD POINT Emission

Bar Graph: Percentage Fractions of the Four Source Categories

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

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 particlerelated 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. 
Page 73

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 
Page 74

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 particles13. 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 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.

 

13 Odum, J.R., Jungkamp, T.P.W., Griffin, R.J., Flagan, R.C., and Seinfeld, J.H. (1997) “The Atmospheric Aerosol-forming 

Potential of Whole Gasoline Vapor.” 276: 96-99.
Page 75

Figure 30: 2002 Volatile Organic Carbon (VOC) Emissions by State

0%

25%

50%

75%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

AREA NONROAD ONROAD POINT Emission

Bar Graph: Percentage Fractions of the Four Source Categories

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

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 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 

199814. 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 

 

14 EPA. (2000) National Air Quality and Emission Trends Report, 1998, EPA 454/R-00-003, available online: 

http://www.epa.gov/oar/aqtrnd98/.
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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 31: Trends in Annual Nitrogen Oxide (NOx) Emissions by State

0.0

0.5

1.0

1.5

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

NEI 1996

NEI 1999 V3

MANE-VU 2002 V3

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 hazerelated pollutants, including primary fine particle and ammonia emissions, further efforts could improve current 

inventories in a number of areas (Appendix P). 
Page 77
Page 78

Figure 32: 2002 Nitrogen Oxide (NOx) Emissions by State

0%

25%

50%

75%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

0.0

0.3

0.6

0.9

AREA NONROAD ONROAD POINT Emission

Bar Graph: Percentage Fractions of the Four Source Categories

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

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.
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Figure 33: Trends in Primary Coarse Particle (PM10) Emissions by State

0.0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

NEI 1996

NEI 1999 V3

MANE-VU 2002 V3

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

0.0

0.1

0.2

0.3

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

NEI 1996

NEI 1999 V3

MANE-VU 2002 V3
Page 80

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 bestvisibility 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 
Page 81

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. 
Page 82

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 greenhighlighted 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 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.
Page 83

Figure 35: Wood Smoke Source Regional Aggregations

NE: ACAD, PMRC, LYBR

MA: WASH, SHEN, JARI

SE: GRSM, MACA
Page 84

Figure 36 and 
Page 85

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. 
Page 86

Figure 36: 2002 Primary PM10Emissions by State

0%

20%

40%

60%

80%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

0.0

0.1

0.2

0.3

0.4

0.5

AREA NONROAD ONROAD POINT Emission

Bar Graph: Percentage Fractions of the Four Source Categories

 (-o-) Line Graph: Total State Annual Emissions (106tpy)
Page 87

Figure 37: 2002 Primary PM2.5 Emissions by State

0%

25%

50%

75%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

0.00

0.05

0.10

0.15

0.20

AREA NONROAD ONROAD POINT Emission

 Bar Graph: Percentage Fractions of the Four Source Categories

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

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 atmosphere15. 

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 

 

15 EPA 454/R-00-002. (2000) National Air Pollutant Trends, 1900 – 1998. Available online: 

http://www.epa.gov/ttn/chief/trends/trends98/trends98.pdf.
Page 88

can result. Ansari and Pandis16 showed that a 1 g/m3reduction 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.17

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.18 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 formats19

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.

20 1999 emissions were generated using an EPA model, whereas the 2002 

 

16Ansari, A. S., and Pandis, S.N. (1998) “Response of inorganic PM to precursor concentrations,” Environ Sci Technol, 32: 

2706-2714.

17 SO2 reacts in the atmosphere to form sulfuric acid (H2SO4). Ammonia can partially or fully neutralize this strong acid to 

form ammonium bisulfate or ammonium sulfate. If planners focus future control strategies on ammonia and do not 

achieve corresponding SO2 reductions, fine particles formed in the atmosphere will be substantially more acidic than those 

presently observed.

18 Davidson, C., Strader, R., Pandis, S., and Robinson, A. Preliminary Proposal to MARAMA and NESCAUM: Development of 

an Ammonia Emissions Inventory for the Mid-Atlantic States and New England. Carnegie Mellon University, Pittsburgh, PA. 

January, 1999.

19 For example, the user will have the flexibility to choose the temporal resolution of the output emissions data or to 

spatially attribute emissions based on land-use data.

20 The NEI 1999 V.3 NH3 emissions were developed by EPA for a limited amount of livestock. 

(ftp://ftp.epa.gov/EmisInventory/finalnei99ver3/criteria/documentation/area/area_99nei_finalv3_0204.pdf) 

In contrast, the MANE-VU 2002 V.3 NH3 emissions were developed by the Carnegie Mellon University (CMU) Ammonia 

Model that is more comprehensive than EPA's 1999 method.
Page 89

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 38: Trends in Ammonia Emissions by State

0.00

0.05

0.10

0.15

0.20

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

NEI 1996

NEI 1999 V3

MANE-VU 2002 V3

Figure 39: 2002 NH3 Emissions by State
Page 90

0%

25%

50%

75%

100%

Connecticut

Delaware

District of Columbia

Maine

Maryland

Massachusetts

New Hampshire

New Jersey

New York

Pennsylvania

Rhode Island

Vermont

million t/y

0.00

0.06

0.12

AREA NONROAD ONROAD POINT Emission

Bar Graph: Percentage Fractions of the Four Source Categories

(-o-) Line Graph: Total State Annual Emissions (106tpy)
Page 91

8.BEST AVAILABLE RETROFIT TECHNOLOGY

In the Regional Haze Rule, EPA included provisions designed specifically to reduce emissions of visibilityimpairing 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.21 To be considered BARTeligible, 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.22 Visibilityimpairing 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.

8.2. 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,

 

21 A full list of the 26 source categories can be found in 40 CFR Part 51 Appendix Y: Guidelines for BART Determinations 

Under the Regional Haze Rule.

22 “Source” can refer to an emission unit or to a facility and is used in the Clean Air Act and in EPA’s Guidance on Regional 

Haze.
Page 92

 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.23 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.24

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.

8.3. 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. 

 

23 40 CFR Part 51 Appendix Y: Guidelines for BART Determinations Under the Regional Haze Rule.

24 On August 8, 2011, EPA promulgated the Cross-State Air Pollution Rule (CSAPR) to replace CAIR.
Page 93

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.
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Table 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

8.4. 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 
Page 95

that all BART-eligible sources are subject to BART. As such, no BART exemptions will be given, meaning all BARTeligible sources are included in the BART review process.

8.5. Pollutants Covered by BART

As allowed under BART, Massachusetts has determined that SO2, NOx and PM are the contributing visibilityimpairing 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.

8.6. Modeling of BART Visibility Impacts

MANE-VU conducted modeling analyses of BART-eligible sources using CALPUFF in order to provide a regionallyconsistent 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.25 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 

 

25 Emissions information was gathered from the MANE-VU 2002 Version 2 (Base A) emissions inventory. Since then, the 

MANE-VU 2002 Version 3 (Base B) emissions inventory has been developed which includes several changes made by the 

OTC modeling committee.
Page 96

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.26

8.7. Visibility Impacts of Massachusetts BART-Eligible Sources

The results of CALPUFF modeling using MM5 and NWS meteorological platforms for Massachusetts BARTeligible 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.

 

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

controls, the entire MANE-VU population of these units was modeled together to examine their cumulative impacts at each 

Class I site. The results of this modeling demonstrated that the maximum 24-hour impact at any Class I area of all modeled 

sources with individual impacts below 0.1 dv was only a 0.35 dv change relative to the estimated best days natural 

conditions at Acadia National Park. This value is well below the 0.5 dv impact recommended by EPA for exemption 

modeling and used by most other RPOs.
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Table 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 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
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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

8.8. 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 “cappingout” 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 
Page 99

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. 
Page 100

Table 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 7.32.27 

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). 

 

27 MassDEP is developing a replacement to MassCAIR that will continue to limit ozone season NOx emissions when 

MassCAIR is replaced by EPA’s Cross-State Air Pollution Rule.
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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.
Page 102

Table 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

8.9. 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
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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

28

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.29 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 NOxlimits 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 NonCatalytic 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, 

 

28 No data was reported for PM emissions.

29 EPA recalculated and changed the emissions limits for some of the pollutants in the Emissions Guidelines in a direct final 

rule in 1997.
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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 NOxlimit 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 
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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.

8.10. 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.
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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:

1. 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. 

2. The retirement of Somerset Power.

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

NOx emissions. 

4. 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.

5. 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 oilfired, while Brayton Point Units 1, 2, and 3 are primarily coal-fired.
Page 107

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 15: MANE-VU BART Workgroup Recommended BART Emission Limits for SO2 and NOx for nonCAIR 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
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MassDEP’s Alternative to BART for SO2 relies on:

1. 310 CMR 7.29, Emissions Standards for Power Plants, which establishes SO2 emissions standards for 

certain EGUs.

2. 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. 

3. 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.

4. The retirement of Somerset Power in 2010.

5. 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 
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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 230 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 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

 

30 Salem Harbor Units 1 and 2 were removed from service as of December 31, 2011, which means that these units can no 

longer generate electricity for the power grid. These units are not restricted from operating for other purposes; therefore, 

MassDEP established permit restrictions in order for emission reductions at these units to be counted in the Alternative to 

BART.
Page 110

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 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
Page 111

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:

1. 310 CMR 7.29, Emissions Standards for Power Plants, which establishes NOx emissions rates for certain 

EGUs.

2. 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.
Page 112

3. The retirement of Somerset Power in 2010.

4. 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 gasfired 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 
Page 113

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 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.
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Table 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
Page 115

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.

8.11. 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 areas31, 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; 32 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 20: Massachusetts PM10 BART Sources, Emissions and Controls

I.D. Source Unit

PM10

ddv33

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

 

31 For further discussion of CALPUFF modeling, see Sections 8.6 and 8.7 of the Regional Haze SIP. 

32 As described in Appendix R (Five-Factor Analysis of BART-Eligible Sources) and Appendix U (Assessment of Control 

Technology Options for BART-Eligible Sources). 

33 Values for MM5 and NWS meteorological modeling platforms; see Tables 12 and 13.
Page 116

1200061 Brayton Point 4

0.000, 

0.000 6 0ESP

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

8.12. 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 MANEVU states.
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9.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 
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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 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.34

 

34 “Baseline and Natural Visibility Conditions, Considerations and Proposed Approach to the Calculation of Baseline and

Natural Visibility Conditions at MANE-VU Class I Areas,” NESCAUM, December 2006.
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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 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 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

 
Page 120
Page 121

10. 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.

10.2. 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 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
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 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 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 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 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.
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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 coalfired 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.

10.3. 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 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 E)

 MANE-VU Modeling for Reasonable Progress Goals: Model Performance Evaluation, Pollution 

Apportionment, and Control Measure Benefits (Appendix F)

 2018 Visibility Projections (Appendix G)

 Five-Factor Analysis of BART-Eligible Sources: Survey of Options for Conducting BART Determinations

(Appendix R) 
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 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)

 Assessment of Control Technology Options for BART-Eligible Sources: Steam Electric Boilers, 

Industrial Boilers, Cement Plants and Paper and Pulp Facilities (Appendix 0)

 The Nature of the Fine Particle and Regional Haze Air Quality Problems in the MANE-VU Region: A 

Conceptual Description (Appendix 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.
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10.4. 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 MANEVU 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 F)

 2018 Visibility Projections (Appendix G)

 Development of Emissions Projections for 2009, 2012, and 2018 for Non-EGU Point, Area, and Nonroad Sources in the MANE-VU Region (Appendix N)

 Documentation of 2018 Emissions from Electric Generating Units in the Eastern U.S. for MANE-VU’s 

Regional Haze Modeling (Appendix 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: 
Page 126

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.35 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 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)

 

35 Although the IPM® model runs also anticipated the implementation of EPA’s Clean Air Mercury Rule (CAMR), that rule has 

since been vacated by the courts. However, it is anticipated the adjustments to the predicted SO2 emissions from EGUs 

used in the air quality modeling, which were based on state-specific comments on the amount of SO2 controls that will 

actually be installed due to state-specific regulations and EPA’s CAIR rule, will have more of an impact on the air quality 

modeling analysis conducted for this SIP than the vacatur of the CAMR rule. MANE-VU believes the adjustments based on 

state-specific comments improved the reliability of the inventory and made the modeling results more dependable.
Page 127

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

1. Reg. 1144, Control of Stationary Generator Emissions, SO2, PM, VOC and NOx emission control, 

Statewide, Effective January 2006.

2. 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.

3. 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 fuelfired 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).
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 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:

1. 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)

2. 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:

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

2. 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.
Page 129

3. 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.

4. 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 
Page 130

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 MACT36

 EPA’s Refinery Enforcement Initiative

 

36 The inventory was prepared before the MACT for Industrial Boilers and Process Heaters was vacated. Control efficiency 

was assumed to be at 4 percent for SO2 and 40 percent for PM.
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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);
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 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/bhphr, 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.
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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, MANEVU’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 
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 VOC measure: adhesives and sealants application (all MANE-VU states except NJ37 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) 

10.5. 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 Virginia38.

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 

 

37 Note that New Jersey indicated that the reductions from the adhesives and sealants application control measure should 

only apply to area sources—no reductions for point sources (SCC 4-02-0007-xx) were included due to inventory double 

counting issues, not due to rule change issues. 

38 In addition, the State of Vermont identified at least one source in the State of Wisconsin as a significant contributor to 

visibility impairment at the Lye Brook Wilderness Class I Area.
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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 setting the 

reasonable progress goals. These factors are sometimes termed the “four statutory factors,” since their 

consideration is required by the Clean Air Act.

Focus on SO2: MANE-VU conducted a Contribution Assessment (Appendix A) and developed a conceptual 

model that indicated particulate sulfate formed from emissions of SO2 was the dominant contributor to visibility 

impairment at all sites and during all seasons in the base year. While other pollutants, including organic carbon 

and NOx, will need to be addressed in order to achieve the national visibility goals, MANE-VU’s contribution 

assessment suggested that an early emphasis on SO2 will yield the greatest near-term benefit. Therefore, it is 

reasonable to conclude that the additional measures considered in establishing reasonable progress goals 

require reductions in SO2 emissions. 

Contributing Sources: The MANE-VU Contribution Assessment indicates that emissions in 2002 from within the 

MANE-VU region were responsible for about 25 to 30 percent of the sulfate at MANE-VU Class I areas. Sources 

in the Midwest and Southeast regions were responsible for about 15 to 25 percent each, respectively. Point 

sources dominated the inventory of SO2 emissions. Therefore, the MANE-VU’s long-term strategy includes 

additional measures to control sources of SO2 both within the MANE-VU region and in other states that were 

determined to contribute to regional haze at MANE-VU Class I areas. 

The Contribution Assessment documented the source categories most responsible for visibility degradation at 

MANE-VU Class I areas. As described earlier, there was a collaborative effort between the Ozone Transport 

Commission and MANE-VU to evaluate a large number of potential control measures. Several measures that 

would reduce SO2 emissions were identified for further study. 

These efforts led MANE-VU to prepare the report entitled, “Assessment of Reasonable Progress for Regional 

Haze in MANE-VU Class I Areas” MACTEC, July 9, 2007 otherwise known as the Reasonable Progress Report 

(Appendix T), which documented an analysis of the four statutory factors for five major source categories. Table 
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24 summarizes the results of MANE-VU’s Reasonable Progress Report, which considered EGUs, ICI boilers, 

cement kilns, heating oil and residential wood combustion.

The MANE-VU states reviewed the four-factor analysis presented in the Reasonable Progress Report, consulted 

with each other about the measures, and concluded by adopting the statements known as the MANE-VU “Ask”

on June 20, 2007. These statements identify the control measures that would be pursued toward improving 

visibility in the region and that were included in the modeling used to establish reasonable progress goals.
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Table 24: Summary of Results from the Four-Factor Analysis

Source 

Category

Primary 

Regional 

Haze 

Pollutant Control Measure(s)

Average Cost in 

2006 dollars (per 

ton of pollutant 

reduction)

Compliance 

Timeframe

Energy and Non-Air 

Quality 

Environmental 

Impacts

Remaining 

Useful Life

Electric 

Generating 

Units 

SO2 Switch to a low sulfur coal 

(generally <1% sulfur), 

switch to natural gas 

(virtually 0% sulfur), coal 

cleaning, 

Flue Gas Desulfurization 

(FGD): Wet, Spray Dry, or

Dry.

IPM®* v.2.1.9 

predicts $775-

$1,690. $170-

$5,700 based on 

available 

literature

*Integrated Planning 

Model®

2-3 years 

following SIP 

submittal

Fuel supply issues, 

potential permitting 

issues, reduction in 

electricity production 

capacity, wastewater 

issues

50 years or 

more

Industrial, 

Commercial, 

Institutional 

Boilers

SO2 Switch to a low sulfur coal 

(generally <1% sulfur), 

switch to natural gas 

(virtually 0% sulfur), switch 

to a lower sulfur oil, coal 

cleaning, combustion 

control, Flue Gas 

Desulfurization (FGD): Wet, 

Spray Dry, or Dry.

$130-$11,000 

based on 

available 

literature. 

Depends on size.

2-3 years 

following SIP 

submittal

Fuel supply issues, 

potential permitting 

issues, control device 

energy requirements, 

wastewater issues

10-30 

years

Cement and 

Lime Kilns

SO2 Fuel switching, Dry Flue 

Gas Desulfurization: Spray 

Dryer Absorption (FGD), 

Wet Flue Gas 

Desulfurization (FGD), 

Advanced Flue Gas 

Desulfurization (FGD).

$1,900-$73,000 

based on 

available 

literature. 

Depends on size.

2-3 years 

following SIP 

submittal

Control device energy 

requirements, 

wastewater issues

10-30 

years

Heating Oil SO2 Lower the sulfur content in 

the fuel. Depends on the 

state.

$550-$750 based 

on available 

literature. There 

is a high 

uncertainty 

associated with 

this cost estimate.

Currently 

feasible. 

Capacity issues 

may influence 

timeframe for 

implementation 

of new fuel 

standards

Increases in 

furnace/boiler 

efficiency, decreased 

furnace/boiler 

maintenance 

requirements

18-25 

years

Residential 

Wood 

PM State implementation of 

NSPS, ban on resale of 

$0-$10,000 based 

on available 

Several years -

dependent on 

Reduce greenhouse 

gas emissions, 

10-15 

years
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Combustion uncertified devices, 

installer training 

certification or inspection 

program, pellet stoves, EPA 

Phase II certified RWC 

devices, retrofit 

requirement, accelerated 

changeover requirement, 

accelerated changeover 

inducement.

literature mechanism for 

emission 

reduction 

increase efficiency of 

combustion device

MANE-VU Statement of June 20, 2007

The reasonable progress goals adopted by the MANE-VU Class I states represent implementation of the regional 

course of action set forth by MANE-VU on June 20, 2007 entitled “Statement of the Mid-Atlantic/Northeast 

Visibility union (MANE-VU) Concerning a Course of Action within MANE-VU toward Assuring Reasonable 

Progress.” As such, these reasonable progress goals are intended to reflect the pursuit by MANE-VU states of a 

course of action including pursuing the adoption and implementation of the following “emission management” 

strategies, as appropriate and necessary:

a Timely implementation of BART requirements; and

b A low sulfur fuel oil strategy in the inner zone states (New Jersey, New York, Delaware, and 

Pennsylvania, or portions thereof) to reduce the sulfur content of: 

o Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 2012,

o #4 residual oil to 0.25 percent sulfur by weight by no later than 2012,

o #6 residual oil to 0.3 – 0.5 percent sulfur by weight by no later than 2012, and

o Further reduce the sulfur content of distillate oil to 15 ppm by 2016; and

c A low sulfur fuel oil strategy in the outer zone states (the remainder of the MANE-VU region) to 

reduce the sulfur content of: 

o Distillate oil to 0.05 percent sulfur by weight (500 ppm) by no later than 2014,

o #4 residual oil to 0.25 percent-0.50 percent sulfur by weight by no later than 2018,
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o #6 residual oil to no greater than 0.5 percent sulfur by weight by no later than 2018, and

o Further reduce the sulfur content of distillate oil to 15 ppm by 2018 depending on supply and 

availability; and

d A 90 percent or greater reduction in SO2 emissions from each of the 167 EGU stacks identified by 

MANE-VU as reasonably anticipated to cause or contribute to impairment of visibility in each 

mandatory Class I Federal area in the MANE-VU region. If it is infeasible to achieve that level of 

reduction from a unit, alternative measures will be pursued in such State; and

e Continued evaluation of other control measures including energy efficiency, alternative clean fuels, 

and other measures to reduce SO2 and NOx emissions from all coal-burning facilities by 2018 and 

new source performance standards for wood combustion. 

This long-term strategy to reduce and prevent regional haze will lead each state to pursue adoption and 

implementation of reasonable and cost-effective NOx and SO2 control measures as appropriate and necessary. 

While some measures that states pursue may not represent enforceable commitments immediately, they may 

become enforceable in the future as new laws are passed, rules are written, and facility permits are issued. 

Massachusetts will provide an update on the implementation of the strategies listed in the “Ask” in the 2013 

mid-term review.

This suite of additional control measures are those that the MANE-VU states have agreed to pursue for the 

purpose of mitigating regional haze. The corollary is that the MANE-VU Class I states (Maine, New Hampshire, 

Vermont, and New Jersey) asked states outside of the MANE-VU region that contribute to visibility impairment 

inside the region to pursue similar measures. The control measures that non-MANE-VU states choose to pursue 

may be directed toward the same emission source sectors identified by MANE-VU for its own emission 

reductions, or they may be equivalent measures targeting other source sectors. 

Best Available Retrofit Technology

Implementation of the BART provisions of the Regional Haze Rule [40 CFR 51.308(e)] is one of the reasonable 

strategies included in this SIP. BART controls in Massachusetts are described in Section 8 of this SIP. 

Additional emission reductions will occur at many other BART-eligible facilities within MANE-VU as a result of 

controls achieved by other programs that serve as BART but are not specifically identified as such (e.g., RACT 
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control measures). While not specifically identified as being attributable to BART, these additional emission 

reductions were fully accounted for in the 2018 CMAQ modeling.

Additional visibility benefits are likely to result from installation of new emission controls at BART-eligible 

facilities located in neighboring RPOs. However, the MANE-VU modeling

did not account for BART controls in other RPOs and, consequently, did not include visibility

improvements at MANE-VU Class I Areas that would be likely to accrue from such measures.

Low-Sulfur Fuel Oil Strategy

The important assumption underlying MANE-VU’s low-sulfur fuel oil strategy is based on the production and use 

of home heating and fuel oils that contain 50% less sulfur for the heavier grades (#4 and #6 residual), and a 

minimum of 75% and a maximum of 99.25% less sulfur in #2 fuel oil (also known as home heating oil, distillate, 

or diesel fuel) at an acceptably small increase in price to the end user. As much as three-fourths of the total 

sulfur reductions achieved by this strategy come from using the low-sulfur #2 distillate for space heating in the 

residential and commercial sectors. The costs of these emission reductions are estimated at $550 to $750 per 

ton, as documented in the MANE-VU Reasonable Progress Report. In some seasons and some locations, lowsulfur diesel is actually cheaper than regular diesel fuel. NESCAUM’s report, “Low Sulfur Heating Oil in the 

Northeast States: An Overview of Benefits, Costs, and Implementation Issues,” December 2005 (Appendix Y)

notes that the incremental cost of low-sulfur (500 ppm) highway diesel fuel has averaged 1.5 cents per gallon 

more than the cost of heating oil over the past decade. However, any increased cost would be more than offset 

by the avoided maintenance costs resulting from the reduced rate of equipment fouling when using low-sulfur 

oil. 

A recent study developed for the National Oilheat Research Alliance (NORA)39 uses data from the U.S. Energy 

Information Administration to evaluate the potential for suppliers to bring 15 ppm sulfur content heating oil into 

widespread use in the Northeast by 2018. While the study acknowledges that additional refining capacity is 

needed to meet the increased demand in 2018 and beyond, it concludes that, given appropriate advance notice, 

the refining industry can supply the necessary fuels with minimal market disruptions and price impacts. In the 

short-term, excess production capacity of ultra-low sulfur diesel (ULSD) exists in the region. In the longer term, 

the transition to ULSD in the transportation sector, combined with clear signals from regulatory agencies that 

similar requirements will be widespread for heating oil in the coming years, will support a move toward greater 

availability of 15 ppm sulfur content heating oil. 

 

39 Ultra-low Sulfur Diesel Fuel/Heating Oil Market Study, Kevin J. Lindemer, LLC, prepared for the National Oilheat Research 

Alliance, April 2010 ( http://www.nora-oilheat.org/site20/uploads/lowsstudy.pdf).
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The study projects a wholesale price differential between ULSD and higher sulfur heating oil of 1-3 cents per 

gallon, suggesting that the incremental cost of providing 15 ppm sulfur content heating oil will not be significant 

compared to normal price fluctuations. The study also notes that the incremental cost to consumers will be 

more than offset by cost savings associated with lower maintenance costs and higher fuel efficiency. For 

example, a typical consumer who uses 800 gallons of fuel per year would spend an additional $24 per year if 

per-gallon fuel costs increased by $0.03. However, the same consumer could expect to save approximately $50 

per year in avoided maintenance costs (cleaner fuel reduces the frequency with which equipment must be 

serviced) and another $50 in avoided fuel costs from higher efficiency. This is because existing equipment 

generally operates more efficiently with lower sulfur fuels, so less fuel is required to produce the same amount 

of heat; even larger efficiency gains are possible using newer furnaces specifically designed to use lower sulfur 

fuels.

The sulfur content of residual fuel oils burned by power plants and other large sources also can be costeffectively reduced. Residual oil is a byproduct of the refining process, and is produced in several grades that 

can be blended to meet a specified fuel sulfur content limit. In April 2011, MANE-VU published an Addendum to 

its 2007 “Assessment of Reasonable Progress” Report that evaluated residual oil (Appendix T-1). The report 

averaged monthly price averages to compute annual prices and price differentials in cents per gallon for the 

years 2006 – 2009. For these years in the Northeast, lower sulfur No. 6 residual oil (≤ 1%) ranged from 8.9 to 

12.9 cents per gallon more than higher sulfur No. 6 residual oil (> 1%). The additional expense would be at least 

partially offset by reduced maintenance costs with the use of lower sulfur oil. Low sulfur oil is cleaner burning 

and emits less particulate matter than higher sulfur oil; this reduces the rate of fouling of heating units 

substantially and permits longer time intervals between cleanings. The decreased deposits also would enable a 

more efficient transfer of heat, thereby reducing fuel use. Thus, there are potential costs savings for switching to 

lower sulfur residual oil. Reducing the sulfur content of residual fuel is a cost-effective SO2 reduction strategy; a 

simple calculation using a price differential of $0.089 – $0.129 suggests that a 78% reduction in SO2 emissions 

(by converting from 2.2 percent to 0.5 percent sulfur residual oil) is achievable at an approximate cost of $800 -

$1,100 per ton of SO2 removed. This cost per ton removal compares favorably to the costs of other pollution 

controls typically required by environmental agencies and is well within the range considered to be costeffective for SO2 reductions.

While the costs of the low-sulfur oil strategy will vary depending on market conditions, they are reasonable 

when compared to the costs of controlling other sectors. Importantly, a January 2008 Public Health Benefits 

study prepared by NESCAUM shows that the low-sulfur fuel strategy will result in billions of dollars in public 

health benefits for the region (see Appendix AA). Controlling the fuel-sulfur content to 500 ppm leads to health 

benefits of almost 3.4 billion dollars in MANE-VU and controlling the fuel-sulfur content to 15 ppm could lead to 

an additional 431 million dollars in benefits, bringing the total benefits to 3.7 billion dollars.
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The MANE-VU states agreed through consultations to pursue a low-sulfur fuel oil strategy within the region. The 

MANE-VU low-sulfur fuel strategy will be implemented in two phases; however, both components of the 

strategy are to be fully implemented by 2018. The first phase of the MANE-VU low-sulfur fuel strategy requires 

the lowering of fuel sulfur content in distillate (#1 and #2 oil) from current levels that range between 2,000 and 

2,300 ppm down to 500 ppm. The second phase of the strategy further reduces the fuel-sulfur content of the 

distillate fraction to 15 ppm sulfur. It also requires the lowering of sulfur content in residual oil to 0.5 percent 

sulfur by weight.

The two phases of the MANE-VU low-sulfur fuel strategy are to be implemented in sequence with slightly 

different timing for an “inner zone”40 and the remainder of MANE-VU. All MANE-VU states have agreed that a 

low-sulfur oil strategy is reasonable to pursue by 2018 as appropriate and necessary. 

Based on the fuel sulfur limits within the first phase of the strategy, MANE-VU estimated a decrease of 140,000 

tons of SO2 emitted from distillate combustion and a decrease of 40,000 tons of SO2 from residual combustion in 

MANE-VU. In the second phase in which distillate fuel sulfur limits are lowered from 500 ppm to 15 ppm, 

MANE-VU estimated an additional reduction of 27,000 tons of SO2 emissions in MANE-VU in 2018. 

Figure 40 shows the combined impact of both phases of the MANE-VU low-sulfur fuel strategy relative to the On 

The Books/On The Way baseline. NESCAUM used the concentration changes illustrated in Figure 40 to estimate 

the visibility benefits for this strategy. Because the fuel sulfur program only affects sources within MANE-VU, 

that region sees the largest PM2.5 reduction and the greatest visibility benefits.

In July 2012, Massachusetts adopted amendments to 310 CMR 7.05: Fuels All Districts to implement the MANEVU Strategy (Appendix II).

 

40 The inner zone includes New Jersey, Delaware, New York City, and potentially portions of eastern Pennsylvania. 
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Figure 40: Average Change in 24-hr PM2.5 Due to Low Sulfur Fuel Strategies Relative to OTB/OTW 

(g/m3)

Targeted EGU Strategy

SO2 emissions from power plants (electric generating units or EGUs) are the single largest sector contributing to 

the visibility impairment experienced in the Northeast’s Class I areas. The SO2 emissions from power plants 

continue to dominate the inventory. Sulfate formed through atmospheric processes from SO2 emissions are 

responsible for over half the mass and approximately 70-80 percent of the light extinction on the worst visibility 

days (Contribution Assessment, Appendix A). 

In order to properly target controls on EGUs, modeling was conducted to identify those EGUs with the greatest 

impact on visibility in MANE-VU. A list was developed that includes the 100 largest impacts at each MANE-VU 

Class I site during 2002. These emissions were from 167 EGU stacks and are illustrated below (a complete list

can be found in Appendix W; see Appendix A). Some of the stacks identified as important were outside the 

states identified as contributing at least 2 percent of the sulfate at MANE-VU Class I areas and were dropped 

from the list. Massachusetts sources identified in the list include Brayton Point, Canal Station, Mount Tom, 
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Salem Harbor, and Somerset Station. Given the magnitude of their potential impact, controlling emissions from 

these stacks is important to improving visibility at MANE-VU Class I areas.

MANE-VU’s agreed to regional approach for the EGU sector is to pursue a 90 percent reduction in SO2 emissions 

(from 2002 emissions) from these 167 targeted stacks by 2018 as appropriate and necessary. MANE-VU 

concluded that pursuing this level of sulfur reduction is both reasonable and cost-effective. Even though current 

wet scrubber technology can achieve sulfur reductions greater than 95 percent, historically a 90 percent sulfur 

reduction level includes lower average reductions from dry scrubbing technology. The cost for SO2 emissions 

reductions will vary by unit, and the MANE-VU Reasonable Progress report (Appendix T) summarizes the various 

control methods and costs available, ranging from $170 to $5,700 per ton, depending on site-specific factors 

such as the size and type of unit, combustion technology, and type of fuel used.

 

Figure 41: 167 Targeted EGU Stacks Affecting MANE-VU Class I Areas
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To evaluate the impact of reducing emissions from the 167 EGU stacks, NESCAUM used CMAQ to 

model sulfate concentrations in 2018 after implementation of this control program. 2018 SO2 emissions 

for these stacks were modeled at levels equal to 10 percent of their 2002 SO2 emissions; sulfate 

concentrations were then converted to PM2.5 concentrations. This preliminary modeling showed that 

requiring SO2 emissions from the 167 EGU stacks to be reduced by 90 percent from 2002 emission 

levels could reduce 24-hour PM2.5 concentrations. Figure 43 shows the reduction in fine particle 

pollution in the Eastern U.S. that would result from implementing the targeted EGU SO2 strategy. 

Improvements in PM2.5 concentrations would occur throughout the MANE-VU region as well as for 

portions of the VISTAS and Midwest RPO regions, especially the Ohio River Valley.

Figure 42: Average Change in 24-hr PM2.5 due to 90 Percent Reduction in SO2 Emissions from 167 EGU 

Stacks Affecting MANE-VU

Although the reductions are potentially large, MANE-VU determined, after consultation with affected states, 

that it was unreasonable to expect that the full 90-percent reduction in SO2 emissions would be achieved by 

2018. Therefore, additional modeling was conducted to assess the more realistic scenario in which emissions 

would be controlled by the individual facilities and/or states to levels already projected to take place by that 

date. At some facilities, the actual emission reductions are anticipated to be greater or less than the 90 percent 

benchmark. For details, see Appendix W “Documentation of 2018 Emissions from Electric Generating Units in 

the Eastern United States for MANE-VU’s Regional Haze Modeling.”
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Massachusetts has five sources (Table 25) with a total of 10 EGUs on the 167 Stacks list, including Brayton Point 

(Units 1-3), Canal Station (Units 1-2), Mt. Tom Station (Unit 1), Salem Harbor (Units 1, 3, 4), and Somerset Power 

(Unit 8). Each of these facilities is subject to MassDEP’s 310 CMR 7.29, which limits SO2 emissions facility-wide. 

Several of the Massachusetts EGUs already have installed SO2 controls or are planning additional SO2 controls to 

help them meet 310 CMR 7.29 limits. Brayton Point has installed spray dryer absorbers on Units 1 and 2 and 

plans to operate a dry scrubber on Unit 3 in 2013; Mt. Tom Station has installed a dry scrubber. Salem Harbor is 

currently using lower sulfur coal and oil to meet its 310 CMR 7.29 limits (Unit 4 is subject to MassDEP’s amended 

310 CMR 7.05 sulfur in fuels regulation) and plans to shut down all units by June 2014. Somerset Power shut 

down in 2010. Canal Station is using lower sulfur oil to comply with 310 CMR 7.29, and is subject to MassDEP’s 

amended 310 CMR 7.05 sulfur in fuels regulation.

Table 25 shows that SO2 emissions were reduced by 72% from 2002 to 2011 at the targeted units. Additional 

reductions will occur in the 2012-14 timeframe as the Salem Harbor units retire and the Brayton Point Unit 3 

scrubber becomes operational. 

MassDEP believes that there will be further emissions reductions at the targeted units as a result of EPA’s 

recently issued Mercury and Air Toxics Standards (MATS) rule.41 MATS gives coal units with scrubbers a 

compliance option to meet an SO2 emissions rate of 0.2 lbs/MMBtu as an alternative to a hydrogen chloride 

emissions rate, which is more stringent than MassDEP’s 310 CMR 7.29 annual SO2 emissions rate (3.0 lbs/MWh, 

which is roughly equivalent to 0.3 lbs/MMBtu). Brayton Point and Mt. Tom Station may choose this option for 

their coal units, thereby further reducing their permitted SO2 emissions. 

To be subject to MATS in a given year, an EGU must fire coal or oil for more than 10 percent of the average 

annual heat input during the 3 previous consecutive calendar years, or for more than 15 percent of the annual 

heat input during any one of the 3 previous calendar years. This provision provides an incentive to Canal Unit 2, 

which can burn oil or natural gas, to limit the amount of oil it burns so that it is not subject to MATS, which 

would result in future SO2 emissions continuing to be lower than permitted emissions. MATS also establishes 

work practices (versus emissions rates) for oil-fired units with an annual capacity factor of less than 8% of its 

maximum heat input. Canal Station Unit 1’s utilization was 1% in 2011, and thus has an incentive to remain 

below 8%, which would result in future SO2 emissions continuing to be lower than its permitted emissions. Even 

without MATS, oil-fired combustion at Canal Units 1 and 2 is expected to be low well into the future because of 

the high cost of oil relative to natural gas. This cost differential is why Canal’s utilization currently is very low.

 

41 www.gpo.gov/fdsys/pkg/FR-2012-02-16/pdf/2012-806.pdf
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In addition, EPA’s 1-hour SO2 National Ambient Air Quality Standards (NAAQS) may require MassDEP to establish 

new SO2 emission rates that are more stringent than 310 CMR 7.29 for Brayton Point, Mt. Tom Station, and 

Canal Station, as well as to establish emission rates for other large emitters of SO2. MassDEP will be working 

with facilities to determine whether their potential emissions could result in exceedances of the 1-hour SO2

NAAQS, and to develop permit conditions where necessary to limit SO2 emissions in order to meet the NAAQS.

Taking into account 310 CMR 7.29 SO2 emission rates, permit restrictions and retirements, and MassDEP’s 

amended 310 CMR 7.05 sulfur in fuels regulation, MassDEP conservatively projects SO2 emissions in 2018 would 

represent at least a 67% reduction in SO2 emissions compared to 2002 emissions (see Table 25).

42

 However, 

taking into account EPA’s MATS, including the SO2 compliance option and incentives for low utilization of oilfired units, MassDEP believes there is a likelihood that SO2 emissions in 2018 will be up to 87% lower than 2002 

emissions (see Table 25). Therefore, MassDEP believes that existing regulatory programs will lead to SO2

emission reductions that fulfill the MANE-VU Targeted EGU Strategy for Massachusetts. MassDEP will review 

emissions and individual facility MATS compliance strategies in a mid-course planning review in 2013, and if 

emissions reductions are not projected to be close to 90%, MassDEP will assess whether other equivalent SO2

reduction strategies may be necessary. 

 

42 The 67% projection is less than the 72% reduction already achieved in 2011 because it assumes the same unit utilization 

as in the 2002 baseline year, whereas the reduction achieved in 2011 is due in part to low utilization of several units, 

including Canal Units 1 and 2 and Mt. Tom Station. 
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Table 25: Massachusetts Targeted EGUs

Facility Unit

2002 SO2

Emissions

2011 SO2

Emissions

2018 Projected 

SO2 Emissions 

(Conservative)

2018 Projected 

SO2 Emissions 

(Likely)

2018 Projected 

SO2 Emissions 

(90% Target) 

Brayton Point 1 9,254

 

4,298 2,928

 

1,700

 

925 

Brayton Point 2 8,853

 

3,535 2,783

 

1,590 

 

885 

Brayton Point 3 19,450

 

10,769 6,442

 

3,634 1,945 

Canal Station 1 13,066

 

99 7,643

 

1,069 1,307 

Canal Station 2 8,948

 

29 5,443

 

1,479 

 

895 

Mt Tom 1 5,282

 

129 1,571

 

1,033 

 

528 

Salem Harbor 1 3,425

 

893 0 0

 

343 

Salem Harbor 3 4,999

 

2,344 0 0

 

500 

Salem Harbor 4 2,886

 

69 0 0

 

289 

Somerset 8 4,399 0 0 0

 

440 

Total 80,562

 

22,165 

 

26,811 

 

10,505 8,057 
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Reduction 59,396 53,75143 70,057 72,505

Percent 

Reduction 72% 67% 87% 90%

It should be noted that even the conservative projection of a 67% reduction in SO2 emissions from the targeted 

EGUs is more than enough to meet the level of SO2 emissions projected from Massachusetts EGUs that was used 

in the MANE-VU 2018 regional modeling, as documented in NESCAUM’s 2018 Visibility Projections (Appendix G). 

Emission results from the 2018 Inter-Regional Planning Organization CAIR Case Integrated Planning Model v. 

2.1.9 estimated 17,486 tons of SO2 emissions for Massachusetts (See Appendix W, Table 1). However, MANE-VU 

planners recognized that CAIR allows emissions trading, and that reductions at one unit could offset increases at 

another unit within the CAIR region. Because most states do not restrict trading, MANE-VU decided that 

projected emissions should be increased to represent the implementation of the strategy for the 167 stacks 

within the limits of the CAIR program, and therefore increased the projected emissions from states subject to 

the CAIR cap and trade program. For Massachusetts, this modification resulted in projected SO2 emissions of 

45,941 tons for Massachusetts (see Appendix W, Table 9), effectively doubling Massachusetts’ SO2 emissions 

inventory for EGUs. As shown in Table 25, MassDEP’s conservative 67% reduction projection for targeted EGUs 

results in 2018 emissions of 26,811 tons of SO2

44, well below the 45,941 tons of SO2 that is needed to meet the 

modeled 2018 reasonable progress goals for the Class I areas Massachusetts affects. 

Other State EGU Programs Assumed in 2018 EGU Modeling 

Several other states have implemented state-specific EGU emission reduction programs. These commitments, 

identified below, are included in the long-term strategy as reasonable measures to meet MANE-VU’s reasonable 

progress goals and were used in the Best and Final 2018 CMAQ modeling (Appendix G).

Maryland Healthy Air Act: Maryland adopted the following requirements governing EGU emissions:

1. For NOx:

 

43 Note that this SO2 emissions reduction is less than the SO2 emissions reduction under the Alternative to BART (Table 17 in 

Section 8.10) because fewer units are included in the Targeted EGU Strategy. 

44 Two additional EGUs beyond the “167 Stack” Targeted EGUs were projected to have 2018 SO2 emissions, totaling 3,588 

tons, which would bring the total 2018 emissions to 30,399 tons, which is still well below the 45,941 tons used in the 2018 

modeling.
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a. Phase I (2009): Sets unit-specific annual caps (totaling 20,216 tons) and ozone season caps 

(totaling 8,900 tons).

b. Phase II (2012): Sets unit-specific annual caps (totaling 16,667 tons) and ozone season caps 

(totaling 7,337 tons).

2. For SO2:

a. Phase I (2010): Sets unit-specific annual caps (totaling 48,818 tons).

b. Phase II (2013): Sets unit-specific annual caps (totaling 37,235 tons).

3. For mercury:

a. Phase I (2010): 12-month rolling average of a minimum of 80% removal efficiency.

b. Phase II (2013): 12-month rolling average of a minimum of 90% removal efficiency.

The specific EGUs covered are: Brandon Shores (Units 1 and 2), C.P.Crane (Units 1 and 2), Chalk Point (Units 1, 

and 2), Dickerson (Units 1, 2, and 3), H.A. Wagner (Units 2 and 3) Morgantown (Units 1 and 2) and R. Paul Smith 

(Units 3 and 4). No out-of-state trading, no inter-company trading, and no banking from year to year is 

permitted. 

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

Chapter Env-A 2900 requires the installation of scrubbers on Merrimack Station (Units 1 and 2) by July 1, 2013 to 

control SO2 and mercury emissions with state-level SO2 credits for over- or early- compliance.

New Jersey Hg MACT Rule: All coal-fired EGUs must have a mercury removal efficiency of 90%.

Consent Agreements in the VISTAS region: The impacts of the additional following consent agreements in the 

VISTAS states were reflected in the emissions inventory used for those states:

 EKPC: A July 2, 2007 consent agreement between EPA and East Kentucky Power Cooperative 

requires the utility to reduce its emissions of SO2 by 54,000 tons per year and its emissions of NOx by 

8,000 tons per year by installing and operating selective catalytic reduction (SCR) technology, lowNOx burners, and PM and mercury Continuous Emissions Monitors at the utility’s Spurlock, Dale and 

Cooper Plants. According to EPA, total emissions from the plants will decrease between 50 and 75 

percent from 2005 levels. As with all federal consent decrees, EKPC is precluded from using 

reductions required under other programs, such as CAIR, to meet the reduction requirements of the 

consent decree. EKPC is expected to spend $654 million to install pollution controls.
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AEP: American Electric Power agreed to spend $4.6 billion dollars to eliminate 72,000 tons of NOx emissions each 

year by 2016 and 174,000 tons of SO2 emissions each year by 2018 from sixteen plants located in Indiana, 

Kentucky, Ohio, Virginia, and West Virginia.

10.6. Source Retirement and Replacement Schedules 

40 CFR Section 51.308(d)(3)(v)(D) requires Massachusetts to consider source retirement and replacement 

schedules in developing reasonable progress goals. Source retirement and replacement were considered in 

developing the 2018 emissions inventory described in Appendix N, Appendix B-5. 

10.7. Measures to Mitigate the Impacts of Construction Activities

40 CFR Section 51.308(d)(3)(v)(B) requires States to consider measures to mitigate the impacts of construction 

activities. A description of MANE-VU’s consideration of measures to mitigate the impacts of construction can be 

found in the MANE-VU document entitled, Technical Support Document on Measures to Mitigate the Visibility 

Impacts of Construction Activities in the MANE-VU Region (Appendix X). The following statements summarize 

the main points of this technical support document:

 Although a temporary source, fugitive dust and diesel emissions from construction activities can affect 

local air quality.

 While construction activities are responsible for a relatively large fraction of direct PM2.5 and PM10

emissions in the region, the contribution of construction activities to reduced visibility is much smaller 

because dust settles out of the air relatively close to the sources.

 Ambient air quality data shows that soil dust makes up only a minor fraction of the PM2.5 measured in 

MANE-VU Class I areas. Furthermore, the impacts of diesel emissions in these rural areas are a small 

part of the total PM2.5.

 The use of measures such as clean fuels, retrofit technology, best available technology, specialized 

permits, and truck staging areas (to limit the adverse impacts of idling) can help decrease the effects of 

diesel emissions on local air quality.

 MANE-VU states have rules in place to mitigate potential impacts of construction activities on visibility in

Class I areas.

MassDEP requires contractors working on certain state-financed projects to install retrofit pollution controls in 

their construction equipment engines. In addition, Massachusetts regulation 310 CMR 7.09 regulates dust from 

construction and demolition activities. 7.09(3) states, “No person responsible for an area where construction or 

demolition has taken place shall cause, suffer, allow, or permit particulate emissions therefrom to cause or 

contribute to a condition of air pollution...” Furthermore, the construction or demolition of large buildings 

requires a written notification to MassDEP ten working days prior to operations. Due to the lower visibility 
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impact of particulate matter from Massachusetts at Class I areas (relative to SO2 and NOx emissions), MassDEP

concludes that its regulations are currently sufficient to mitigate the impacts of construction activities.

10.8. Agricultural and Forestry Smoke Management

40 CFR Section 51.308(d)(3)(v)(E) requires States to consider smoke management techniques for the purposes of 

agricultural and forestry management. A description of MANE-VU’s analysis of smoke management in the 

context of Regional Haze SIPs can be found in the MANE-VU Smoke Management TSD entitled, “Technical 

Support Document on Agricultural and Forestry Smoke Management in the MANE-VU Region” (Appendix Q).

This technical support document concluded that Smoke Management Programs (SMPs) are only required when 

smoke impacts from fires managed for resource benefits contribute significantly to regional haze. 

Massachusetts does not currently have a smoke management program. The results of the emissions inventory 

indicate that emissions from agricultural, managed, and prescribed burning are very minor source categories 

(totaling 1.34% of PM2.5 emissions in the MANE-VU region). Source apportionment results show that wood 

smoke is a moderate contributor to visibility impairment at some Class I areas in the MANE-VU region; however, 

smoke is not an especially important contributor to MANE-VU Class I areas on either the 20% best or 20% worst 

visibility days. Most of the wood smoke is attributable to residential wood combustion and it is unlikely that 

fires for agricultural or forestry management cause large impacts on visibility in any of the Class I areas in the 

MANE-VU region. On rare occasions, smoke from major fires degrades the air quality and visibility in the MANEVU area. However, these fires are generally unwanted wildfires that are not subject to SMPs. 

MassDEP’s air regulations include 310 CMR 7.00, which bans open burning entirely in 22 urban municipalities 

and prohibits the use of open burning to clear commercial or institutional land for non-agricultural purposes. 

Burning for “activities associated with the normal pursuit of agriculture” and the open burning of brush and 

debris between January 14 and April 30, “except during periods of adverse meteorological conditions,” are 

currently allowed. Prescribed burning also is allowed under 310 CMR 7.07(3)(f) upon specific permission from 

MassDEP. Massachusetts considers these efforts to be sufficient to protect visibility in the Class I areas affected 

by emissions from Massachusetts sources, including agricultural and forestry smoke.

Regulation of Outdoor Hydronic Heaters

On December 26, 2008, MassDEP finalized new regulations, 310 CMR 7.26(50) through (54), to control emissions 

from outdoor hydronic heaters (OHHs, also known as outdoor wood-fired boilers or OWBs), which are included 

in Appendix CC as part of this SIP. The regulations are based in part on a NESCAUM model rule developed in 

January 2007 and have requirements for manufacturers, sellers, and owners of OHHs. Manufacturers must 

meet stringent performance standards in order to sell OHHs in Massachusetts. The Phase I emission standard is 

0.44 lb/MMBtu for units sold after October 1, 2008, and the Phase II emission standard is 0.32 lb/MMBtu for 

units sold after March 31, 2010. Owners of current and new OHHs are subject to regulations regarding the 
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operation of their OHHs. Massachusetts concludes that adoption of these proposed regulations will reduce 

future smoke and particulate emissions from OHHs.

10.9. Estimated Impacts of Long-Term Strategy on Visibility

Preliminary modeling was conducted to estimate the impact of various elements of the MANE-VU “Ask.” This 

modeling is described in NESCAUM’s report entitled MANE-VU Modeling for Reasonable Progress Goals

(Appendix F). NESCAUM also conducted additional revised modeling to assess combined impacts. This 

modeling is described in NESCAUM’s report entitled 2018 Visibility Projections (Appendix G). The following 

information about the effects of specific strategies is taken from those reports. As with all modeling, emissions 

estimates and modeling results for 2018 entail uncertainty, and further evaluation may be conducted as part of 

the progress report required in five years under 40 CFR Section 51.308(g).

Additional Measures Included in Best and Final Modeling

In addition to the measures described in Section 10.5 (BART controls within MANE-VU, low-sulfur fuel within 

MANE-VU, and controls on specific EGUs), MANE-VU asked neighboring RPOs to consider further non-EGU 

emissions reductions comparable to those achieved through MANE-VU’s low-sulfur fuel strategies. Prior 

modeling indicated that the MANE-VU low-sulfur fuel strategy is expected to achieve a greater than 28 percent 

reduction in non-EGU SO2 emissions in 2018. After consultation with other states and consideration of 

comments received, the MANE-VU Class I states decided that the Best and Final modeling would include 

implementation of measures to match MANE-VU’s 28 percent reduction in non-EGU SO2 emissions in the VISTAS 

and MRPO regions. In order to model the impact of this strategy on visibility at MANE-VU Class I areas, 

additional emissions reductions in the VISTAS and MRPO states were assumed to occur, resulting in a modeled 

28 percent reduction in non-EGU SO2 emissions in those regions. These reductions include:

For both Southeast and Midwest States:

Coal-Fired ICI Boilers: emissions were reduced by 60 percent

Oil-Fired ICI boilers: emissions were reduced by 75 percent

ICI Boilers lacking fuel specification: emissions were reduced by 50 percent

Additional controls only in the Southeast States:

Emissions from Other Area Oil-Combustion sources were reduced by 75 percent (Used the same 

SCCs identified in MANE-VU Oil strategies list.)
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In addition, NESCAUM removed SO2 emissions from 6500 MW of six coal-burning EGUs in Canada that are 

scheduled to be shut down for the Best and Final Modeling.45 It is expected that these units will be replaced 

with nine natural gas turbine units with selective catalytic reduction controls. NESCAUM based estimated 

emission rates for modeled pollutants on a combination of factors, including recommendations from the State 

of New Hampshire, a NYSERDA study, and AP-42 ratios among pollutants. Emissions were reduced by more than 

144,000 tons per year as a result of this measure.

Visibility Impacts of Additional Reasonable Controls from Best and Final Modeling

40 CFR Section 51.308(d)(3)(v)(G) requires states to address the net effect on visibility resulting from changes 

projected in point, area and mobile source emissions by 2018. The starting point for indicating progress 

achieved by measures included in this SIP and other MANE-VU-member SIPs is the 2000-2004 baseline visibility 

at affected Class I areas. To calculate the baseline visibility for affected Class I areas, using 2000-2004 IMPROVE 

monitoring data, the deciview value for the 20 percent best days in each year were averaged together, 

producing a single average deciview value for the best days. Similarly, the deciview values for the 20 percent 

worst days in each year were averaged together, producing a single average deciview value for the worst days.

Initial modeling (Appendix F) was then performed to identify reasonable progress goals. Results of this modeling 

showed that sulfate aerosol – the dominant contributor to visibility impairment in the Northeast’s Class I areas 

on the 20 percent worst visibility days – has significant contributions from states in all three of the eastern RPOs. 

These emissions are projected to continue in future years. An assessment of potential control measures 

identified a number of promising strategies, including the adoption of a low-sulfur fuel oil strategy, the 

implementation of BART requirements, and additional controls on select EGUs, as well as a 28 percent reduction 

in non-EGU SO2 emissions in VISTAS and MRPO states. These strategies were predicted to yield significant 

visibility benefits beyond the uniform rate of progress and, in fact, significantly beyond the projected visibility 

conditions that would result from “on the books/on the way” air quality protection programs.

NESCAUM conducted modeling for MANE-VU to document the impacts of the long-term strategy on visibility at 

affected Class I areas. This “Best and Final” modeling is documented in the report 2018 Visibility Projections

(Appendix G), and estimates the composite visibility benefits of all strategies within and outside MANE-VU. 

Emissions inventory adjustments were made for this modeling in order to better represent the likely outcome of 

efforts to pursue the BART, low-sulfur oil, and EGU control measures included in the MANE-VU June 20, 2007 

statements.

 

45 NESCAUM’s 2018 Visibility Projections report cited a November 2006 paper by the Ontario Power Authority, “Ontario’s 

Integrated power System Plan Discussion Paper 7: Integrating the Elements—A Preliminary Plan. See 

http://www.powerauthority.on.ca/ipsp/Storage/32/2734_DP7_IntegratingTheElements.pdf
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Figure 43 to Figure 46 illustrate the predicted visibility improvement by 2018 resulting from the implementation 

of the MANE-VU regional long-term strategy (the short green line above the year 2018). This improvement is 

compared to the Uniform Rate of Progress for affected Class I areas (shown as the diagonal purple line). No 

degradation is represented by the dashed line, blue dots at the upper left indicate the 20 percent worst 

observed visibility days, and the pink line at bottom left indicate the 20 percent best observed visibility days. All 

MANE-VU sites are projected to meet or exceed the uniform rate of progress for 2018. In addition, no site 

anticipates increases in best-day visibility relative to the baseline.

Figure 43: Projected Visibility Improvement at Acadia National Park Based on 2018 Visibility Projections
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Figure 44: Projected Visibility Improvement at Great Gulf Wilderness Area Based on 2018 Visibility 

Modeling46

Figure 45: Projected Visibility Improvement at Lye Brook Wilderness Area Based on 2018 Visibility 

Modeling

 

46 The estimate for Great Gulf Wilderness Area also serves to provide an estimate for the Presidential Range/Dry River 

Wilderness Area
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Figure 46: Projected Visibility Improvement at Moosehorn Wilderness Area Based on 2018 Visibility

Modeling 47

10.10. Massachusetts’ Share of Emissions Reduction

40 CFR Section 51.308(d)(3)(ii) requires states to demonstrate that its implementation plan includes all 

measures necessary to obtain its share of emission reductions needed to meet reasonable progress goals. The 

control measures included in this SIP represent the contribution of Massachusetts towards achieving the 

reasonable progress goals of Class I states by 2018. 

Table 8 in Section 6.8 shows that Massachusetts’ overall projected reduction of total regional haze pollutants 

between 2002 and 2018 is 31 percent. This is closely comparable to MANE-VU’s overall reduction of 29 percent 

for the same period. In addition, MANE-VU modeling demonstrates that Massachusetts’ long-term strategy, 

when coordinated with other states’ strategies as defined by the MANE-VU statement, is sufficient to meet the 

reasonable progress goals of Class I states. Thus, Massachusetts is contributing its share of emissions reductions 

needed to meet reasonable progress goals.

 

47 The estimate for Moosehorn Wilderness Area also serves to provide an estimate for Roosevelt/Campobello International 

Park.
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The MANE-VU statement of June 20, 2007 provided that each state will have up to 10 years to pursue adoption 

and implementation of reasonable NOx and SO2 control measures as appropriate and necessary. This SIP is 

consistent with that statement.

10.11. Emission Limitations and Compliance Schedules

40 CFR 51.308(d)(3)(v)(C) requires Massachusetts to consider emission limitations and compliance schedules to 

achieve reasonable progress goals. Emission limitations and compliance schedules are already in place for the 

Massachusetts programs outlined in Subsection 10.4. MassDEP’s amended 310 CMR 7.05: Fuels All Districts

establishes emissions limitations and compliance schedules for the low sulfur fuel oil strategy consistent with 

the MANE-VU Ask. MassDEP has established emissions limitations for Wheelabrator – Saugus that require 

implementation of BART in 2012. MassDEP has adopted an alternative to BART that ensures emissions 

reductions by July 1, 2014, and a Targeted EGU Strategy. All emissions limitations will be in place by 2018 in 

order to achieve the reasonable progress goals. MassDEP will provide a status update on emissions limitations 

and compliance schedules in the 2013 regional haze SIP progress report. 

10.12. Enforceability of Emission Limitations and Control Measures

40 CFR 51.308(d)(3)(v)(F) requires Massachusetts to consider the enforceability of emissions

limitations and control measures. Emissions reductions due to ongoing air pollution controls described 

in Section 10.4 are or will be enforceable by 2018. For the additional reasonable strategies identified 

above, MassDEP has promulgated regulations, 310 CMR 7.26(50) through (54) to control emissions 

from outdoor hydronic heaters, and amended 310 CMR 7.05 to reduce the sulfur content of fuel oil, and 

includes these regulations in this SIP. MassDEP has issued an Emissions Control Plan for Wheelabrator 

– Saugus reflecting BART, and has issued Emissions Control Plans for Salem Harbor, Brayton Point, 

and Mt. Tom that support MassDEP’s Alternative to BART. All of the Emissions Control Plans are 

submitted as part of this SIP.

10.13. Prevention of Significant Deterioration

The Prevention of Significant Deterioration (PSD) program applies to all new major stationary sources (or 

existing major stationary sources making a major modification) located in an area that is in attainment or is 

unclassified for a pollutant with a NAAQS. A major source is an emissions source that has the potential to emit 

more than 100 tons per year of a regulated pollutant in a listed category or 250 tons per year in any other 

category. One of the intentions of the PSD program is to protect air quality in national parks, wilderness areas, 

and other areas of special natural, scenic, or historic value. The PSD permitting process requires a technical air 

quality analysis and additional analyses to assess the potential impacts on soils, vegetation and visibility at Class 

I areas.

MassDEP accepted delegation of the federal PSD program in 1982. In 2003, consistent with its delegation 

agreement, MassDEP returned the program to EPA and EPA Region I assumed the responsibility for issuing PSD 
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permits for Massachusetts facilities. In April 2011, MassDEP took back delegation of the PSD program, and is 

developing state regulatory adoption of the PSD program for inclusion in the federally enforceable 

Massachusetts State Implementation Plan. 

In addition, MassDEP has retained its state new source review program, which permits new and modified 

sources of emissions under 310 CMR 7.02 – Plan Approval and Emission Limitations. This regulation requires 

Best Available Control Technology (BACT) for all pollutant emissions and a determination that the new or 

modified source will not cause or contribute to a violation of a NAAQS.

Depending upon the specific pollutant, the new or modified source also may be subject to non-attainment 

review under 310 CMR 7.00 Appendix A – Emissions Offsets and Non-Attainment Review, which requires Lowest 

Achievable Emissions Rate (LAER).