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Printed on Recycled Paper

Date Stamped: September 9, 2013

Mr. Scott G. Silverstein

Footprint Power Salem Harbor

 Development LP

1140 Route 22 East, Suite 303

Bridgewater, NJ 08807

RE: SALEM

Transmittal No.: X254064

Application No.: NE-12-022

Class: OP119

FMF No. 

PROPOSED AIR QUALITY PLAN

APPROVAL

Dear Mr. Silverstein:

The Massachusetts Department of Environmental Protection (MassDEP), Bureau of 

Waste Prevention, has reviewed your Major Comprehensive Plan Application (Application)

listed above, dated December 21, 2012. The Application was supplemented with amendments 

thereto dated April 12, 2013, June 10, 2013, June 18, 2013, August 6, 2013, August 20, 2013, 

September 4, 2013, and September 9, 2013. This Application concerns the proposed construction 

and operation of a 630 megawatt (MW) nominal combined cycle electric generating facility (the 

proposed Facility) to be located at 24 Fort Avenue in Salem, Massachusetts, the location of your 

existing power generating facility (Salem Harbor Station). With duct firing under summer 

conditions, the proposed Facility will be capable of generating an additional 62 MW, for a total 

of 692 MW. The Application bears the seal and signature of George S. Lipka, P.E.,

Massachusetts Registered Professional Engineer number 29704.

This Application was submitted in accordance with 310 CMR 7.02 Plan Approval and 

Emission Limitations as contained in 310 CMR 7.00 “Air Pollution Control” regulations adopted 

by MassDEP pursuant to the authority granted by Massachusetts General Laws, Chapter 111, 

Section 142 A-J, Chapter 21C, Section 4 and 6, and Chapter 21E, Section 6. MassDEP’s review 

of your Application has been limited to air pollution control regulation compliance and does not 

relieve you of the obligation to comply with any other regulatory requirements.

MassDEP has determined that the Application is administratively and technically 

complete and that the Application is in conformance with the Air Pollution Control regulations 

and current air pollution control engineering practice, and hereby grants this Proposed Plan 

Approval for said Application, as submitted, subject to the conditions listed below.

This Proposed Plan Approval combines and includes: the 310 CMR 7.02 

Comprehensive Plan Approval and 310 CMR 7.00: Appendix A Emission Offsets and 

Nonattainment Review Approval. This Proposed Plan Approval allows for construction and 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 2 of 59

operation of the proposed Facility, and provides information on the proposed Facility 

description, emission control systems, emissions limits, CEMS, COMS, monitoring/testing, 

record keeping, and reporting requirements.

Between March 3, 2003 and April 11, 2011, the United States Environmental Protection 

Agency (EPA) Region 1 administered the PSD Program in Massachusetts. Effective April 11, 

2011, a Delegation Agreement between MassDEP and EPA Region 1 was finalized for MassDEP 

to resume administration of the PSD Program in Massachusetts pursuant to 40 CFR 52.21 and 

the terms of the Delegation Agreement. Therefore, MassDEP is concurrently issuing a separate 

Draft PSD Permit for the above described Facility.

The Fact Sheet for the Draft PSD Permit is attached to this Proposed Plan Approval. 

This Fact Sheet also explains MassDEP’s evaluation of Best Available Control Technology 

(BACT) for emissions of pollutants subject to PSD review and air quality impacts. MassDEP 

verified and concurs with the BACT and Lowest Achievable Emission Rate (LAER) analyses for 

pollutants not subject to PSD review in the Permittee’s Application. The PSD Permit and the 310 

CMR 7.02 Comprehensive Plan Approval process have the same review considerations for these 

items for this Facility.

Please review the entire Proposed Plan Approval, as it stipulates the conditions with 

which the Facility owner/operator (Permittee) must comply in order for the Facility to be 

operated in compliance with this Plan Approval.

1. DESCRIPTION OF FACILITY AND APPLICATION

Footprint Power Salem Harbor Development LP (the Permittee) proposes to construct 

and operate a nominal 630 Megawatt (MW) natural gas fired, quick start (capable of producing 

300 MW within 10 minutes of startup) combined cycle electric generating facility (the proposed 

Facility) at Salem Harbor Station. With duct firing under summer conditions, the Facility will be 

capable of generating an additional 62 MW, for a total of 692 MW. Construction of the Facility 

is scheduled to begin in June 2014 and continue for a period of approximately 23 months. The 

Facility is expected to commence commercial operation in June 2016. The existing Salem 

Harbor Station is comprised of four (4) steam electric generating units (Boiler Units 1, 2, 3, and 

4). Boiler Units 1 and 2, 84 MW and 81 MW, respectively, and both primarily coal fired, were

removed from service on or prior to December 31, 2011. Boiler Unit 3, a 150 MW primarily 

coal-fired unit, and Boiler Unit 4, a 440 MW primarily oil fired unit, are required to cease 

operation, permanently shutdown, and be rendered inoperable no later than June 1, 2014 (see 

Final Amended Emission Control Plan Approval, Application No. NE-12-003, Transmittal No. 

X241756).

The proposed Facility will be constructed on approximately 20 acres in the northwestern 

portion of the approximately 65 acre Salem Harbor Station site. The Salem Harbor Station site is 

bordered by Fort Avenue and the South Essex Sewerage District (SESD) wastewater treatment 

plant to the north; Salem Harbor and Cat Cove to the east and northeast; the Blaney Street Ferry 

terminal and several mixed-use buildings to the southeast; and by Derby Street and Fort Avenue 

to the west. Residential neighborhoods and the Bentley Elementary School are located to the 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 3 of 59

west across Fort Avenue and Derby Street. Terrain elevations rise gradually to the north, west, 

and southwest, with elevations rising 200 feet or more within approximately 10 kilometers.

The proposed Facility will be configured as two emission units (EU1 and EU2) each 

capable of operating independently in order to respond to ISO – New England (ISO – NE) 

dispatch requirements. EU1 and EU2 each will include one General Electric (GE) Model 107F 

Series 5 combustion turbine generator (CTG), one duct burner, one Heat Recovery Steam 

Generator (HRSG), and one steam turbine generator (STG). EU1 and EU2 each will have a 

nominal generating capacity of approximately 315 MW (346 MW with duct firing). EU1 and 

EU2 shall each burn natural gas with a sulfur content that does not exceed 0.5 grains per 100 

standard cubic feet (pipeline natural gas) only in the CTG and duct burner. Based on an ambient 

temperature of 90 degrees Fahrenheit, each CTG/duct burner pair shall be restricted to a 

maximum design firing rate of 2,449 million British thermal units per hour (MMBtu/hr), higher 

heating value (HHV), in combination. EU1 and EU2 shall each be restricted to a maximum fuel 

heat input of 18,888,480 MMBtu per twelve month rolling period.

Other auxiliary equipment at the Facility will include an 80 MMBtu/hr, HHV auxiliary 

boiler (EU3), a 750 Kilowatt (KW) electrical output emergency engine/generator set (EU4), a 

371 brake horsepower (bhp) fire pump engine (EU5), an aqueous NH3 storage tank, an auxiliary 

cooling tower, a demineralized water tank, a fire protection service water tank, and generator 

step-up (GSU) transformers.

EU3 shall be equipped with Ultra Low NOx burners and shall burn pipeline natural gas 

only. EU3 shall be restricted to a maximum fuel heat input of 525,600 MMBtu per twelve month 

rolling period and will primarily be used to provide steam needed for plant start-up if the 

combustion turbines are off-line, but also to provide process steam for other plant equipment.

EU4 and EU5 shall each burn ultra low sulfur diesel (ULSD) fuel oil (with a sulfur 

content that does not exceed 15 parts per million) only and will be required for backup electrical 

power if no power is available internally or from the utility grid and for fire protection service, 

respectively. EU4 and EU5 shall each be used for emergency purposes only and shall each be 

restricted to no more than 300 hours of operation per twelve month rolling period.

During normal operating conditions, EU1 and EU2 shall each operate in combined cycle 

mode only. The first stage in combined cycle mode involves combustion of natural gas in the 

combustion turbine with Dry Low Oxides of Nitrogen (NOx) Combustors to produce thermal 

energy that is converted into mechanical energy to drive the turbine compressor section as well 

as the generator that produces electrical energy. Under periods of operation when more electrical 

power is needed, evaporative coolers located at the inlet air assembly of each turbine are 

employed to evaporate a water mist into the turbine inlet air in order to cool the inlet air to the 

combustion turbine. Cooler inlet air is denser, and with higher mass flow of inlet air, the turbine 

can fire more natural gas and therefore produce more electrical energy than it otherwise would 

produce if the evaporative coolers were not in operation.

In the second stage of combined cycle mode, the hot exhaust gases, with temperatures in 

excess of 1000 degrees Fahrenheit exiting the combustion turbine, pass through a three pressure 

level HRSG, which uses the heat from these gases to produce steam. Each HRSG houses an 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 4 of 59

oxidation catalyst for carbon monoxide (CO) and volatile organic compounds (VOC) control, 

followed by an ammonia (NH3) injection grid and selective catalytic reduction (SCR) catalyst for 

control of NOx. The steam produced by the HRSG is then directed to the STG where heat energy 

is extracted and converted to additional electrical energy. The exhaust gases exiting the 

combustion turbine also contain sufficient oxygen to allow the placement of a supplemental 

firing burner in the duct (duct burner) allowing the production of additional steam, which 

increases electrical energy production in the STG. An air-cooled condenser (ACC) is used to 

condense the steam exiting the steam turbine and return the water produced to the HRSG through 

a system of pumps and control mechanisms. Efficiency is enhanced in this cycle by using reheat 

systems as well as using waste steam to heat feed water in the HRSG, thereby improving overall 

efficiency.

Overall energy efficiency at the proposed Facility will be further improved by reducing 

the plant parasitic load. High efficiency exterior and industrial interior Light Emitting Diode 

(LED) lighting will be used throughout the proposed Facility, including in the Administration 

Building and Operations Center. The analysis provided by the Permittee shows that operational 

energy savings in Watts of 30 percent and 38 percent are expected for exterior and industrial 

interior lighting, respectively, when compared to standard lighting. Based on a total energy 

savings of 248 MW-hours per year and the proposed Facility’s carbon dioxide (CO2) emission 

rate of 825 pounds per MW-hour net to the grid, avoided CO2 emissions via usage of LED 

lighting amount to 102.3 tons per year. Variable speed drives will be used for all ACC fan 

motors and the primary boiler feed water pump and condensate pump motors. Piping and valves 

to reduce pressure losses will be considered in the detailed plant design. The highest efficiency 

commercially available transformers compatible for interconnection with the nearby National 

Grid switchyard will be installed.

Continuous Emissions Monitoring Systems (CEMS) shall be installed on EU1 and EU2 

to sample, analyze and record NOx, CO, and NH3 concentration levels, and the percentage of 

oxygen (O2), in the exhaust gas from each of the two HRSG exhaust flues. Samples shall also be 

taken in the turbine exhaust upstream of the SCR system in order to provide data to optimize 

usage of the NH3 injection control systems. In addition, Continuous Opacity Monitoring Systems 

(COMS) shall be installed in the stacks of EU1, EU2, and EU3 to monitor and record opacity.

Most of the proposed Facility’s power plant equipment will be housed in a building 

structure that will be approximately 115,000 square feet. In addition, the Facility will include 

areas within other buildings for administrative and operating staff, warehousing of parts and 

consumables, and maintenance shops and equipment servicing. All of the operations at the 

proposed Facility will be contained within these buildings or conducted behind screening to 

minimize visual impacts.

The proposed Facility will interconnect with the National Grid transmission system at 

two (2) locations within the existing National Grid switchyard located on site. One unit of the 

proposed Facility will interconnect at the same location where the existing Boiler Unit 4 is 

presently connected. The other unit of the proposed Facility will interconnect at a new circuit 

breaker bay to be constructed within the existing National Grid switchyard.

Natural gas will be delivered to the site via a new pipeline owned and operated by 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

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Algonquin Gas Transmission, a subsidiary of Spectra Energy (Spectra). The pressure, capacity, 

and route of the new pipeline are still being developed by Spectra. Spectra will also construct an 

on site natural gas metering station. Spectra will obtain all federal, state, and local approvals for 

the above equipment, as necessary.

2. EMISSION OFFSETS AND NONATTAINMENT REVIEW

Review considerations with respect to 310 CMR 7.00: Appendix A Emission Offsets and 

Nonattainment Review (Appendix A) are not part of the PSD Review Process and are therefore 

not addressed in the Fact Sheet. Therefore, MassDEP’s evaluation of Emission Offsets and 

Nonattainment Review for the construction of the proposed Facility is provided below.

Appendix A applies to a new major source or major modification of an existing major 

source located in a non-attainment area; or that is major for NOx or VOC emissions. With respect 

to NOx and/or VOC emissions, Appendix A applies for a new major source of fifty (50) or more 

tons per year or a major modification of an existing major source amounting to an increase of 

twenty five (25) or more tons per year. Appendix A requires new major sources, or major 

modifications thereat, to meet Lowest Achievable Emission Rate (LAER) and to obtain emission 

offsets at a ratio of 1.20 to 1, plus a five (5) percent set aside that must be held and can neither be 

sold nor used elsewhere. This yields an overall offset ratio of 1.26 to 1. LAER is defined in 

Appendix A as the more stringent rate of emissions of: (a) the most stringent emissions

limitation which is contained in any State Implementation Plan (SIP) for such class or category 

of stationary source, unless the owner or operator of the proposed stationary source demonstrates 

that such limitations are not achievable; or, (b) the most stringent emissions limitation which is 

achieved in practice by such class or category of stationary source.

The proposed Facility is expected to commence commercial operation in June 2016. The 

proposed Facility shall be restricted to 144.8 and 28.0 tons per year of NOx and VOC emissions, 

respectively. Therefore, the proposed Facility is a new major source of NOx emissions and is 

subject to Appendix A for its NOx emissions. The proposed Facility is required to meet LAER 

for NOx emissions and the Permittee must obtain NOx emission offsets at a ratio of 1.26 to 1.

Since VOC emissions from the proposed Facility are below the new major source threshold of 

fifty (50) or more tons per year, the Permittee is not subject to regulation under Appendix A for 

LAER and emission offsets pertaining to VOC emissions. However, the VOC emissions from the 

proposed Facility are subject to, and must comply with, Best Available Control Technology 

(BACT) pursuant to 310 CMR 7.02.

The Permittee has proposed a NOx emission limit for EU1 and EU2 of 2.0 parts per 

million by volume, dry basis, corrected to 15 percent Oxygen (ppmvd @ 15% O2), one hour 

block average. The Permittee provided a LAER analysis in the Application that included the 

sources of data reviewed in support of this NOx LAER determination. These sources were EPA’s 

RACT/BACT/LAER Clearinghouse, EPA’s Region IV National Combustion Turbine 

Spreadsheet, the California Air Resources Board BACT Clearinghouse, the South Coast Air 

Quality Management District BACT Clearinghouse, and New Jersey’s State of the Art Manual 

for combustion turbines. The LAER analysis concluded that there are no large natural gas fired 

combined cycle turbines where a NOx emission limit of less than 2.0 ppmvd @ 15% O2 has been 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 6 of 59

approved and subsequently demonstrated in practice. In addition, the two most recent NOx

LAER determinations for similar Massachusetts projects such as Brockton Power Company LLC 

(Application No. 4B08015, Transmittal No. W207973 dated July 20, 2011) and Pioneer Valley 

Energy Center LLC (Application No. 1-B-08-037, Transmittal No. X223780 dated December 31, 

2010) were also 2.0 ppmvd @ 15% O2, one hour block average, during natural gas firing.

MassDEP has verified and concurred with the Permittee’s LAER analysis as presented in this 

Application that this NOx emission limit constitutes NOx LAER for the proposed Facility.

The proposed Facility is a new major source of NOx emissions restricted to 144.8 tons 

per year and the Permittee must obtain NOx emission offsets at a ratio of 1.26 to 1. The total 

number of NOx emission offsets needed for the proposed Facility is (144.8) multiplied by (1.26), 

or 183 tons per year. In accordance with 310 CMR 7.00: Appendix A(6), for a new major 

stationary source of NOx located in an area that is not a nonattainment area, prior to commencing 

operation of any emission unit(s), for which offsets are required under Appendix A, NOx

emission offsets must actually occur and be obtained from the same source or other sources 

within the Ozone Transport Region.

The Permittee entered into an agreement on February 5, 2013 to purchase 59 tons per 

year of rate-based NOx Emission Reduction Credits (ERCs) from The Newark Group Inc. These 

ERCs were created and banked on April 7, 2010 by MassDEP, pursuant to the provisions of the 

Commonwealth of Massachusetts Air Pollution Control Regulation at 310 CMR 7.00: Appendix 

B, due to the shutdown of two (2) Massachusetts facilities owned and operated by The Newark 

Group Inc. Thirty seven (37) tons per year of NOx ERCs were created and banked from the 

shutdown of Natick Paperboard, 90 North Main Street, Natick and twenty two (22) tons per year 

of NOx ERCs were created and banked from the shutdown of Haverhill Paperboard, 100 South 

Kimball Street, Haverhill. ERCs in the Massachusetts Rate ERC Bank shall revert to the state to 

be retired for the benefit of the environment if they have not been used by midnight of the date 

ten years from the date of MassDEP approval, or April 7, 2020.

In addition, the Permittee entered into an agreement on April 4, 2013 to purchase 135 

tons per year of rate-based NOx Emission Reduction Credits (ERCs) from Osram Sylvania Inc. 

These ERCs were created and banked on March 11, 2004 by the Rhode Island Department of 

Environmental Management, Office of Air Resources (OAR), pursuant to the provisions of the 

State of Rhode Island Air Pollution Control Regulation No. 9, due to the shutdown of a number 

of operations at Osram Sylvania Inc., 1193 Broad Street, Central Falls, Rhode Island. In 

accordance with the Memorandum of Understanding by and between the State of Rhode Island 

Department of Environmental Management and the Commonwealth of Massachusetts 

Department of Environmental Protection on the Interstate Trading of NOx Emission Reduction 

Credits (ERCs), dated April 2005, NOx ERCs generated in the State of Rhode Island may be 

used in the Commonwealth of Massachusetts to meet emission offset requirements set forth in 

310 CMR 7.00: Appendix A. The Osram Sylvania Inc. facility is located in the Ozone Transport 

Region. Unlike Massachusetts ERCs in the Rate ERC Bank, Rhode Island ERCs are not subject 

to retirement.

In total, the Permittee has entered into agreements to purchase 194 tons of rate-based 

NOx ERCs. Since 183 tons per year of NOx emission offsets will be used to offset NOx emissions 

from the Facility, 183 tons per year of NOx ERCs in the Rate ERC Bank must be retired at the 
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 7 of 59

approved annual offset rate regardless of the Facility’s annual actual emissions. ERCs utilized as 

offsets are considered “used” commencing with start-up of the Facility. If the Facility start-up 

occurs after April 7, 2020, then the Permittee shall not use the abovementioned Newark Group 

ERCs.

Appendix A requires the Permittee to demonstrate, and MassDEP to concur, that the 

benefits of the proposed project significantly outweigh the environmental and social costs 

imposed as a result of the project's location, construction or modification (310 CMR 7.00: 

Appendix A (8)(b)). This demonstration requires analysis of alternative sites, sizes, production 

processes, and environmental control techniques. The Application contains the details of the 

required demonstration, a summary of which is provided here.

Alternative Site Evaluation

The Permittee’s site selection process focused on sites with shuttered or challenged coal

and/or oil fired electric generating facilities. The sites where these smaller, older oil and coal 

fired electric generating facilities presently operate also typically offer ready access to 

transmission, available water supply, and proximity to electric load. Developing a natural gas

fired facility at these challenged sites offers numerous and substantial benefits to the State and 

local community. In addition to retention of jobs and tax revenues, when an older fossil fuel fired 

electric generating facility is replaced by a state of the art natural gas fired electric generating 

facility with sophisticated emissions controls, significant decreases in sulfur dioxide (SO2), CO2, 

NOx, particulates, and emissions of other air pollutants are realized. Moreover, while site 

contamination associated with an older coal or oil fired electric generating facility may go 

unaddressed or, at least, may not get addressed in a timely manner when a facility is simply shut 

down, the Permittee will address contamination and other environmental liability issues as an 

integral part of the plans to construct and operate the proposed Facility.

The Salem site presents a significant number of attributes that satisfy the Permittee’s 

location, environmental and community criteria set forth above. For example:

 The existing Salem Harbor Station facility was considered to be one of the “Filthy Five” 

electric generation plants in Massachusetts, with a long history of environmental 

challenges. Indeed, construction of the proposed Facility on the landward portion of the 

site will afford the Permittee the opportunity to clean up the portion of the site currently 

occupied by the soon-to-be shutdown existing Salem Harbor Station facility, and return 

that valuable waterfront land to productive use, consistent with State law. Having entered 

commercial operation as an electric generating facility in 1951, the Salem Harbor site has 

a long history as a site for electricity generation.

 The existing Salem Harbor Station facility has been required by ISO - New England to 

operate for reliability purposes through May 2014, offering the Permittee the opportunity 

to minimize any gaps in electricity generation beyond that date through the development 

and permitting of the new state of the art Facility.
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 8 of 59

 The site is nearby (less than two miles from) a natural gas pipeline facility, namely the 

Maritimes and Northeast pipeline.

 There is strong local support for the continuation of electric generation on the site as a 

means of maximizing tax revenues and local employment. The Mayor, other city 

officials, and state senators and representatives, have been supporters of continued 

presence of electric generation at the site, in general, and particularly of the development 

of this Facility.

 There is support for potential reuse of the site as demonstrated by (1) the 2011 decision to 

use Regional Greenhouse Gas Initiative (RGGI) funds to supplement the City of Salem’s 

tax revenues for an eight-year period; (2) funding of the Salem Site Reuse Study by the 

Massachusetts Clean Energy Center; and (3) the enactment of Chapter 209 of the Acts of 

2012 and the establishment of the Salem Harbor Power Station Plan Revitalization Task 

Force.

 Permitting of the proposed Facility is expected given city and state support of the electric

power generation/site reuse concept, as well as compatibility of the proposed Facility 

development with local zoning requirements.

 The site is located in close proximity to the electric grid (National Grid system) and a 

water supply.

 The 65-acre site is sufficiently large to accommodate the proposed Facility and enable 

further redevelopment opportunities.

 The site offers the Permittee the opportunity to significantly reduce air, water supply, 

wastewater, noise, visual, and other impacts relative to the existing Salem Harbor Station 

facility.

 The absence of new electric generation in the Northeastern Massachusetts/Boston 

(NEMA/Boston) load zone. Indeed, it has been nearly a decade since any significant new 

electric generation, i.e. Mystic 8 and 9, has been added in NEMA/Boston. Over the 

course of these last ten years, there have been several unit retirements and still more 

retirements are anticipated, while load in the NEMA/Boston area is not expected to 

decrease.

 The construction of the proposed Facility, along with demolition of the existing facility 

and attendant remediation of the site, will bring a significant number of jobs over the 

course of the next several years. The Permittee expects that approximately 30-40 

permanent employees will be needed to operate the proposed Facility, assuring that 

operations related employment at the Salem Harbor Station site will continue beyond the 

June 1, 2014 retirement date of the existing facility.
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

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 The demolition of the existing facility and remediation of the site will enable future use 

of the remainder of the site for a variety of marine industrial purposes, thereby providing 

opportunities to revitalize this valuable waterfront area.

In sum, the site satisfied the Permittee’s overall site selection objectives, as well as most, 

if not all, of its location, environmental and community criteria. Accordingly, the site was 

deemed to be superior to the alternative sites analyzed by the Permittee.

Alternative Project Sizes, Production Processes, and Environmental Control Techniques 

Evaluation

The Permittee considered positioning the proposed Facility on the portion of the site 

located outside of Chapter 91 jurisdiction. However, the Permittee concluded that the 

approximately 14.5 acre, irregularly shaped, non-Chapter 91 portion of the site is not large 

enough to accommodate the proposed Facility. 

The Permittee also considered a wet-cooling system as a design alternative for the 

proposed Facility. However, wet cooling was not considered to be a reasonable option because it 

would result in greater impacts to Salem Harbor from withdrawal/discharge in terms of water 

quality and impingement/entrainment versus the air cooled condenser option chosen.

The Permittee also considered a “dual fuel” alternative in which the proposed Facility 

could run on either natural gas or diesel fuel oil. This alternative was considered not to be a 

reasonable alternative due to intense local opposition to diesel fuel oil at the site and the potential 

increased environmental risks (both to Salem Harbor and on and near the site) associated with 

fuel delivery to/use on the site.

State and Regional Project Benefits

The Permittee has documented that electric generation that will be provided by the 

proposed Facility is essential to ensure reliability in the NEMA/Boston load zone. The need for 

reliability of the electric power grid clearly constitutes an overriding public benefit.

In addition, the public benefit served by the redevelopment of the site represented by the 

proposed Facility has been expressly identified in recently enacted special legislation. Section 42 

of Chapter 209 of the Acts of 2012 expressly provides:

“There shall be a plant revitalization task force established to implement a plan, adopt 

rules and regulation and recommend necessary legislative action to ensure the full 

deconstruction, remediation and redevelopment or repowering of the Salem Harbor 

Station by December 31, 2016.”

The proposed Facility achieves all of the legislative goals of full demolition, remediation 

and redevelopment of the site within the legislatively prescribed deadline of December 31, 2016. 

It is difficult to conceive of any other project that could implement a plan for redevelopment of

the site by December 31, 2016.
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 10 of 59

The proposed Facility also serves the Commonwealth’s interest in developing renewable 

energy sources. That is, the quick-start technology designed into the proposed Facility facilitates 

and supports the development of wind generation. Because wind power is an intermittent 

resource, it is especially important for the region to be able to rely on clean and cost effective 

quick-start electric generation during those periods when wind output is not available. While a 

number of quick-start “peaking” facilities have recently been sited in New England, the proposed 

state of the art quick-start technology at the proposed Facility will be more efficient and will 

have fewer emissions than the peaking units which presently fill the gap when wind is 

unavailable.

While the proposed Facility clearly fulfills the need for electricity reliability, the state of

the art natural gas fired emission units also offer significant air quality benefits. An analysis 

prepared for the Permittee by Charles River Associates concludes that because the proposed 

Facility “displaces other, less efficient generation on the New England Grid, operation of [the 

Facility] reduces annual regional air emissions by approximately 457,626 tons (1.3%) of CO2, 

984 tons (10%) of NOx, and 888 tons (8%) of SO2.

1”

The important air quality improvements resulting from the proposed Facility are also 

recognized in the Massachusetts Clean Energy and Climate Action Plan for 2020, which 

estimates that the displacement of the former Salem Harbor Station and Somerset Station 

facilities by natural gas fired power plants would result in a net 1.2 million metric ton reduction 

in Greenhouse Gases (CO2e) in 2020.2

Local Project Benefits

Without the proposed Facility, the upcoming retirement of the Salem Harbor Station 

facility would result in a significant loss of tax revenues for the City of Salem. In fiscal year 

2010, former owner and operator of Salem Harbor Station, Dominion Energy Salem Harbor 

LLC, paid $4.75 million in taxes, making the facility the largest contributor of tax revenue in the 

City of Salem. The $4.75 million included a negotiated usage fee of $1.75 million, and property 

taxes of $3 million, which included $800,000 attributable to the land. The proposed Facility will 

help ensure that tax revenues associated with the site are maintained, thus not adversely affecting 

the City’s budget and it will permit dollars from the RGGI Trust Account to be redirected away 

from Salem and to other environmentally beneficial uses.

In addition, the proposed Facility will result in opportunities for public enjoyment of the 

waterfront, consistent with the site’s location in a Designated Port Area. Currently, there is no 

public access to the waterfront on the site. In contrast, as a result of the proposed Facility, the 

public will have the opportunity to access paths on the Derby Street (residential) side of the site, 

as well as linear access to view Salem Harbor. In addition, the demolition and remediation 

efforts to be undertaken by the Permittee will enable future development options for the rest of 

the site that could even further enhance public access to and enjoyment of the waterfront.
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 11 of 59

Minimization of Environmental and Social Costs

The Permittee has committed to reduce and/or mitigate any environmental and social 

impacts as a result of development of the site. The proposed Facility will minimize emissions 

and will not cause or contribute to violation of any applicable air quality standard, through use of 

only clean burning natural gas as fuel, advanced pollution control equipment, and highly 

efficient combustion turbines. As a result, emissions from the proposed Facility will be amongst

the lowest of any fossil fuel fired electric generating facility in the United States.

MassDEP acknowledges that there will be environmental and social costs. There will be 

new emissions to the ambient air which will be minimized through addition of control 

technology and the purchase of NOx emission offsets. Further, the impacts to the ambient air 

from the project are well within the standards and guidelines designed to protect public health.

Based upon review of the detailed demonstration provided by the Permittee in the 

Application, MassDEP finds that the benefits of this project significantly outweigh this project's 

environmental and social costs.

Notes:

1. “Analysis of the Impact of Salem Harbor Repowering on New England Air Emissions” dated November 

21, 2012, p. 1, included in Appendix C to the Draft Environmental Impact Report, EEA# 14937; values updated per 

June 10, 2013 letter to MassDEP, Attachment 4.

2. “Massachusetts Clean Energy and Climate Plan for 2020, A report to the Great and General Court pursuant 

to the Global Warming Solutions Act (Chapter 298 of the Acts of 2008, and as codified at M.G.L. c. 21N)” dated 

December 29, 2010, submitted by Secretary of Energy and Environmental Affairs Ian A. Bowles, p. 44.

3. AIR QUALITY IMPACT ANALYSIS

The EPA has developed National Ambient Air Quality Standards (NAAQS) for six air 

contaminants known as criteria pollutants for the protection of public health and welfare. These 

criteria pollutants are Nitrogen Dioxide (NO2), Sulfur Dioxide (SO2), Particulate Matter (PM), 

Carbon Monoxide (CO), Ozone (O3), and Lead (Pb). The NAAQS include both primary and 

secondary standards of different averaging periods, which protect public health and public 

welfare, respectively.

One of the basic goals of federal and state air pollution control regulations is to ensure 

that ambient air quality, including background, existing, and new sources, is in compliance with 

the NAAQS. To identify new pollution sources with the potential to significantly alter ambient 

air quality, the EPA and MassDEP have adopted significant impact levels (SILs) for the criteria 

pollutants except O3 and Pb. New major sources (or major modifications of existing major 

sources) are required to perform an air quality dispersion modeling analysis to predict air quality 

impacts of the new (or modified) source in comparison to the SILs. If the predicted impact of the 

new or modified source is less than the SIL for a particular pollutant and averaging period, then 

the impact is considered “insignificant” for that pollutant and averaging period. However, if the 

predicted impact of the new or modified source is equal to or greater than the SIL for a particular 
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pollutant and averaging period, then further impact evaluation is required. This additional 

evaluation must include measured background levels of pollutants, and emissions from both the 

proposed new (or modified) source and existing interactive sources (cumulative dispersion 

modeling).

General Conditions

Dispersion modeling analyses were performed to assess the proposed Facility’s air impacts 

of criteria air pollutants and air toxics against applicable SILs, NAAQS, and MassDEP’s Allowable 

Ambient Levels (AALs) and Threshold Effects Exposure Limits (TELs) Guidelines for air toxics. 

These analyses were conducted in accordance with EPA’s “Guideline on Air Quality Models” 

(November 2005) and MassDEP’s “Modeling Guidance of Significant Stationary Sources of Air 

Pollution” (June 2011) and as described in the Air Quality Modeling Protocol submitted to 

MassDEP on August 29, 2012. The EPA-recommended AERMOD model (current AERMOD 

version 12060, AERMAP version 11103) was used to perform the dispersion modeling. Dispersion 

modeling was conducted in a manner that evaluated worst case operating conditions in an effort to 

predict the highest impact for each pollutant and averaging period.

The dispersion modeling was conducted using five years (2006 through 2010) of surface 

data collected by the National Weather Service (NWS) from the Logan Airport Station in 

Boston, Massachusetts and the corresponding upper air data from Gray, Maine. These stations 

are the closest NWS Stations and most representative of the Salem area. AERMET (version 

11059), AERMINUTE (version 11059), and AERSURFACE were employed to prepare the 

meteorological files. Land use within a 3 kilometer radius of the proposed Facility was 

characterized as rural and water covered (approximately 64 percent). Therefore, rural dispersion 

coefficients were used in the dispersion modeling. The modeling analyses included the two 

combustion turbine units, auxiliary boiler, emergency generator and fire pump engines, and the 

auxiliary cooling tower, all operating simultaneously. Three GE combustion turbine operating 

loads (46, 75, and 100 percent loads), including a worst case combustion turbine start-up 

condition, were modeled. Table 1 presents the maximum predicted ambient air quality impact 

concentrations for the proposed Facility. The proposed Facility was predicted to have maximum 

ambient air quality impact concentrations below SILs for all pollutants and averaging periods, 

except for 1-Hour NO2 and 24-Hour PM2.5.

Table 1

Criteria

Pollutant

Averaging 

Period

Primary 

NAAQS 

(ug/m3)

Secondary 

NAAQS 

(ug/m3)

Significant 

Impact Level 

(ug/m3)

Maximum 

Predicted Facility 

Impact (ug/m3)

NO2 Annual (1)

1-Hour (2)

100

188

Same

None

1

7.5

0.4

41.8

SO2 Annual (1,3)

24-Hour (3,4)

3-Hour (4)

1-Hour (5,6)

80

365

None

196

None

None

1,300

None

1

5

25

7.8

0.03

0.7

1.1

1.0

PM2.5 Annual (7)

24-Hour (8)

12

35

Same

Same

0.3

1.2

0.12

3.2
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Table 1

Criteria

Pollutant

Averaging 

Period

Primary 

NAAQS 

(ug/m3)

Secondary 

NAAQS 

(ug/m3)

Significant 

Impact Level 

(ug/m3)

Maximum 

Predicted Facility 

Impact (ug/m3)

PM10 24-Hour (9) 150 Same 5 4.3

CO 8-Hour (4)

1-Hour (4)

10,000

40,000

None

None

500

2,000

112.4

313.6

O3 8-Hour (10) 147 Same NA NA

Pb 3-Month (1) 0.15 Same NA < 0.00016

Table 1 Notes:

1. Not to be exceeded.

2. Compliance based on 3 year average of the 98th percentile of the daily maximum 1 hour average at each 

monitor within an area.

3. EPA has indicated that the 24 hour and annual average primary standards for SO2 will be revoked.

4. Not to be exceeded more than once per year.

5. Compliance based on 3 year average of 99th percentile of the daily maximum 1 hour average at each 

monitor within an area.

6. The 1 hour SO2 standard was effective as of August 23, 2010.

7. Compliance based on 3 year average of weighted annual mean PM2.5 concentrations at community oriented 

monitors.

8. Compliance based on 3 year average of 98th percentile of 24 hour concentrations at each population 

oriented monitor within an area.

9. Not to be exceeded more than once per year on average over 3 years.

10. Compliance based on 3 year average of fourth highest daily maximum 8 hour average ozone concentrations 

measured at each monitor within an area.

Table 1 Key:

NAAQS = National Ambient Air Quality Standards

EPA = United States Environmental Protection Agency

NO2 = Nitrogen Dioxide

SO2 = Sulfur Dioxide

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

PM10 = Particulate Matter less than or equal to 10 microns in diameter

CO = Carbon Monoxide

O3 = Ozone

Pb = Lead

ug/m3= micrograms per cubic meter

NA = Not Applicable

< = less than
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Cumulative Dispersion Modeling

Since dispersion modeling predicted maximum impact concentrations above SILs for 1

Hour NO2 and 24-Hour PM2.5, cumulative impact modeling was performed for these pollutants 

with the same pollutant emissions from existing interactive sources and measured background 

levels to compare against the NAAQS for 1-Hour NO2 and 24-Hour PM2.5. Background 

concentrations were obtained from MassDEP’s Lynn monitoring location, approximately 5.9 

miles southwest of the Facility. The existing interactive sources in Massachusetts nearby the 

Facility considered in the cumulative modeling were: a) General Electric Lynn and Wheelabrator 

Saugus for 1-Hour NO2 and 24-Hour PM2.5; and b) Rousselot Peabody, Peabody Municipal 

Light, and Marblehead Municipal Light for 1-Hour NO2. Table 2 shows the cumulative impacts. 

The results of the cumulative impact analysis show that under no condition did the proposed 

Facility’s worst case emissions in combination with emissions from the existing interactive 

sources plus measured background levels result in concentrations which exceeded the applicable 

NAAQS.

Table 2

Criteria

Pollutant

Averaging

Period

Cumulative Impact, 

Facility Plus Existing 

Sources (2)

(ug/m3)

Background 

(ug/m3) (1)

Total Impact Plus 

Background 

(ug/m3)

Primary 

NAAQS

(ug/m3)

NO2 1-Hour 83.7 (3) 82.3 166.0 188

PM2.5 24-Hour 3.5 18.9 22.4 35

Table 2 Notes:

1. Background concentrations are based on the measured values from 2010 through 2012. Short term 

background concentrations for 24-Hour PM2.5 and 1-Hour NO2, are the average of the 98th percentile values over the 

3 years (2010-2012). These assumptions are consistent with the form of the NAAQS for the pollutant.

2. Consistent with EPA modeling guidance for NAAQS compliance assessments, impact concentrations are 

based on the 5 year average of the 1st highest values occurring in each year for the 24-Hour PM2.5 concentration, and 

the 5 year average of the 8th highest daily maximum concentrations occurring in each year for the 1-Hour NO2

concentration.

3. The modeled cumulative impacts represent an EPA-approved Tier 2 approach reflecting an 80 percent 

conversion of NOx emissions to NO2 in the ambient air.

Table 2 Key:

NAAQS = National Ambient Air Quality Standards

NO2 = Nitrogen Dioxide

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

ug/m3= micrograms per cubic meter

Air Toxics Analysis

MassDEP has established health based ambient air guidelines for a variety of chemicals 

(air toxics). These air guidelines establish two limits for each chemical listed: an AAL, which is 
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based on an annual average concentration; and a TEL, which is based on a 24-hour time period. 

In general, AALs are lower than TELs, and represent the concentration associated with a one in 

one million excess lifetime cancer risk, assuming a lifetime of continuous exposure to that 

concentration. For chemicals that do not pose cancer risks, the AAL is equal to the TEL.

Table 3 presents the projected maximum impacts for each air toxic that will potentially be 

emitted by the proposed Facility for which an AAL or TEL has been established. Impacts are 

based on the worst case emission scenarios predicted by AERMOD. As shown in Table 3, the 

proposed Facility’s maximum predicted ambient air quality impact concentrations were 

significantly below applicable AALs and TELs for all of the air toxics modeled.

Table 3

Pollutant Averaging Period AAL/TEL (ug/m3) Maximum Predicted Facility 

Impact (ug/m3)

Acetaldehyde 24-Hour (TEL)

Annual (AAL)

2

0.5

0.053708

0.000775

Ammonia 24-Hour (TEL)

Annual (AAL)

100

100

1.093673

0.034497

Benzene 24-Hour (TEL)

Annual (AAL)

1.74

0.12

0.080104

0.000591

1,3-Butadiene 24-Hour (TEL)

Annual (AAL)

1.20

0.003

0.002035

0.000019

o-Dichlorobenzene 24-Hour (TEL)

Annual (AAL)

81.74

81.74

0.000047

0.000006

p-Dichlorobenzene 24-Hour (TEL)

Annual (AAL)

122.61

0.18

0.000047

0.000006

Ethylbenzene 24-Hour (TEL)

Annual (AAL)

300

300

0.012962

0.000409

Formaldehyde 24-Hour (TEL)

Annual (AAL)

2.0

0.8

0.203990

0.005265

Naphthalene 24-Hour (TEL)

Annual (AAL)

14.25

14.25

0.009739

0.000067

Propylene Oxide 24-Hour (TEL)

Annual (AAL)

6

0.3

0.334015

0.002126

Sulfuric Acid 24-Hour (TEL)

Annual (AAL)

2.72

2.72

0.053184

0.001841

Toluene 24-Hour (TEL)

Annual (AAL)

80

20

0.083392

0.001857

Xylenes 24-Hour (TEL)

Annual (AAL)

11.80

11.80

0.047138

0.000942

Arsenic 24-Hour (TEL)

Annual (AAL)

0.003

0.0003

0.000012

0.000001

Beryllium 24-Hour (TEL)

Annual (AAL)

0.001

0.0004

0.000000

0.0000001
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Table 3

Pollutant Averaging Period AAL/TEL (ug/m3) Maximum Predicted Facility 

Impact (ug/m3)

Cadmium 24-Hour (TEL)

Annual (AAL)

0.003

0.001

0.000044

0.000006

Chromium (total) 24-Hour (TEL)

Annual (AAL)

1.36

0.68

0.001137

0.000013

Chromium (hexavalent) 24-Hour (TEL)

Annual (AAL)

0.003

0.0001

0.000205

0.000002

Copper 24-Hour (TEL)

Annual (AAL)

0.54

0.54

0.00003

0.00000

Lead (1) 24-Hour (TEL)

Annual (AAL)

0.14

0.07

0.00009

0.000003

Mercury (elemental) 24-Hour (TEL)

Annual (AAL)

0.14

0.07

0.00001

0.000001

Nickel 24-Hour (TEL)

Annual (AAL)

0.27

0.18

0.00021

0.00001

Selenium 24-Hour (TEL)

Annual (AAL)

0.54

0.54

0.00002

0.0000002

Vanadium 24-Hour (TEL)

Annual (AAL)

0.27

0.27

0.00009

0.00001

Table 3 Notes:

1. Most air toxics do not have a NAAQS, with the exception of lead.

Table 3 Key:

AAL = Allowable Ambient Limit

TEL = Threshold Effects Exposure Limit

ug/m3= micrograms per cubic meter

Preconstruction Monitoring Analysis

As described in the “Cumulative Dispersion Modeling” section above, ambient 

background monitoring data from MassDEP’s Lynn monitoring site for the three (3) year period 

of 2010 through 2012 were used to characterize criteria pollutant ambient air impacts. PSD 

regulations allow proposed sources to use existing monitoring data in lieu of PSD 

preconstruction monitoring requirements for a pollutant if the source can demonstrate that its 

ambient air impact is less than a de minimis amount (also called a significant monitoring 

concentration or SMC) as specified in those regulations. As shown in Table 4 below, dispersion 

modeling conducted by the Permittee predicted maximum proposed Facility impact 

concentrations well below corresponding SMC levels for all pollutants for which SMCs exist.
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Table 4

Pollutant Averaging Period SMC (ug/m3) Maximum Predicted Facility 

Impact (ug/m3)

NO2 Annual 14 0.4

SO2 24-Hour 13 0.7

PM10 24-Hour 10 4.3

CO 8-Hour 575 112.4

Table 4 Key:

SMC = Significant Monitoring Concentration

ug/m3= micrograms per cubic meter

EPA had also established an SMC for PM2.5 but this SMC was remanded by the United 

States Court of Appeals for the DC Circuit on January 22, 2013 (No. 10-1413, Sierra Club v. 

EPA). On March 4, 2013, the EPA Office of Air Quality Planning and Standards issued guidance 

to applicants and regulators with regard to the ramifications of the January 22, 2013 Appeals 

Court decision. The pertinent excerpt of this recent EPA guidance is as follows:

“As a result of the Court’s decision, Federal PSD Permits issued henceforth by either the 

EPA or a delegated state permitting authority pursuant to 40 CFR 52.21 should not rely 

on the PM2.5 SMC to allow applicants to avoid compiling air quality monitoring data for 

PM2.5. Accordingly, all applicants requesting a federal PSD permit, including those 

having already applied for but have not yet received the permit, should submit ambient 

PM2.5 monitoring data in accordance with the Clean Air Act requirements whenever 

either direct PM2.5 or any PM2.5 precursor is emitted in a significant amount. In lieu of 

applicants setting out PM2.5 monitors to collect ambient data, applicants may submit 

PM2.5 ambient data collected from existing monitoring networks when the permitting 

Authority deems such data to be representative of the air quality in the area of concern for 

the year preceding receipt of the application. We believe that applicants will generally be 

able to rely on existing representative monitoring data to satisfy the monitoring data 

requirement.”

The Lynn monitoring site, located approximately 5.9 miles to the southwest of the 

proposed Facility, is representative of the proposed Facility site due to its proximity. Use of the 

data from this monitoring site is conservative for the following reasons:

a) Lynn is a more industrialized and densely populated area than the proposed Facility 

site, particularly without the influence of the existing Salem Harbor Station after its 

shutdown prior to when the proposed Facility commences operation. The proposed 

Facility site is located adjacent to Salem Harbor, a significantly large water body where 

potential emission sources are more limited. The Lynn monitoring site is located closer to 

the metropolitan Boston area than the proposed Facility site. Any potentially elevated 

ambient background pollutant concentrations from mobile and stationary emission 

sources located in and around the Boston metropolitan area that may be transported to the 

proposed Facility site via predominant winds from the south or southwest, typically pass 
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the Lynn monitoring location and are therefore represented in the measurement data 

collected at the Lynn monitoring site. 

b) The General Electric Lynn and Wheelabrator Saugus facilities, which have been 

identified by MassDEP as the only two major industrial emission sources to be modeled 

cumulatively with the proposed Facility emissions for 24-Hour PM2.5, are located slightly 

less than 2 miles from the Lynn monitoring site but are located about 7 miles from the 

proposed Facility site. Therefore, the cumulative modeling compliance demonstration, 

which includes both the background ambient concentrations and impacts from the 

interactive existing major sources likely double counts the contribution of these sources 

and therefore, provides additional conservatism to the required modeling results by 

potentially overestimating cumulative impact concentrations. This is particularly 

significant given that these two major sources are located to the south-southwest of the 

monitoring site, which means that they could potentially influence the monitoring site 

concentrations during winds coming from the south or southwest, the predominant wind 

directions in this area.

For the reasons set forth above, in accordance with the PSD regulations and recent EPA 

guidance, MassDEP has determined that preconstruction monitoring is not required.

Justification for Using Significant Impact Levels (SILs) for PM2.5

Despite the fact that the PSD regulations dealing with SILs for PM2.5 were partially 

vacated and remanded (at EPA’s request) in the January 22, 2013 Appeals Court decision, the 

use of the PM2.5 SILs is still valid in certain circumstances in which ambient background 

concentrations are relatively low. EPA did not concede that it lacked authority to promulgate 

SILs and the court found that it was not necessary to address the question of whether EPA had 

such authority. In fact, the SILs were vacated and remanded in only PSD sections 40 CFR 

51.166(k)(2) and 52.21(k)(2) but were not vacated in 40 CFR 51.165(b)(2). This is most likely 

because the text of this latter regulation does not exempt a source from ambient air quality 

analysis but states that if a source located in an attainment area exceeds a SIL in a nonattainment 

area (or predicted nonattainment situation), it is deemed to have contributed to or caused a 

violation of a NAAQS.

Key examples in the Appeals Court decision supporting the vacature and remand 

involved cases in which the ambient air quality background is very close to the NAAQS. This is 

not the case in the Salem region where the PM2.5 background is only slightly over half of the 

NAAQS, 18.9 ug/m3vs. 35 ug/m3. Therefore, use of the prior PM2.5 SILs is appropriate in the 

case of the ambient air quality impact analysis for the proposed Facility because the background 

concentrations plus the SILs still leave a significant margin before the NAAQS would come 

close to being jeopardized.

Use of the prior PM2.5 SILs is also consistent with the recent EPA guidance on this matter 

which states 1:

 The EPA does not interpret the Court’s decision to preclude the use of SILs for PM2.5 

entirely but additional care should be taken by permitting authorities in how they apply 
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those SILs so that the permitting record supports a conclusion that the source will not 

cause or contribute to a violation of the PM2.5 NAAQS.

 PSD permitting authorities have the discretion to select PM2.5 SIL values if the 

permitting record provides sufficient justification for the SIL values that are used and the 

manner in which they are used to support a permitting decision.

 The PM2.5 SIL values in the EPA’s regulations may continue to be used in some 

circumstances if permitting authorities take care to consider background concentrations 

prior to using these SIL values in particular ways.

 Because of the Court’s decision vacating the PM2.5 SMC, all applicants for a federal 

PSD permit should include ambient PM2.5 monitoring data as part of the air quality 

impacts analysis. If the preconstruction monitoring data shows that the difference 

between the PM2.5 NAAQS and the monitored PM2.5 background concentrations in the 

area is greater than the EPA’s PM2.5 SIL value, then the EPA believes it would be 

sufficient in most cases for permitting authorities to conclude that a proposed source with 

a PM2.5 impact below the PM2.5 SIL value will not cause or contribute to a violation of 

the PM2.5 NAAQS and to, therefore, forego a more comprehensive cumulative modeling 

analysis for PM2.5.

 As part of a cumulative analysis, the applicant may continue to show that the proposed 

source does not contribute to an existing violation of the PM2.5 NAAQS by 

demonstrating that the proposed source’s PM2.5 impact does not significantly contribute 

to an existing violation of the PM2.5 NAAQS. However, permitting authorities should 

consult with the EPA before using any of the SIL values in the EPA’s regulations for this 

purpose (including the PM2.5 SIL value in section 51.165(b)(2), which was not vacated 

by the Court).

Notes:

1. EPA, Office of Air Quality Planning and Standards, “Circuit Court Decision on PM2.5 Significant Impact 

Levels and Significant Monitoring Concentration – Questions and Answers”, March 4, 2013.

http://www.epa.gov/nsr/documents/20130304qa.pdf

4. ACCIDENTAL RELEASE MODELING OF AQUEOUS AMMONIA (NH3)

Aqueous NH3 will be used as the reducing agent in the proposed Facility’s SCR system 

to control NOx emissions. A solution of aqueous NH3 (19% solution) will be stored onsite in an 

above-ground 34,000-gallon single-walled steel tank located north of the building structures. The 

tank, as well as NH3 transfer pumps, valves, and piping will be contained within a concrete dike 

designed to contain 110 percent of the total volume of the tank.

In order to minimize the exposed surface area of any aqueous NH3 that enters the 

containment area, passive evaporative controls (polyethylene balls or equivalent) will be utilized

to reduce the surface area by 90 percent. In order to further mitigate the potential impacts of an 
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accidental NH3 release, the entire tank and containment area will be located within an enclosure 

with walls that will be fully sealed and ventilation provided by roof vents.

The aqueous NH3 storage tank will be constructed in accordance with the Massachusetts 

Department of Public Safety requirements for storage tanks greater than 10,000 gallons 

containing material other than water. The dike wall and enclosure surrounding the tank will 

decrease the risk of damage to the tank caused by accidental vehicle contact.

Transfer from NH3 delivery trucks to the storage tank will take place within a contained 

concrete storage unloading pad with drainage design such that any spills during NH3 delivery 

will drain into the containment area. Delivery trucks will be required to have fast-acting shutoff 

valves in the unlikely event that a leak or other problem should arise. A hose from the top of the 

tank connected back to the truck will return displaced vapor to the truck, or an equivalent method 

for control of transfer losses will be used.

The storage tank will be equipped with level monitoring instrumentation that will be 

continuously monitored in the proposed Facility’s control room. In the event that the tank level 

approaches an overfill condition during filling, a high level alarm will sound, initiating an 

immediate response to the situation. In addition, NH3 sensors in the enclosure will alert plant 

staff and prevent the accumulation of significant amounts of NH3 in the containment area.

Ammonia in aqueous solution is volatile, and the accidental release of this material would 

result in some release of NH3 to the ambient air. Therefore, a worst case accidental release 

scenario was performed to evaluate the potential health impacts of such a release. This scenario 

assumed a release of the entire contents of the tank into the containment area, and conservatively 

evaluated the air quality impacts of such a release at the nearest projected controlled access 

perimeter (PCAP), approximately 230 feet from the NH3 storage area. The NH3 emissions 

resulting from this hypothetical worst case release scenario were calculated using the Area 

Locations of Hazardous Atmospheres model. This model was developed by EPA and the 

National Oceanic and Atmospheric Administration, and is included as a prescribed technique 

under the EPA Risk Management Program (RMP) guidance.

In order to conservatively evaluate offsite consequences of an NH3 release, the 

AERMOD dispersion model used for evaluation of air quality impacts from the exhaust stacks 

was used to determine maximum NH3 concentrations at receptors at or near the PCAP, evaluated 

in terms of the American Industrial Hygiene Association (AIHA) Emergency Response Planning 

Guideline Level 1 (ERPG-1) of 25 parts per million (ppm) by volume, and the ERPG-2 of 150 

ppm by volume. ERPG-1 is defined as the maximum airborne concentration below which nearly

all individuals could be exposed to for up to one hour without experiencing either mild transient 

health effects and/or a clearly defined objectionable odor. ERPG-2 is defined as the maximum 

airborne concentration which it is believed that nearly all individuals could be exposed to for up 

to one hour without experiencing or developing irreversible or other serious health effects or 

symptoms that could impair the ability to take self directed protective action.

The results of the AERMOD model indicate that in the event of a hypothetical worst case 

release, the NH3 concentrations would be less than the ERPG-1 level of 25 ppm by volume at all 

locations outside of the PCAP. Thus, the NH3 concentrations at all locations outside of the PCAP 
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would be well below the ERPG-2 level of 150 ppm by volume. Table 5 presents the results of the 

predicted 1 hour maximum concentrations of NH3:

Table 5

Location Distance from NH3

Storage Enclosure (Feet)

ERPG-1 ERPG-2 NH3 Concentration 

(Maximum Hourly Value, 

ppm)

Power Plant North 

PCAP

230 25 150 20.2

Power Plant West 

PCAP

340 25 150 13.1

Power Plant East 

PCAP

450 25 150 4.4

Nearest Residence 

(Fort Avenue)

570 25 150 6.7

Salem Essex 

Sewerage District 

(SESD)

750 25 150 6.8

Table 5 Key:

PCAP = Projected Controlled Access Perimeter

ERPG-1 = Emergency Response Planning Guideline Level 1

ERPG-2 = Emergency Response Planning Guideline Level 2

NH3 = Ammonia

ppm = parts per million by volume

In addition, Section 112(r) of the Clean Air Act and associated EPA regulations at 40 

CFR Part 68 apply to owners or operators of stationary sources producing, processing, handling 

or storing toxic or flammable substances. The substances regulated under Section 112(r) and 

their threshold quantities are listed at Section 68.130 of 40 CFR Part 68. Although the proposed 

Facility will not store regulated substances above the threshold quantities, the general duty clause 

in Section 112(r)(1) applies:

“The owners and operators of stationary sources producing, processing, handling or 

storing hazardous substances have a general duty in the same manner and to the same extent as 

Section 654, Title 29 of the United States Code, to identify hazards which may result from 

accidental releases using appropriate hazard assessment techniques, to design and maintain a safe 

facility taking such steps as are necessary to prevent releases, and minimize the consequences of 

accidental releases which do occur.”

The Permittee shall take all steps necessary to meet the general duty clause above.
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4. EMISSION UNIT (EU) IDENTIFICATION

Each Emission Unit (EU) identified in Table 6 is subject to and regulated by this Plan 

Approval:

Table 6

EU# Description Design Capacity Pollution Control 

Device (PCD)

EU1 General Electric Model No. 107F Series 5

Combustion Turbine/Heat Recovery Steam Generator

Including Duct Burner

2,449 MMBtu/hr, 

HHV (energy 

input)

346 MW (electric 

power output)

Dry Low NOx

Combustors (PCD1)

Selective Catalytic 

Reduction (PCD2)

CO Oxidation Catalyst 

(PCD3)

EU2 General Electric Model No. 107F Series 5

Combustion Turbine/Heat Recovery Steam Generator

Including Duct Burner

2,449 MMBtu/hr, 

HHV (energy 

input)

346 MW (electric 

power output)

Dry Low NOx

Combustors (PCD4)

Selective Catalytic 

Reduction (PCD5)

CO Oxidation Catalyst 

(PCD6)

EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or 

equivalent

Auxiliary Boiler

80 MMBtu/hr, 

HHV (energy 

input)

Ultra Low NOx Burners

(PCD7)

EU4 Cummins Model No. DQFAA or equivalent

Emergency Engine/Generator

7.4 MMBtu/hr, 

HHV (energy 

input)

1102 bhp (engine 

mechanical power

output)

750 KW

(generator electric 

power output)

None

EU5 Cummins Model No. CFP9E-F50 or equivalent

Fire Pump Engine

2.7 MMBtu/hr, 

HHV (energy 

input)

371 bhp (engine 

mechanical power 

output)

None

Table 6 Key:

EU# = Emission Unit Number

No. = Number

MMBtu/hr = fuel heat input, million British thermal units per hour
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Proposed Plan Approval

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HHV = higher heating value basis

bhp = mechanical engine rating, brake horsepower

MW = generator net electrical output, Megawatts

KW = generator net electrical output, Kilowatts

NOx = Oxides of Nitrogen

CO = Carbon Monoxide

5. APPLICABLE REQUIREMENTS

A. OPERATIONAL, PRODUCTION and EMISSION LIMITS

The proposed Facility is subject to, and the Permittee shall ensure that the proposed 

Facility shall not exceed the Operational, Production, and Emission Limits as contained in Table 

7 below, including footnotes:

Table 7

EU# Operational / Production 

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and 

shutdowns

Fuel Heat Input Rate of 

each EU:

< 2,449 MMBtu per hour, 

HHV

Natural Gas shall be the 

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu, 

HHV per 12-month rolling 

period (9)

NOx (no duct firing) < 18.1 lb/hr (1, 2)

< 0.0074 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.051 lb/MW-hr (1, 2, 10, 14)

< 15.0 ppmvd @ 15% O2

or

< 0.43 lb/MW-hr (13)

NOx (duct firing) < 18.1 lb/hr (1, 2)

< 0.0074 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.055 lb/MW-hr (1, 2, 15)

< 15.0 ppmvd @ 15% O2

or

< 0.43 lb/MW-hr (13)

CO (no duct firing) < 11.0 lb/hr (1, 2)

< 0.0045 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.031 lb/MW-hr (1, 2, 10, 14)

CO (duct firing) < 11.0 lb/hr (1, 2)

< 0.0045 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.033 lb/MW-hr (1, 2, 15)
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Transmittal No. X254064

Application No. NE-12-022

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Table 7

EU# Operational / Production 

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and 

shutdowns

Fuel Heat Input Rate of 

each EU:

< 2,449 MMBtu per hour, 

HHV

Natural Gas shall be the 

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu, 

HHV per 12-month rolling 

period (9)

VOC (no duct firing),

as Methane (CH4)

< 3.0 lb/hr (1, 2)

< 0.0013 lb/MMBtu (1)

< 1.0 ppmvd @ 15% O2

(1)

< 0.009 lb/MW-hr (1, 2, 10, 14)

VOC (duct firing),

as Methane (CH4)

< 5.4 lb/hr (1, 2)

< 0.0022 lb/MMBtu (1)

< 1.7 ppmvd @ 15% O2

(1)

< 0.016 lb/MW-hr (1, 2, 15)

S in Fuel < 0.5 grains/100 scf

SO2 (no duct firing) < 3.7 lb/hr (1, 2)

< 0.0015 lb/MMBtu (1)

< 0.3 ppmvd @ 15% O2

(1)

< 0.010 lb/MW-hr (1, 2, 10, 14)

SO2 (duct firing) < 3.7 lb/hr (1, 2)

< 0.0015 lb/MMBtu (1)

< 0.3 ppmvd @ 15% O2

(1)

< 0.011 lb/MW-hr (1, 2, 15)

H2SO4 (no duct firing) < 2.3 lb/hr (1, 2)

< 0.0010 lb/MMBtu (1)

< 0.1 ppmvd @ 15% O2

(1)

< 0. 007 lb/MW-hr (1, 2, 10, 14)

H2SO4 (duct firing) < 2.3 lb/hr (1, 2)

< 0.0010 lb/MMBtu (1)

< 0.1 ppmvd @ 15% O2

(1)

< 0.008 lb/MW-hr (1, 2, 15)

PM/PM10/PM2.5 (no duct 

firing)

< 15.5 lb/hr (1, 2, 8)

< 0.0088 lb/MMBtu (1, 8)

< 0.044 lb/MW-hr (1, 2, 8, 10, 14)

PM/PM10/PM2.5 (duct firing) < 15.5 lb/hr (1, 2, 8)

< 0.0067 lb/MMBtu (1, 8)

< 0.049 lb/MW-hr (1, 2, 8, 15)

NH3 (no duct firing) < 6.6 lb/hr (1, 2)

< 0.0027 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.019 lb/MW-hr (1, 2, 10, 14)

NH3 (duct firing) < 6.6 lb/hr (1, 2)

< 0.0027 lb/MMBtu (1)

< 2.0 ppmvd @ 15% O2

(1)

< 0.020 lb/MW-hr (1, 2, 15)

Greenhouse Gases, CO2e < 825 lb/MW-hr (11)

< 895 lb/MW-hr (16)
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

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Table 7

EU# Operational / Production 

Limit

Air Contaminant Emission Limit

EU1, EU2 Operation at > MECL, (17)

excluding start-ups and 

shutdowns

Fuel Heat Input Rate of 

each EU:

< 2,449 MMBtu per hour, 

HHV

Natural Gas shall be the 

only fuel of use.

Fuel Heat Input of each EU:

< 18,888,480 MMBtu, 

HHV per 12-month rolling 

period (9)

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour 

(5)

Operation at < MECL 

during start-ups (3, 12)

Start-up duration:

< 45 minutes (3, 12)

Natural Gas shall be the 

only fuel of use.

NOx < 89 lb per event (4, 12)

CO < 285 lb per event (4, 12)

VOC,

as Methane (CH4)

< 23 lb per event (4, 12)

S in Fuel < 0.5 grains/100 scf

SO2 < 2.0 lb per event (4, 12)

H2SO4 < 1.3 lb per event (4, 12)

PM/PM10/PM2.5 < 7.3 lb per event (4, 8, 12)

NH3 NA

Opacity < 10% (5, 12)

Operation at < MECL 

during shutdowns (3, 12)

Shutdown duration:

< 27 minutes (3, 12)

Natural Gas shall be the 

only fuel of use.

NOx < 10 lb per event (12)

CO < 151 lb per event (12)

VOC,

as Methane (CH4)

< 29 lb per event (12)

S in Fuel < 0.5 grains/100 scf

SO2 < 0.3 lb per event (12)

H2SO4 < 0.2 lb per event (12)

PM/PM10/PM2.5 < 5.8 lb per event (8, 12)

NH3 NA

Opacity < 10% (5, 12)
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Table 7

EU# Operational / Production 

Limit

Air Contaminant Emission Limit

EU3 Operation at > MECL (18)

Fuel Heat Input Rate:

< 80 MMBtu per hour, 

HHV

Natural Gas shall be the 

only fuel of use.

Total Fuel Heat Input:

< 525,600 MMBtu, HHV 

per 12-month rolling period 

(9)

NOx < 0.88 lb/hr (1)

< 0.011 lb/MMBtu (1)

< 9.0 ppmvd @ 3% O2

(1)

CO < 2.8 lb/hr (1)

< 0.035 lb/MMBtu (1)

< 47 ppmvd @ 3% O2

(1)

VOC,

as Methane (CH4)

< 0.4 lb/hr (1)

< 0.005 lb/MMBtu (1)

< 11.8 ppmvd @ 3% O2

(1)

S in Fuel < 0.5 grains/100 scf

SO2 < 0.12 lb/hr (1)

< 0.0015 lb/MMBtu (1)

< 0.9 ppmvd @ 3% O2

(1)

H2SO4 < 0.009 lb/hr (1)

< 0.0001 lb/MMBtu (1)

< 0.05 ppmvd @ 3% O2

(1)

PM/PM10/PM2.5 < 0.4 lb/hr (1, 8)

< 0.005 lb/MMBtu (1, 8)

Greenhouse Gases, CO2e < 119.0 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour 

(5)

EU4 < 300 hours of operation 

per 12-month rolling period

Ultra Low Sulfur Diesel 

Fuel Oil shall be the only 

fuel of use.

NOx and VOC (NMHC as 

CH1.8),

Combined Total

< 11.60 lb/hr (6)

< 4.8 gm/bhp-hr (6)

< 6.4 gm/KW-hr (6)

CO < 6.34 lb/hr (6)

< 2.6 gm/bhp-hr (6)

< 3.5 gm/KW-hr (6)

S in Fuel < 0.0015% by weight

SO2 < 0.011 lb/hr (6)

H2SO4 < 0.0009 lb/hr (6)

PM/PM10/PM2.5 < 0.36 lb/hr (6)

< 0.15 gm/bhp-hr (6)

< 0.2 gm/KW-hr (6)

Greenhouse Gases, CO2e < 162.85 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour
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Table 7

EU# Operational / Production 

Limit

Air Contaminant Emission Limit

EU5 < 300 hours of operation 

per 12-month rolling period

Ultra Low Sulfur Diesel 

Fuel Oil shall be the only 

fuel of use.

NOx and VOC (NMHC as 

CH1.8),

Combined Total

< 2.44 lb/hr (6)

< 3.0 gm/bhp-hr (6)

< 4.0 gm/KW-hr (6)

CO < 2.14 lb/hr (6)

< 2.6 gm/bhp-hr (6)

< 3.5 gm/KW-hr (6)

S in Fuel < 0.0015% by weight

< 300 hours of operation 

per 12-month rolling period

Ultra Low Sulfur Diesel 

Fuel Oil shall be the only 

fuel of use.

SO2 < 0.004 lb/hr (6)

H2SO4 < 0.0003 lb/hr (6)

PM/PM10/PM2.5 < 0.12 lb/hr (6)

< 0.15 gm/bhp-hr (6)

< 0.2 gm/KW-hr (6)

Greenhouse Gases, CO2e < 162.85 lb/MMBtu

Opacity < 5%, except 5% to < 10% for

< 2 minutes during any one hour

EU1, EU2, 

EU3, EU4, 

EU5

NA Smoke 310 CMR 7.06 (1)(a)

Facility-Wide NA NOx < 144.8 TPY (7)

CO < 106.4 TPY (7)

VOC < 28.0 TPY (7)

SO2 < 28.8 TPY (7)

PM/PM10/PM2.5 < 109.4 TPY (7, 8)

NH3 < 51.0 TPY (7)

H2SO4 < 18.8 TPY (7)

Pb < 0.00013 TPY (7)

Formaldehyde or Single HAP < 6.6 TPY (7)

Total HAPs < 13.1 TPY (7)

CO2 < 2,277,333 TPY (7)

Greenhouse Gases, CO2e < 2,279,530 TPY (7)

Table 7 Notes:

1. Emission limits are one hour block averages and do not apply during start-ups and shutdowns.

2. Emission rates are based on burning natural gas in any one combustion turbine at a maximum natural gas 

firing rate of 2,449 MMBtu/hr, HHV, at 90 oF ambient temperature, 14.7 psia ambient pressure, and 60% ambient 

relative humidity (combustion turbine and duct burner combined). These constitute worst case emissions.

3. Start-ups include the time from flame-on in the combustor (after a period of downtime) until the minimum 

emissions compliance load (MECL) is reached. Shutdowns include the time from dropping below the MECL until 

flame-out.

4. Emission limits represent worst case emissions for cold start-ups. Emissions for warm and hot start-ups are 
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expected to be lower.

5. Opacity emission limits are one minute block averages.

6. Emission limits are one hour block averages and apply throughout the operating range, including during startup and shutdown. Emissions are based on manufacturer’s certifications using gaseous testing procedures in accordance 

with 40 CFR Part 89. VOC emissions are assumed to be equivalent to NMHC emissions. In accordance with the 

calculations found at 40 CFR 89.424 for No. 2 diesel fuel oil exhaust, NMHC mass emissions are calculated by 

assuming that each carbon atom is accompanied (using a weighted average) by 1.8 atoms of hydrogen (i.e. NMHC as 

CH1.8), which corresponds to a gas density of 0.5746 kg/m3.

7. Facility emissions include the two CTG/HRSG pairs with duct burners (EU1 and EU2), the auxiliary boiler 

(EU3), the emergency diesel engine/generator set (EU4), the fire pump engine (EU5), and the auxiliary cooling tower.

Emissions, except CO emissions, for each of EU1 and EU2 are based on 8,040 hours of natural gas firing per 12 

month rolling period at 100% load and 50oF ambient temperature with no duct burner firing (2,130 MMBtu/hr, 

HHV) or evaporative cooling, and 720 hours of natural gas firing per 12 month rolling period at peak load 

(approximately 102% load) and 90oF ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV)

and evaporative cooling, and include start-up and shutdown emissions. Worst case CO emissions for each of EU1 and 

EU2 are based on a typical annual operating scenario of 3,272 hours at full load and different seasonal emission rates 

depending on heat input rates, ambient temperatures, and duct burner/evaporative cooling status, and 36, 166, and 4 

cold, warm, and hot start-up/shutdown cycles, respectively. Emissions for EU3 are based on 6,570 hours of natural gas 

firing per 12 month rolling period at 100% load (80 MMBtu/hr, HHV). Emissions for each of EU4 and EU5 are 

based on restricted operation of 300 hours per unit, including maintenance and periodic readiness testing, while firing 

ULSD having a sulfur content that does not exceed 0.0015% by weight. Worst case NOx and VOC emissions for EU4 

are assumed to be emitted at the EPA Tier 2 limit of 6.4 gm/KW-hr and the EPA Tier 1 limit of 1.3 gm/KW-hr, 

respectively. Worst case NOx and VOC emissions for EU5 are assumed to be emitted at the EPA Tier 3 limit of 4.0 

gm/KW-hr and the EPA Tier 1 limit of 1.3 gm/KW-hr, respectively. EPA Tier 1, 2, and 3 emission standards are 

published in the United States Code of Federal Regulations, Title 40, Part 89 [40 CFR Part 89]. There are no NH3

emissions from the auxiliary boiler, emergency engine/generator set, fire pump engine, and auxiliary cooling tower. 

The auxiliary cooling tower contributes to PM/PM10/PM2.5 emissions only based on 8,760 hours of operation per 12 

month rolling period.

8. Emission limit is for the sum of filterable and condensable particulates, including sulfates.

9. Maximum fuel (natural gas only) heat input for each CTG/HRSG with duct burner is based on 8,040 hours 

of operation per 12 month rolling period at 100% load and 50oF ambient temperature with no duct burner firing 

(2,130 MMBtu/hr, HHV), and 720 hours of operation per 12 month rolling period at peak load (approximately 102% 

load) and 90oF ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV). Maximum total fuel 

heat input for the auxiliary boiler is based on 6,570 hours of operation per 12 month rolling period at 100% load (80 

MMBtu/hr, HHV).

10. Emission limit is based on full (base) load (100% load) ISO corrected (59 oF, 14.7 psia, 60% humidity) heat 

rate of 6,940 Btu, higher heating value, per KW-hr net electrical output to the grid.

11. Emission limit is based on full (base) load (100% load) without duct firing ISO corrected (59 oF, 14.7 psia, 

60% humidity) heat rate of 6,940 Btu, higher heating value, per KW-hr net electrical output to the grid and the EPA 

40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu. Compliance shall be determined during the initial 

emissions compliance test performed within 180 days after initial firing of the EU. If the EU does not meet this 

limit, then the Permittee shall remedy the EU’s failure to meet this limit, and shall not combust fuel in the EU until 

the Permittee has shown compliance with this limit during a subsequent emissions compliance test.

12. Start-up and shutdown emission limits and duration are subject to revision by MassDEP based on review of 

compliance testing (stack testing) data and CEMs/COMs data generated from the first year of commercial operation.

13. NOx emission limits are from 40 CFR Part 60 Subpart KKKK. Compliance with the more stringent LAER 

NOx emission limits of this Plan Approval shall be deemed compliance with the NOx limits from 40 CFR Part 60 
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Subpart KKKK.

14. Limit is based on an initial compliance test at full (base) (100% load) with no duct firing. Compliance 

demonstration shall be made by emissions compliance testing within 180 days after initial firing of each EU.

15. Limit is based on an initial compliance test at peak load (approximately 102% load) with 100% duct firing. 

Compliance demonstration shall be made by emissions compliance testing within 180 days after initial firing of each 

EU.

16. Emission limit is effective 365 days after initial firing of the EU and is based on a 365 day rolling average, 

net electrical output to the grid and the EPA 40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu. A new 

365 day rolling average emission rate shall be calculated each day by calculating the arithmetic average of all hourly 

emission rates for the preceding 365 days, excluding the hours in which the EU was not operating. Hourly CO2 mass 

emissions (lb) shall be calculated by obtaining monitored and recorded actual hourly heat input (MMBtu) and 

multiplying by the EPA 40 CFR Part 75 default CO2 emission factor of 118.9 lb/MMBtu.

17. Minimum Emissions Compliance Load (MECL) for EU1 and EU2 shall be a function of ambient 

temperature and other system parameters.

18. MECL for EU3 shall be determined during the initial emissions compliance testing to be performed within 

180 days after initial firing of EU3.

Table 7 Key:

EU# = Emission Unit Number

No. = Number

NOx = Nitrogen Oxides

CO = Carbon Monoxide

VOC = Volatile Organic Compounds

NMHC = Non-Methane Hydrocarbons

S = Sulfur

SO2 = Sulfur Dioxide

PM = Total Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in diameter

PM2.5 = Particulate Matter less than or equal to 2.5 microns in diameter

NH3 = Ammonia

H2SO4 = Sulfuric Acid

Pb = Lead

HAP = Hazardous Air Pollutants

CO2 = Carbon Dioxide

CO2e = Greenhouse Gases expressed as Carbon Dioxide equivalent and calculated by multiplying each of the six 

greenhouse gases (Carbon Dioxide, Nitrous Oxide, methane, Hydrofluorocarbons, Perfluorocarbons, Sulfur 

Hexafluoride) mass amount of emissions, in tons per year, by the gas’s associated global warming potential 

published at Table A-1 of 40 CFR Part 98, Subpart A and summing the six resultant values.

lb = pounds

lb/hr = pounds per hour

MMBtu = million British thermal units, higher heating value (HHV) basis

lb/MMBtu = pounds per million British thermal units

ppmvd @ 15% O2 = parts per million by volume, dry basis, corrected to 15 percent oxygen

ppmvd @ 3% O2 = parts per million by volume, dry basis, corrected to 3 percent oxygen

scf = standard cubic feet

kg/m3= kilograms per cubic meter

% = percent

gm/KW-hr = grams per Kilowatt-hour

lb/MW-hr = pounds per Megawatt-hour net electrical output to the grid

Btu/KW-hr = British thermal units per Kilowatt-hour net electrical output to the grid
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TPY = tons per 12-month rolling period

oF = degrees Fahrenheit

psia = pounds per square inch, absolute

EPA = Unites States Environmental Protection Agency

CFR = Code of Federal Regulations

ISO = International Organization for Standardization

CTG/HRSG = combustion turbine generator/heat recovery steam generator

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015 weight percent sulfur

CEMS = Continuous Emission Monitoring Systems

COMS = Continuous Opacity Monitoring Systems

HHV = higher heating value basis

MECL = minimum emissions compliance load

< = less than

> = greater than

< = less than or equal to

> = greater than or equal to

NA = Not Applicable

B. NEW SOURCE PERFORMANCE STANDARDS (NSPS)

Stationary Combustion Turbines/Heat Recovery Steam Generators/Duct Burners (EU1 and EU2)

The NSPS, 40 CFR Part 60 Subpart KKKK, apply to stationary combustion turbines with a 

heat input rating greater than or equal to 10 MMBtu/hr, and which commenced construction, 

reconstruction, or modification after February 18, 2005. The NSPS, 40 CFR Part 60 Subpart 

KKKK, also apply to emissions from any associated HRSGs or duct burners, and therefore includes 

both the combustion turbines and the duct burners (EU1 and EU2) at the proposed Facility.

These NSPS allow the turbine owner or operator the choice of either a concentration based 

or output based NOx emission standard. The concentration based limit is expressed in units of 

ppmvd @ 15% O2. The output based emission limit is expressed in units of mass emissions per unit 

of useful recovered energy, nanograms per Joule (ng/J), or lb/MW-hr. The applicable NOx emission 

standard for EU1 and EU2 is 15 ppmvd @ 15% O2 or 54 ng/J of useful output (0.43 lb/MW-hr). 

The Permittee has ensured that the proposed Facility will comply with these limits through the use 

of dry low-NOx combustion technology in conjunction with SCR add-on NOx control technology to 

control NOx emissions to 2.0 ppmvd @ 15% O2 and 0.051 lb/MW-hr during natural gas firing, well 

below the NSPS limits.

The NSPS for SO2 emissions are the same for all turbines regardless of size or fuel type. The 

NSPS for turbines located in the continental area prohibits the discharge into the atmosphere of any 

gases that contain SO2 in excess of 110 ng/J (0.90 lb/MW-hr) gross energy output. The owner or 

operator of the turbine can choose to comply with either the SO2 limit or the limit on the sulfur 

content of the fuel burned. For a turbine located in a continental area, the fuel sulfur content limit is 

26 ng/J (0.060 lb SO2/MMBtu) heat input. The Permittee will meet the NSPS for SO2 by burning 

natural gas with sulfur content not exceeding 0.5 grains sulfur per 100 standard cubic feet of gas 

fired (0.0015 lb SO2/MMBtu), well below the NSPS limit.

The Permittee shall comply with all applicable emission standards, monitoring, record 

keeping, and reporting requirements of 40 CFR Part 60 Subpart KKKK for EU1 and EU2.
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Auxiliary Boiler (EU3)

The NSPS, 40 CFR Part 60 Subpart Dc, apply to steam generating units for which 

construction commenced after June 9, 1989, and that have a heat input rating of between 10 and 100 

MMBtu/hr. Based on the design heat input rating of 80 MMBtu/hr, HHV, the NSPS, 40 CFR Part 

60 Subpart Dc, apply to the natural gas fired auxiliary boiler (EU3) at the Facility. For natural gas 

fired boilers, the NSPS does not impose specific emission limits.

The Permittee shall comply with all applicable monitoring, record keeping, and reporting 

requirements of 40 CFR Part 60 Subpart Dc for EU3.

Emergency Engine/Generator and Fire Pump Engine (EU4 and EU5)

The emergency generator (EU4) and fire pump (EU5) engines serving the Proposed Facility 

will both be subject to the NSPS under 40 CFR Part 60 Subpart IIII. The NSPS requires emergency 

generator engines to meet the non-road engine emission standards identified in 40 CFR Part 89.112 

and 89.113. The fire pump engine will be subject to the emission standards identified in 40 CFR 

Part 60 Subpart IIII, Table 4. The NSPS require engine manufacturers to produce engines that 

comply with these standards. The Permittee shall install emergency generator and fire pump engines 

serving EU4 and EU5 that comply with the 40 CFR Part 60 Subpart IIII requirements.

The Permittee shall comply with all applicable emission standards, operating restrictions, 

monitoring, record keeping, and reporting requirements of 40 CFR Part 60 Subpart IIII for EU4 

and EU5.
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C. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS

(NESHAP) for the following Source Categories

Stationary Combustion Turbines/Heat Recovery Steam Generators/Duct Burners (EU1 and EU2)

The NESHAP at 40 CFR Part 63 Subpart YYYY apply to combustion turbines at major 

sources of hazardous air pollutant (HAP) emissions. A major source of HAP emissions is a 

source which has the potential to emit ten (10) or more tons per year of any single HAP, or 

twenty five (25) or more tons per year of all HAPs combined. The proposed Facility is not a 

major source of HAP emissions. Therefore, the proposed Facility’s combustion turbines are not 

subject to the 40 CFR Part 63 Subpart YYYY requirements.

The proposed Facility’s duct burners are considered “steam electric generating units” 

under the NESHAP. Steam electric generating units are regulated under 40 CFR Part 63 Subpart 

UUUUU. However, the NESHAP at 40 CFR Part 63 Subpart UUUUU only apply to coal and 

oil-fired steam electric generating units, and not to gas fired units such as the proposed Facility 

duct burners. Therefore, the duct burners are not subject to the 40 CFR Part 63 Subpart UUUUU

requirements.

Auxiliary Boiler (EU3)

The NESHAP at 40 CFR Part 63 Subpart DDDDD for industrial, commercial, and 

institutional boilers apply only to major sources of HAP emissions. However, the Facility is not a 

major source of HAP emissions. Therefore, EU3 is not subject to the 40 CFR Part 63 Subpart 

DDDDD requirements.

The NESHAP at 40 CFR Part 63 Subpart JJJJJJ for industrial, commercial, and 

institutional boilers apply to area (or minor) sources of HAP emissions, but do not include 

natural gas fired boilers. Since the auxiliary boiler shall fire natural gas only, it is not subject to 

the 40 CFR Part 63 Subpart JJJJJJ requirements.

Emergency Engine/Generator and Fire Pump Engine (EU4 and EU5)

The NESHAP at 40 CFR Part 63 Subpart ZZZZ, for stationary reciprocating internal 

combustion engines (RICE) apply to both major and area sources of HAP emissions, and covers 

both emergency and non-emergency engines. Both EU4 and EU5 have stationary emergency 

engines that are subject to 40 CFR Part 63 Subpart ZZZZ. However, for new stationary emergency 

engines at area sources of HAP emissions that began construction or reconstruction after June 12, 

2006, the NESHAP requirements are satisfied if the engines comply with the NSPS requirements 

under 40 CFR Part 60 Subpart IIII. The Permittee shall install emergency generator and fire pump 

engines serving EU4 and EU5 that comply with the 40 CFR Part 60 Subpart IIII requirements.

D. ALLOWANCES

The Permittee’s proposed Facility is subject to various emission allowance programs. 

Emission allowance programs are market based air quality regulatory programs for which 
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Application No. NE-12-022

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various classes of emission sources are required to obtain, secure, and/or hold a sufficient 

number of “allowances” to cover actual reported emissions emanating therefrom. Allowances are 

measured in “tons” of emissions (one allowance equals one ton of emissions). At specified 

intervals, “true-up” occurs at which time allowances in the Permittee’s account are withdrawn to 

cover actual emissions over a specified time period. The Permittee is required to hold a sufficient 

number of allowances to cover reported emissions from the proposed Facility for the applicable 

time period as of the “true-up” date. The true-ups are done on a facility-wide basis, for emissions 

from all subject emission units at the proposed Facility. True-ups for annual SO2 and ozone 

season NOx (May through September) emissions are done annually. True-up for CO2 emissions 

is done every three years.

These allowance programs require that actual facility emissions of SO2, NOx, and CO2 ( 

see Table 7, footnote 16) be monitored, recorded, and reported pursuant to documented 

monitoring plans and the regulatory provisions of 40 CFR Part 75.

Table 8 below contains the Permittee’s applicable allowance programs for each pollutant, 

including the applicable regulation(s) and subject EUs at the proposed Facility covered in this 

Proposed Plan Approval.

Table 8

Pollutant Program Applicable 

Regulation

Subject Facility Emission 

Units

SO2 Acid Rain 

Program (ARP)

40 CFR Parts 

72, 73, and 75

EU1, EU2

NOx NOx Ozone 

Season Clean Air 

Interstate Rule 

(CAIR)

310 CMR 7.32 EU1, EU2

CO2 Regional 

Greenhouse Gas 

Initiative (RGGI)

CO2 Budget 

Trading Program

(State Only 

Requirement)

310 CMR 7.70 EU1, EU2

Table 8 Key:

EU = Emission Unit

ARP = Acid Rain Program

CAIR = Clean Air Interstate Rule

RGGI = Regional Greenhouse Gas Initiative

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

SO2 = Sulfur Dioxide

NOx = Nitrogen Oxides

CO2 = Carbon Dioxide
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Transmittal No. X254064

Application No. NE-12-022

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The Permittee shall submit to MassDEP:

1. A Phase II Acid Rain Permit Application at least 24 months prior to commencement of 

commercial operation of any subject emission unit;

2. A CAIR Permit Application at least 18 months prior to commencement of commercial 

operation of any subject emission unit; and,

3. A CO2 Budget Emission Control Plan (ECP) at least 12 months prior to commencement 

of commercial operation of any subject emission unit.

E. COMPLIANCE DEMONSTRATION

The proposed Facility is subject to, and the Permittee shall ensure that the proposed 

Facility shall comply with, the monitoring, testing, record keeping, and reporting requirements as 

contained in Tables 9, 10, and 11 below:

Table 9

EU# Monitoring and Testing Requirements

EU1, 

EU2, EU3

1. The Permittee shall ensure that the proposed Facility is constructed to accommodate the 

emissions (compliance) testing requirements as stipulated in 40 CFR Part 60 Appendix A. The 

two outlet sampling ports (90 degrees apart from each other) for each emission unit must be 

located at a minimum of one duct diameter upstream and two duct diameters downstream of 

any flow disturbance. In addition, the Permittee shall facilitate access to the sampling ports and 

testing equipment by constructing platforms, ladders, or other necessary equipment.

2. The Permittee shall ensure that compliance testing of the proposed Facility is completed 

within 180 days after initial firing of each EU to demonstrate compliance with the emission 

limits specified in Table 7 of this Proposed Plan Approval. All emissions testing shall be 

conducted in accordance with MassDEP’s “Guidelines for Source Emissions Testing” and in 

accordance with EPA reference test methods as specified in 40 CFR Part 60, Appendix A, 40 

CFR Part 60 Subpart KKKK, 40 CFR Parts 72 and 75, or by another method which has been 

approved in writing by MassDEP. The Permittee shall schedule the compliance testing such that 

MassDEP personnel can witness it.
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Transmittal No. X254064

Application No. NE-12-022

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Table 9

EU# Monitoring and Testing Requirements

EU1, 

EU2, EU3

3. The Permittee shall conduct initial compliance tests of the proposed Facility to document 

actual emissions of EU1, EU2, and EU3 so as to determine their compliance status versus the 

emission limits (in lb/hr, lb/MMBtu, ppmvd, and lb/MW-hr, as applicable) in Table 7 for the 

pollutants listed below.

Testing for these pollutants for EU1 and EU2 as specified below shall be conducted at four (4) 

load conditions that cover the entire normal operating range: the minimum emissions 

compliance load (MECL); 75 percent load; 100 percent (base) load without duct firing; and 

peak (approximately 102 percent load) with 100 percent duct firing.

NOx, CO, VOC, SO2, PM, PM10, PM2.5, NH3, CO2, H2SO4, opacity

Testing for these pollutants for EU3 as specified below shall be conducted at four (4) load 

conditions that cover the entire normal operating range: the MECL (to be determined during the 

compliance test); 50 percent load; 75 percent load; and 100 percent load.

NOx, CO, VOC, SO2, PM, PM10, PM2.5, H2SO4, opacity

4. The above referenced emissions testing shall include testing to develop a correlation 

between CO and VOC emissions for EU1 and EU2; parametric monitoring testing for PM, 

PM10, and PM2.5 emissions for EU1 and EU2; and NOx/CO emissions optimization testing 

for EU3.

5. The Permittee shall conduct NOx/CO optimization on, and tune, EU3 according to 

procedures contained in EPA 340/1-83-023 “Combustion Efficiency Optimization Manual 

for Operators of Oil and Gas Fired Boilers” with the goal of reducing air pollutant emissions 

to optimum levels. In addition, the Permittee shall tune EU3 in accordance with said 

procedures and inspect and maintain EU3 per manufacturer recommendations as well as test 

EU3 for efficient operation on an annual basis. The Permittee shall allow MassDEP 

personnel to witness tuning of EU3 if and when requested by MassDEP.

6. The Permittee shall install, calibrate, test, and operate a Data Acquisition and Handling 

System(s) (DAHS), CEMS, and COMS serving EU1 and EU2 to measure and record the 

following emissions:

a) O2; b) NOx; c) CO; e) NH3; d) opacity.

The Permittee shall install, calibrate, test, and operate a DAHS and COMS to measure and 

record opacity on EU3.

7. The Permittee shall ensure that all emission monitors and recorders serving EU1, EU2 and 

EU3 comply with MassDEP approved performance and location specifications, and conform 

with the EPA monitoring specifications at 40 CFR 60.13 and 40 CFR Part 60 Appendices B 

and F, and all applicable portions of 40 CFR Parts 72 and 75, 310 CMR 7.32, and 310 CMR 

7.70, as applicable.

8. The Permittee shall ensure that the subject CEMS and COMS are equipped with properly 

operated and properly maintained audible and visible alarms to activate whenever emissions 

from the Facility exceed the limits established in Table 7 of this Plan Approval.
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Transmittal No. X254064

Application No. NE-12-022

Page 36 of 59

Table 9

EU# Monitoring and Testing Requirements

EU1, 

EU2, EU3

9. The Permittee shall operate each CEMS and/or COMS serving EU1, EU2 and EU3 at all 

times except for periods of CEMS and COMS calibration checks, zero and span adjustments, 

preventative maintenance, and periods of unavoidable malfunction.

10. The Permittee shall obtain and record emissions data from each CEMS and/or COMS 

serving EU1, EU2 and EU3 for at least seventy (75) percent of each emission unit’s 

operating hours per day, for at least seventy five (75) percent of each emission unit’s 

operating hours per month, and for at least ninety five (95) percent of each emission unit’s 

operating hours per quarter, except for periods of CEMS and COMS calibration checks, zero 

and span adjustments, and preventive maintenance.

11. All periods of excess emissions occurring at the Facility, even if attributable to an 

emergency/malfunction, start-up/shutdown or equipment cleaning, shall be quantified and 

included by the Permittee in the compilation of emissions and determination of compliance 

with the emission limits as stated in Table 7 of this Plan Approval. (“Excess Emissions” are 

defined as emissions which are in excess of the emission limits as stated in Table 7). An 

exceedance of emission limits in Table 7 due to an emergency or malfunction shall not be 

deemed a federally permitted release as that term is used in 42 U.S.C. Section 9601(10).

12. The Permittee shall use and maintain its CEMS and/or COMS serving EU1, EU2 and 

EU3 as “direct-compliance” monitors to measure NOx, CO, NH3, O2, and/or opacity. 

“Direct-compliance” monitors generate data that legally documents the compliance status of 

a source.

13. The Permittee shall develop a quality assurance/quality control (QA/QC) program for the 

long-term operation of the CEMS and/or COMS serving EU1, EU2 and EU3 so as to 

conform with 40 CFR Part 60 Appendices B and F, all applicable portions of 40 CFR Parts 

72 and 75, 310 CMR 7.32, and 310 CMR 7.70.

14. The Permittee shall install, operate, and maintain a fuel metering device and recorder for 

EU1, EU2 and EU3 that records natural gas consumption in standard cubic feet (scf).

15. The Permittee shall monitor fuel heat input rate (MMBtu/hr, HHV) and total fuel heat 

input (MMBtu) for EU1, EU2, and EU3.

16. The Permittee shall monitor each date and daily hours of operation and total hours of 

operation for EU1, EU2, and EU3 per month and twelve month rolling period.

EU1, EU2 17. The Permittee shall ensure that initial compliance tests of the proposed Facility are 

conducted for “hot start”, “warm start”, “cold start”, and shutdown periods as defined in the 

Permittee’s Application for EU1 and EU2. These compliance tests shall represent periods of 

operation below the MECL for EU1 and EU2. Emission data generated from this testing 

shall be made available for review by MassDEP prior to determining and approving the 

maximum allowable emission limits for all pollutants listed in Table 7 (lb per event) and 

opacity limits, for these periods of time. MassDEP will incorporate these emission limits into 

a Final Plan Approval for the as-built Facility upon issuance and such limits shall be 

considered enforceable.

18. Whenever either combustion turbine is operating below the MECL for start-up and 

shutdown, the VOC emissions shall be considered as occurring at the rate determined in the 

most recent compliance test for start-up/shutdown conditions.
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Transmittal No. X254064

Application No. NE-12-022

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Table 9

EU# Monitoring and Testing Requirements

EU1, EU2 19. If either combustion turbine is operating at the MECL or greater, and if its CO emissions 

are below the CO emission limit at the given combustion turbine operating conditions, its 

VOC emissions shall be considered as meeting the emission limits contained in this 

Proposed Plan Approval, subject to correlation as contained in Condition 20 below.

20. If either combustion turbine is operating at the MECL or greater, and if its CO emissions 

are above the CO emission limit at the given combustion turbine operating conditions, its 

VOC emissions shall be considered as occurring at a rate determined by the equation: 

VOCactual = VOClimit x (COactual/COlimit), pending the outcome of compliance testing, after 

which a VOC/CO correlation curve for each combustion turbine will be developed and used 

for VOC compliance determination purposes.

21. The Permittee shall monitor the natural gas consumption of EU1 and EU2 in accordance 

with 40 CFR Part 60 Subpart KKKK utilizing a continuous monitoring system accurate to +

5 percent, and as approved by MassDEP.

22. The Permittee shall monitor the sulfur content of the natural gas combusted by EU1 and 

EU2 in accordance with 40 CFR Part 60 Subpart KKKK, or pursuant to any alternative fuel 

monitoring schedule issued in accordance with 40 CFR Part 60 Subpart KKKK.

23. The Permittee shall install and operate continuous monitors fitted with alarms to monitor 

continuously the temperatures at the inlets to the SCR and CO catalysts serving EU1 and 

EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambient 

temperatures for EU1 and EU2.

24. The Permittee shall install and operate high and low level audible alarm monitors on the 

NH3 storage tank and shall ensure that they are properly maintained.

25. The Permittee shall monitor the load, start-up and shutdown duration, and mass 

emissions (lb/event) during start-up and shutdown periods of EU1 and EU2.

26. The Permittee shall monitor the operation of EU1 and EU2, in accordance with the 

surrogate methodology or parametric monitoring developed during the most recent 

compliance test concerning PM, PM10, and PM2.5 emission limits.

27. The Permittee shall monitor the SO2 and CO2 emissions in accordance with 40 CFR Part 

75.

28. The Permittee shall monitor the Greenhouse Gas emission rate utilizing the calculation 

procedures in 40 CFR Part 98 Subpart A, Table A-1.

29. The Permittee shall continuously monitor the net electrical output to the grid of the 

proposed Facility.

EU4, EU5 30. The Permittee shall equip, operate, and maintain non-resettable hour meters on the 

emergency generator and fire pump engines in order to monitor the hours of operation of 

each emission unit.

31. The Permittee shall monitor the quantity and sulfur content of ULSD fuel oil burned in 

EU4 and EU5.

FacilityWide32. The Permittee shall monitor all operations to ensure sufficient information is available to 

comply with 310 CMR 7.12 Source Registration.

33. If and when MassDEP requires it, the Permittee shall conduct compliance testing in 

accordance with EPA Reference Test Methods and 310 CMR 7.13.
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Transmittal No. X254064

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Page 38 of 59

Table 9 Key:

EU# = Emission Unit Number

EPA = United States Environmental Protection Agency

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

DAHS = Data Acquisition and Handling System

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

QA/QC = Quality Assurance/Quality Control

O2 = Oxygen

NOx = Nitrogen Oxides

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

CO2 = Carbon Dioxide

SO2 = Sulfur Dioxide

H2SO4 = Sulfuric Acid

lb = pounds

lb/hr = pounds per hour

lb/MMBtu = pounds per million British thermal units

ppmvd = parts per million by volume, dry basis

lb/MW-hr = pounds per MW-hr net electrical output to the grid

scf = standard cubic feet

MMBtu/hr = million British thermal units per hour

MMBtu = million British thermal units

HHV = higher heating value basis

MECL = Minimum Emissions Compliance Load

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015weight percent sulfur

Table 10

EU# Record Keeping Requirements

EU1, 

EU2, EU3

1. The Permittee shall maintain records of each emission unit’s hourly fuel heat input rate 

(MMBtu/hr, HHV), total fuel heat input (MMBtu), and natural gas consumption (scf) per 

month and twelve month rolling period basis.

2. The Permittee shall maintain records of each date and daily hours of operation and total 

hours of operation of each EU per month and twelve month rolling period.

3. The Permittee shall maintain on-site permanent records of output from all continuous 

monitors (including CEMS and COMS) for flue gas emissions and natural gas consumption

(scf).

4. The Permittee shall maintain a log to record problems, upsets or failures associated with 

the subject emission control systems, DAHS, CEMS, and/or COMS serving EU1, EU2, and 

EU3, and the NH3 handling system serving EU1 and EU2.

EU1, EU2 5. The Permittee shall continuously estimate and record VOC emissions on the DAHS using the 

CO/VOC correlation curve developed from the most recent compliance test.

6. The Permittee shall continuously estimate and record PM, PM10, and PM2.5 emissions on the 

DAHS using the surrogate methodology or parametric monitoring derived from the most recent 

compliance test.
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Transmittal No. X254064

Application No. NE-12-022

Page 39 of 59

Table 10

EU# Record Keeping Requirements

EU1, EU2 7. The Permittee shall maintain records of the load, start-up and shutdown duration, and 

mass emissions (lb/event) during start-up and shutdown periods of EU1 and EU2.

8. The Permittee shall maintain records of net electrical output to the grid from the Facility 

on a daily basis.

9. The Permittee shall maintain records of the sulfur content of the natural gas combusted by 

EU1 and EU2 at the frequency required pursuant to 40 CFR Part 60 Subpart KKKK, or 

pursuant to any alternative fuel monitoring schedule issued in accordance with 40 CFR Part 

60 Subpart KKKK.

10 The Permittee shall record SO2 and CO2 emissions from EU1 and EU2 in accordance 

with 40 CFR Part 75.

11. The Permittee shall record the Greenhouse Gas emission rate of EU1 and EU2 on a daily 

basis utilizing the calculation procedures in 40 CFR Part 98 Subpart A, Table A-1.

12. The Permittee shall maintain continuous records of SCR and CO control system inlet 

temperatures, combustion turbine inlet temperatures and ambient temperatures.

13. The Permittee shall maintain the SOMP for the NH3 handling system serving EU1 and 

EU2 in a convenient location and make them readily available to all employees.

EU3 14. The Permittee shall record and post conspicuously on or near EU3 the results of annual 

inspections, maintenance, and testing and the date(s) upon which it was performed.

EU4, EU5 15. The Permittee shall maintain a record of the quantity of ULSD fuel oil combusted in, and

the total hours of operation of, EU4 and EU5 per month and per 12-month rolling period.

16. The Permittee shall maintain a record of the sulfur content of each ULSD fuel oil delivery at 

the Facility.

17. The Applicant shall maintain records concerning engine certifications as described in 310 

CMR 7.26 (42)(e)1. at the Facility.

FacilityWide18. A record keeping system for the Facility shall be established and maintained up-to-date 

by the Permittee such that year-to-date information is readily available. Record keeping 

shall, at a minimum, include:

a) Compliance records sufficient to document actual emissions from the Facility in order to 

determine compliance with what is allowed by this Proposed Plan Approval. Such records 

shall include, but are not limited to, fuel usage rates, emissions test results, monitoring 

equipment data and reports;

b) Maintenance: A record of routine maintenance activities performed on the subject 

emission units’ control equipment and monitoring equipment at the Facility including, at a 

minimum, the type or a description of the maintenance performed and the date(s) and time(s) 

the work was commenced and completed; and,

c) Malfunctions: A record of all malfunctions on the subject emission units’ control and 

monitoring equipment at the Facility including, at a minimum: the date and time the 

malfunction occurred; a description of the malfunction and the corrective action taken; the 

date and time corrective actions were initiated; and the date and time corrective actions were 

completed.
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Transmittal No. X254064

Application No. NE-12-022

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Table 10

EU# Record Keeping Requirements

FacilityWide19. The Permittee shall maintain all records required by 310 CMR 7.32, 310 CMR 7.70, 310 

CMR 7.71 (Reporting of Greenhouse Gas Emissions), and 40 CFR Part 98 (Mandatory 

Greenhouse Gas Emissions Reporting) at the Facility.

20. The Permittee shall maintain monthly records to demonstrate the Facility’s compliance 

status regarding the Facility-Wide emission limits (TPY) specified in Table 7. Records shall 

include actual emissions for the month as well as for the previous 11 months. (The MassDEP 

approved format can be downloaded at 

http://www.mass.gov/eea/agencies/massdep/air/approvals/limited-emissions-record-keepingand-reporting.html#WorkbookforReportingOn-SiteRecordKeeping in Microsoft Excel 

format.)

21. The Permittee shall maintain a copy of this Plan Approval, underlying Application, and 

the most up-to-date Standard SOMP for each emission unit and PCD approved herein onsite.

22. The Permittee shall maintain a complaint log concerning emissions, odor, and noise from 

the Facility. The Permittee shall make available to the general public a telephone number 

which receives and records complaints concerning the Facility 24 hours per day, 7 days per 

week. The complaint log shall be maintained for the most recent five (5) year period. The 

complaint log shall be made available to the public or MassDEP upon request. The Permittee 

shall take all reasonable actions to respond to said complaints in a timely manner.

23. The Permittee shall maintain records for the annual preparation of a Source 

Registration/Emission Statement Form in accordance with 310 CMR 7.12.

24. The Permittee shall maintain records of monitoring and testing as required by Table 9. 

All records required by this Plan Approval shall be kept on site for five (5) years and made 

available for inspection by MassDEP or EPA upon request.

Table 10 Key:

EU# = Emission Unit Number

PCD = Pollution Control Device

SOMP = Standard Operating and Maintenance Procedures

EPA = United States Environmental Protection Agency

DAHS = Data Acquisition and Handling System

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

CFR = Code of federal Regulations

CMR = Code of Massachusetts Regulations

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

SO2 = Sulfur Dioxide

CO2 = Carbon Monoxide

ULSD = Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015weight percent sulfur

lb = pounds

scf = standard cubic feet
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Transmittal No. X254064

Application No. NE-12-022

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MMBtu/hr = million British thermal units per hour

MMBtu = million British thermal units

HHV = higher heating value basis

TPY = tons per 12-month rolling period

Table 11

EU# Reporting Requirements

EU1, 

EU2, EU3

1. The Permittee must obtain written MassDEP approval of an emissions test protocol prior 

to initial compliance emissions testing of EU1, EU2 and EU3 at the Facility. The protocol 

shall include a detailed description of sampling port locations, sampling equipment, 

sampling and analytical procedures, and operating conditions for any such emissions testing. 

In addition, the protocol shall include procedures for: a) the required CO and VOC 

correlation for EU1 and EU2; b) a parametric monitoring strategy to ensure continuous 

monitoring of PM, PM10, and PM2.5 emission from EU1 and EU2; and c) procedures for the 

required NOx and CO optimization for EU3. The protocol must be submitted to MassDEP at 

least 30 days prior to commencement of testing.

2. The Permittee shall submit a final emissions test results report to MassDEP within 45 days 

after completion of the initial compliance emissions testing program.

3. A QA/QC program plan for the CEMS and/or COMS serving EU1, EU2 and EU3 must be 

submitted, in writing, at least 30 days prior to commencement of commercial operation of 

the subject emission units. MassDEP must approve the QA/QC program prior to its 

implementation. Subsequent changes to the QA/QC program plan shall be submitted to 

MassDEP for MassDEP approval prior to their implementation.
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Transmittal No. X254064

Application No. NE-12-022

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Table 11

EU# Reporting Requirements

EU1, 

EU2, EU3

4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the 

thirtieth (30th) day of April, July, October, and January covering the previous calendar periods 

of January through March, April through June, July through September, and October through 

December, respectively. The report shall contain at least the following information:

a) The Facility CEMS and COMS excess emissions data, in a format acceptable to 

MassDEP.

b) For each period of all excess emissions or excursions from allowable operating conditions 

for the emission unit(s), the Permittee shall list the duration, cause, the response taken, and 

the amount of excess emissions. Periods of excess emissions shall include periods of startup, shutdown, malfunction, emergency, equipment cleaning, and upsets or failures associated 

with the emission control system or CEMS or COMS. (“Malfunction” means any sudden 

and unavoidable failure of air pollution control equipment or process equipment or of a process 

to operate in a normal or usual manner. Failures that are caused entirely or in part by poor 

maintenance, careless operation, or any other preventable upset condition or preventable 

equipment breakdown shall not be considered malfunctions. “Emergency” means any 

situation arising from sudden and reasonably unforeseeable events beyond the control of this 

source, including acts of God, which situation would require immediate corrective action to 

restore normal operation, and that causes the source to exceed a technology based limitation 

under the Plan Approval, due to unavoidable increases in emissions attributable to the 

emergency. An emergency shall not include noncompliance to the extent caused by improperly 

designed equipment, lack of preventative maintenance, careless or improper operations, 

operator error or decision to keep operating despite knowledge of these things.)

c) A tabulation of periods of operation (including dispatch) of each emission unit and total 

hours of operation of each emission unit during the calendar quarter.

EU1, EU2 5. After completion of the initial compliance emissions testing program, the Permittee shall 

submit information for MassDEP review that documents the actual emissions impacts

generated by EU1 and EU2 during start-up and shutdown periods versus any applicable 

NAAQS and SILs or the AALs and TELs for air toxics. This information shall be submitted 

to MassDEP as part of the final emissions test results report.

6. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310 

CMR 7.02(5)(c), plans and specifications for the main exhaust stack, CTGs, the SCR control 

system (including the NH3 handling and storage system), the CO catalyst control system, and 

the CEMS, COMS, and DAHS once the specific information has been determined, but in any 

case not later than 30 days prior to commencement of construction/installation of each 

component of each subject emission unit.

EU3 7. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310 

CMR 7.02(5)(c), the plans and specifications for the auxiliary boiler, and its Ultra Low NOx 

burner, exhaust stack, COMS and DAHS once the specific information has been determined, 

but in any case not later than 30 days prior to commencement of construction/installation of 

each component of EU3.
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Transmittal No. X254064

Application No. NE-12-022

Page 43 of 59

Table 11

EU# Reporting Requirements

EU4, EU5 8. The Permittee shall submit to MassDEP a certification for each engine in accordance with 

310 CMR 7.26 (42)(e)1 not later than 30 days prior to commencement of its 

construction/installation.

9. The Permittee shall submit to MassDEP, in accordance with the provisions of Regulation 310 

CMR 7.02(5)(c), the plans and specifications for the emergency engine/generator set, fire pump 

engine, and associated exhaust stacks once the specific information has been determined, but in 

any case not later than 30 days prior to commencement of construction/installation of each 

component of the subject emission unit.

FacilityWide10. The Permittee shall submit to MassDEP a plan for monitoring and abating air and noise 

impacts during the period of construction of the proposed Facility.

11. The Permittee shall submit, in writing, the following notifications to MassDEP within 

fourteen (14) days after each occurrence:

a) date of commencement of construction of each subject emission unit at the Facility;

b) date when construction has been completed of each subject emission unit at the Facility;

c) date of initial firing of each subject emission unit at the Facility;

d) date when each subject emission unit at the Facility is either ready for commercial 

operation or has commenced commercial operation.

12. The Permittee shall submit to MassDEP an Operating Permit Application in accordance 

with 310 CMR 7.00: Appendix C no later than 12 months after commencement of 

commercial operation of the Facility.

13. If the Facility is subject to 40 CFR Part 68, due to the presence of a regulated substance 

above a threshold quantity in a process, the Permittee must submit a Risk Management Plan 

no later than the date the regulated substance is first present above a threshold quantity.

14. The Permittee shall report to EPA in accordance with 40 CFR Part 75.

15. The Permittee shall comply with all applicable reporting requirements of 310 CMR 7.32, 

310 CMR 7.70, 310 CMR 7.71 (Reporting of Greenhouse Gas Emissions), and 40 CFR Part 98 

(Mandatory Greenhouse Gas Emissions Reporting).

16. The Permittee must notify MassDEP by telephone or fax or e-mail 

[nero.air@massmail.state.ma.us] as soon as possible, but in any case no later than three (3) 

business days after the occurrence of any upsets or malfunctions to the Facility equipment, 

air pollution control equipment, or monitoring equipment which result in an excess emission 

to the air and/or a condition of air pollution.

17. The Permittee shall notify MassDEP immediately by telephone or fax or e-mail 

[nero.air@massmail.state.ma.us] and within three (3) working days, in writing, of any upset 

or malfunction to the NH3 handling or delivery systems that resulted in a release or threat of 

release of NH3 to the ambient air at the Facility. In addition, the Permittee must comply with 

all notification procedures required under M.G.L. c. 21 E for any release or threat of release 

of NH3.
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Transmittal No. X254064

Application No. NE-12-022

Page 44 of 59

Table 11

EU# Reporting Requirements

FacilityWide18. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 30 of 

each year to demonstrate the Facility’s compliance status regarding the Facility-Wide emission 

limits (TPY) specified in Table 7. Reports shall include actual emissions for the previous 12 

months. (The MassDEP approved format can be downloaded at 

http://www.mass.gov/eea/agencies/massdep/air/approvals/limited-emissions-record-keepingand-reporting.html#WorkbookforReportingOn-SiteRecordKeeping in Microsoft Excel 

format.)

19. The Permittee shall submit to MassDEP a SOMP for the subject emission units and 

associated control and monitoring/recording systems at the Facility no later than 30 days 

prior to commencement of commercial operation of the unit. Thereafter, the Permittee shall 

submit updated versions of the SOMP to MassDEP no later than thirty (30) days prior to the 

occurrence of a significant change. MassDEP must approve of significant changes to the 

SOMP prior to the SOMP becoming effective. The updated SOMP shall supersede prior 

versions of the SOMP.

20. The Permittee shall submit to MassDEP all information required by this Plan Approval 

over the signature of a “Responsible Official” as defined in 310 CMR 7.00 and shall include 

the Certification statement as provided in 310 CMR 7.01(2)(c).

21. All notifications and reporting to MassDEP required by this Plan Approval shall be made 

to the attention of:

Department of Environmental Protection/Bureau of Waste Prevention

205B Lowell Street

Wilmington, Massachusetts 01887

Attn: Permit Chief

Phone: (978) 694-3200

Fax: (978) 694-3499

E-Mail: nero.air@massmail.state.ma.us

22. The Permittee shall report annually to MassDEP, in accordance with 310 CMR 7.12, all 

information as required by the Source Registration/Emission Statement Form. The Permittee 

shall note therein any minor changes (under 310 CMR 7.02(2)(e), 7.03, 7.26, etc.), which did 

not require Plan Approval.

23. The Permittee shall provide a copy to MassDEP of any record required to be maintained 

by this Plan Approval within thirty (30) days from MassDEP’s request.

24. The Permittee shall submit to MassDEP for approval a stack emission pretest protocol, at 

least thirty (30) days prior to emission testing, for emission testing as defined in Table 9 

Monitoring and Testing Requirements.

25. The Permittee shall submit to MassDEP a final stack emission test results report, within 

forty five (45) days after emission testing, for emission testing as defined in Table 9 

Monitoring and Testing Requirements.

Table 11 Key:

EU# = Emission Unit Number

EPA = United States Environmental Protection Agency
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

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CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

DAHS = Data Acquisition and Handling System

CFR = Code of Federal Regulations

CMR = Code of Massachusetts Regulations

M.G.L. = Massachusetts General Laws

SOMP = Standard Operating and Maintenance Procedures

QA/QC = Quality Assurance/Quality Control

CTG = Combustion Turbine Generator

SCR = Selective Catalytic Reduction

TPY = tons per 12 month rolling period

NOx = Oxides of Nitrogen

CO = Carbon Monoxide

NH3 = Ammonia

PM = Particulate Matter

PM10 = Particulate Matter less than or equal to 10 microns in size

PM2.5 = Particulate Matter less than or equal to 2.5 microns in size

VOC = Volatile Organic Compounds

NAAQS = National Ambient Air Quality Standards

SILs = Significant Impact Levels

AAL = Allowable Ambient Limit

TEL = Threshold Effects Exposure Limit

6. SPECIAL REQUIREMENTS

A. SPECIAL TERMS AND CONDITIONS

The Facility is subject to, and the Permittee shall ensure that the Facility shall comply 

with, the special terms and conditions as contained in Table 12 below:

Table 12

EU# Special Terms and Conditions

EU1, EU2 1. The Permittee shall not allow the combustion turbines at the Facility to operate below the 

MECL, except for start-ups and shutdowns. Emissions during start-ups and shutdowns shall 

be included in the TPY limits specified in Table 7.

2. The Permittee shall ensure that the SCR control equipment serving EU1 and EU2 is 

operational whenever the turbine exhaust temperature at the SCR unit attains the minimum 

exhaust temperature specified by the SCR vendor and other system parameters are satisfied 

for SCR operation. The specific load at which this exhaust temperature and other system 

parameters are achieved will vary based on ambient conditions and whether the start-up is 

cold, warm, or hot.

3. The Permittee shall maintain in the Facility control room, properly maintained, operable, 

portable NH3 detectors for use during an NH3 spill, or other emergency situation involving 

NH3, at the Facility.

EU1, EU2, 

EU3

4. The Permittee shall develop as part of the Standard Operating Procedures for EU1, EU2, 

and EU3, an MECL optimization protocol to establish minimum operating load(s) that 

maintain compliance with all emission limitations at various ambient temperatures and 

conditions for each respective emission unit.
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 46 of 59

Table 12

EU# Special Terms and Conditions

EU1, EU2, 

EU3

5. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the online availability and data capture requirements for the CEMS and COMS equipment serving 

the Facility.

FacilityWide6. The Permittee shall properly train all personnel to operate the Facility and the control and 

monitoring equipment serving the Facility in accordance with vendor specifications. All 

persons responsible for the operation of the Facility shall sign a statement affirming that 

they have read and understand the approved SOMP. Refresher training shall be given by the 

Permittee to Facility personnel at least once annually.

7. Prior to commencing construction of any emission unit at the Facility, the roadways 

serving said Facility shall be paved and maintained free of deposits that could result in 

excessive dust emissions.

8. The Permittee shall comply with all provisions of 40 CFR Parts 72 and 75, 40 CFR Part 

60, 40 CFR Part 63, 40 CFR Part 64, 40 CFR Part 68, 40 CFR Part 98, and 310 CMR 6.00 

through 8.00 that are applicable to this Facility.

9. All requirements of this Approval which apply to the Permittee shall apply to all 

subsequent owners and/or operators of the Facility.

Table 12 Key:

EU# = Emission Unit Number

CFR = Code of federal regulations

CMR = Code of Massachusetts Regulations

SOMP = Standard Operating and Maintenance Procedures

CEMS = Continuous Emission Monitoring System

COMS = Continuous Opacity Monitoring System

SCR = Selective Catalytic Reduction

NH3 = Ammonia

TPY = tons per 12 month rolling period

MECL = Minimum Emissions Compliance Load

B. STACK INFORMATION

The Permittee shall install, maintain, and utilize exhaust stacks with the following 

parameters, as contained in Table 13 below, for the Emission Units that are regulated by this 

Plan Approval:

Table 13

EU# Stack Height 

Above Ground

(feet)

Stack Inside Exit 

Dimensions

(feet)

Stack Gas Exit 

Velocity Range

(feet per second)

Stack Gas Exit 

Temperature Range

(

o

F)

EU1, EU2

(1)

230

(Each Flue)

20

(Each Flue)

39.2 to 61.9

(Each Flue)

175 to 215

(Each Flue)

EU3 (1) 230 3 < 70.2 < 530

EU4 86 1 < 113.3 < 620
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Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 47 of 59

Table 13

EU# Stack Height 

Above Ground

(feet)

Stack Inside Exit 

Dimensions

(feet)

Stack Gas Exit 

Velocity Range

(feet per second)

Stack Gas Exit 

Temperature Range

(

o

F)

EU5 22 0.667 < 80.6 < 820

Table 13 Notes:

1. EU1, EU2, and EU3 shall emit through one stack, containing three (3) flues.

Table 13 Key:

EU# = Emission Unit Number

o

F = degrees Fahrenheit

< = less than or equal to

C. NOISE (State-Only Requirement)

Daytime and nighttime sound measurements to determine ambient (background) sound 

levels were taken at twelve locations (ST1 through ST12 in Table 14). Two additional 

monitoring locations (R1 and R2 in Table 14) were added with data in the public record to 

expand the study area and supplement the measurement data set, as collected by the Permittee. 

Baseline sound measurements were taken on May 17/18, 2012 and November 20/21, 2012. 

Salem Harbor Station’s existing Boiler Units 3 and 4 were not operating during the measurement 

time periods. It is expected that the National Grid substation transformers will remain operating 

at the site even after the existing facility has been demolished; therefore, sound measurements 

included operation of these transformers. The sound measurements consisted of both A-weighted 

sound levels and octave band sound levels. A-weighted sound levels emphasize the middle 

frequency sounds and de-emphasize lower and higher frequency sounds, and are reported in 

decibels designated as “dBA”. The A-weighted sound levels were recorded for each of the five

categories most commonly used to describe ambient environments: L90, L50, L10, Lmax, and Leq. 

The L90 level represents the sound level exceeded 90 percent of the time and is used by 

MassDEP for the regulation of sound emissions.

In general, background (L90) levels (in dBA) at locations ST1 through ST12 averaged from 

36 to 49 during nighttime hours (with the exception of location ST9 where no nighttime 

measurements were taken) and from 39 to 51 during daytime hours. To compensate for nighttime 

measurements taken before midnight instead of during the typically quietest time of the day (12AM 

to 4AM), the Permittee conservatively deducted 2 dBA from the measured ambient sound levels at 

locations ST1, ST2, ST5, ST6, and ST8.

Calculations of operational noise impacts from the proposed Facility were calculated using 

DataKustic GmbH’s CadnaA, a computer-aided noise abatement program (version 4.1.137). 

CadnaA conforms to International Standard ISO-9613.2, “Acoustics – Attenuation of Sound during 

Propagation Outdoors.” The method evaluated A-weighted sound pressure levels under 

meteorological conditions favorable to propagation from sources of known sound emissions.
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Transmittal No. X254064

Application No. NE-12-022

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The allowable sound levels generated from base load (100% load) operation of the 

proposed Facility by the Permittee are summarized in Table 14 below:

Table 14

Location Ambient 

(L90,dBA) (1)

Facility 

(L90,dBA)

Ambient and 

Facility 

(L90,dBA)

Increase Over 

Ambient (dBA) 

(2)

ST1 – Located to the 

North/ Residences near 

39 Fort Avenue

47 44 49 2

ST2 - Existing Property 

Line to the West/Block 

House 

Square/Residences near 

Fort Avenue and Derby 

Street Intersection

42 44 46 4

ST3 – Located to the 

Northeast/25 Memorial 

Drive/Bentley 

Elementary School

39 41 43 4

ST4 – Existing Property 

Line to the 

Southwest/Residences 

near Intersection of 

Webb Street and Derby 

Street/23 Derby Street

39 43 44 5

ST5 – Existing Property 

Line to the Southwest/59 

Derby Street

39 44 45 6

ST6 – Located to the 

East across Salem 

Harbor/76 Naugus 

Avenue (Marblehead)

36 34 38 2

ST7 – Located to the 

East/Winter Island Park 

(Harbormaster Office)

39 39 42 3

ST8 – Located to the 

Northeast/Intersection of 

Fort Avenue and Winter 

Island Road/Winter 

Island Road

38 33 39 1

ST9 – Existing Property 

Line to the South/Blaney 

Street Pier on Salem 

Wharf

39 42 44 5
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 49 of 59

Table 14

Location Ambient 

(L90,dBA) (1)

Facility 

(L90,dBA)

Ambient and 

Facility 

(L90,dBA)

Increase Over 

Ambient (dBA) 

(2)

ST10 – Southwest 

Corner of the Existing 

Property/Mackey 

Building/Art Gallery

36 41 42 6

ST11 – Near House of 

Seven Gables across 

from 41 Turner Street

39 37 41 2

ST12 – Pickering Wharf 

near Victoria’s Station 

approximately 100 feet 

behind Sail Schooner 

“Fame” Kiosk

41 32 42 1

R1 – Plummer House 40 33 41 1

R2 – Winter Island Road 

Residences

34 33 38 4

Table 14 Notes:

1. The lowest existing background levels observed during either nighttime or daytime where the sound level is 

exceeded 90 percent of the time (L90) which is the level regulated by MassDEP Noise Policy 90-001.

2. MassDEP Noise Policy 90-001 limits sound level increases to no more than 10 dBA over the L90 ambient 

levels. Pure tone conditions or tonal sounds, defined as any octave band level which exceeds the levels in adjacent 

octave bands by 3 dBA or more, are not allowed.

Table 14 Key:

L90 = sound level exceeded 90 percent of the time

dBA = decibels, A-weighted

In addition, the Permittee shall comply with the following conditions:

1. The Facility shall be operated and maintained such that at all times:

a) No condition of air pollution shall be caused by sound as provided in 310 CMR 

7.01.

b) No sound emissions resulting in noise shall occur as provided in 310 CMR 7.10 

and MassDEP’s Noise Policy 90-001. MassDEP’s Noise Policy 90-001 limits increases 

over the existing L90 background level to 10 dBA. Additionally, "pure tone" sounds, 

defined as any octave band level which exceeds the levels in adjacent octave bands by 3 

dBA or more, are also prohibited. The Permittee, at a minimum, shall ensure that the 

Facility complies with said Policy.
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Transmittal No. X254064

Application No. NE-12-022

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2. Facility personnel shall continue to identify and evaluate all plant equipment that may cause 

a noise condition. Sources of noise include, but are not limited to: main exhaust stack containing 

three flues, ACC, CTG packages, combustion turbine air inlets, STG packages, HRSG packages,

CTG step up transformers, STG step up transformers, screw type natural gas compressor, natural 

gas metering station, auxiliary boiler, and auxiliary cooling tower.

3. The Permittee shall perform the following measures or equivalent alternative measures at 

the proposed Facility as noise mitigation as indicated in (and in addition to) the Application and the 

Permittee’s responses, dated April 12, June 10, and June 18, 2013, to MassDEP’s requests for 

additional information with regard to noise mitigation:

a) Enclose the CTG, low noise HRSG, and STG packages for EU1 and EU2 within 

acoustically treated buildings consisting of absorptive double layer acoustic walls 

constructed of steel skin, mineral wool, and perforated metal interior designed for a 

Sound Transmission Class (STC) rating of 46. All ventilation openings and rooftop fans 

shall be acoustically silenced and attenuated. Machinery and personnel access into the 

buildings shall be through high performance acoustic doors.

b) Enclose the natural gas compressor and metering station within an acoustically 

treated building with airways into the building and exhausts adequately sound attenuated 

through the use of silencers.

c) Install GE 12 foot Silencers with Acoustic Plenums on combustion turbine inlet air 

filter houses for EU1 and EU2.

d) Install turbine exhaust silencers in the HRSG discharge flow paths, either in the 

connecting ducts and/or in the vertical stack flues for EU1, EU2, and EU3 designed to meet 

a total sound power attenuation of 22 dBA and a 90-degree directional sound power level of 

83 dbA or less at stack exits.

e) Install ultra low noise CTG and STG step up transformers providing sound power 

levels (Lw) of 83 dBA for CTG step-up transformers and 90 dBA for STG step up 

transformers on EU1 and EU2, and enclose the transformers with firewalls/barriers to 

provide shielding to the receptors located on Derby Street to the west and the residential area 

to the south.

f) Install ACC with low noise fans and Acoustic Louvers on the inlet of the ACC, 

which shall be designed to meet 51 dbA or less at 400 feet from the ACC.

g) Install a retaining wall and berm surrounding the majority of the Facility site.

These noise mitigation measures, which result in a maximum increase of 6 dbA above ambient as 

shown in Table 14, are identified as Option 2 noise mitigation measures in the Permittee’s June 18, 

2013 Supplement to the Application amongst the four (4) options evaluated by the Permittee as 

compared to the reference (or standard) design noise mitigation measures for this type of facility.
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Transmittal No. X254064

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4. The Permittee shall complete a sound survey in accordance with MassDEP

procedures/guidelines within one hundred eighty (180) days after the Facility commences 

commercial operation, while the Facility is in operation, to verify compliance with the allowable 

sound levels specified in Table 14 of this Plan Approval. Prior to conducting the sound survey, 

the Permittee shall submit in writing to MassDEP for review a sound survey protocol at least 

thirty (30) days prior to commencing the sound survey. The Permittee shall submit to MassDEP 

a written report, describing the results of the required sound survey, within 45 days after its 

completion.

D. CONSTRUCTION REQUIREMENTS

Construction of the Facility will result in temporary increases in sound levels near the site. 

The construction process will require the use of equipment that will be audible from off site 

locations during certain time periods. Facility construction consists of site clearing, excavation, 

foundation work, steel erection, mechanical work, and finishing work. Work on these phases will 

overlap. Pile driving, generally considered the loudest construction activity, may also be required 

during the excavation phase to provide proper structural support for the combustion turbine building 

foundation. No blasting would be performed on site. Construction of the Facility is expected to 

begin in June 2014 and continue for a period of approximately 23 months.

In order to minimize construction noise impacts, the Permittee shall, at minimum, install and 

maintain a non-retractable temporary sound wall, 12 feet in height, constructed of 3⁄4 inch Medium 

Density Overlay (MD) plywood, or other material of equivalent utility and appearance, having a 

surface weight of 2 pounds per square foot or greater. These specifications are based upon a Sound 

Transmission Class of STC 30, or greater, per American Society for Testing and Materials (ASTM) 

Test Method E90, having glass fiber, mineral wool, or other similar type sound absorptive surface 

material at least 2 inches thick on the side facing the site with a Noise Reduction Coefficient rating 

of NRC-0.85, or greater, per ASTM Test Method C423. When the barrier units are joined together, 

the mating surfaces of the barrier sides are flush with each other and gaps between barrier units and 

the bottom edges of the barrier panels and the ground are closed with material of sufficient density 

to attenuate sound. The Permittee shall install and maintain in good repair said temporary noise 

barrier, or equivalent, throughout the duration of the construction of the Facility. 

In addition, the Permittee shall comply with the following conditions during the construction 

phases of the Facility:

1. The Permittee shall ensure that Facility personnel take all reasonable precautions (noted 

below) to minimize air pollution episodes (dust, odor, and noise):

a) Personnel shall exercise care in operating any noise generating equipment 

(including mobile power equipment, power tools, etc.) at all times to minimize noise.

b) Construction vehicles transporting loose aggregate to or from the Facility shall be 

covered.
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c) Open storage areas, piles of soil, loose aggregate, etc. shall be covered or watered 

down as necessary to minimize dust emissions.

d) Any spillage of loose aggregate and dirt deposits on any public roadway, leading 

to or from the Facility shall be removed by the next business day or sooner, if necessary. 

(A mobile mechanical sweeper equipped with a water spray is an acceptable method to 

minimize dust emissions).

e) On-site roadways/excavation areas subject to vehicular traffic shall be watered 

down as necessary or treated with the application of a dust suppressant to minimize the 

generation of dust.

2. The Permittee shall ensure that all contractors associated with the construction of the 

Facility shall comply with MassDEP’s Clean Air Construction Initiative. The main aspects of 

this program include:

a) All contractors shall use ULSD oil in diesel-powered non-road vehicles.

b) All non-road engines used on the construction site shall meet the applicable nonroad engine standard limitations per 40 CFR 89.112.

c) All contractors shall utilize the best available technology for reducing the 

emission of PM and NOx for diesel-powered non-road vehicles. The best available 

technology for reducing the emission of pollutants is that which has been verified by EPA 

or the California Air Resources Board for use in non-road vehicles or on-road vehicles 

where such technology may also be used in non-road vehicles.

d) All contractors shall turn off diesel combustion engines on construction 

equipment not in active use and on dump trucks that are idling while waiting to load or 

unload material for five minutes or more.

e) All contractors shall establish a staging zone for trucks that are waiting to load or 

unload material at the work zone in a location where diesel emissions from the trucks will 

not be noticeable to the public, and;

f) All contractors shall locate construction equipment away from sensitive receptors 

such as residents and passersby, fresh air intakes to buildings, air conditioners, and 

windows.

For informational purposes only, the City of Salem Code of Ordinances, Chapter 22, Section 

22-1 governs construction noise, setting forth requirements on construction hours, allowable 

activities, and procedures for obtaining a special variance during times when certain construction 

activities are not allowed. Construction is allowed without a variance between the hours of 8:00 AM 

and 5:00 PM, Mondays through Saturdays, and at other times if it does not “create a noise 

disturbance across a residential property boundary”. The same restrictions are imposed on the 

operation of drilling and/or blasting equipment, rock crushing machinery, pile driving or jack 
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Transmittal No. X254064

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hammers used in construction. Special variances can be granted by the building inspector for 

construction work on Sundays or holidays with prior approval of the City Council.

7. GENERAL CONDITIONS

The Permittee is subject to, and shall comply with, the following general conditions:

A. Pursuant to 310 CMR 7.01, 7.02, 7.09 and 7.10, should any nuisance condition(s), 

including but not limited to smoke, dust, odor or noise, occur as the result of the operation of the 

Facility, then the Permittee shall immediately take appropriate steps including shutdown, if 

necessary, to abate said nuisance condition(s).

B. If asbestos remediation/removal will occur as a result of the approved construction, 

reconstruction, or alteration of this Facility, the Permittee shall ensure that all 

removal/remediation of asbestos shall be done in accordance with 310 CMR 7.15 in its entirety 

and 310 CMR 4.00.

C. If construction or demolition of an industrial, commercial or institutional building will 

occur as a result of the approved construction, reconstruction, or alteration of this Facility, the 

Permittee shall ensure that said construction or demolition shall be done in accordance with 310 

CMR 7.09(2) and 310 CMR 4.00.

D. Pursuant to 310 CMR 7.01(2)(b) and 7.02(7)(b), the Permittee shall allow MassDEP

and/or EPA personnel access to the Facility, buildings, and all pertinent records for the purpose 

of making inspections and surveys, collecting samples, obtaining data, and reviewing records.

E. This Plan Approval does not negate the responsibility of the Permittee to comply with 

any other applicable Federal, State, or local regulations now or in the future.

F. Should there be any differences between the Application and this Plan Approval, the Plan 

Approval shall govern.

G. Pursuant to 310 CMR 7.02(3)(k), MassDEP may revoke this Plan Approval if the 

construction work is not commenced within two years from the date of issuance of this Plan 

Approval, or if the construction work is suspended for one year or more.

H. This Plan Approval may be suspended, modified, or revoked by MassDEP if MassDEP 

determines that any condition or part of this Plan Approval is being violated.

I. This Plan Approval may be modified or amended when in the opinion of MassDEP such 

is necessary or appropriate to clarify the Plan Approval conditions or after consideration of a 

written request by the Permittee to amend the Plan Approval conditions.

J. The Permittee shall conduct emission testing, if requested by MassDEP, in accordance 

with EPA Reference Test Methods and regulation 310 CMR 7.13. If required, a pretest protocol 

report shall be submitted to MassDEP at least 30 days prior to emission testing and the final test 
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Transmittal No. X254064

Application No. NE-12-022

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results report shall be submitted within 45 days after emission testing.

K. Pursuant to 310 CMR 7.01(3) and 7.02(3)(f), the Permittee shall comply with all 

conditions contained in this Plan Approval. Should there be any differences between provisions

contained in the General Conditions and provisions contained elsewhere in the Plan Approval, 

the latter shall govern.

8. MASSACHUSETTS ENVIRONMENTAL POLICY ACT

The Facility was also subject to the requirements of the Massachusetts Environmental 

Policy Act (MEPA) Massachusetts General Laws (M.G.L.) Chapter 30, Sections 61-62I and 

Section 11.08 of the MEPA regulations at 301 CMR 11.00. On May 17, 2013, the Secretary of 

the Executive Office of Energy and Environmental Affairs issued a certificate that the Final 

Environmental Impact Report (FEIR) (EEA #14937) adequately and properly complied with the 

MEPA and its implementing regulations.

9. SECTION 61 FINDINGS

MassDEP has carefully considered the Permittee’s Final Environmental Impact Report 

(FEIR) prior to taking action on their Plan Approval Application. MassDEP, in issuing this 

Proposed Plan Approval, requires the Permittee to use all feasible means and measures to avoid or 

minimize adverse environmental impacts. Measures MassDEP deems necessary to mitigate or 

prevent harm to the environment are included in the conditions of this Proposed Plan Approval. 

MassDEP has made its decision under applicable law based on a balancing, where appropriate, of 

environmental and socioeconomic objectives, as mandated by 301 CMR 11.01(4).

In the issuance of this Proposed Plan Approval, MassDEP has considered the reasonably 

foreseeable climate change impacts, including greenhouse gas (GHG) emissions and effects as 

addressed in the FEIR through the MEPA Greenhouse Gas Emissions Policy and Protocol and the 

GHG emission mitigation/adaptation measures adopted by the Permittee in the FEIR as referenced 

in the Secretary’s Certificate of finding on the FEIR, dated May 17, 2013 (EOEA #14937). This 

finding incorporates by reference said mitigation/adaptation measures.

Pursuant to M.G.L. Chapter 30 Section 61 of the Massachusetts Environmental Policy Act, 

(MEPA), 301 CMR 11.12 of the MEPA regulations, and the Secretary’s Certificate of finding on 

the FEIR, MassDEP’s Section 61 Findings on the proposed Facility determining that all feasible 

measures have been taken to avoid or minimize impacts to the environment are presented here as 

follows.

Project Description

As described in the FEIR, the project consists of demolition of an existing coal-fired 

power plant, remediation of the site, and construction of a new 630 megawatt (MW) nominal 

electrical generating facility and associated infrastructure and equipment (the proposed Facility) 

on a 65-acre site in Salem. The proposed Facility will be fired by natural gas and include “quick-
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start" capability (ability to generate 300 MW within 30 minutes of start-up and 630 MW within 

60 minutes). Use of duct-firing under summer conditions, will increase capacity by 62 MW for a 

total of 692 MW. The project will have the capacity to generate 5.1 million megawatt hours 

(MWh) annually. The proposed Facility will be constructed on approximately 20 acres of the 

northwestern portion of site. The proposed Facility main stacks will be contained in a common 

collar with a height of 230 feet.

The Permittee will operate the existing power plant until its scheduled shut down on June 

1, 2014. Construction is proposed to begin in June 2014 and will extend for approximately 23 

months. Demolition will include removal of all above-ground features of the existing facility, 

including power plant buildings and equipment, stacks and precipitators, coal handling 

equipment, storage tanks and associated appurtenances such as spill prevention berms; and 

intake screen and pumphouse structures. The proposed Facility will include two quick-start 

natural gas fired Combustion Turbine Generators (CTG); two STGs; two Heat Recovery Steam 

Generators (HRSG), including pollution control equipment; an auxiliary steam boiler; 

administrative/warehouse/shops space; a service bay; an auxiliary bay; a water treatment facility; 

step-up transformers; an ammonia storage tank; two water tanks; and, air cooled condensers 

(ACC). The proposed Facility is not dual-fueled and, therefore, does not have the potential to use 

significant amounts of diesel fuel. It will include a diesel-fueled back-up generator and a dieselfueled fire pump engine.

Environmental Impact

Construction of the Facility has the potential to generate noise and dust. Operation of the 

Facility will result in the emission of air pollutants including nitrogen oxides (NOx), volatile 

organic compounds (VOC), and greenhouse gases (GHG).

Mitigation Measures

The project includes the following measures to avoid, minimize and mitigate impacts:

Air Pollution -

 use of a high-efficiency advanced turbine combined cycle technology, emission 

controls and reporting equipment to minimize all pollutants;

 use of natural gas will limit emissions of PM, SO2 and HAPs compared to other 

fossil fuels;

 use of Dry Low NOx turbine combustors in combination with SCR will reduce 

NOx emissions;

 183 tons per year of NOx Emission Reduction Credits (ERC) will be obtained to 

meet NSR offset requirements;

 advanced combustor design, combustor practices, and use of a catalytic oxidation 

system in the HRSG will reduce emissions of CO and VOCs; and,

 quick start capability to minimize all pollutants associated with start-up. 

GHG Emissions -

 use of combined cycle natural gas turbines;
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 56 of 59

 $4 million in CO2 allowances for RGGI offsets; 

 solar PV array with potential to offset 175 tons per year GHG emissions;

 Administrative Building is designed to meet the United States Green Building 

Council’s Leadership in Energy and Environmental Design (LEED) Certification 

at the Platinum level and includes a green roof, geothermal heat pumps for 

heating and cooling, variable volume ventilation fans, increased insulation to 

minimize heat loss, lighting motion sensors, climate control and building energy 

management systems, a 10% reduction for lighting power density (LPD) (and 

identifies the potential for larger reductions), and water conserving fixtures that 

exceed building code requirements; and

 Operations Building includes a high albedo roof, geothermal heat pumps for 

heating and cooling; increased insulation to minimize heat loss, daylighting, 

lighting motion sensors; climate control, building energy management systems, a 

10% reduction for LPD (and identifies the potential for larger reductions), a high 

albedo roof, and water conserving fixtures;

 the Permittee will provide a certification to the MEPA Office indicating that all of 

the measures proposed to mitigate GHG emissions, or measures that will achieve 

equivalent reductions (e.g. 56.5 tons per year reductions, or 29%, from 

Administrative Building and Operations Building), are included in the project; 

and,

 a commitment to provide a GHG analysis, prepared consistent with the MEPA 

GHG Policy and Protocol, for the subsequent redevelopment of the site 

(regardless of whether the proposed redevelopment exceeds EIR thresholds) as 

part of the NPC.

Noise -

 siting of Facility equipment to maximize distance between receptors and noiseproducing equipment;

 acoustical treatment of combustion and steam turbine buildings;

 locating equipment within enclosures or buildings that provide noise attenuation 

through layers of insulation and siding;

 use of equipment silencers including a gas turbine inlet silencing package; a stack 

silencing package to reduce sound pressure levels in each flue of the stack 

structure, silencers on steam system vents and, as permitted by relevant codes, on 

safety and relief valves that release high pressure steam;

 gas turbines and steam turbines will be fully enclosed;

 steam turbine insulation will be designed to provide thermal and acoustical 

insulation;

 large pumps in the HRSG enclosure (boiler feed pumps) will be enclosed in 

additional acoustical structures as necessary;

 location of piping, valving and control systems within enclosures or underground 

to limit fluid transfer noise;

 larger fans that operate at slower speeds and shielding of fans by cowlings or 

other acoustical treatments on the ACC;

 intake filter houses, transformers, fuel gas compressors and boiler feed water 

pumps will be wrapped in acoustic barriers;
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 57 of 59

 acoustically designed barrier walls around transformers to shield sensitive 

receptors from transformer noise;

 gas compressors and gas metering enclosure will be designed with acoustic 

silencing; and

 construction of a retaining wall and planted berm will be constructed around the 

western, southern and eastern edges of the Facility to deflect sound.

Construction Period -

 dust suppression methods during demolition will include pre-cleaning of larger 

surfaces and structural members prior to demolition, water suppression sprays and 

misting to prevent airborne particulates, and enclosure of areas to prevent the 

migration of dust;

 dust suppression during earth moving will include use of water trucks to wet 

ground surface, stabilization of soils, and creation of wind breaks;

 noise mitigation including construction hour limits, establishment and 

enforcement of construction site and access road speed limits, mufflers on noiseproducing construction equipment and vehicles, siting of noisiest equipment as far 

as possible from sensitive receptors, and maintenance of engine housing panels in 

the closed position;

 stabilized construction and exit points;

 use of ultra-low sulfur diesel (ULSD) fuel (15 parts per million sulfur) in off-road 

vehicles;

 anti-idling measures including turning off diesel combustion engines on 

construction equipment not in active use and limiting idling of dump trucks to 

five minutes or less;

 vehicles greater than 50 brake horsepower will have engines that meet EPA PM 

emission standards or emission control technology certified by manufacturers to 

meet or exceed emissions standards and emission control devices, such as diesel 

oxidation catalysts (DOCs) or diesel particulate filters (DPFs), will be installed on 

the exhaust system side of engine equipment;

 delivery of large pieces of equipment or material will be by barge to minimize 

impacts on local roadways.

Funding Responsibility

The Permittee has committed to funding all of the mitigation measures discussed in these 

Section 61 findings.

Summary of Section 61 Findings

Based upon its review of the MEPA documents, the Plan Approval Application and 

amendments thereof submitted to date and MassDEP’s regulations, MassDEP finds that the 

terms and conditions of this Proposed Plan Approval constitute all feasible measures to avoid 

damage to the environment and will minimize and mitigate such damage to the maximum extent 

practicable. Implementation of the mitigation measures will occur in accordance with the terms 

and conditions set forth in this Proposed Plan Approval.
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 58 of 59

10. MASSACHUSETTS ENERGY FACILITIES SITING BOARD

The Energy Facility Siting Board (EFSB) has not issued approval under M.G.L. Chapter 

164, § 69J1⁄4 of the Permittee’s Petition to construct and operate the Facility at the time of 

issuance of this Proposed Plan Approval. Among other things, Section 69J1⁄4 provides that “...no 

state agency of the Commonwealth shall issue a construction permit for any such generating 

facility unless the petition to construct such generating facility has been approved by [EFSB] 

....”. Accordingly, MassDEP will not issue a final plan approval or PSD permit until EFSB has 

issued the approval required by Section 69J1⁄4.

11. PUBLIC PARTICIPATION

This Proposed Plan Approval is subject to a public comment period. Attached is a 

Public Notice with publishing instructions. Please have the attached Public Notice published as 

instructed at your expense in newspapers of general circulation in the municipalities where the 

modifications are proposed. A minimum thirty (30) day public comment period will commence 

with the date of publication of the Public Notice. It is in your interest to publish this Public 

Notice as instructed and forward proof of publication to the attention of the Permit Chief, Bureau 

of Waste Prevention, at the address shown on this letterhead to avoid delays in processing your 

submittal. In addition to providing for a public comment period, MassDEP will hold a public 

hearing on the Proposed Plan Approval, the details of which are stated in the attached Public 

Notice.

[Remainder of Page Intentionally Left Blank]
Footprint Power Salem Harbor Development LP

Proposed Plan Approval

Transmittal No. X254064

Application No. NE-12-022

Page 59 of 59

Should you have any questions concerning this Plan Approval, please contact Cosmo 

Buttaro by telephone at (978) 694-3281, or in writing at the letterhead address.

Sincerely,

Cosmo Buttaro

Environmental Engineer

Edward J. Braczyk

Environmental Engineer

James E. Belsky

Regional Permit Chief

Bureau of Waste Prevention

Enclosures

cc: George Lipka, Tetra Tech, 160 Federal Street, 3rd Floor, Boston, MA 02110

Lauren A. Liss, Rubin & Rudman LLP, 50 Rowes Wharf, Boston, MA 02110

Board of Health, 120 Washington Street, 4th Floor, Salem, MA 01970

Fire Headquarters, 48 Lafayette Street, Salem, MA 01970

City Hall, 93 Washington Street, Salem, MA 01970

Board of Health, 7 Widger Road, Marblehead, MA 01945

Fire Headquarters, One Ocean Avenue, Marblehead, MA 01945

Town Hall, 188 Washington Street, Marblehead, MA 01945

Metropolitan Area Planning Council, 60 Temple Place, Boston, MA 02111

Deirdre Buckley, MEPA, Executive Office of Energy and Environmental Affairs, 100 Cambridge Street,

Suite 900, Boston, MA 02114

John Ballam, Department of Energy Resources, 100 Cambridge Street, Suite 1020, Boston, MA 02114

Department of Public Utilities, One South Station, Boston, MA 02110

Robert J. Shea and Kathryn Sedor, Energy Facilities Siting Board, One South Station, Boston, MA 02110

United States Environmental Protection Agency (EPA) – New England Regional Office,

5 Post Office Square, Suite 100, Mail Code OEP05-2, Boston, Massachusetts 02109-3912

Attn: Air Permits Program Manager

EPA: Donald Dahl (e-copy)

MassDEP/Boston: Karen Regas (e-copy), Yi Tian (e-copy)

MassDEP/WERO: Marc Simpson (e-copy)

MassDEP/CERO: Roseanna Stanley (e-copy)

MassDEP/SERO: Thomas Cushing (e-copy)

MassDEP/NERO: Marc Altobelli (e-copy & hard copy), Jim Belsky (e-copy), Ed Braczyk (e-copy), 

 Mary Persky (hard copy), Cosmo Buttaro (hard copy), Susan Ruch (e-copy)