SALEM HARBOR SUBSTATION Commonwealth of Massachusetts
5 Executive OfficEpf Energy &Environmental Affairs
Department of Environmental Protection
Northeast Regional Office•2058 Lowell Street, Wilmington MA 011387.97B-694-3200
Charles D,Baker Matthew A.Beaton
Governor Secretary
Karyn E.Polito q Martin Suuberg
Lieutenant Governor FEB U 6 2015 Commissioner
URGENT LEGAL MATTER: PROMPT ACTION NECESSARY
National Grid RE: Salem
170 Medford Street Salem Harbor Substation
Malden,MA 02148 Canal Street
RTN 3-32689
Attention:Beverly Auxford-Paiva
NOTICE OF RESPONSIBILITY;
MGL c. 21E & 310 CMR 40.0000
Dear Ms. Auxford-Paiva:
On January 14, 2015 at 2:57 pm, the Massachusetts Department of Environmental
Protection (MassDEP) received oral notification of a release/threat of release of Oil/Hazardous
Material at the subject location, which requires one or more Response Actions. Based on this
information, MassDEP has reason to believe that the subject property or portion(s) thereof is a
disposal site as defined in the Massachusetts Oil and Hazardous Material Release Prevention and
Response Act,M.G.L. c. 21E and the Massachusetts Contingency Plan (MCP), 310 CMR 40.0000.
M.G.L. c.21E and the MCP govern the assessment and cleanup of Disposal Sites.
The purpose of this notice is to inform you of your legal responsibilities under state law for
assessing and/or remediating the subject release. For purposes of this notice, the terms and phrases
used herein shall have the meaning ascribed to them by the MCP unless the text clearly indicates
otherwise.
STATUTORY LIABILITIES
MassDEP also has reason to believe that you (as used in this letter "you" refers to National
Grid) are a Potentially Responsible Party (PRP) with liability under M.G.L. c. 21E, Section 5, for
This information Is available In alternate format.Call Michelle Waters-Ekanem,Diversity Director,at 617492-5751.TTY#MassRelay Service 1-600-439-2370
MassDEP Website www.mass goNdep
Printed on Recycled Paper
National Grid
Notice of Responsibility
Page 2 of 5
Response Action Costs. Section 5 makes the following parties liable to the Commonwealth of
Massachusetts: current owners or operators of a site from or at which there is or has been a
release/threat of release of oil or hazardous material;any person who owned or operated a site at the
time hazardous material was stored or disposed of; any person who arranged for the transport,
disposal, storage or treatment of hazardous material to or at a site; any person who transported
hazardous material to a transport, disposal, storage or treatment site from which them is or has been
a release/threat of release of such material; and any person who otherwise caused or is legally
responsible for a release/threat of release of oil or hazardous material at a site.
This liability is "strict" meaning that it is not based on fault but solely on your status as
owner, operator, generator, transporter or disposer. It is also "joint and several", meaning that you
may be liable for all response action costs incurred at the site, regardless of the existence of any
other liable parties.
The MCP requires responsible parties to take necessary Response Actions at properties
where there is or has been a release or threat of release of oil and/or hazardous material. If you do
not take the necessary Response Actions, or fail to perform them in an appropriate and timely
manner, MassDEP is authorized by M.G.L. c. 21E to have the work performed by its contractors.
By taking such actions, you can avoid liability for Response Action Costs incurred by MassDEP
and its contractors in performing these actions, and any sanctions, which may be imposed, for
failure to perform Response Actions under the MCP.
You may be liable for up to three (3) times all Response Action Costs incurred by
MassDEP. Response Action Costs include, without limitation, the cost of direct hours spent by
MassDEP employees arranging for response actions or overseeing work performed by persons other
than MassDEP or its contractors, expenses incurred by MassDEP in support of those direct hours,
and payments to MassDEP's contractors. (For more detail on cost liability,see 310 CMR 40.1200.)
MassDEP may also assess interest on costs incurred at the rate of twelve percent (12%),
compounded annually. To secure payment of this debt, the Commonwealth may place liens on all
of your property in the Commonwealth. To recover the debt,the Commonwealth may foreclose on
these liens or the Attorney General may bring legal action against you.
In addition to your liability for up to three (3) times all response action costs incurred by
MassDEP,you may also be liable to the Commonwealth for damages to natural resources caused by
the release. Civil and criminal liability may also be imposed under M.G.L. c. 21E, § 11, and civil
administrative penalties may be imposed under M.G.L. c. 21A, § 16 for each violation of M.G.L.c.
21E,the MCP,or any order,permit or approval issued hereunder.
National Grid
r Notice of Responsibility q t r
Page 3 of 5
p
Q
NECESSARY RESPONSE ACTIONS
The subject site shall not be deemed to have all the necessary and required Response Actions
taken unless and until all Substantial Hazards presented by the site have been eliminated and a level
of No Significant Risk exists or has been achieved in compliance with M.G.L. c. 21E and the MCP.
In addition, the MCP requires persons undertaking Response Actions at Disposal Sites perform
Immediate Response Actions (IRAs) in response to "sudden releases", Imminent Hazards and
Substantial Release Migration. Such persons must continue to evaluate the need for IRAs and notify
MassDEP immediately if such a need exists.
MassDEP has determined that an IRA is necessary to respond to a release of On
_ and/or Hazardous Material at the subject site.
You are authorized to conduct only the specific response actions for which you
received oral approval from MassDEP at the time oral notification was provided to MassDEP
of the release of Oil and/or Hazardous Materials. All additional Immediate Response Actions
require MassDEP approval in accordance with 310 CMR 40.0420.
MassDEP reminds you that IRAs must include site assessment activities necessary
to evaluate potential Imminent Hazard (III), Substantial Release Migration (SRM), and
Critical Exposure Pathway (CEP) conditions. Additional Immediate Response Actions will
be required in the event that one or more of these conditions are observed.
You must employ or engage a Licensed Site Professional (LSP) to manage, supervise or
actually perform the necessary response actions at the subject site. In addition, the MCP requires
persons undertaking response actions at a disposal site submit to MassDEP a Permanent Solution
Statement prepared by an LSP in accordance with 310 CMR 40.1000 upon determining that a level
of No Significant Risk already exists or has been achieved at a disposal site or portion thereof. [You
may obtain a list of the names and addresses of these licensed professionals from the Board of
Registration of Hazardous Waste Site Cleanup Professionals at
httD://www.mass.eov/eea/aeencies/lso/ or(617)556-1091.]
There are several other submittals required by the MCP which are related to release
notification and/or Response Actions that may be conducted at the subject site in addition to a
Permanent Solution Statement that, unless otherwise specified by MassDEP, must be provided to
MassDEP within specific regulatory timeframes. The submittals are as follows:
(1) If information is obtained after making an oral or written notification to indicate that the
release or threat of release didn't occur, failed to meet the reporting criteria at 310 CMR
40.0311 through 40.0315, or is exempt from notification pursuant to 310 CMR 40.0317, a
Notification Retraction may be submitted within 60 days of initial notification pursuant to
310 CMR 40.0335;
r ,
National Grid
- Notice of Responsibility'
Page 4 of 5
(2) If a Notification Retraction has not been submitted, a Release Notification Form (RNF)
musttbe submitted to MassDEP pursuant to section 310 CMR 40.0333 within 60 calendar
days of the initial date of oral notification to MassDEP of a release pursuant to 310 CMR
40.0300 or from the date MassDEP issues a Notice of Responsibility (NOR), whichever
occurs earlier. The RNF can either be submitted electronically or using the PDF Form at
httn://www.mass.eov/eea/docs/den/cleanup/avnrovals/bwsc-103.ndf;
(3) Unless a Permanent Solution Statement or Downgradient Property Status Submittal is
provided to MassDEP earlier, an Immediate Response Action (IRA) Plan prepared in
accordance with 310 CMR 40.0420, or an IRA Completion Statement (310 CMR 40.0427)
must be submitted to MassDEP within 60 calendar days of the initial date of oral
notification to MassDEP of a release pursuant to 310 CMR 40.0300 or from the date
MassDEP issues an NOR,whichever occurs earlier;and
(4) Unless a Permanent Solution Statement or Downgradient Property Status Submittal is
provided to MassDEP earlier, a completed Tier Classification Submittal pursuant to 310
CMR 40.0510 must be submitted within one year of the initial date of notification of a
release pursuant to 310 CMR 40.0300 or from the date MassDEP issues an NOR,whichever
occurs earlier or as otherwise specified by the Department in an Interim Deadline or order
issued pursuant to 310 CMR 40.0501 (2).
(5) Pursuant to MassDEP's "Timely Action Schedule and Fee Provisions", 310 CMR 4.00, the
appropriate fee must be included with a Permanent Solution Statement that is submitted to
MassDEP more than 120 calendar days after the initial date of oral notification to MassDEP
of a release pursuant to 310 CMR 40.0300, or more than 120 calendar days after the date
MassDEP issues an NOR,whichever occurs earlier,and before Tier Classification. A fee is
not required for a Permanent Solution Statement submitted to MassDEP within 120 days of
the date of oral notification to MassDEP, or within 120 days of the date MassDEP issues an
NOR,whichever date occurs earlier, or after Tier Classification.
It is important to note that you must dispose of any Remediation Waste generated at the
subject location in accordance with 310 CMR 40.0030 including, without limitation, contaminated
soil and/or debris. Any Bill of Lading accompanying such waste must bear the seal and signature of
an LSP or, if the response action is performed under the direct supervision of MassDEP, the
signature of an authorized representative of MassDEP.
MassDEP encourages parties with liability under M.G.L. c. 21E to take prompt action in
response to releases and threats of release of oil and/or hazardous material.By taking prompt action,
you may significantly lower your assessment and cleanup costs and avoid the imposition of, or
reduce the amount of, certain annual compliance fees for response actions payable under 310 CMR
4.00.
National Grid
Notice of Responsibility s
Page 5 of 5
If you have any questions relative to this notice, you should contact the undersigned at the
letterhead address or (978) 694-3386. All future communications regarding this release must
reference the Release Tracking Number(RTN)3-32689 contained in the subject block of this letter.
Sincerely,
Ida Babroudi
Environmental Engineer
Bureau of Waste Site Cleanup
MassDEP,Northeast Regional Office
cc: Board of Health, City of Salem,Joanne Scott
"via electronic submittal", iscottCn salem.com
MassDEP data entry/file (NOR/Issued)
I
Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
LlDepartment of Environmental Protection
Northeast Regional Office-20513 Lowell Street, Wilmington MA 01887.978.694-3200
DEVAL L PATRICK RICHARD K.SULIVAN JR.
Governor Secretary
KENNETH KIMMELL
Commissioner
January 30, 2014
Mr. Scott G. Silverstein RE: SALEM
Footprint Power Salem Harbor Transmittal No.: X254064
Development LP Application No.: NE-12-022
1140 Route 22 East, Suite 303 Class: OP119
Bridgewater,NJ 08807 FMF No.: 546374
AIR QUALITY PLAN APPROVAL
310 CMR 7.02
310 CMR 7.00: Appendix A
Including Section 61 Findings
PREVENTION OF SIGNFICANT
DETERIORATION PERMIT
40 CFR 52.21
Dear Mr. Silverstein:
Footprint Power Salem Harbor Development LP (Footprint)has proposed the construction and
operation of a new, natural gas-fired, quick-start 630 megawatt (MW)nominal (692 MW with
duct firing) combined cycle electric generating facility (the proposed Facility) at 24 Fort Avenue
in Salem, Massachusetts. The Massachusetts Department of Environmental Protection
(MassDEP), Bureau of Waste Prevention,has reviewed your Application identified as
Transmittal No. X254064, Application No. NE-12-022 and determined that the Application is
administratively and technically complete.
MassDEP hereby approves the construction and operation of the proposed Facility, subject to the
conditions set forth in the attached documents. Enclosed please find the: (1)Plan Approval;
(2)Prevention of Significant Deterioration (PSD) Permit; (3) PSD Permit Fact Sheet; and
(4) Response to Public Comments. These documents can also be accessed electronically at:
httn://www.mass.aov/eea/a2encies/massdei)/air/annrovals/footnrint.htmi.,
This information is available in alternate format.Call Michelle Waters-Ekanem,Diversity Director,at 617-2925751.TDD#1-866539-7622 or 1.617-574-6868
MassDEP Website w .mass.9ovldep
Printed on Recycled Paper
MassDEP letter re: Footprint Power Salem Harbor Development LP +/
Plan Approval and Prevention of Significant Deterioration Permit
Transmittal No.X254064,Application No.NE-12-022
January 2014
Page 2 of 3
The Notice of Public Hearing and Public Comment Period ("Public Notice"), advising the public
of the availability of the Proposed CPA and the Draft PSD Permit and Draft PSD Fact Sheet, was
published in The Boston Globe and The Salem News on Tuesday, September 10, 2013. The
Public Notice was also published in the Environmental Monitor on Wednesday, September 11,
2013. MassDEP sent copies of the Public Notice to a number of individuals and organizations as
a notice method reasonably calculated to give actual notice of the proposed permits to persons
potentially affected by the proposed project and to elicit public participation. MassDEP also
posted the Public Notice on its website, in addition to issuing a tweet and a press release
regarding the availability of the Proposed CPA and the Draft PSD Permit and Draft PSD Fact
Sheet.
The required Public Comment period commenced with the date of publication of the Public
Notice. The Public Comment period, originally scheduled to end at 5:00 PM on October 11,
2013, was extended to 5:OOPM on November 1, 2013. MassDEP announced the,extension
through a press release and a Revised Public Notice that was published on MassDEP's website
and in the Environmental Monitor on October 9, 2013. The Revised Public Notice was also sent
to the individuals and organizations as a notice method reasonably calculated to give actual
notice of the proposed permits to persons potentially affected by the proposed project and to
elicit public participation. MassDEP also announced the extension at the Public Hearing held on
Thursday, October 10, 2013, officially commencing at 7:12PM and ending at 9:12PM, at the
Bentley Elementary School, 25 Memorial Drive, Salem, Massachusetts.
After the Public Hearing and the close of the Public Comment period, MassDEP conducted a
public comment review and responded to all significant testimony and comments raised during
the public review process as summarized in the enclosed Response to Comments document. A
copy of the Response to Comments document is being sent to all individuals and organizations
who participated in the public review process.
As you are aware, on October 10, 2013, the Energy Facilities Siting Board(EFSB) issued a Final
Decision under Massachusetts General Laws, M.G.L. c. 164, Section 69J1/4 on Footprint's
Petition for Approval to Construct a Bulk Generating Facility in the City of Salem,
Massachusetts (EFSB 12-2). In accordance with that statute, MassDEP may issue this Plan
Approval and PSD Permit for the proposed Facility to be constructed and operated.
This letter and the enclosed documents can also be accessed electronically at:
httD://www.mass.gov/eea/aRencies/massdeD/air/aDDrovals/footl)rint.html.
Should you have any questions concerning this matter, please contact Cosmo Buttaro by
telephone at(978) 694-3281, or in writing at the letterhead address.
r�
4� MassDEP letter re: Footprint Power Salem Harbor Development LP
Plan Approval and Prevention of Significant Deterioration Permit
Transmittal No.X254064,Application No.NE-12-022
January 2014
Page 3 of 3
Sincerely,
Cosmo Buttaro
Environmental Engineer
Ed . Bracz
Environmental Engineer
James E. Belsky
Regional Permit Chi f
Bureau of Waste Pr ention
Enclosures
cc: George Lipka,Tetra Tech, 160 Federal Street, 3`"Floor, Boston,MA 02110
Lauren A. Liss,Rubin&Rudman LLP, 50 Rowes Wharf,Boston, MA 02110
Board of Health, 120 Washington Street,4"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 Seder,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)
MassDEPBoston:Karen Regas(e-copy),Yi Tian(e-copy),Madelyn Morris(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)
Shauna Cleveland,Esq., on behalf of CLF and Ten Persons Group
(per Motion for Mandatory Intervention, dated November 8,2013)
Copies are also being provided to persons who participated in the public hearing and comment
Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
LlDepartment of Environmental Protection
Northeast Regional Office•205B Lowell Street, Wilmington MA 01887.978-694-3200
D=JAL L PATRICK RICHARD K.SULLIVAN JR,
Governor Secretary
KENNETH L KIMMELL
JAN
SALEM
1 A AI Ll1
3 0 ' T,4 commissioner.
Mr. Scott G. Silverstein RE: SFI IALV EMl9
Footprint Power Salem Harbor Transmittal No.: X254064
Development LP Application No.: NE-12-022
1140 Route 22 East, Suite 303 Class: OP119
Bridgewater,NJ 08807 FMF No. 546374
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, September 9, 2013, November 1, 2013, December 11, 2013, January 10,
2014, January 16, 2014, January 17, 2014 and January 21, 2014. This Application concerns the
proposed construction and operation of a 630 megawatt (MW) nominal combined cycle electric
generating facility (the 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 Plan Approval for
said Application, as submitted, subject to the conditions listed below.
This Information is available in alternate format Call Michelle Waters-Ekanem,Diversity Director,at 617-292-5751.TDD#1-866-539-7622
or 1-617-5743868
MassDEP Website:wvm.mass.gov/dep
Printed nn PPnvriied Panef
l
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 2 of 60
This 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 Plan Approval allows for construction and operation of the proposed Facility,
and provides information on the proposed Facility description, emission control systems,
emissions limits, Continuous Emissions Monitoring Systems (CEMS), Continuous Opacity
Monitoring Systems (COMS),monitoring/testing, record keeping, and reporting requirements.
Effective April 11, 2011, a Delegation Agreement between MassDEP and EPA Region 1
was finalized for MassDEP to resume administration of the Prevention of Significant
Deterioration (PSD) Program in Massachusetts pursuant to 40 CFR 52.21 and the terms of the
Delegation Agreement. Therefore, MassDEP is concurrently issuing a separate PSD Permit for
the above described Facility.
Pursuant to 310 CMR 7.02(3)0)6., this Plan Approval includes a determination that the
emissions limits represent the most stringent emission limitation as specified in 310 CMR
7.02(8). Such limitations include Lowest Achievable Emission Rate (LAER) for nitrogen oxides
(NO.) (the pollutant subject to the requirements of Emission Offsets and Non-attainment Review
in 310 CMR 7.00: Appendix A), and Best Available Control Technology (BACT) for all air
contaminants addressed in the Plan Approval. The Fact Sheet for the PSD Permit, attached to
this Plan Approval, addresses MassDEP's determination of BACT for emissions of regulated
New Source Review (NSR) pollutants subject to PSD review, a subset of the air contaminants
subject to BACT in this Plan Approval, along with air quality impacts and other special
considerations of PSD review.
MassDEP verified and concurs with the BACT analyses submitted by the Applicant for
all air contaminants emitted by this proposed project including: nitrogen oxides (NO.), volatile
organic compounds (VOC), carbon monoxide (CO), particulate matter (PM/PM10/PM2.5), sulfur
dioxide (SOA sulfuric acid mist (H2SO4), greenhouse gases (GHG) and ammonia (NH3). The
BACT determinations contained in this Plan Approval are lower than or equal to BACT
emission limits established and published in EPA's RACT/BACT/LAER Clearinghouse (RBLC)
and other BACT determinations made in other states including California and New Jersey.
MassDEP therefore has determined that the emission limits contained in this Plan Approval are
BACT for this Facility.
MassDEP also has verified and concluded that the Lowest Achievable Emission Rate
(LAER) analysis for NO., included in the Application was the most stringent NO, emission rate
demonstrated in practice for the all emission units included in the Application.
Please review the entire 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 (MV) natural gas fired, quick start (capable of producing
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 3 of 60
300 MW within 10 minutes of startup) combined cycle electric generating facility (the proposed
Facility or 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 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 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 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 Facility will be configured as two emission units (EU1 and EU2) each capable of
operating independently in order to respond to Independent System Operator — 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). EUI and
EU2 each shall burn only natural gas with a sulfur content that does not exceed 0.5 grains per
100 standard cubic feet (pipeline natural gas) in the CTG and duct burner. Based on an ambient
temperature of 90 degrees Fahrenheit, each CTG/duct bumer 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. EUI 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 ammonia (NH3) storage tank,
an auxiliary cooling tower, a demineralized water tank, a fire protection service water tank, and
generator step-up transformers.
EU3 shall be equipped with Ultra Low NO. burners and an oxidation catalyst for carbon
monoxide (CO) and volatile organic compounds (VOC) control. EU3 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 4 of 60
EU4 and EU5 shall each burn ultra low sulfur diesel (ULSD) fuel oi,l 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 each shall be
restricted to no more than 300 hours of operation per twelve month rolling period.
During normal operating conditions, EUI 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 (NO.) 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
oxidation catalyst for CO and VOC control, followed by an 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 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 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 Facility's carbon dioxide equivalents (CO2e) emission rate of 895 pounds
per MW-hour net to the grid after the first year of operation, avoided COZe emissions via usage
of LED lighting amount to 111.0 tons per year. Per the "Section 61 Findings" (see Section 10,
pages 54to 58), there are a number of other Greenhouse Gases (GHG) efficiency measures that
will be implemented. As described in the Final Environmental Impact Report (FEIR), these
measures include the following. The Administrative Building has been designed to meet the
Massachusetts Energy Stretch Code and the U.S. Green Building Council's Leadership in Energy
and Environmental Design (LEED) at the Platinum level. The Administrative Building 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
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 5 of 60
energy management systems, a 10% reduction beyond Code for lighting power density, and
water conserving fixtures. The Operations Building includes geothermal heat pumps for heating
and cooling, increased insulation to minimize heat loss, day lighting, lighting motion sensors,
climate control, building energy management systems and a 10% reduction in lighting power
density, a high albedo roof and water conserving fixtures. These measures will result in a
reduction of GHG of 57 tons per year or a 29.4% reduction in GHG emissions. The buildings
have been elevated 6 feet above the existing 100-year flood level to protect the Facility from the
reasonable anticipated affects of sea level rise. All of these energy efficiency measures are
additional GHG mitigation strategies required by the Energy Facilities Siting Board (EFSB)
Final Decision and the Massachusets Environmental Policy Act (MEPA) FEIR Certificate and
are not associated with the Applicant's GHG BACT evaluation.
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 System (CEMS) shall be installed on EUI and EU2 to
sample, analyze and record NO., CO, and NH3 concentration levels, and the percentage of
oxygen (02), 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 System
(COMS) shall be installed in the stacks of EUI, EU2, and EU3 to monitor and record opacity.
Most of the 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 Facility will be
contained within these buildings or conducted behind screening to minimize visual impacts.
The 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 Facility
will interconnect at the same location where the existing Boiler Unit 4 is presently connected.
The other unit of the Facility will interconnect at a new circuit breaker bay to be constructed
within the existing National Grid switchyard. The Permittee shall ensure that its sulfur
hexafluoride (SF6) mitigation approach shall be at least as stringent as measures currently used
by National Grid for its circuit breakers and switchers to be located in the new switchyard and
plant areas to be constructed by the Permittee. The Permittee shall consult with National Grid
and develop a joint comprehensive S176 reduction plan in connection with the anticipated
National Grid upgrades to the Salem Harbor Substation (and shall file the joint plan as a
compliance filing to the EFSB prior to operation of the Facility).
Natural gas will be delivered to the site via a new pipeline owned and operated by -
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
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 6 of 60
onsite 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 PSD Fact Sheet. Therefore, MassDEP's evaluation of Emission Offsets and
Nonattainment Review for the construction of the 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 NO, or VOC emissions. With respect
to NO, 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 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 Facility is expected to commence commercial operation in June 2016. The Facility
shall be restricted to 144.8 and 28.0 tons per year of NO, and VOC emissions, respectively.
Therefore, the Facility is a new major source of NO, emissions and is subject to Appendix A for
its NO, emissions. The Facility is required to meet LAER for NO, emissions and the Permittee
must obtain NO. emission offsets at a ratio of 1.26 to 1. Since VOC emissions from the 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 Facility are subject to, and must comply with,
Best Available Control Technology (BACT)pursuant to 310 CMR 7.02.
The Permittee has proposed a NO. emission limit for EUl and EU2 of 2.0 parts per
million by volume, dry basis, corrected to 15 percent Oxygen (ppmvd @ 15% Oz), one hour
block average. The Permittee provided a LAER analysis in the Application that included the
sources of data reviewed in support of this NO, LAER determination. These sources were EPA's
RACTBACT/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 NO, emission limit of less than 2.0 ppmvd @ 15% OZ has been
approved and subsequently demonstrated in practice. In addition, the two most recent NO,
LAER determinations for similar Massachusetts projects such as Brockton Power Company LLC
(Application No. 41308015, Transmittal No. W207973 dated July 20, 2011) and Pioneer Valley
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 7 of 60
Energy Center LLC (Application No. 1-B-08-037, Transmittal No. X223780 dated December 31,
2010) were also 2.0 ppmvd @ 15% 02, 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 N%LAER for the Facility.
The NOx emission limits for the auxiliary boiler (EU3) is 9.0 ppmvd @ 3% 02. There
were no lower LAER determinations found in the RACTBACT LAER Clearinghouse for boilers
in the Applicant's size range, achieved in practice. The emergency reciprocating internal
combustion engine/generator (RICE) set (EU4) is 6.4 gm/KW-hr and for the fire pump engine
(EU5) is 4.0 gm/KW-hr. There were no more stringent applicable SIP emission limitations, no
projects found with lower emissions performance achieved in practice, or lower emissions limits
set in permits on the basis of LAER for RICE.
The Facility is a new major source of NOx emissions restricted to 144.8 tons per year and
the Permittee must obtain NO, emission offsets at a ratio of 1.26 to 1. The total number of NO,
emission offsets needed for the Facility is (144.8) multiplied by (1.26), or 183 tons per year. In
accordance with 310 CMR 7.00: Appendix A(6)(b), for a new major stationary source of NO,
located in an area that is not a nonattaimnent area, prior to commencing operation of any
emission unit(s), for which offsets are required under Appendix A, NO, 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 NO, 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 NO, ERCs were created and banked from the
shutdown of Natick Paperboard, 90 North Main Street,Natick and twenty two (22)tons per year
of NO, 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 in this case, on April 7,2020.
In addition, the Permittee entered into an agreement on April 4, 2013 to purchase 135
tons per year of rate-based NO. 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 NO, ERCs, dated April 2005, NO, 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 8 of 60
In total, the Permittee has entered into agreements to purchase 194 tons of rate-based
NO,ERCs. Since 183 tons per year of NO,; emission offsets will be used to offset NO, emissions
from the Facility, 183 tons per year of NO, ERCs in the Rate ERC Bank must be retired at the
approved annual offset rate regardless of the Facility's annual actual NO, 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 project significantly outweigh the environmental and social costs imposed as a
result of the project's location, construction or modification (3 10 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,
NO., 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 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 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 9 of 60
• 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. ISO-New England has also determined
that the Facility is needed to ensure reliability beginning in 2016.
• The site is nearby (less than two miles from) a natural gas pipeline facility, namely the
Maritimes and Northeast pipeline.
• There is 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.
• 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 Facility and enable further
redevelopment opportunities.
• 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. This is the only site that met Footprint's criteria and was located in the
NEMA/Boston load zone.
• The construction of the 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 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.
• 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No,NE-12-022
Page 10 of 60
• 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 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 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 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
ISO has determined that electric generation that will be provided by the 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
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 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,
The Facility also serves the Commonwealth's interest in developing renewable energy
sources. That is, the quick-start technology designed into the Facility facilitates and supports the
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 11 of 60
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 Facility will be more efficient and will have fewer emissions than the
peaking units that presently fill the gap when wind is unavailable.
While the 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 Facility "displaces
other, less efficient generation on the New England Grid, operation of [the Facility] reduces
annual regional air emissions including GHG emissions.t
The important air quality improvements resulting from the 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 reduction in Greenhouse Gases (COZe) in 2020 2
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.
Local Project Benefits
Without the 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 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 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 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
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 12 of 60
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 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 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, the GHG mitigation measures identified in the Section 61 Findings, the purchase of
NO, emission offsets and Regional Greenhouse Gas Initiative (RGGI) allowances. 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.
3. AIR OUALITY 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 (03), 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 concentrations, emissions from existing sources,
and new source emissions, 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 03 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 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 (referred to as cumulative dispersion modeling).
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 13 of 60
Modeling Approach and Significant Impact Analysis
Dispersion modeling analyses were performed to assess the 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 12345, 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 first order 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 Facility was characterized as
rural and significantly 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), plus a worst case combustion turbine start-up condition,
were modeled. Table 1 presents the maximum predicted ambient air quality impact
concentrations for the Facility. The 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-
�I Tah16 IAMB
Criteria ' z Averaging*+ = Primary Secondary; ";Srgniticant r Maximum
{ ae e 'w 4 *M- t - 1 0 1 _' [ + �a
Pollutant = T r,ePeriodi ' ; NAAQS NAAQSt Impact Level ;Predicfed Fac►lity`:
L s ' t i. ri .-�^ -•r � * X -�s +� 'Y"..3' �y�" �"' d t '''E i&''�- 3 x""x - -`kr. ' z v.. 2.r �3 *`
' °- -� ,� -.'� �:_, g} ��� k` .(u>;1'n►.) ,-, a, �_(ug/m3), , _(ug/m )� �eImpact_(ug/m-)s�:
NO2 Annual t'1 100 Same 1 0.4
1-Hour(2) 188 None 7.5 41.8
SO2 Annual t`.}l 80 None 1 0.03
24-Hour(3'4) 365 None 5 0.7
3-Hour(4) None 1,300 25 1.1
1-Hour(5'6) 196 None 7.8 1.0
PM2.5 Annual vl 12 Same 0.3 0.11
24-Hour(8) 35 Same 1.2 3.2
PM10 24-Hour M 150 Same 5 4.3
CO 8-Hour t41 10,000 None 500 112.4
1-Hour(4) 40,000 None 2,000 313.6
03 8-Hour t101 147 Same NA NA
Pb 3-Month°1 0.15 Same NA <0.00016
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 14 of 60
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.The 1 hour NO2 standard was effective April 12,2010.
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 99h 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 98 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 Kev:
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
PMI,=Particulate Matter less than or equal to 10 microns in diameter
CO=Carbon Monoxide
03=Ozone
Pb=Lead
ug/m3=micrograms per cubic meter
NA=Not Applicable
<=less than
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
and averaging periods with emissions from existing interactive sources and measured
background levels to compare against the corresponding NAAQS. 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 I-Hour NO2. Table 2 shows the cumulative impacts. The results of the
cumulative impact analysis show that under no condition did the Facility's worst case emissions
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 15 of 60
in combination with emissions from the existing interactive sources plus measured background
levels result in concentrations which exceeded the applicable NAAQS.
—Tallle 2'
Criteria ` 'Averaging ; Cumalative Impact; #Background " .Total Impach Plus Primary;t ;
Pollutant Pyeriod§ FacilrtyPlus Existing � (ug/m3) tl Bacicgrtiund t �r{ 1VAAQS7
7 SdurCcis
a5 ,,/ 3 C L `4 h. w - �' •- k'+ `°,.�L$,• y'4'�Wt r v
NO2 1-Hour 83.7131 82.3 166.0 188
PMZ., 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 PMz 5 and I-Hour NO2,are the average of the 98"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 8h highest 24-hour average values occurring in each year for the 24-Hour PMz 5
concentration, and the 5 year average of the 8b highest daily maximum concentrations occurring in each year for the
1-Hour NOz concentration.
3. The modeled cumulative NOz impacts represent an EPA-approved Tier 2 approach reflecting an 80 percent
conversion of NOx emissions to NOz in the ambient air. "Tier 2" is the Ambient Ratio Method for NO. to NOz
conversion of AERMOD modeling results. It specifies that the results of NO,; modeling be multiplied by an
empirically-derived NO2/NO, ratio, using a value of 0.75 for the annual standard and 0.8 for the 1-hour standard.
This modeling guidance is contained in USEPA's Clarification Memo, dated March 1, 2011, "Additional
Clarification Regarding Application of Appendix W Modeling Guidance for the I-hour NOz National Ambient Air
Quality Standard".
Table 2 Kev:
NAAQS=National Ambient Air Quality Standards
NOz=Nitrogen Dioxide
PMz 5=Particulate Matter less than or equal to 2.5 microns in diameter
ug/m'=micrograms per cubic meter
Air Toxics Analvsis
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
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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 16 of 60
Table 3 presents the projected maximum impacts for each air toxic that will potentially be
emitted by the Facility for which an AAL or TEL has been established. Predicted impacts are
based on the worst case emission scenarios input to AERMOD. As shown in Table 3, the
Facility's maximum predicted ambient air quality impact concentrations were significantly
below applicable AALs and TELs for all of the air toxics modeled.
:a:,ppm�
�:. '_'+ttfl' �...;-._Talile3:'•nT•. a.r-`•,. Fh'w. 't-..,�.' g,-, a�, �.uJ..�
1 �,Pollutant - `,I Averaging Period, AAL/TEL (ug/m,' =Malumum Predicted Fac►litf
.-�
6 --t-._,.ar.a.�...-.._ ,',. --tih x3.'°7.•a.+2'' '- �t �5-r 'so=.,�._ -z _:.." "'!" *IRlpact (Rg/m3) f� -...
Acetaldehyde 24-Hour(TEL) 2 0.053708
Annual (AAL) 0.5 0.000775
Ammonia 24-Hour (TEL) 100 1.093673
Annual (AAL) 100 0.034497
Benzene 24-Hour(TEL) 1.74 0.080104
Annual (AAL) I 0.12 0.000591
1,3-Butadiene 24-Hour (TEL) 1.20 0.002035
Annual (AAL) 0.003 0.000019
o-Dichlorobenzene 24-Hour(TEL) 81.74 0.000047
Annual (AAL) 81.74 0.000006
p-Dichlorobenzene 24-Hour(TEL) 122.61 0.000047
Annual (AAL) 0.18 0.000006
Ethylbenzene 24-Hour (TEL) 300 0.012962
Annual (AAL) 300 0.000409
Formaldehyde 24-Hour(TEL) 2.0 0.203990
Annual (AAL) 0.8 0.005265
Naphthalene 24-Hour(TEL) 14.25 0.009739
Annual (AAL) 14.25 0.000067
Propylene Oxide 24-Hour(TEL) 6 0.334015
Annual (AAL) 0.3 0.002126
Sulfuric Acid 24-Hour(TEL) 2.72 0.084823
Annual (AAL) 2.72 0.005963
Toluene 24-Hour(TEL) 80 0.083392
Annual (AAL) 20 0.001857
Xylenes 24-Hour(TEL) 11.80 0.047138
Annual (AAL) 11.80 0.000942
Arsenic 24-Hour (TEL) 0.003 0.000012
Annual (AAL) 0.0003 0.000001
Beryllium 24-Hour (TEL) 0.001 0.000000
Annual (AAL) 0.0004 0.0000001
Cadmium 24-Hour (TEL) 0.003 0.000044
Annual (AAL) 0.001 0.000006
Chromium (total) 24-Hour(TEL) 1.36 0.001137
Annual (AAL) 0.68 0.000013
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 17 of 60
able-
4L,
'Pollutant }_ " `Averaging Penod -A_ AL/I EL (ug/m')* Maxim_ u_ft► P'redreted Eacility -„
.
:Impact (ug/mi) =v
Chromium (hexavalent) 24-Hour (TEL) 0.003 0.000205
Annual (AAL) 0.0001 0.000002
Copper 24-Hour(TEL) 0.54 0.00003
Annual (AAL) 0.54 0.00000
Lead ... 24-Hour(TEL) 0.14 0.00009
Annual (AAL) 0.07 0.000003
Mercury (elemental) 24-Hour (TEL) 0.14 0.00001
Annual (AAL) 0.07 0.000001
Nickel 24-Hour(TEL) 0.27 0.00021
Annual (AAL) 0.18 0.00001
Selenium 24-Hour(TEL) 0.54 0.00002
Annual (AAL) 0.54 0.0000002
Vanadium 24-Hour (TEL) 0.27 0.00009
Annual (AAL) 0.27 0.00001
Table 3 Notes:
1. Most air toxics do not have a NAAQS,with the exception of lead.
Table 3 Kev:
AAL=Allowable Ambient Limit
TEL=Threshold Effects Exposure Limit
Ug/M3=micrograms per cubic meter
Preconstruction Monitorine Analvsis
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 Facility impact concentrations well
below corresponding SMC levels for all pollutants for which SMCs exist.
,�.,a.__ i'. Wiz. �_ x ;tE'"`-`,-n-.'g-3ti: iY' a - _ ,,,gr9nt-�.Pn__y- -;..��.m., .. .. ...i"r ,ssxk.• dF?'._;
rPollutant �� Averaging Period { -SMC (ug/mx) Maximum Predicted Facility.
?'
NO2 Annual 14 0.4
SO2 24-Hour 13 0.7
PMIo 24-Hour 10 4.3
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 18 of 60
-, ;_�' , �.�_ , ', . `` �'� .r�= '_�t.L;..,�:Talile,'4��� •�, rs-. ,�-: s.?�'.. ,�-:-�a,�.-W��=
x Pollutant:; `_.: Averaging Peri60mum'�j? dictedFad ity
+ •et aril m .R �5 y ' -�—*7A ' .� - ti v 3rA 'r„
CO 8-Hour 575 - 112.4
Table 4 Kev:
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
Facility, is representative of the 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 Facility site,
particularly without the influence of the existing Salem Harbor Station after its shutdown
prior to when the Facility commences operation. The 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 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 Facility site via predominant
winds from the south or southwest, typically pass 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
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 19 of 60
cumulatively with the 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 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 PMS
Despite the fact that the PSD regulations addressing 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/m3 vs. 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 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
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.
Footprint Power Salem Harbor Development LP
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• 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 PM25 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.
httD://www.eDa.2ov/nsr/documents/20130304cia.i)df
4. ACCIDENTAL RELEASE MODELING OF AOUEOUS AMMONIA(NII3)
Aqueous NH3 will be used as the reducing agent in the Facility's SCR system to control
NO, 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
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.
Footprint Power Salem Harbor Development LP
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Transmittal No.X254064
Application No.NE-12-022
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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 shall be equipped with level monitoring instrumentation that will be
continuously monitored in the 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 (ALOHA) 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
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:
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 22 of 60
;=Takile•5--,
t. I oeatiori "� t °--Dis'tance from NH3 ,:: ERPG 1 ti ERPG-24 CNH Concentration- ,'
3
t
cl F Storage Enclosure(Feet) (ppm) (Maximum Hourly-Yalae;
'�. . ._ .A.eA.' - a �.ea ^+i'{'-, ✓_ - v '�K k - '`..� ' . ¢.aA ..v i. ` d ...;., rPpm) L{
Power Plant North 230 25 150 20.2
PCAP
Power Plant West 340 25 150 13.1
PCAP
Power Plant East 450 25 150 4.4
PCAP
Nearest Residence 570 25 150 6.7
(Fort Avenue)
Salem Essex 750 25 150 6.8
Sewerage District
(SESD) J
Table 5 Kev:
PCAP=Projected Controlled Access Perimeter
ERPG-1 =Emergency Response Planning Guideline Level I
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 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 Perrnittee shall take all steps necessary to meet the general duty clause above.
Footprint Power Salem Harbor Development LP
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Transmittal No.X254064
Application No.NE-12-022
Page 23 of 60
5. EMISSION UNIT (EU) IDENTIFICATION
Each Emission Unit (EU) identified in Table 6 is subject to and regulated by this Plan
Approval:
'�•- i :ra' _ a.X...uY y �. `x r- - ._.4'".'Patile 6.rs5'£� rxd= w= =. 4 rr; sj✓,'r r, w„ti` '. II
EU# ;Descrrption ° DesrO"1 Cipnfici ' Pollutron Control
r+'^a .m, _pfd iso'.¢"gDevree(PCD)F_-b '
EUI General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO.
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCDI)
Including Duct Burner input) Selective Catalytic
Reduction(PGD2)
346 MW(electric Oxidation Catalyst
power output) (PCD3)
EU2 General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD4)
Including Duct Burner input) Selective Catalytic
Reduction(PCD5)
346 MW(electric Oxidation Catalyst
power output) (PCD6)
EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or 80 MMBtu/hr, Ultra Low NO,Burners
equivalent HHV (energy (PCD7)
Auxiliary Boiler input) Oxidation Catalyst
(PCD8)
EU4 Cummins Model No. DQFAA or equivalent 7.4 MMBtu/hr, None
Emergency Engine/Generator HHV (energy
input)
1102 bhp (engine
mechanical power
output)
750 KW
(generator electric
power output)
EU5 Cummins Model No. CFP9E-F50 or equivalent 2.7 MMBtu/hr, None
Fire Pump Engine HHV (energy
input)
371 bhp (engine
mechanical power
output)
Table 6 Key:
EU#=Emission Unit Number
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
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No.=Number
MMBtu/hr=fuel heat input,million British thermal units per hour
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
6. APPLICABLE REQUIREMENTS
A. OPERATIONAL, PRODUCTION and EMISSION LIMITS
The Facility is subject to, and the Permittee shall ensure that the Facility shall not exceed
the Operational, Production, and Emission Limits as contained in Table 7 below, including
footnotes:
Y��y 'i.moi,... _ .. .�}';aV`S"" yi'•' "'�'i'm',�� ^l4i e:rd• .�- _ �.44v
Operational/Production Au Contaminant Emission Lrinita � ,
x '€+
1,
t'+ -. 6 ro.r•a-",R-. 'N' .-sa .v�k"ms,^.r m:,.� s„ ", .-
EU 1, EU2 Operation at>MECL, 'o NO, (no duct firing) < 17.0 lb/hr 2)
excluding start-ups and <0.0074 lb/MMBtu(1)
shutdowns <2.0 ppmvd @ 15% 02 (1)
<0.051 lb/MW-hr(1,1,10,14)
Fuel Heat Input Rate of
each EU: < 15.0 ppmvd @ 15% 02
<2,449 MMBtu per hour, or
HHV <0.43 lb/MW-hr(ls)
NO, (duct firing) < 18.1 lb/hr 1",�1
Natural Gas shall be the <0.0074 lb/NIMBtu(1)
only fuel of use. <2.0 ppmvd @ 15% 02(1)
<0.055 Ib/MW-hr(1,2,15)
Fuel Heat Input of each EU:
< 18,888,480 MMBtu, < 15.0 ppmvd @ 15% 02
HHV per 12-month rolling or
period(9) <0.43 lb/MW-hr(ls)
CO (no duct firing) < 8.0 Ib/hr 11,2)
<0.0045 lb/MMBtu(1)
<2.0 ppmvd @ 15%02(1)
<0.027 lb/MW-hr(1,2,10,14)
CO (duct firing) < 8.0 lb/hr 1",21
< 0.0045 lb/MMBtu(')
<2.0 ppmvd @ 15% 02(t)
<0.025 lb/MW-hr(1,2,15)
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 25 of 60
=,Table,7i
II>4EU# Operational/Producoon -` Atr Contaminant - _ Emission Ltuttt ,''`�
j ffi 1s t5d � �8,
-
EU 1, EU2 Operation at>MECL, 11'1 VOC (no duct firing), <3.0 lb/hr
excluding start-ups and as Methane (CH4) <0.0013 lb/MMBtu�I)
shutdowns < 1.0 ppmvd @ 15% 02 ll)
<0.009 lb/MW-hr(1,2,10,14)
Fuel Heat Input Rate of VOC (duct firing), <5.4 lb/hr
each EU: as Methane(CH4) <0.00221b/MMBtu�l)
<2,449 MMBtu per hour, < 1.7 ppmvd @ 15% 02 (1)
HHV <0.016 lb/MW-hr(1,2,15)
S in Fuel <0.5 grains/100 scf
Natural Gas shall be the S02 (no duct firing) <3.5 lb/hr 1"21
only fuel of use. < 0.0015 lb/MMBtu(1)
< 0.3 ppmvd @ 15% 02(1)
Fuel Heat Input of each EU: <0.010 lb/MW-hr(1,2,10,14)
< 18,888,480 MMBtu, S02 (duct firing) < 3.7 lb/hr
HHV per 12-month rolling < 0.0015 lb/MMBtu(l)
period(9) <0.3 ppmvd @ 15% 02 ll)
< 0.011 lb/MW-hr(l,2,15)
H2SO4 (no duct firing) <2.2 lb/hr 1 ,21
<0.0010 lb/MMBtu
<0.1 ppmvd @ 15% 02 (1)
< 0. 007 lb/MW-hr(l,2,10,14)
H2SO4 (duct firing) <2.3 lb/hr 1"2
1
<0.00101b/MMBtu(l)
<0.1 ppmvd @ 15%02 (1)
<0.008 lb/MW-hr(1,2,15)
PM/PMIO/PM2,5 (no duct < 8.8 lb/hr u,61
firing) —<0.0071 Ib/MMBtu
<0.029 lb/MW-hr(l,8,10,14)
PM/PMIO/PM2,5 (duct firing) — < 13.0 lb/hr 1"61
< 0.0062 Ib/MMBtu
<0.041 lb/MW-hr ll,e,15)
NH3 (no duct firing) <6.2 lb/hr I""
<0.0027 Ib/MMBtu(l)
<2.0 ppmvd @ 15%02 (1)
<0.0191b/MW-hr(1,2,10,14)
NH3 (duct firing) <6.6 lb/hr u,21
< 0.00271b/MMBtu�l)
<2.0 ppmvd @ 15%02 (1)
_<0.020 lb/MW-hr(1,2,15)
Greenhouse Gases, CO2e < 825 lb/MW-hr
— < 895 lb/MW-hr 116)
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Transmittal No.X254064
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'�4 :,. S. _:. � „:. �.,:`°�'.:.<_: ;i..' ''`?!y�°T h C 7.�^+r �>•:_ �' h5 -r y,tr'aM- 4 eu: '�
....I - dm: � - , Pt d - e: -.:v=" ;b• •;:S+n:��.%'s."'`Px_•;» :.- -a!�,_:✓;:e'
`EU# .a Operational'%Production'. m Air<,Contarninant;?- ._� Em
yb >Sston Lwinit; ter.
_Ail
EU1, EU2 Operation at> MECL, ") Opacity <5%,except 5%to < 10%for
excluding start-ups and <2 minutes during any one
shutdowns hour 15)
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)
Operation at<MECL NO, _< 89 lb per event 14"2)
during start-ups (3,12) CO <285 Ib per event 14,12)
VOC, <23 Ib per event 14'12)
Start-up duration: as Methane (CH4)
<45 minutes (3,12)
� Sin Fuel < 0.5 grains/100 scf
S02 <2.0 lb per event
Natural Gas shall be the I H2SO4 < 1.3 lb per event
only fuel of use. PM/PMIa/PM2.5 < 6.6 lb per event 14'"12)
NH3 NA
Opacity < 10% 15'12.)
Operation at<MECL NOx < 10 lb per event(12)
during shutdowns (3,12) CO < 151 lb per event(12)
VOC, <29 lb per event ")
Shutdown duration: as Methane (CH4)
<27 minutes(3,12)
� Sin Fuel <0.5 grains/100 scf
S02 <0.3 lb per event(12)
Natural Gas shall the i H2SO4 <0.2 lb per event 111)
only fuel of use.
I PM/PMI0/PM2.5 <3.96 lb per event
NH3 NA
Opacity < 10%(5'12)
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abli 71
� EU#- 5 006fifioiffl-7 Pr6dfidfibn' Air Contaminant X ."lEinissi6n',Limit:
to-uifift
EU3 Operation at>MECL llxl NO, <0.88 lb/hr
< 0.011 lb/MMBtu
Fuel Heat Input Rate: <9.0 ppmvd P,3% 02
< 80 MMBtu per hour, CO <0.28 lb/hr")
HHV < 0.0035 lb/MMBtu 111
:S 4.7 ppmvd g, 3% 02
Natural Gas shall be the VOC, <0.4 lb/hr"I
only fuel of use. I as Methane (CH4) <0.005 lb/MMBtu (1)
< 11.8 ppmvd (a0 3%02(1)
Total Fuel Heat Input: S in Fuel < 0.5 grains/100 sef
< 525,600 MMBtu' HHV SO2 < 0.12 lb/hr
per 12-month 9)rolling period < 0.0015 lb/MMBtu(1)
(
<0.9 ppmvd (& 3% 02
H2SO4 < 0.072 lb/hr"I
< 0.000 lb/MMBtu(1)
0.35 ppmvd (&, 3% 02
PM/PM10/PM2.5 <0.4 lb/hr("8)
< 0.005 lb/MMBtu c1.sl
Greenhouse Gases, CO2, < 119.0 lb/MMBtu
Opacity <5%, except 5%to< 10%for
<2 minutes during any one
hour(5)
EU4 <300 hours of operation pe i NOx and VOC (NMHC as < 11.60 lb/hr tbl
12-month rolling period CH1.8), <4.8 gm/bhp-hr
Combined Total < 6.4 gm/KW-hr(6)
Ultra Low Sulfur Diesel CO <6.34 lb/hr 161
Fuel Oil shall be the only <2.6 gm/bhp-hr
fuel of use. <3.5 gm/KW-hr(6)
S in Fuel <0.0015%by weight
S02 <0.011 lb/hr
H2SO4 < 0.0009 lb/hr
PM/PM10/PM2.5 <0.36 lb/hr I))
<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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Transmittal No.X254064
Application No.NE-12-022
Page 28 of 60
Table°")
r to E V tt Y..ku Il e • -:yv w - w- '' :--yc O
m-;t -4=-*f - ,w erattonal/Production 4 Air Contamma_nt� -� �� � Eucslon
EU5 < 300 hours of operation pe NO,and VOC (NMHC as <2.44 lb/hr
12-month rolling period CHI g), <3.0 gm/bhp-hr(6)
Combined Total <4.0 gm/KW-hr(6)
Ultra Low Sulfur Diesel CO <2.14 lb/hr 161
Fuel Oil shall be the only <2.6 gm/bhp-hr 161
fuel of use. < 3.5 gm/KW-hr(6)
S in Fuel <0.0015%by weight
SO2 < 0.004 lb/hr 16)
H2SO4 <0.0003 lb/hr(61
PM/PMI0/PM2.5 <0.12 lb/hr(6)
< 0.15 gm/bhp-hr 161
< 0.2 gm/KW-hr(6)
Greenhouse Gases, CO2e < 162.851b/MMBtu
Opacity <5%, except 5%to < 10%for
<2 minutes during any one
hour
EUI, EU2, NA Smoke 310 CMR 7.06 (1)(a)
EU3, EU4,
EU5
Facility-Wide NA NOx < 144.8 TPY(o
CO <88.0 TPY ul
VOC <28.0 TPY t'1
SO2 <28.8 TPY
PM/PMIo/PM2.5 < 82.0 TPY v,xl
NH3 <51.0 TPY ul
H2SO4 < 19.0 TPY til
Pb <0.00013 TPY
Formaldehyde or Single HAP <6.6 TPY '
Total HAPs < 13.1 TPY
CO2 <2,277,333 TPY(7
)
Greenhouse Gases, CO2, <2,279,530 TPY u)
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 2,300 MMBtu/hr,HHV(no duct firing),at 0°F ambient temperature,and 2,449 MMBtu/hr,HHV(duct
firing), at 90 OF ambient temperature, both at 14.7 psia ambient pressure and 60% ambient relative humidity. 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 WCL) is reached. Shutdowns include the time from dropping below the MECL until
flame-out.
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4. Emission limits represent worst case emissions for cold start-ups.Emissions for warm and hot start-ups are
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
start-up 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 CHI,$),which corresponds to a gas density of 0.5746 kg/m3.
7. Facility emissions include the two CTG/HRSG pairs with duct burners(EUI 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 EUI and EU2 are based on 8,040 hours of natural gas firing per
12 month rolling period at 100% load and 50°F 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 90°F 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 EUI
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 bumer/evaporative cooling status, and 13, 189,
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 NO, and VOC
emissions for EU4 are
U assumed U be emitted at the EPA Tier 2 limit of 6.4 gm/KW-Lr and the EPA Tier 1 limit of
1.3 gm/KW-hr, respectively. Worst case NO, 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/PM25 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 50°F 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 90°F 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)without duct firing ISO corrected(59°F, 14.7 psis,
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°F, 14.7 psia,
60%humidity)heat rate of 6,940 Btu, higher heating value,per KW-hr net electrical output to the grid and a COU
emission factor of 119.0 lb/MNVIBm. This emission factor is based on a CO2 emission factor of 118.9 lb/MlvlBtu
calculated from Equation G-4 of 40 CFR Part 75 Appendix G plus an emission factor of 0.1 lb/NRvIBtu for other
greenhouse gases(methane and nitrous oxide)calculated utilizing the emission factors for these two pollutants from
Table C-2 of 40 CFR Part 98 Subpart C and the global warming potentials for these two pollutants from Table A-1
of 40 CFR Part 98 Subpart A.. 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.
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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/COMB data generated from the first year of commercial operation.
13. NO,emission limits are from 40 CFR Part 60 Subpart KKKK.Compliance with the BACT and LAER NO,
emission limits of this Plan Approval shall be deemed compliance with the NO,limits from 40 CFR Part 60 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 a CO2,emission factor of 119.0 lb/NIMBtu(see Footnote 11 above).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(MIv1Btu) and
multiplying by the CO2,emission factor of 119.0 lb/MIvMtu.
17. Minimum Emissions Compliance Load (MECL) for EUI 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 Kev:
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
CO2, = Greenhouse Gases expressed as Carbon Dioxide equivalent and calculated by multiplying each of the six
greenhouse gases (Carbon Dioxide, Nitrous Oxide, Methane, Hydrofluorocarbons, Perfluorocarbon, 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.
Ib=pounds
lb/br=pounds per hour
grains/scf=grains per standard cubic foot
MMBtu=million British thermal units,higher heating value(HHV)basis
lb/MMBtu=pounds per million British thermal units
ppmvd @ 15%02=parts per million by volume,dry basis, corrected to 15 percent oxygen
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ppmvd @ 3%Oz=parts per million by volume, dry basis,corrected to 3 percent oxygen
scf=standard cubic feet
kg/m' =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
TPY=tons per 12-month rolling period
°F=degrees Fahrenheit
psia=pounds per square inch,absolute
EPA=Unites States Environmental Protection Agency
CFR=Code of Federal Regulations
ISO=International Organization for Standardization
CTG41RSG=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 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% 02. 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 NO,emission
standard for EUI and EU2 is 15 ppmvd @ 15% 02 or 54 ng/J of useful output (0.43 lb/MW-hr).
The Permittee has ensured that the Facility will comply with these limits through the use of dry low-
NO, combustion technology in conjunction with SCR add-on NO, control technology to control
NO, emissions to 2.0 ppmvd @ 15% 02 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
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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 EUl and EU2.
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.
Emereencv Eneine/Generator and Fire Pumn Eneine (EU4 and EU5)
The emergency generator(EU4) and fire pump (EU5) engines serving the 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.
C. NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
(NESHAP) for the followine Source Cateeories
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 Facility is not a major source
of HAP emissions. Therefore, the Facility's combustion turbines are not subject to the 40 CFR
Part 63 Subpart YYYY requirements.
The 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.
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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 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.
Emergencv Engine/Generator and Fire PumD 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 IIIL 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 Facility is subject to various emission allowance programs. Emission
allowance programs are market based air quality regulatory programs for which 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 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 Facility. True-ups for annual SO2 and ozone season NO, (May through
September) emissions are done annually. True-up for CO2 emissions is done every three years. A
partial true-up for CO2 emissions is done annually.
These allowance programs require that actual facility emissions of SO2, NO., 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.
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Table 8 below contains the Permittee's applicable allowance programs for each pollutant,
including the applicable regulation(s) and subject EUs at the Facility covered in this Plan
Approval.
',ykbK, .er"•A d' - ','� i�3:,
Table
``Pollutant' '' Program 4 Applicable Subject facrbty ssiongUn►ts`Jon .
J:aY '• "a [� _ ",�3� P "w., u. &x,yti
n"
SO2 Acid Rain Program 40 CFR Parts 72, 73, EUI, EU2
(ARP) and 75
NO, NO,Ozone Season Clean 310 CMR 7.32 EUI, EU2
Air Interstate Rule
(CAIR)
CO2 Regional Greenhouse 310 CMR 7.70 EUI, EU2
Gas Initiative (RGGI)
CO2 Budget Trading
Program(State Only
Requirement)
Table 8 Kev:
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
N%=Nitrogen Oxides
CO2=Carbon Dioxide
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 Facility is subject to, and the Permittee shall ensure that the Facility shall comply
with, the monitoring, testing, record keeping, and reporting requirements as contained in Tables
9, 10, and 11 below:
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k L,EU# - s'- -- -«a. —_-Monttorrng
EUI, 1. The Permittee shall ensure that the Facility is constructed to accommodate the emissions
EU2, EU3 (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 flo
disturbance. In addition, the Permittee shall facilitate access to the sampling ports and testin
equipment by constructing platforms, ladders, or other necessary equipment.
2. The Permittee shall ensure that compliance testing of the 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 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, 4C
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.
3. The Permittee shall conduct initial compliance tests of the Facility to document actual
emissions of EUI,EU2, and EU3 so as to determine their compliance status versus the emission
limits (in lb/hr, lb/MIvIBtu, ppmvd, and lb/MW-hr, as applicable) in Table 7 for the pollutant
listed below.
Testing for these pollutants for EUI 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; an
peak(approximately 102 percent load)with 100 percent duct firing.
NOX, CO,VOC, SO2,PM, PM1o, 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.
NO, 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 EUI and EU2; parametric monitoring testing for PM,
PM10, and PM2.5 emissions for EUI and EU2; and NO./CO emissions optimization testing
for EU3.
EU3 5. The Permittee shall conduct NO./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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 36 of 60
tip ' fiw'"S.� sear` M P - Y e 1
M.on�fonng and.Testing:Requirements , :" g,, r
EUI, 6. The Permittee shall install, calibrate, test, and operate a Data Acquisition and Handling
EU2, EU3 System(s) (DANS), CEMS, and COMS serving EU1 and EU2 to measure and record the
following emissions:
a) OZ; b)NOX; c) CO; e)NH3; d) opacity.
The Permittee shall install, calibrate, test, and operate a DAHS and COMS to measure an
record opacity on EU3.
7. The Permittee shall ensure that all emission monitors and recorders. serving EUI, EU2 an
EU3 comply with MassDEP approved performance and location speifications,-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 7.3 2, and 310 CM
7.70, as applicable.
'. The
Permittee shall ensure that the subject CEMS and COMS are equipped with properl
operated and properly maintained audible and visible alarms to activate whenever emissions
from the Facility exceed the short term limits established in Table 7 of this Plan Approval. 1
9. The Permittee shall operate each CEMS and/or COMS serving EUI, EU2 and EU3 at all
imes except for periods of CEMS and COMS calibration checks, zero and span adjustments,
reventative maintenance, and periods of unavoidable malfunction.
10. The Permittee shall obtain and record emissions data from each CEMS and/or COMS
serving EUI, EU2 and EU3 for at least seventy (75) percent of each emission unit'
operating hours per day, for at least seventy five (75) percent of each emission unit'
operating hours per month, and for at least ninety five (95) percent of each emission unit'
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 an
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 b
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 EUI, EU2 and'
EU3 as "direct-compliance" monitors to measure NO., CO, NH3, OZ, 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 program for the long-
term operation of the CEMS and/or COMS serving EUI, 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.
114. The Permittee shall install, operate, and maintain a fuel metering device and recorder for
UI, 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 EUI, EU2, and EU3.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 37 of 60
I n&Testini� &1ififements
0 FIL�PRI
Int6r n R
EUI, 16. The Permittee shall monitor each date and daily hours of operation and total hours of
EU2, EU3 operation for EU1, EU2, and EU3 per month and twelve month rolling period.
EUI, EU2 17. The Permittee shall ensure that initial compliance tests of the Facility are conducted for
"hot start", "warm start", "cold start", and shutdown periods as defined in the Permittee's
Application for EUI and EU2. These compliance tests shall represent periods of operation
below the MECL for EUI 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.
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 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:
VOCamal = VOCI,mit x (COauai/COIin,t), 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 EUI 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 EUI 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 oxidation catalysts serving EU1
and EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambient
temperatures for EUI 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 EUI 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,PMIO, and PM2.5 emission limits.
27. The Permittee shall monitor the SO2 and CO2 emissions in accordance with 40 CFR
Part 75.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 38 of 60
$'F k' .24 K*V41
EU#� Mourtorin and&Testm Re'uiremeiits
g..__ i;.__- 9 s-
EUI, EU2 X28. 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
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.
Facility- 32. The Permittee shall monitor all operations to ensure sufficient information is available to
Wide 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.
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
02=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
Ib=pounds
Ib/hr=pounds per hour
lb/1 MBtu=pounds per million British thermal units
ppmvd=parts per million by volume,dry basis
lb/MW-hr=pounds per megawatt-hr net electrical output to the grid
scf=standard cubic feet
MMBtu/hr=million British thermal units per hour
MMBm=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 0.0015 weight percent sulfur
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 39 of 60
NUI
z ,.'.Table10
F_F�U# � Record We—e--i" R rqe!
. I - _ -Keeping .�c�qqwq
EU1, 11. The Permittee shall maintain records of each emission unit's hourly fuel heat input rat
EU2, EU3 fti/hr, HHV), total fuel heat input (MA4Btu), and natural gas consumption
ronth and twelve month rolling period basis. I
I2- The Pennittee shall maintain records of each date and daily hours of operation and total
ours of operation of each EU per month and twelve month rolling period.
13.Zan
The Permittee shall maintain on-site permanent records of output from all continuous
tutors (including CEMS d COMS) for flue gas emissions and natural gas consumptio
I�scf).
4. The Permittee shall maintain a log to record problems, upsets or failures associated wi
vi
the subject emission control systems, DAHS, CEMS, and/or COMS serving EUI, EU2, anj
EU3, and the NH3 handling system serving EU1 and EU2.
EUI, EU2 5. The Permittee shall continuously estimate and record VOC emissions on the DAHS using the
CONOC correlation curve developed from the most recent compliance test.
16. The Permittee shall continuously estimate and record PM, PM,o, and PM2.5 emissions on the
PAHS using the surrogate methodology or parametric monitoring derived from the most recent
Icompliance test.
UThe Permittee shall maintain records of the load, start-up and shutdown duration, an
s emissions (lb/event) during start-up and shutdown periods of EUI and EU2. I
I8. 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 byl
EUI 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.
110 The Permittee shall record SO2 and CO2 emissions from EU1 and EU2 in accordance!
[with 40 CFR Part 75. 1
L1The Permittee shall record the Greenhouse Gas emission rate of EU1 and EU2 on a daily
.is utilizing the calculation procedures in 40 CFR Part 98 Subpart A, Table A-1. i
112. The Permittee shall maintain continuous records of SCR and oxidation catalyst inlet'
�temperatures, combustion turbine inlet temperatures and ambient temperatures.
13. The Permittee shall maintain the SOMP for the NH3 handling system serving EUI 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 Pennittee 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.
116. The Permittee shall maintain a record of the sulfur content of each ULSD fuel oil delivery
Imade to the Facility.
I17. The Applicant shall maintain records concerning engine certifications as described in 310
CMR 7.26(42)(e)1. at the Facility. I
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 40 of 60
,�µ1,��,�;•r:- .; ;���: �.!. ,-_, rad 4 _> 'Talile 10;; �,�4 � �:�.. Y a� � � �;
IZZEU#_, i'" '°': ,' „ g Record Keeping Requirement's;,,, .
Facility- 18. A record keeping system for the Facility shall be established and maintained up-to-date!
Wide 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 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 al
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 thej
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.
19. The Permittee shall maintain all records required by 310 CMR 7.32, 310 CMR 7.70, 3101
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
httn://www.mass.gov/eea/aQencies/mas sden/air/annrovals/limited-emissions-record-keening_-
and-renortine_.html#WorkbookforReDortineOn-SiteRecordKee_ning_ in Microsoft Excel
format.)
i21. The Permittee shall maintain a copy of this Plan Approval, underlying Application, andl
the most up-to-date Standard SOMP for each emission unit and PCD approved herein on-
site.
22. The Permittee shall maintain a complaint log concerning emissions, odor, and noise froml
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. Thel
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 Pennittee shall maintain records for the annual preparation of a Source j
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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 41 of 60
Table 10 Kev:
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
PMIo=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
MMBtu/hr=million British thermal units per hour
MMBm=million British thermal units
HHV=higher heating value basis
TPY=tons per 12-month rolling period
-, i .y ::cisx-
-: N '".Table
EU
# as"x ....�',-. z1»: wt�+, .. ..��.,',"-x :. Reporting.R iluirements ,,:s': �a : -. t_ '$hx."'"-,=`'I
EUI, 1. The Permittee must obtain written MassDEP approval of an emissions test protocol prior
EU2, EU3 to initial compliance emissions testing of EUI, 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.
[n addition, the protocol shall include procedures for: a) the required CO and VOC
correlation for EUI and EU2; b) a parametric monitoring strategy to ensure continuous
monitoring of PM, PMIo, and PM2.5 emission from EUI and EU2; and c) procedures for the
required NO, and CO optimization for EU3. The protocol must be submitted to MassDEP a
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 EUI, EU2 and EU3 must b
submitted, in writing, at least 30 days prior to commencement of commercial operation o
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 t
MassDEP for MassDEP approval prior to their implementation.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
1 Page 42 of 60
.Table'11:•�>r, `.5:; _ s_ wy _ ",`z`"
f4J .� i'kY�'b :+Y a't ] M.r. Y:6 n iY
t ,EU#. .. Re orcin `Re in put
5
.. . .' -tee•+,rix.;}...:a-.�.• P, g q.
EUl, 4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the
EU2, EU3 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 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 start-up,
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.
EUI,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 EUI 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 oxidation 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 43 of 60
Z'
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)l not later than 30 days prior to commencement
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.
Facility- 10. The Permittee shall submit to MassDEP a plan for monitoring and abating air and nois
Wide impacts during the period of construction of the Facility, not later than 30 days prior
commencement of construction. 01
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. No later than 12 months after commencement of operation of the Facility, the Permitted
shall submit an Operating Permit Application to MassDEP in accordance with 310 CMR!
7.00: Appendix C.
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.usI 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.aira,massmail.state.ma.usI 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-
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 44 of 60
_A ,rnTab
t%-EUW44 1' `
iwkin Requirements` -_ I �2
Facility- 118. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 301
Wide of each year to demonstrate the Facility's compliance status regarding the Facility-Wide
emission limits (TPI) specified in Table 7. Reports shall include actual emissions for the
previous 12 months. (The MassDEP approved format can be downloaded at
httD://www.mass.gov/eea/a2encies/massdei)/air/ai)t)rovals/lin-ited-emissions-record-keeDina-
land-rei)ortina.html#WorkbookforRei)ortinvOn-SiteRecordKeei)ing in Microsoft Excel
Iformat.)
119. 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.
0. 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
he 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.airamassmail.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. If and when MassDEP requires compliance testing, 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.
�5. If and when MassDEP requires compliance testing, the Permittee shall submit t
MassDEP a final stack emission test results report, within forty five (45) days after emissio
�esting, for emission testing as defined in Table 9 Monitoring and Testing Requirements.
Table 11 Kev:
EU#=Emission Unit Number
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 45 of 60
EPA=United States Environmental Protection Agency
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
NO,=Oxides of Nitrogen
CO=Carbon Monoxide
NH3=Ammonia
PM=Particulate Matter
PM10=Particulate Matter less than or equal to 10 microns in size
PMZ 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
7. SPECIAL REOUIREMENTS
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:
->':.- '_r�:..ul�"•b'.h.: -^p''. .... - - Y � .' s
i '" N ' ;'e_th i •,'`.y^y c..� ...-:1Y: ..�i-`:.5
'�. t ;V:.;� ��,�,r:
Special Te'r'ms and,Cond►t►ons
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.
EUI, EU2, 4. The Permittee shall develop as part of the Standard Operating Procedures for EU1, EU2,
EU3 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 46 of 60
#
AEU ' 1' "'.
�3 ``" , x=_� Spectal:Terms and'Conditions'
EUI, EU2, 5. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the on-
EU3 line availability and data capture requirements for the CEMS and COMS equipment serving
the Facility.
Facility- 6. The Permittee shall properly train all personnel to operate the Facility and the control and
Wide 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.
L0.',
ThePermittee shall comply with all provisions of 40 CFR Parts 72 and 75, 40 CFR Part
40 CFR Part 63, 40 CFR Part 64, 40 CFR Part 68, 40 CFR Part 98, and 310 CMR 6.00
ough 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.
10. The Permittee shall use variable speed drives for all ACC fan motors and the primary
boiler feed water pump and condensate pump motors. Piping and valves to reduce pressure
losses shall be considered in the detailed plant design. The highest efficiency commercially
available transformers compatible for interconnection with the nearby National Grid
switchyard shall be installed.
M11. The Permittee shall comply with all applicable portions of Section I I2(r) of the Clean
it Act and associated regulations at 40 CFR Part 68.
Table 12 Kev:
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:
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 47 of 60
41- W.
able:
v., . 11J#k' StaekStack Inside Exit ;# Statk Gas Exit
AbtiVi Gr
61thd -,Ilbinensionv' $
Velocity '
, ,Ranger;- Temperature 4ange�i,,
$(Net)',:
(feet Pee.se coti M,
EU1, EU2 230 20 39.2 to 61.9 175 to 215
(Each Flue) (Each Flue) (Each Flue) (Each Flue)
EU3 230 3 <70.2 < 530
EU4 86 1 < 113.3 < 620
EU5 22 0.667 < 80.6 < 820
Table 13 Notes:
1. EUI,EU2,and EU3 shall emit through one stack,containing three(3)flues.
Table 13 Kev:
EU#—Emission Unit Number
'17=degrees Fahrenheit
<=less than or equal to
C. NOISE
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 (RI 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, L5o, Ljo, LI., and L,q.
The L90 level represents the sound level exceeded 90 percent of the time and is used by
MassDEP for determining background(ambient) sound levels.
In general, background (Lgo) levels (in dBA) at locations STI 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 STI, ST2, STS, ST6,and STB.
Footprint Power Salem Harbor Development LP
Plan Approval
_ Transmittal No.X254064
Application No.NE-12-022
Page 48 of 60
Calculations of operational acoustic impacts from the Facility were calculated using
DataKustie 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.
The impact sound levels generated from base load (100% load) operation of the Facility
modeled by the Permittee are summarized in Table 14 below:
-.,t.Mtxl,r... ... _ �, .t �,�-.a.. . . . ��.,, �:�-tea •. � x. � _3 -
K _ -i' ocattoa 'a •,:Ambtcnt Facility(i1BA)"' Ambient ase ands* `IncreOver i
ii 1 M h
(L,o;aBA) Facility (dBA) ' Ambrent(dBA)'
STl —Located to the 47 44 49 2
North/Residences near 39
Fort Avenue
ST2 -Existing Property 42 44 46 4
Line to the West/Block
House Square/Residences
near Fort Avenue and
Derby Street Intersection
ST3 —Located to the 39 41 43 4
Northeast/25 Memorial
Drive/Bentley Elementary
School
ST4—Existing Property 39 43 44 5
Line to the
Southwest/Residences near
Intersection of Webb Street
and Derby Street/23 Derby
Street
ST5—Existing Property 39 44 45 6
Line to the Southwest/59
Derby Street
ST6—Located to the East 36 34 38 2
across Salem Harbor/76
Naugus Avenue
(Marblehead)
ST7—Located to the 39 39 42 3
East/Winter Island Park
(Harbormaster Office)
ST8—Located to the 38 33 39 1
Northeast/Intersection of
Fort Avenue and Winter
Island Road/Winter Island
Road
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 49 of 60
a Vii'. Table,l4 -Ov... x
- Location t`Ambient $ Facthty (dBA) Ambient And F;!! Increase Over. t
Facthty'(dBA). Ambient(dBA){
k' }• a Y • .'d Z P. .—A. V q 5 - i\uy t'4
P da ._. .J-,..> � a� • - - 4»-
ST9—Existing Property 39 42 44 5
Line to the South/Blaney
Street Pier on Salem Wharf
ST10—Southwest Corner 36 41 42 6
of the Existing
Property/Mackey
Building/Art Gallery
STl l —Near House of 39 37 41 2
Seven Gables across from
41 Turner Street
ST12—Pickering Wharf 41 32 42 1
near Victoria's Station
approximately 100 feet
behind Sail Schooner
"Fame"Kiosk
Rl —Plummer House 40 33 41 1
R2—Winter Island Road 34 33 38 4
Residences
Table 14 Notes:
1. The background levels observed during equipment operating hours either nighttime or daytime where the
sound level is exceeded 90 percent of the time(L9o)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 1.90 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 Kev:
L90=sound level exceeded 90 percent of the time
dBA=decibels,A-weighted
In addition to operating the facility such that sound impacts conform to the preceding
analysis,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,
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 50 of 60
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.
2. Facility personnel shall continue to identify and evaluate all plant equipment that may cause
a noise condition. Sound sources with potential to cause 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 Facility to minimize sound emissions 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 EUl 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 EUI 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 EUI, 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 (L,) of 83 dBA for CTG step-up transformers and 90 dBA for STG step up
transformers on EUl 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 around the western, southern, and eastern edges of
the Facility site.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 51 of 60
These 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.
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 that sound emissions from the
Facility do not exceed the levels associated with Option 2 Noise Mitigation. These sound
emissions were assumed in the modeling analysis, based on observed impacts at affected
receptors and subtracting the influence of non-project-influenced background sound levels. 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.
5. The Permittee shall develop and implement an operational noise monitoring protocol in
consultation with the City of Salem and MassDEP that will include an ongoing periodic noise
monitoringprogram and reporting procedures.
P 8r' P g
D. CONSTRUCTION REOUIREMENTS
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 shall 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 1/4 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 shall be flush with each other and gaps between barrier units
and the bottom edges of the barrier panels and the ground shall be 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:
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 52 of 60
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.
Noisy construction activities shall be confined to weekdays (7:00 a.m. to 5:00 p.m.) only
with the exception of work that necessarily has a larger required continuous duration than
normal construction hours allow, such as a concrete pour.
b) Construction vehicles transporting loose aggregate to or from the Facility shall be
covered.
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 non-
road engine standard limitations per 40 CFR 89.112.
c) All contractors shall utilize the best available technology for reducing the
emission of PM and NO, 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. All diesel-powered non-
road construction equipment with engine horsepower ratings of 50 and above to be used
for 30 or more days over the course of project construction shall have EPA-verified (or
equivalent) emission control devices, such as oxidation catalysts or other comparable
technologies (to the extent that they are commercially available) installed on the,exhaust
system side of the diesel combustion engine.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 53 of 60
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.
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 Durrooses 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
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.
8. 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.
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 54 of 60
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
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.
9. 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.
10. SECTION 61 FINDINGS
MassDEP has carefully considered the Pennittee's Final Environmental Impact Report
(FEIR) prior to taking action on their Plan Approval Application. MassDEP, in issuing this 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 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).
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 55 of 60
In the issuance of this 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 Perrnittee in the FEIR as referenced in the
Secretary's Certificate of finding on the FEK 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 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 Facility) on a 65-
acre site in Salem. The Facility will be fired by natural gas and include "quick-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
Facility will be constructed on approximately 20 acres of the northwestern portion of site. The
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 of the Facility is 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 Facility will include two quick-start natural gas
fired Combustion Turbine Generators (CTG); two Steam Turbine Generators (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 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
diesel-fueled 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 (NO.), volatile
organic compounds (VOC), and greenhouse gases (GHG).
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 56 of 60
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 CEMS and DAHS 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 NO, turbine combustors in combination with SCR will reduce NO,
emissions;
• 183 tons per year of NO, 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;
• acquisition of one RGGI allowance for each ton of CO2 emitted;
• solar PV array with potential to offset 175 tons per year GHG emissions;
• administrative building 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;
• operations building that 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), and water conserving fixtures;
• 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;
• 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 Notice of Project
Change (NPC);
• Establishment of purchasing specifications for low GHG Potential refrigerant;
• Mitigation of the greenhouse gas impacts of mobile sources by encouraging ride sharing
and or use of public transportation for commuting through financial incentives, supplying
indoor bicycle racks for bicycle commuters, purchasing plant supplies from local
suppliers where possible to reduce transport distances, and by ordering supplies in bulk
and/or concentrated form to reduce the number of deliveries needed;
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 57 of 60
• Contribution of at least$300,000 to the City of Salem dedicated to the development of an
off-site emission reduction program targeted to GHG and PM 2.5 among other air
pollutants and prepare a report detailing the activities to be funded by the off-site
emissions reduction program including the costs, timeframes and anticipated
environmental benefits of the identified program to be submitted to the EFSB within one
year of operation of the Facility; and,
• Implementation of a SF6 mitigation approach that is at least as stringent as measures
currently used by National Grid by consulting with National Grid and developing a joint
comprehensive S176 reduction plan in connection with the anticipated National Grid
upgrades to the Salem Harbor Substation.
Noise -
• siting of Facility equipment to maximize distance between receptors and noise-producing
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;
• 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;
• construction of a retaining wall and planted berm will be constructed around the western,
southern and eastern edges of the Facility to deflect sound; and,
• development of an operational noise monitoring protocol in consultation with the City of
Salem and MassDEP that will include an ongoing periodic noise monitoring program and
reporting procedures.
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;
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 58 of 60
• noise mitigation including construction hour limits, establishment and enforcement of
construction site and access road speed limits, mufflers on noise-producing 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;
• all diesel-powered non-road construction equipment with engine horsepower ratings of
50 and above to be used for 30 or more days over the course of project construction will
have EPA-verified(or equivalent) emission control devices, such as oxidation catalysts or
other comparable technologies (to the extent that they are commercially available)
installed on the exhaust system side of the diesel combustion engine;
• delivery of large pieces of equipment or material will be by barge to minimize impacts on
local roadways;
• limitation on noisy construction activities to weekdays (7:00 a.m. to 5:00 p.m.) only with
the exception of work that necessarily has a larger required continuous duration than
normal construction hours allow, such as a concrete pour; and,
• installation of a temporary sound wall at the western boundary of the site along Derby
Street prior to commencement of construction and demolition.
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 NEPA documents, the Plan Approval Application and
amendments thereof submitted to date and MassDEP's regulations, MassDEP finds that the
terms and conditions of this 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 Plan Approval.
11. MASSACHUSETTS ENERGY FACILITIES SITING BOARD
On October 10, 2013, the Energy Facilities Siting Board (EFSB) issued a Final Decision
under M.G.L. Chapter 164, § 69J`/4 of the Permittee's Petition for approval to construct the
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 59 of 60
Facility. Accordingly, MassDEP is issuing this Plan Approval (and, concurrently, the PSD
Permit). The Permittee is required to construct the Facility in accordance with the Final Decision
of the EFSB.
12. PUBLIC PARTICIPATION
On September 9, 2013, MassDEP issued a Proposed Plan Approval and Draft PSD
Permit for this Application. MassDEP offered a public comment period and held a public hearing
on the proposed actions. Notice of the proposed actions was published in the Boston Globe and
the Salem News on September 10, 2013, and in the Environmental Monitor on September 11,
2013. The public comment period extended to November 1, 2013. MassDEP held a public
hearing on the Proposed Plan Approval and Draft PSD Permit on October 10, 2013. Oral and
written testimony received at the public hearing and written comments received during the public
comment period have been considered, and are addressed as appropriate, in this Plan Approval
(and in the PSD Permit). [See Response to Comments Document attached to PSD Permit and
Fact Sheet] The notice of public comment and public hearing was published in Spanish and
Portuguese in the Boston Globe and Salem News. A translator was present at the public hearing
and available.
13. APPEAL PROCESS
This Plan Approval is an action of MassDEP. If you are aggrieved by this action, you
may request an adjudicatory hearing. A request for a hearing must be made in writing and
postmarked within twenty-one (21) days of the date of issuance of this Plan Approval.
Under 310 CMR 1.01(6)(b), the request must state clearly and concisely the facts, which
are the grounds for the request, and the relief sought. Additionally, the request must state why
the Plan Approval is not consistent with applicable laws and regulations.
The hearing request along with a valid check payable to the Commonwealth of
Massachusetts in the amount of one hundred dollars ($100.00) must be mailed to:
Commonwealth of Massachusetts
Department of Environmental Protection
P.O. Box 4062
Boston, MA 02211
This request will be dismissed if the filing fee is not paid, unless the appellant is exempt
or granted a waiver as described below. The filing fee is not required if the appellant is a city or
town (or municipal agency), county, or district of the Commonwealth of Massachusetts, or a
municipal housing authority.
MassDEP may waive the adjudicatory hearing-filing fee for a person who shows that
paying the fee will create an undue financial hardship. A person seeking a waiver must file,
i
Footprint Power Salem Harbor Development LP
Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 60 of 60
together with the hearing request as provided above, an affidavit setting forth the facts believed
to support the claim of undue financial hardship.
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,
l /wn'a �
Cosmo Buttaro
Environmental Engineer
Edw 'a k
En nmental Engineer
ames E. Belsky
Regional Permit C 'ef
Bureau of Waste evention
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,0 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)
i MassDEPBoston: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),Jim Belsky(e-copy),Ed Braczyk(e-copy),
Mary Persky(hard copy),Cosmo Buttaro(hard copy),Susan Ruch(e-copy)
I
a Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
Department of Environmental Protection
Northeast Regional Office•205B Lowell Street, Wilmington MA 01887 978-694-3200
DEVAL L PATRICK RICHARD K SULUVAN JR.
Governor seoreary
KENNETH L,KiMMELL
Commicsioner
Prevention of Significant Deterioration Permit
Application No.NE-12-022
Transmittal No.X254064
Footprint Power Salem Harbor Development 1,P
Salem Harbor Station
24 Fort Avenue
Salem,MA 01970
692 MW Combustion Turbine Combined Cycle
Electric Generating Facility
Pursuant to the provisions of the Clean Air Act(CAA)Chapter 1, Part C(42 U.S.C. Section 7470,
et seq.), the regulations found at the Code of Federal Regulations Title 40, Section 52.21, and the
Agreement for Delegation of the Federal Prevention of Significant Deterioration Program, dated April
2011, by the United States Environmental Protection Agency, Region 1 (EPA) to the Massachusetts
Department of Environmental Protection (MassDEP), MassDEP is issuing a Prevention of Significant
Deterioration (PSD) Pennit to Footprint Power Salem Harbor Development LP (the Permittee)
concerning its proposed, new 692 Megawatt, combined cycle electric generating facility to be located at
24 Fort Avenue in Salem,MA (proposed Facility or Facility).This is the site of the present Salem Harbor
Station electric generating facility.
The design, construction, and operation of the proposed Facility shall be subject to the permit
conditions and permit limitations set forth herein. This PSD Permit is valid only for the equipment
described herein and as submitted to MassDEP in the December 21, 2012 application for a PSD Permit
under 40 CFR 52.21 and subsequent application submittal addenda. In accordance with 40 CFR
124.15(b), this PSD Permit shall be effective 30 days after the date of service of notice of this final
decision unless review by the Environmental Appeals Board (EAB) is requested in accordance with 40
CFR 124.19. This Permit becomes invalid if the construction does not commence as defined in 40 CFR
52.21(b)(9)within 18 months after this PSD Permit takes effect, is discontinued for a period of 18 months
or more, or is not completed within a reasonable time. Pursuant to 40 CFR 52.21, MassDEP may extend
the 18 month period upon a satisfactory showing that an extension is justified. This Final PSD Permit
does not relieve the Permittee from the obligation to comply with applicable state and federal air pollution
control rules and regulations. Failure to comply with the terms and conditions of this PSD Permit may
result in enforcement ac * n b sDEP and/or EPA pursuant to Sections 113 and 167 of the CAA.
Lt, I
James E. Belsky V& Date Issued
Permit Chief
Bureau of Waste Pr ention
This information is available in alternate format.Cali Michelle Waters-Ekanem,Diversity Director,at 817.2925755.Too#1-866-538.7622 or 1-617-574.6866
MassDEP Website.v .mass.gov/dep
Printed on Recycled Paper
F •
ootprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 2 of 21
TABLE OF CONTENTS
I. PROJECT DESCRIPTION (For Informational Purposes) 3
11. EMISSION UNIT (EU)IDENTIFICATION 3
111. OPERATIONAL, PRODUCTION and EMISSION LIMITS 5
IV. MONITORING AND TESTING REQUIREMENTS 10
V. RECORD KEEPING REQUIREMENTS 14
VI. REPORTING REQUIREMENTS 17
VII. SPECIAL TERMS AND CONDITIONS 21
VIII. RIGHT OF ENTRY 22
IX. TRANSFER OF OWNERSHIP 23
X. SEVERABILITY 23
XL CREDIBLE EVIDENCE 23
XIL OTHER APPLICABLE REGULATIONS 23
XIII. AGENCY ADDRESSES 23
XIV. APPEAL PROCEDURES 23
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 3 of 21
L PROJECT DESCRIPTION (For Informational Purnoses)
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 Facility)
at Salem Harbor Station. With duct firing, the proposed Facility will be capable of generating an
additional 62 MW, for a total of 692 MW. The existing Salem Harbor Station Boiler Units 1 and
2 were removed from service on or prior to December 31, 2011. Boiler Unit 3 and Boiler Unit 4
are required to cease operation, permanently shutdown, and be rendered inoperable no later than
June 1, 2014.
The Facility components include two combustion turbine generators with integrated duct
burners, Heat Recovery Steam Generators, and Steam Turbine Generators, as well as an auxiliary
boiler, an emergency engine/generator set, a fire pump, an aqueous ammonia storage tank, an
auxiliary cooling tower, and generator step-up transformers.
II. EMISSION UNIT (EU) IDENTIFICATION
Each Emission Unit (EU) identified in Table 1 is subject to and regulated by this PSD
Permit:
y' .s�.-_ •.h.' .'-:;�atx---.c�.^e--:= .: '.;'._..+.tea. - w,, . ; ;t;<_ - ;sj,. ix:._-'
t3' i ,- ,..,; k_
t.a.:✓�... - .� ��:� °>l �-- -, .� .� �« '� =s:.wa@itt,�4r;A.y='�arw'-.r3 _.
Descrrption lxy .. uE D rgnuC�apacrty PollutdonrContro-101"
a rt a' x 4. pa.,.. DCVlee"(PCD),
EU1 General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD1)
Including Duct Burner input) Selective Catalytic
Reduction(PGD2)
346 MW (electric Oxidation Catalyst
power output) (PCD3)
EU2 General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD4)
Including Duct Burner input) Selective Catalytic
Reduction(PCD5)
346 MW (electric Oxidation Catalyst
power output) (PCD6)
EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or 80 MMBtu/hr, Ultra Low NO,Burners
equivalent HHV (energy (PCD7)
Auxiliary Boiler input) Oxidation Catalyst
(PCD8)
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 4 of 21
in,
9tAl
--D�scfipfiow 0 00igfi.Capacit—
yPolluttou Control; .
4,
At i P D)
EU4 Cummins Model No. DQFAA or equivalent 7.4 MMBtu/hr, None
Emergency Engine/Generator HHV (energy
input)
1102 bhp (engine
mechanical power
output)
750 KW
(generator electric
power output)
EU5 Cummins Model No. CFP9E-F50 or equivalent 2.7 MMl3tu/hr, None
Fire Pump Engine HHV (energy
input)
371 bhp (engine
mechanical power
output)
Table I Kev:
EU#=Emission Unit Number
No.=Number
MNMtu/hr=fuel heat input,million British thermal units per hour
HHV=higher heating value basis
bhp=mechanical engine rating,brake horsepower
MW=generator net electrical output,Megawatts
KW=generator net electrical output;Kilowatts
N%=Oxides of Nitrogen
r Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 5 of 21
III. OPERATIONAL,PRODUCTION and EMISSION LIMITS
The Facility is subject to, and the Permittee shall ensure that the Facility shall not exceed
the Operational, Production, and Emission Limits as contained in Table 2 below, including
footnotes:
-.� ., �S Ta-ble`Z a �sr nsn:.k1�'��.P�'--'-r.�-
EU# Operatwnal/vProductlon ' Air,1. Contaminant < ,-, * Emrsswn Lim t ` Y8.
-.x .. �a R' `s "g
t. Lrm►t„ �, , l.iR ;r, Per,EU
EU 1, EU2 Operation at>MECL, (11) NO,(no duct firing) < 17.0 Ib/hr(1'
excluding start-ups and < 0.0074 lb/MMBtu(1)
shutdowns <2.0 ppmvd @ 15% 02 (1)
<0.051 lb/MW-hr(1,2,9,13)
Fuel Heat Input Rate of
each EU: < 15.0 ppmvd @ 15% 02
<2,449 MMBtu per hour, or
HHV <0.43 lb/MW-hr(12)
NOx (duct firing) < 18.1 lb/hr",21
Natural Gas shall be the <0.0074 lb/MMBtu(1)
only fuel of use. <2.0 ppmvd @ 15% 02(1)
<0.055 lb/MW-hr(1,2,14)
Fuel Heat Input of each EU:
< 18,888,480 MMBtu, < 15.0 ppmvd @ 15% 02
HHV per 12-month rolling or
period(9) _<0.431b/MW-hr(12)
S in Fuel < 0.5 grains/100 scf
H2SO4 (no duct firing) <2.2 lb/hr(1,2)
<0.0010 lb/MMBtu(1)
<0.1 ppmvd @ 15% 02(t)
< 0. 007 Ib/MW-hr(1,2,9,13)
H2SO4 (duct firing) <2.3 lb/hr(1'2)
<0.0010 lb/MMBtu (1)
<0.1 ppmvd @ 15% 02(t)
<0.008 lb/MW-hr(1,2,14)
PM/PM10/PM2.5 (no duct < 8.8 lb/hr(1'')
firing) <0.0071 Ib/MMBtu
<0.029 lb/MW-hr(1,',9,13)
PM/PM1p/PM2.5 (duct firing) < 13.0 lb/hr(1'')
< 0.0062 lb/MMBtu(1'')
<0.041 lb/MW-hr(1,7,14)
Greenhouse Gases, CO2e < 825 lb/MW-hr(1u)
< 8951b/MW-hr(15)
EUI, EU2 Operation at<MECL NO, < 89 lb per event(4,11)
during start-ups (3,12)
S in Fuel <0.5 grains/100 scf
H2SO4 < 1.3 lb per event(4'")
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 6 of 21
�Jibk 14��'-,:
Goeiation-al kiaductw
-4Etni§sj6nLftfiit
Y
AI L*
,. " M I W-'1� _er,V EU
EUI, EU2 Start-up duration: PM/PM10/PM2.5 <6.60 lb per event
<45 minutes (3,12)
Natural Gas shall be the
only fuel of use.
Operation at<MECL NO, < 10 lb per event
during shutdowns (3,12) S in Fuel <0.5 grains/100 scf
H2SO4 < 0.2 lb per event
Shutdown duration: PM/PMIG/PM2.5 <3.96 lb per event
<27 minutes(3,12)
Natural Gas shall be the
only fuel of use.
EU3 Operation at>MECL NO, <0.88 lb/hr
<0.011 lb/MMBtu(1)
Fuel Heat Input Rate: <9.0 ppmvd P 3% 02
< 80 MMBtu per hour, S in Fuel < 0.5 grains/100 scf
HHV H2SO4 <0.072 lb/hr(')
<0.0009 lb/MMBtu(1)
Natural Gas shall be the < 0.35 ppmvd @ 3% 02
only fuel of use. PM/PM10/PM2 5 <0.4 lb/hr(1°')
<0.005 lb/MNMtU(1,7)
Total Fuel Heat Input:
< 525,600 MMBtu, HHV Greenhouse Gases, CO21 119.0 lb/MMBtu
per 12-month rolling period
(9)
EU4 <300 hours of operation NO,and VOC (NMHC as < 11.60 lb/hr
per 12-month rolling period CH1.8), <4.8 gm/bhp-hr
Combined Total (limit <6.4 gm/KW-hr(5)
Ultra Low Sulfur Diesel includes VOC)
Fuel Oil shall be the only S in Fuel < 0.0015%by weight
fuel of use. H2SO4 <0.0009 lb/hr
PM/PMIO/PM2 5 <0.36 lb/hr(')
<0.15 gm/bhp-hr
<0.2 gm/KW-hr
Greenhouse Gases, CO2, < 162.85 lb/MMBtu
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 7 of 21
21,
'*A*g C
1per,AW
EU5 <300 hours of operation NO,and VOC (NMHC as <2.44 lb/hr 151
per 12-month rolling period CHI 8), <3.0 gm/bhp-hr
Combined Total (limit <4.0 gm/KW-hr
Ultra Low Sulfur Diesel includes V0Q
Fuel Oil shall be the only S in Fuel <0.0015%by weight
fuel of use. H2SO4 <0.0003 lb/hr 161
PMfPM10/PM2.5 <0.12 lb/hr"I
<0.15 gm/bhp-hr
<0.2 gm/KW-hr
Greenhouse Gases, CO2, < 162.85 lb/MMBta
Facility-Wide NA NO, < 144.8 TPY M
PN"MIO/PM2.5 <82.0 TPY"") I
H2SO4 < 19.0 TPY"') I
CO2 <2,277,333TPYtbI
Greenhouse Gases, CO21 <2,279,530 TPY 161
Table 2 Notes:
I. 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 2,300 MNMtu/hr,HHV(no duct firing),at 0'F ambient temperature,and 2,449 MMBtu/hr,HHV(duct
firing), at 90 'F ambient temperature, both at 14.7 psia ambient pressure and 60%ambient relative humidity. 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 (NMCL) 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
expected to be lower.
5. Emission limits are one hour block averages and apply throughout the operating range, including during start-
up 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
CHI 8),which corresponds to a gas density of 0.5746 kg/m. (Limit includes VOC)
6. Facility emissions include the two CTG/HRSG pairs with duct burners (EU1 and EU2), the auxiliary boiler
(M),the emergency diesel engine/generator set(EU4),the fire pump engine(EU5), and the auxiliary cooling tower.
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 50°F ambient temperature with no duct burner firing (2,130 MNMtu/hr, HHV) or evaporative
cooling,and 720 hours of natural gas firing per 12 month rolling period at peak load(approximately 102%load)and
90°F ambient temperature with 100% duct burner firing (2,449 MNMtu/hr, HHV) and evaporative cooling, and
include start-up and shutdown emissions. Emissions for EU3 are based on 6,570 hours of natural gas firing per 12
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 8 of 21
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 NO,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 (Limit
includes VOC). Worst case NO,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 (Limit includes VOQ. 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].
The auxiliary cooling tower contributes to PM/PM1c/PM25 emissions only based on 8,760 hours of operation per 12
month rolling period.
7. Emission limit is for the sum of filterable and condensable particulates,including sulfates.
8. Maximum fuel(natural gas only)heat input for each CTG/HRSG with duct bumer is based on 8,040 hours
of operation per 12 month rolling period at 100% load and 50°F ambient temperature with no duct burner firing
(2,130 NMMM/hr,HHV),and 720 hours of operation per 12 month rolling period at peak load(approximately 102%
load) and 90°F 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).
9. Emission limit is based on full(base) load(100%load)without duct firing ISO corrected(59°F, 14.7 psia,
60%humidity)heat rate of 6,940 Btu,higher heating value,per KW-hr net electrical output to the grid.
10. Emission limit is based on full (base)load(100%load)without duct firing ISO corrected(59°F, 14.7 psia,
60%humidity)heat rate of 6,940 Btu, higher heating value, per KW-hr net electrical output to the grid and a CO2,
emission factor of 119.0 Ib/MMBtu. This emission factor is based on a CO2 emission factor of 118.9 lb/MMBtu
calculated from Equation G-4 of 40 CFR Part 75 Appendix G plus an emission factor of 0.1 lb/MMIBtu for other
greenhouse gases(methane and nitrous oxide)calculated utilizing the emission factors for these two pollutants from
Table C-2 of 40 CFR Part 98 Subpart C and the global warming potentials for these two pollutants from Table A-1
of 40 CFR Part 98 Subpart A.. 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.
11. 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 data generated from the fust year of commercial operation.
12. NO,emission limits are from 40 CFR Part 60 Subpart KKKK. Compliance with the BACT NO,emission
limits of this PSD Permit shall be deemed compliance with the NO,limits from 40 CFR Part 60 Subpart KKKK.
13. 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.
14. 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.
15. 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 a CO2,emission factor of 119.0 Ib/NffviBtu(see Footnote 11 above).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 CO2,emission factor of 119.0 lb/NDABtu.
16. Minimum Emissions Compliance Load (MECL) for EUI and EU2 shall be a function of ambient
temperature and other system parameters.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 9 of 21
17. MECL for EU3 shall be determined during the initial emissions compliance testing to be performed within
180 days after initial firing of EU3.
Table 2 Kev:
EU#=Emission Unit Number
PSD=Prevention of Significant Deterioratrion
No.=Number
NOx=Nitrogen Oxides
VOC=Volatile Organic Compounds
NMHC=Non-Methane Hydrocarbons
S=Sulfur
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
H2SO4=Sulfuric Acid
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
grains/scf=grains per standard cubic foot
lb/hr=pounds per hour
MMBtu=million British thermal units,higher heating value(I HV)basis
lb/MMBm=pounds per million British thermal units
ppmvd @ 15%02=parts per million by volume,dry basis, corrected to 15 percent oxygen
ppmvd @ 3%02=parts per million by volume,dry basis,corrected to 3 percent oxygen
scf=standard cubic feet
kg/m'=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
TPY=tons per 12-month rolling period
°F=degrees Fahrenheit
psia=pounds per square inch,absolute
EPA=Unites States Environmental Protection Agency
CFR=Code of Federal Regulations
ISO=International Organization for Standardization
CTGdI RSG=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
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
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 10 of 21
IV. MONITORING AND TESTING REOUIREMENTS
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EUl, 1. The Permittee shall ensure that the Facility is constructed to accommodate the emission
EU2, EU3,',compliance) testing requirements as stipulated in 40 CFR Part 60 Appendix A. The two outle
sampling ports (90 degrees apart from each other) for each emission unit must be located at
.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 testin
equipment by constructing platforms, ladders,or other necessary equipment. II
EU 1, 2. The Permittee shall ensure that compliance testing of the Facility is completed within 180
EU2,EU3 days alter initial firing of each EU to demonstrate compliance with the emission limits specified
in Table 2 of this PSD Permit. All emissions testing shall be conducted in accordance with
NlassDEP's "Guidelines for Source Emissions Testing" and in accordance with EPA reference
est methods as specified in 40 CFR Part 60, Appendix A. 40 CFR Part 60 Subpart KKK K,40
CFR Parts 72 and 75, or by another method which has been approved in writing by MassDEP.
e Permittee shall schedule the compliance testing such that MassDEP personnel can witness
't.
3. The Pemvttee shall conduct initial compliance tests of the Facility to document actua
emissions of EUl, EU2, and EU3 so as to determine their compliance status versus the emissio
units (in lb/hr, lbtMMBtu, ppmvd, and lb/MW-hr, as applicable) in Table 2 for the pollutant,
fisted below.
Testing for these pollutants for EUI and EU2 as specified below shall be conducted at four(4)I
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 duet firing.
JNOX, PM, PM10, PM2s,CO2,112SO4
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.
NO,,PM, PM10,PM2s,H2SO4 _
EUI, E132 4. The above referenced emissions testing shall include parametric monitoring testing fort
PM,PM10, and PM2.5 emissions for FUl and EU2.
EU3 !,The Permittee shall tune EU3 according to procedures contained in EPA 34011-83-023
"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. _
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 11 of 21
.P '., Table3
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EUI, 6. The Permittee shall install, calibrate, test, and operate a Data Acquisition and Handling
EU2, EU3 System(s) (DAHS) and CEMS serving EUl and EU2 to measure and record the following:
a) 02; b)NOx.
EUI, 7. The Permittee shall ensure that all emission monitors and recorders serving EUI, EU2 and
EU2,EU3 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, and 310 CMR 7.32, as
applicable.
8. The Permittee shall ensure that the subject CEMS are equipped with properly operated and
properly maintained audible and visible alarms to activate whenever emissions from the
Facility exceed the short term limits established in Table 2 of this PSD Permit.
9. The Permittee shall operate each CEMS serving EUI, EU2 and EU3 at all times except for
periods of CEMS 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 serving EUI,
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 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 2 of this PSD Permit. ("Excess Emissions" are
defined as emissions which are in excess of the emission limits as stated in Table 2). An
exceedance of emission limits in Table 2 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 serving EUI, EU2 and EU3 as "direct-
compliance" monitors to measure NO,and 02,. "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 serving EUl, 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.
14. The Permittee shall install, operate, and maintain a fuel metering device and recorder for
EUI, 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 EUI, EU2, and EU3.
16. The Permittee shall monitor each date and daily hours of operation and total hours of
operation for EUI, EU2, and EU3 per month and twelve month rolling period.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 12 of 21
VIA,ER �-" ..2 :<;,'.M,.. .I.fi..t.Un# "4n -T,gstjngReq- yi
EUI, EU2 17. The Permittee shall ensure that initial compliance tests of the Facility are conducted for
"hot start", "warm start", "cold start", and shutdown periods as defined in the Pernuttee's
Application for EUI and EU2. These compliance tests shall represent periods of operation
below the MECL for EUl and EU2. Emission data generated from this testing shall be mad
available for review by MassDEP prior to determining and approving the maximum
allowable emission limits for all pollutants listed in Table 2 (lb per event) and opacity limits,
for these periods of time
18. The Permittee shall comply with all applicable monitoring requirements of 40 CFR Part)
60 Subpart KKKK. J
19. The Permittee shall monitor the natural gas consumption of EUI and EU2 in accordance'
ith 40 CFR Part 60 Subpart KKKK utilizing a continuous monitoring system accurate W
+ 5 percent, and as approved by MassDEP.
120. The Permittee shall monitor the sulfur content of the natural gas combusted by EUI and
EU2 in accordance with 40 CFR Part 60 Subpart KKKK, or pursuant to any alternative fuel
onitoring schedule issued in accordance with 40 CFR Part 60 Subpart KKKK.
21. The Permittee shall install and operate continuous monitors fitted with alarms to monitor
continuously the temperatures at the inlets to the SCR and oxidation catalysts serving EUI
and EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambient
temperatures for EUl and EU2.
2. The Permittee shall monitor the load, start-up and shutdown duration, and mass
emissions (lb/event)during start-up and shutdown periods of EUl and EU2.
23. The Permittee shall monitor the operation of EUI and EU2 in accordance with the
surrogate methodology or parametric monitoring developed during the most recent
compliance test concerning PM, PMIo, and PM2.5 emission limits.
X24. The Permittee shall monitor the CO2 emissions in accordance with 40 CFR Part 75.
r5. The Permittee shall monitor the Greenhouse Gas emission rate utilizing the calculation
rocedures in 40 CFR Part 98 Subpart A, Table A-1.
I26. The Permittee shall continuously monitor the net electrical output to the grid of the
acility.
EU3 7. The Permittee shall comply with all applicable monitoring requirements of 40 CFR Part
60 Subpart Dc.
EU4, EU5k8. The Permittee shall comply with all applicable emissions standards, operating
estrictions, and monitoring requirements of 40 CFR Part 60 Subpart IIII.
9. 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.
30. The Permittee shall monitor the quantity and sulfur content of ULSD fuel oil burned in
EU4 and EU5.
Facility- 31. If and when MassDEP requires it, the Permittee shall conduct compliance testing in
Wide accordance with EPA Reference Test Methods.
Table 3 Kev:
EU#=Emission Unit Number
PSD=Prevention of Significant Deterioration
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 13 of 21
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
SCR=Selective Catalytic Reduction
Oz=Oxygen
NOx=Nitrogen Oxides
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
CO2=Carbon 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
Ib/MW-hr=pounds per megawatt-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 0.0015 weight percent sulfur
V. RECORD KEEPING REOUIREMENTS
;%,.�. ." `�„N','"'- .-•' `.,3t�,` �"..x,r;�„,.�y.. - - .r rte.-'u.; - :„q���.,w ,r:. -•'s "" ;.,-ro�.g gF.gnr`.w.,; r'r" �;ar a-..±;fi -
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EUI, 11. The Permittee shall maintain records of each emission unit's hourly fuel heat input rate
EU2, EU3I(MMBtu/hr, HHV), total fuel heat input (MMBtu), and natural gas consumption (scf) per
onth and twelve month rolling period basis.
I2. 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) for flue gas emissions and natural gas consumption(scf).
EUI, 4. The Permittee shall maintain a log to record problems, upsets or failures associated with.
EU2, EUI the subject emission control systems, DAHS and CEMS serving EUI, EU2, and EU3, and
the NH3 handling system serving EU 1 and EU2.
5. The Permittee shall continuously estimate and record PM, PM10, and PM25 emissions on the
DAHS using the surrogate methodology or parametric monitoring derived from the most recent
compliance test.
� 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 EUI and EU2.
I7. The Permittee shall maintain records of net electrical output to the grid from the Facility
on a daily basis.
art
Permittee shall comply with all applicable record keeping requirements of 40 CFR
part 60 Subpart KKKK.
Footprint Power Salem Harbor Development LP
PSD Permit 7
Transmittal No.X254064
Application No.NE-12-022
Page 14 of 21
$�?,�'•':'xj u'M;.,�:ta-.r•> �:� "'d,<:--a;a.,c.:�r:.- ::+, «-v�. "r.' -- - " - "t!k r?`,�+i=;:=$' ��:N.=q.'';� ,�u,::ts-x= 'pi
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9. The Permittee shall maintain records of the sulfur content of the natural gas combusted by
EUI, EUI and EU2 at the frequency required pursuant to 40 CFR Part 60 Subpart KKKK, or
EU2, EU3 pursuant to any alternative fuel monitoring schedule issued in accordance with 40 CFR Part
60 Subpart KKKK.
10. The Permittee shall record CO2 emissions from EUI and EU2 in accordance with 40
CFR Part 75.
h 1. The Permittee shall record the Greenhouse Gas emission rate of EUI and EU2 on a daily
asis utilizing the calculation procedures in 40 CFR Part 98 Subpart A, Table A-1.
LThe Permittee shall maintain continuous records of SCR and oxidation catalyst inlet
peratures, combustion turbine inlet temperatures and ambient temperatures.
13. The Permittee shall maintain the SOMP for the NH3 handling system serving EUl and
EU2 SCRs in a convenient location and make them-readily available to all employees.
EU3 14. The Permittee shall comply with all applicable record keeping requirements of 40 CFR
Part 60 Subpart Dc.
15. 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 16. The Permittee shall comply with all applicable record keeping requirements of 40 CFR Part
60 Subpart III1.
I17. The Pemuttee shall maintain a record of the quantity of ULSD fuel oil combusted in, and
tthe total hours of operation of,EU4 and EU5 per month and per 12-month rolling period.
18. The Permittee shall maintain a record of the sulfur content of each ULSD fuel oil delivery
made to the Facility.
Facility- 19. A record keeping system for the Facility shall be established and maintained up-to-date
Wide 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 PSD Permit. 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.
0. The Permittee shall maintain all records required by 40 CFR Part 98 (Mandato
Greenhouse Gas Emissions Reporting) at the Facility.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 15 of 21
_-T
RpqordK
epnqg fpeqpirelp.ents
Facility- 21. The Permittee shall maintain monthly records to demonstrate the Facility's compliance
Wide status regarding the Facility-Wide emission limits (in TPY) specified in Table 2. Records shall
include actual emissions for the month as well as for the previous 11 months. (The MassDEP
approved format can be downloaded at
httD://www.mass.izov/eea/agencies/massdeD/air/aDDrovals/limited-emissions-record-keeDina-
land-reDortinQ.html#WorkbookforRei)ortinizOn-SiteRecordKeeDinQ in Microsoft Excel
�format.)
� The Permittee shall maintain a copy of this PSD Permit, underlying Application, and the
ost up-to-date Standard SOMP for each emission unit and PCD approved herein on-site.
123. The Permittee shall maintain records of monitoring and testing as required by Table 3.
[All records required by this PSD Permit shall be kept on site for five (5) years and made
lavailable for inspection by MassDEP or EPA upon request.
Table 4 Kev:
EU#=Emission Unit Number
PSD=Prevention of Significant Deterioration
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
SCR=Selective Catalytic Reduction
CFR=Code of federal Regulations
CMR=Code of Massachusetts Regulations
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
CO2=Carbon Monoxide
ULSD=Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.001 5weight percent sulfur
lb=pounds
scf=standard cubic feet
MMBtu/hr=million British thermal units per hour
M?vlBtu=million British thermal units
HHV=higher heating value basis
TPY=tons per 12-month rolling period
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 16 of 21
VI. REPORTING REOUIREMENTS
,Reportrng< eguirements -'-' - -, ,,
a. �n�,,,1 " �. Ku.x•
EUI, 1. The Permittee must obtain written MassDEP approval of an emissions test protocol prio
EU2,EU3 to initial compliance emissions testing of EUI, EU2 and EU3 at the Facility. The protocols,
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 parametric monitoring strategy to
ensure continuous monitoring of PM, PM10, and PM2.5 emissions from EUl and EU2. 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 serving EUI, 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.
EUI, 4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the
iEU2,EU3 thirtieth(30th) day of April, July, October, and January covering the previous calendar periods
i of January through March, April through June, July through September, and October through
iDecember, respectively. The report shall contain at least the following information:
i
I, a) The Facility CEMS 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 start-
up, shutdown, malfunction, emergency, equipment cleaning, and upsets or failures associated
with the emission control system or CEMS. ("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 poo
maintenance, careless operation, or any other preventable upset condition or preventable
quipment 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
PSD Permit, 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.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 17 of 21
%
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EUI,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 EUI 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 comply with all applicable reporting requirements of 40 CFR Part 60
Subpart KKKK.
7. The Permittee shall submit to MassDEP a Phase H Acid Rain Permit Application at least 2
months prior to commencement of commercial operation of any subject emission unit.
EU3 8. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 60
Subpart Dc.
EU4,EU5 9. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 61
Subpart IIII.
Facility- 10. The Permittee shall submit, in writing, the following notifications to MassDEP within
Wide 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.
11. The Permittee shall submit to MassDEP an Operating Permit, no later than 12 month
after commencement of commercial operation of the Facility in accordance with 40
Part 70.
12, If the Facility is subject to 40 CFR Part 68, due to the presence of a regulated substancel
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.
13. The Pennittee shall report to EPA in accordance with 40 CFR Part 75.
14. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 98
(Mandatory Greenhouse Gas Emissions Reporting).
15. The Permittee must notify MassDEP by telephone or fax or e-mail
fnero.airamassmail.state.ma.usI 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.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 18 of 21
k.f_:c
MWpients-T",
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Facility- 16. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 30 of
Wide each year to demonstrate the Facility's compliance status regarding the Facility-Wide emission
limits (in TPY) specified in Table 2. Reports shall include actual emissions for the previous 12
months. (The MassDEP approved format can be downloaded at
httD://www.mass.gov/eea/ai2encies/massdeD/air/aDi)rovals/limited-emissions-record-keei)inq-
and-reDortiniz.html4WorkbookforRei)ortinaOn-SiteRecordKeei)ing in Microsoft Excel
format.)
17. 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.
18. The Permittee shall submit to MassDEP all information required by this PSD Permit over
the signature of a"Responsible Official".
19. All notifications and reporting to MassDEP required by this PSD Permit 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(a),massmail.state.ma.us
20. The Pertnittee shall provide a copy to MassDEP of any record required to be maintained
by this PSD Permit within thirty (30) days from MassDEP's written request.
21. If and when MassDEP requires additional compliance testing, 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 3 Monitoring and Testing
Requirements.
22. If and when MassDEP requires additional compliance testing, 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 3 Monitoring and Testing
Requirements.
Table 5 Kev:
EU4=Emission Unit Number
PSD=Prevention of Significant Deterioration
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 19 of 21
EPA=United States Environmental Protection Agency
CEMS=Continuous Emission 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
NH,=Ammonia
PM=Particulate Matter
PM10=Particulate Matter less than or equal to 10 microns in size
PMZ 5=Particulate Matter less than or equal to 2.5 microns in size
NAAQS=National Ambient Air Quality Standards
SILs=Significant Impact Levels
AAL=Allowable Ambient Limit
TEL=Threshold Effects Exposure Limit
VII. SPECIAL TERMS AND CONDITIONS
�� . EU# ,_, s- _-,.,� � ,:.- �., � �iwK,,,a,��,Spec►al Terms,and Conditions � M .. - ,-_,���. � .�. ;� .
EUI, EU2 1. The Permittee shall not allow the combustion turbines at the Facility to operate below they
MECL, except for start-ups and shutdowns. Emissions during start-ups and shutdowns shall
be included in the TPY limits specified in Table 2.
2. The Permittee shall ensure that the SCR control equipment serving EUI 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.
EUI, EU2, 3. The Permittee shall develop as part of the Standard Operating Procedures for EUI, EU2,
EU3 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.
EU 1,EU2,4. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the on-
EU3 line availability and data capture requirements for the CEMS equipment serving the
Facility.
Facility- 5. The Permittee shall properly train all personnel to operate the Facility and the control and
Wide 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.
6. 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 and 40 CFR Part 98.
Footprint Power Salem Harbor Development LP
PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 20 of 21
T'[1bIC 6 ,^l�� LL.e+.i ri�r x":
7. The Permittee shall comply with all applicable portions of Section 112(r) of the Clean Air
Act and associated regulations at 40 CFR Part 68.
Table 6 Kev:
EU#=Emission Unit Number
CFR=Code of federal regulations
CMR=Code of Massachusetts Regulations
SOW=Standard Operating and Maintenance Procedures
CEMS=Continuous Emission Monitoring System
SCR=Selective Catalytic Reduction
TPY=tons per 12 month rolling period
MECL=Minimum Emissions Compliance Load
VIII. RIGHT OF ENTRY
The Permittee shall allow all authorized representatives of MassDEP and/or EPA, upon
presentation of credentials, to enter upon or through the Facility where records required under
this PSD Permit are kept. The Permittee shall allow such authorized representatives, at
reasonable times:
1. To access and copy any records that must be kept under this PSD Permit;
2. To inspect any facilities, equipment (including monitoring and air pollution control
equipment),practices, or operations regulated or required under this PSD Permit; and
3. To monitor substances or parameters for purposes of assuring compliance with this
PSD Permit.
IX. TRANSFER OF OWNERSHIP
In the event of any changes in control or ownership of the Facility, this PSD Permit shall
be binding on all subsequent owners and operators. The Permittee shall notify the succeeding
owner and operator of the existence of this PSD Permit and its conditions before such change, if
possible, but in no case later than 14 days after such change. Notification shall be sent by letter
with a copy forwarded within 5 days to MassDEP and EPA.
X. SEVERABILITY
The provisions of this PSD Permit are severable, and if any provision of the PSD Permit
is held invalid,the remainder of this PSD Permit will not be affected thereby.
I
Footprint Power Salem Harbor Development LP
' PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 21 of 21
XI. CREDIBLE EVIDENCE
For the purpose of submitting compliance certifications or establishing whether or not the
Permittee has violated or is in violation of any provision of this PSD Permit, the methods used in
this PSD Permit shall be used, as applicable. However, nothing in this PSD Permit shall preclude
the use, including the exclusive use, of any credible evidence or information, relevant to whether
the Permittee would have been in compliance with applicable requirements if the appropriate
performance or compliance test procedures or methods had been performed.
XII. OTHER APPLICABLE REGULATIONS
The Permittee shall operate all equipment regulated herein in compliance with all other
applicable provisions of federal and state air regulations.
XIII. AGENCY ADDRESSES
Subject to change, all correspondence required by this PSD Permit shall be forwarded to:
Permit Chief, Bureau of Waste Prevention
The Department of Environmental Protection(MassDEP)
Northeast Regional Office
205B Lowell Street
Wilmington, Massachusetts 01887
XIV. APPEAL PROCEDURES
1. Within 30 days after the final PSD Permit decision has been issued under 40 CFR
124.15, any person who filed comments on the Draft Permit or participated in any
public hearing may petition EPA's Environmental Appeals Board to review any
condition of the Permit decision.
2. The effective date of the Permit is 30 days after service of notice to the Applicant and
commenters of the final decision to issue, modify, or revoke and reissue the PSD
Permit, unless review is requested on the Permit under 40 CFR 124.19 within the 30
day period.
3. If an appeal is made to the EAB, the effective date of the Permit is suspended until
the appeal is resolved.
.. ': Commonwealth of Massachusetts
Executive Office of Energy S Environmental Affairs
Department of Environmental Protection
Northeast Regional Office•2056 Lowell Street, Wilmington MA 01887.978-994-3200
DEVAL L PATRICK RICHARD K SULLNAN JR.
Governor Secretary
KENNETH L.KIMMELL
Commissioner
Final Prevention of Significant Deterioration Permit
Fact Sheet
Salem Harbor Redevelopment Project
24 Fort Avenue
Salem, MA
Transmittal No. X254064
Application No. NE-12-022
This information is available in alternate format.Call Michelle Waters-Ekanem,Diversity Director,at 617-292-5751.TDD#1-866-539-7622 or 1-617-574-6868
MassDEP Websde w mass.gov/dep
Printed on Recycled Paper
MassDEP is hereby issuing this Prevention of Significant Deterioration (PSD)Permit Fact Sheet,
concurrently with the PSD Permit for the Salem Harbor Redevelopment (SHR) Project. MassDEP's
permit decisions are based on the information and analysis provided by the Applicant (Footprint) and
MassDEP's own technical expertise. This Fact Sheet documents the information and analysis MassDEP
used to support the PSD Permit decisions. It includes a description of the proposed SHR Project, the
applicable PSD regulations, and an analysis demonstrating how Footprint complied with all applicable
requirements.
I. General Information
Name of Source: Salem Harbor Redevelopment(SHR)Project
Location: Salem, Massachusetts
Applicant's Name and Address: Footprint Power Salem Harbor Development LP
1140 Route 24 East, Suite 303
Bridgewater,NJ 08807
Application Prepared By: Tetra Tech
160 Federal Street
Boston,MA 02110
Prevention of Significant Deterioration/
Comprehensive Plan Application
Transmittal Number: X254064
Application Number: NE-12-022
Massachusetts Department of
Environmental Protection (MassDEP)
MassDEP Contact: Cosmo Buttaro
MassDEP Northeast Regional Office
205B Lowell Street
Wilmington, MA 01887
(978) 694-3281
Cosmo.Buttaronn State.MA.US
On April 11, 2011, MassDEP and the U.S. Environmental Protection Agency Region 1 (EPA)
executed an "Agreement for Delegation of the Federal PSD program by EPA to MassDEP" (PSD
Delegation Agreement). This PSD Delegation Agreement directs that all Permits issued by MassDEP
under the Agreement follow the applicable procedures in 40 CFR 52.21 and 40 CFR Part 124 regarding
permit issuance, modification and appeals.
The SHR Project is also subject to the MassDEP Plan Approval and Emission Limitations
requirements under 310 CMR 7.02 and Emission.Offsets and Nonattainment Review under 310 CMR
7.00:Appendix A (Appendix A).
On December 21, 2012, Footprint Power Salem Harbor Development LP (Footprint) submitted
an initial Application to MassDEP requesting a Prevention of Significant Deterioration (PSD) Permit
and a 310 Code of Massachusetts Regulations (CMR) 7.02 Major Comprehensive Plan Application
2
Approval (Plan Approval) for a new 630 megawatt (MW) (692 MW with duct firing) natural gas fired
quick start combined cycle electric generating facility (the SHR Project) to be located at the site of the
existing Salem Harbor Station. The existing Salem Harbor Station is being shut down. Footprint
submitted additional information on April 12, 2013, June 10, 2013, June 18, 2013, August 6, 2013,
August 20, 2013, September 4, 2013, and September 9, 2013. MassDEP considered the Application for
the Draft PSD Permit to be administratively and technically complete. As such, on September 9, 2013,
MassDEP issued a Draft PSD Permit and Draft PSD Fact Sheet for a 30 day public comment period as
required by the PSD Delegation Agreement and 40 CFR Part 124 - Procedures for Decision Making.
MassDEP subsequently extended the public comment period by three weeks to November 1, 2013.
The Proposed Plan Approval regulates all pollutants affected by the SHR Project, including the
pollutants regulated under the PSD Permit, and also implements MassDEP's nonattainment New Source
Review(NSR)program regulations at Appendix A. Footprint must ensure that its SHR Project complies
with the federal PSD Permit and MassDEP's Plan Approval, as well as other applicable federal and state
requirements.
MassDEP held a Public Hearing on October 10, 2013 concerning both the Draft PSD Permit and
the Proposed 310 CMR 7.02 Plan Approval. A number of comments were submitted to MassDEP
during the hearing and public comment period. On November 1, 2013, the Applicant submitted a
comment to MassDEP indicating that it had obtained an additional guarantee from its equipment vendor,
General Electric (GE), and that, as a result, the emission limits for Particulate Matter (PM\PM�o\PM2.5)
set forth in the Proposed Plan Approval and the Draft PSD Permit could be reduced by approximately
twenty five percent (25%). On December 11, 2013, the Applicant filed a submittal to MassDEP
concerning comments that had been submitted by EPA, CLF and HealthLink. Included in the
Applicant's submittal was an "Emissions Update and Prevention of Significant Deterioration Best
Available Control Technology (BACT)" report dated December 2013. Among other things, the
Applicant's December 2013 submittal included revised emissions estimates and guarantees from the
equipment vendor (GE) for the combined cycle turbines, as well as a Top Down BACT analysis. On
January 10, 2014, the Applicant submitted a letter with supplemental technical information addressing
revised start-up,and shutdown PM emission estimates. On January 16, 17 and 21, 2014, the Applicant
submitted a letter with supplemental technical information addressing revised air quality dispersion
modeling results for PMuo and PM2.5 based upon the reduced PMuo and PM2_5 emission rates obtained
from GE and updated carbon monoxide (CO) and sulfuric acid (H2SO4) emission rates for the auxiliary
boiler due to the requirement for it to be equipped with an oxidation catalyst control device. These five
submittals constitute amendments to the Application, and MassDEP is treating them as such.
In response to the public comments and Applicant's submittals, MassDEP has revised the Draft
PSD Fact Sheet and Draft PSD Permit; both of which are now being issued as final actions, subject to
appeal to EPA's Environmental Appeals Board (See Section XII on Page 34 of this Fact Sheet).
Based on addressing significant public comments and on all submittals, MassDEP has concluded
that Footprint's Application is complete and provides the necessary information showing the SHR
Project meets federal PSD regulations. All of Footprint's submitted information is part of the official
record for the PSD Permit.
3
II. Project Location
The proposed plant site is located in Salem, Massachusetts within the existing +/- 65 acre Salem
Harbor Station property which is bounded by Fort Avenue and the South Essex Sewerage District
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.
III. Proposed Project
Footprint proposes to construct a nominal 630 megawatt (MW) (692 MW with duct firing)
quick-start, combined-cycle natural gas-fired power plant at the proposed plant site. The SHR Project
will be configured as two operating units. Each unit will be able to operate independently to respond to
dispatch requirements. Most of the SHR Project's equipment will be housed in a building structure that
will be approximately 115,000 square feet(sf) in area. The SHR Project will include a variety of power
plant equipment including: two gas turbine generators (GTGs); two steam turbine generators (STGs);
two heat recovery steam generators (HRSGs) with selective catalytic reduction (SCR) and oxidation
catalyst pollution control equipment; generator step-up transformers; two air cooled condensers; an
ammonia storage tank; and water tanks. In addition, the SHR Project will include areas within other
buildings for administrative and operating staff; warehousing of parts and consumables; and
maintenance shops and equipment servicing.
Each operating unit of the proposed SHR Project will be part of a combined-cycle power plant.
The first stage in the generation process will be the operation of a GTG set. Thermal energy will be
produced in the GTGs through the combustion of natural gas, which will be converted into mechanical
energy required to drive the turbine compressor section as well as the generator. Each gas turbine will
have the capability to generate in excess of 200 MW under all environmental conditions using solely
natural gas. The GTG exhaust gas still contains considerable recoverable heat energy. This heat energy
will be recovered in a three pressure level HRSG to produce steam. This steam will be directed to a
STG where this heat energy will be converted to electrical energy representing approximately 40 percent
(%) of the total energy generated by each unit. Efficiency is enhanced in the cycle by using reheat
systems as well as using waste steam to heat feedwater in the HRSG, thereby further improving the
overall efficiency of the SHR Project. Once the steam leaves the steam turbine, it is condensed back to
water using an air cooled condenser(ACC). This water is then returned to the HRSGs through a system
of pumps and control mechanisms. Additional steam may be generated when required by the use of
special burners within the HRSGs (duct firing)to increase the electricity produced by the STGs.
Footprint will be using the GE Energy 7F Series 5 Rapid Response Combined Cycle Plant for
each main power block. Each GE power block can produce approximately 150 MW (300 MW total for
the plant) of output within 10 minutes of startup using both operating units together.
Continuous emissions monitoring systems (CEMS) will sample, analyze and record fuel firing
rates and nitrogen oxides (NO.) concentration levels, as well as other "non PSD pollutant"
concentrations and the percentage of diluent (either oxygen or carbon dioxide) in the exhaust gas from
4
each of the two HRSG exhaust flues. Exhaust gases will be discharged through a single 230 foot tall
stack enclosing two flues (one for each turbine/HRSG), each with a diameter of 20 feet.
Ancillary equipment at the proposed SHR Project will include three additional fuel combustion
emission units:
• An 80 million British thermal units per hour (MMBtu/hr) natural gas fired auxiliary
boiler equipped with ultra low-NOx burners (Cleaver Brooks "Nebraska" D-type boiler Model No.
CBND 80E-300D-65 or equivalent);
• A 750 Kilowatt (KW) (standby rating) emergency generator firing ultra-low sulfur
distillate oil containing no more than 0.0015 weight percent sulfur (ULSD) (Cummins Model No.
DQFAA Diesel Emergency Generator or equivalent); and
• A 371 brake horsepower (BHP) fire pump engine firing ULSD (Cummins Model No.
CFP9E-F50 or equivalent).
Footprint has requested the combined cycle turbines be permitted for year-round operation on
natural gas and for the equivalent of 720 hours of operation of natural gas duct firing per rolling 12-
month period. The auxiliary boiler will be limited to the equivalent of 6,570 hours of natural gas firing
at full (100 percent) load per rolling 12-month period. The emergency diesel engine/generator and the
fire pump will each be limited to no more than 300 hours of operation per rolling 12-month period.
IV. PSD Program Applicability and Review
MassDEP administers the PSD program in accordance with the provisions of the April 11, 2011
PSD Delegation Agreement between MassDEP and EPA which states that MassDEP agrees to
implement and enforce the federal PSD regulations as found in 40 CFR 52.21.'
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 this Fact Sheet. MassDEP's evaluation of Emission Offsets and Nonattaimnent Review for
the construction of the proposed SHR Project, as required by Appendix A, is provided in the
accompanying CPA Approval.
The PSD regulations at 40 CFR 52.21 require that a major new stationary source of an
attainment pollutant, or major modification to an existing major stationary source of an attainment
pollutant, undergo a PSD review and that a PSD Permit be granted before commencement of
construction.
' Section III. Scope of Delegation, Section A.,states,"Pursuant to 40 CFR 52.21(u),EPA hereby delegates to MassDEP full
responsibility for implementing and enforcing the federal PSD regulations for all sources located in the Commonwealth of
Massachusetts, subject to the terms and conditions of this Delegation Agreement."
5
40 CFR 52.21(b)(1) of the federal PSD regulations defines a "major stationary source" as either
(a) any of 28 designated stationary source categories with potential emissions of 100 tons per year (tpy)
or more of any regulated attainment pollutant, or(b) any other stationary source with potential emissions
of 250 tpy or more of any regulated attainment pollutant. Combined cycle generating'facilities like the
SHR Project are one of the 28 designated stationary source categories for which 100 tpy of potential
emissions qualifies the source as "major."2
In addition, once a new stationary source has been determined to be a "major" source, it is
subject to PSD review for each regulated attainment pollutant that the source would have the potential to
emit in "significant" amounts, which in some cases is lower than the "major" thresholds. 40 CFR
52.21(b)(50)(iv) includes pollutants "subject to regulation" as defined in 40 CFR 52.21(b)(49) as
regulated pollutants. Greenhouse Gas (GHG) emissions from new electric generating facilities become
a regulated pollutant if the total GHG emissions on a CO2, basis equal or exceed the GHG PSD
significant emission rate of 100,000 tpy.
If a new stationary source or new modification is subject to the PSD program, the source must
apply for and obtain a PSD Permit that meets regulatory requirements including:
• Best Available Control Technology (BACT) requiring sources to minimize emissions to
the greatest extent practical;
• An ambient air quality, analysis to ensure all the emission increases do not cause or
contribute to a violation of any applicable PSD increments or NAAQS;
• An additional impact analysis to determine direct and indirect effects of the proposed
source on industrial growth in the area, soil,vegetation and visibility; and
• Public comment including an opportunity for a public hearing.
V. PSD Applicability
The SHR Project is considered a major source as defined by EPA's PSD program. Potential
emissions from the proposed facility are significant for six different PSD pollutants: NO., PM, PM10,
PM2 5, sulfuric acid (H2SO4) mist, and GHG. Table 1 shows potential emissions from the proposed new
equipment at the site and Table 2 lists total facility potential to emit relative to the PSD major source
thresholds and significance level thresholds for PSD regulated pollutants.
2 "Determining Prevention of Significant Deterioration (PSD) Applicability Thresholds for Gas Turbine Based Facilities,"
memorandum from Edward J.Lillis,Chief,Permits Branch,EPA,dated February 2, 1993.
6
-Table l:._Facility Wide Annu_a1+Potential:Emissions
_�
Pollutant-. MUnit P ; { CTXnit2`' Auxiliary < i Emergency AFirePump)j rAuxiliary •[ MRility
F 1 1 1 '{ 3p it ]
.TtPY) Boiler(tpy),'. V G6&61or t (tpy) } Cool ng 1 'vTotal(tPY)
Tower. .I
I NO, 69.9 69.9 2.9 1.7 0.4_ _ 0 144.8
CO 42.9 42.9 0.9 1.0 0.3 0 88.0 I
1 VOC 13.1 13.1 1.3 0.35 1 0.12 0 28.0 I
1 SO2 14.2 14.2 0.4 0.0017 1 0.0006 1 0 28.8 1
I PM 40.1 40.1 1.3 0.06 1 0.02 1 0.43 82.0 I
I PM{o ( 40.1 40.1 1.3 1 0.06 1 0.02 1 0.43 82.0 I
1 PM2 5 1 40.1 40.1 I 1.3 0.06 1 0.02 1 0.17 I 81.8 I
I H2SO4 Mist 1 9.4 9.4 1 0.24 1 0.00013 I 0.00005 1 0 19.0 I
Pb I 0 0 I 0.00013 I 0.000001 I 0.0000003 I 0 0.00013
CO2 1 1,122,920 1,122,920 1 31,247 1 180 1 66 1 0 1 2,277,333 1
GHG,CO2, 1 1,124,003 1,124,003 I 31,277 I 181 I 66 I 0 12,279,530
Table 2.,Wivefiti6ni of.Significant_Det&i6raition'Regulatory TlireslioldiEvaluation ,nil
Pollutant ' y,foject Annual, I PSWMajor", '4 'GPSD`Signifcant? '' PSI)Re6i-
Xrnissiotis Source $' Emission Rate Applies
! 0 P3') t
' r (tPY)9'� Threshold.! ` �a t
CO 88.0 100 100 I No TI
NOx I 144.8 100 40 Yes
SO2 I 28.8 100 40 No
PM I 82.0 100 I 25 Yes
PMIO I 82.0 100 15 I Yes
PM2 5 81.8 I 100 10 Yes
VOC 28.0 100 40 No
(Ozone precursor)
Pb I 0.00013 I 100 0.6 No
Fluorides I Negligible 100 3 No
H2SO4 Mist I 19.0 100 7 Yes
H2S none expected I 100 10 I No
Total Reduced Sulfur none expected 100 10 No
(including H2S)
Reduced Sulfur none expected 100 10 No
Compounds
(including H2S)
GHG (as CO20 2,279,530 I 100,000 100,000 Yes
Table 1 and 2 Notes:
1. Emissions, except CO emissions, for each CT are based on 8,040 hours of natural gas firing per 12 month rolling
period at full (base)load(100%load) and 50°F 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 90°F ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV CT and duct burner combined) and
evaporative cooling,and include start-up and shutdown emissions.Based on new CO emission limit guarantees from the turbine
7
vendor(GE)that reduced the CO emission limit from 11.0 lb/hr to 8.0 lb/hr under all operating loads,reduction in the number of
turbine cold start-ups from 36 to 13, and incorporation of an oxidation catalyst control device to limit CO emissions from the
auxiliary boiler from 2.8 Ib/hr to 0.28 lb/hr, emissions of CO have been reduced to 88.0 tpy. This CO emission limit can be
found in the federally enforceable Plan Approval.
2. Auxiliary boiler emissions are based on 6,570 hours of natural gas firing per 12 month rolling period at 100% load
(80 MMBtu/hr,HHV).
3. The emergency diesel generator(EDG) and fire pump (FP) emissions are each based on restricted operation of 300
hours per unit,per 12 month rolling period, including maintenance and periodic readiness testing,while firing ULSD having a
sulfur content that does not exceed 0.0015%by weight.
4. The auxiliary cooling tower contributes to particulate emissions only based on 8,760 hours of operation per 12 month
rolling period.
Table 1 and 2 Kev:
CT=Combustion Turbine
tpy=tons per year
N%=Nitrogen Oxides
CO=Carbon Monoxide
VOC=Volatile Organic Compounds
SO2=Sulfur Dioxide
PM=Total Particulate Matter
PM�o=Particulate Matter less than or equal to 10 microns in diameter
PM2 s=Particulate Matter less than or equal to 2.5 microns in diameter
H2SO4=Sulfuric Acid
Pb=Lead
CO2=Carbon Dioxide
GHG=Greenhouse Gases
CO,=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.
H2S=Hydrogen Sulfide
ULSD=Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015 weight percent sulfur
Y=degrees Fahrenheit
%=percent
MMBtu=million British thermal units
MMBtu/hr=million British thermal units per hour
HHV=higher heating value basis
VI. BACT Analysis
As required by the federal PSD program at 40 CF R 52.210)(2) and (3), the SHR Project is
required to comply with BACT for the NO., PM, PMtc, PM25, 142SO4, and GHG emissions from the
new turbines and other emission units.
BACT is defined as, "an emissions limitation ... based on the maximum degree of reduction for
each pollutant subject to regulation under [the Clean Air] Act which would be emitted from any
proposed major stationary source or major modification which the Administrator; on a case-by-case
basis, taking into account energy, environmental, and economic impacts and other costs, determines is
8
achievable for such source or modification through application of production processes or available
methods, systems and techniques ... for control of such pollutant." 40 CFR 52.21(b)(12); C1eanAir Act
(CAA) 169(3).
BACT determinations involve an evaluation process known as the "top-down" process. In
brief, the "top-down" process involves a ranking of all available control technologies in descending
order of control effectiveness. Applicants are required to first examine the most stringent ("top-case")
alternative. MassDEP will presume this emission limit represents BACT unless the Applicant can
demonstrate that it is not feasible for technical, energy, environmental or economic reasons. If the most
stringent control alternative is eliminated, then the Applicant must consider the second best, and so on.
The details of this procedure are found in the October 1990 Draft EPA New Source Review Workshop
Manual and other EPA policy, guidance, and determinations as applicable, e.g., as indexed in EPA's on-
line NSR Policy and Guidance Database at htto://www.ena.2ov/reeion7/air/search.htm.
The results of the BACT analyses for the proposed SHR Project are presented below for NO.,
PM, PM10,PM2.5, H2SO4 mist, and GHG emissions.
Combined Cycle Combustion Turbines
Clean Fuels
For the combined cycle combustion turbines, a major element of the BACT analysis is the use of
clean fuels. Footprint has proposed to burn solely natural gas in the combustion turbines. MassDEP
agrees that natural gas is the least-emitting fossil fuel available, and therefore represents the most
stringent "top" BACT with respect to the selection of turbine fuels. The possible use of ULSD was
eliminated by Footprint.
NO
In addition to the requirement to apply BACT for NO., the SHR Project is also subject to the
determination of Lowest Achievable Emission Rate (LAER) for NO, because potential NO, emissions
exceed the major source threshold of 50 tpy under 310 CMR 7.00: Appendix A, Emission Offsets and
Nonattainment Review. Please see the CPA Approval for the LAER analysis.
In order to identify BACT for NO, for an "F" Class combined cycle combustion turbine facility,
Footprint evaluated numerous sources of information. These sources included both state and federal
resources of publicly available air permitting information. California, New York, New Jersey,
Connecticut, and Massachusetts were the focus for state specific determinations and guidance. Footprint
evaluated the following sources of information to determine BACT for NO.:
• EPA's RACT,BACT,LAER Clearinghouse (RBLC);
• MassDEP's BACT Guidance of June 2011 including Top Case BACT Guidelines for
Combustion Sources;
• EPA Region IV's National Combustion Turbine List;
9
• The California Air Resources Board (CARE)BACT Clearinghouse;
• The California South Coast Air Quality Management District's (SCAQMD) BACT
guidelines;
• State environmental program websites;
• New Jersey's State Of The Art(SOTA)Manual for Stationary Combustion Turbines; and
• The California Energy Commission Energy Facilities Siting Board.
In addition to these sources of information, additional publicly available information, such as
permits for individual projects not listed in the RBLC or other sources,was also included in the analysis.
Please see Footprint's top-down BACT analysis,which is appended hereto as Appendix 1.
Footprint presented the following conclusions:
• A search of EPA's RBLC for the lowest NO, emission rate for projects approved in the
last 10 years for the EPA characterized"Process Type 15.210" (large gas-fired combined
cycle combustion turbines) showed that the lowest approved NO, rate in RBLC is 2.0
part per million volume dry corrected (ppmvdc).
• The EPA Region IV National Combustion Turbine Spreadsheet was examined to identify
if any NO, emission limits more stringent than 2.0 ppmvdc are reported. The only
project identified with a NO, emission limit less than 2.0 ppmvdc is the Sunlaw (CA)
Cogeneration Project, which shows "l-2 ppm" for NOx. However, the RBLC entry for
Sunlaw (RBLC ID # CA-0863) confirms the emission level demonstrated in practice for
this facility is 2.0 ppm.
• The CARB BACT Clearinghouse had nine records for combined cycle gas turbines
greater than 50 MW; the only one more stringent than 2.0 ppmvdc NO, was the IDC
Bellingham Project(in MA), which is shown as having a NO, limit of 1.5 ppmvdc. This
entry contains a note indicating that the limit(s) "are as stringent or more stringent than
prior existing SCAQMD BACT for this source category. These limits have not been
verified by performance data. These limits were negotiated with the Applicant and are
presumably based on vendor guarantees." The IDC Bellingham Project was never built,
so the approved NO, level of 1.5 ppm was never demonstrated in practice. Therefore,
IDC Bellingham is not a precedent for NO,BACT.
• The SCAQMD BACT Clearinghouse has three gas turbine combined-cycle units listed,
with two approved at 2.0 ppmvdc and one approved at 2.5 ppmvdc.
• New Jersey's SOTA Manual for combustion turbines specifies a NO,limit of 2.5 ppmvdc
for combustion turbine combined cycle units greater than 150 MMBtu/hr heat input.
10
• The June 2011 MassDEP BACT guidance for combustion sources identifies 2.0 ppmvdc
of NO,as the "top case"BACT for large gas-fired combined cycle units.
• The two most recent NO, LAER precedents for similar Massachusetts projects are also
2.0 ppmvdc for gas firing. These are for the Brockton Power Company LLC (Plan
Approval No. 41308015, July 20, 2011) and Pioneer Valley Energy Center (EPA Final
PSD Permit No. 052-042-NMI 5),April 2012).
In summary, Footprint did not identify any BACT precedents for large gas-fired combined cycle
turbines where a NO, emission limit of less than 2.0 ppmvdc has been approved and subsequently
demonstrated in practice. Based on this review, MassDEP has determined that 2.0 ppmvdc represents
the most stringent technically feasible level of emissions control for NO,for the SHR Project's proposed
combustion turbines.
Footprint has proposed to achieve the BACT NO, emission limit of 2.0 ppmvdc by using state-
of-the-art dry low-NO, (DLN) combustors in combination with selective catalytic reduction (SCR).
DLN combustors are designed to minimize the creation of NO, in the turbine's combustion chamber.
SCR reduces NO,to nitrogen (ND and water(H2O) in the presence of a catalyst and ammonia.
SCR is placed in the exhaust flue of the combustion turbine. An SCR system is composed of an
ammonia storage tank, ammonia (NH3) forwarding pumps and controls, an injection grid (a system of
nozzles that spray NH3 into the exhaust gas ductwork), a catalyst reactor, and instrumentation and
controls. The injection grid disperses NH3 in the flue gas upstream of the catalyst, and NH3 and NOx are
reduced to N2 and H2O in the catalyst reactor.
Several different types of catalysts can be used to accommodate a wide range of flue gas
temperatures. Base metal catalysts, typically containing vanadium and/or titanium oxides, are typically
used for flue gas exhausts ranging between 450°F and 800°F. Combined cycle combustion turbine
projects employ a HRSG to produce steam from the hot exhaust gases exiting the turbine in order to
generate additional electricity in a steam turbine. As a result, combined cycle projects proponents can
design the HRSG such that a base metal SCR catalyst can be placed within the HRSG under its optimum
temperature window to maximize NOx reduction.
Based on the results of Footprint's NO. BACT evaluation research, MassDEP accepts
Footprint's conclusion that only SCR has been successfully demonstrated in practice to achieve the 2.0
ppmvdc NO, emission rate that currently represents BACT for large combustion turbines (100 MW or
greater).
PM/PMJoM,5
Emissions of particulate matter result from trace quantities of ash (non-combustibles) in the fuel
as well as products of incomplete combustion. Footprint proposes to minimize particulate emissions
from the proposed SHR Project by utilizing state-of-the-art combustion turbines and good combustion
practices to burn natural gas, the lowest ash-content fuel available. Footprint conservatively presumes
that all particulate matter (PM) emissions from combustion turbines firing natural gas are less than 2.5
11
microns in diameter (PM25). Based on the guarantees supplied by the vendor (GE), Footprint is
proposing to achieve emissions of PM, PM,o, and PM2 5, o£ 0;0038 pounds per million British thermal
units (lb/MMBtu) at 0°F to 0.0047 lb/MMBtu at 105 °F at full load unfired conditions. Footprint
presents the PSD BACT limits for PM/PMIo/PM2.5 for 34 projects approved within the last 5 years.
Eighteen of these projects had PM limits that were less stringent than the limits proposed by Footprint
and sixteen of these projects had PM limits that were more stringent than the limits proposed by
Footprint. Footprint determined that there was no data that show that the PM emissions from any of the
projects with more stringent limits could reliably meet these limits on a long term basis. Because
Footprint needs the flexibility to run the plant under different load conditions, both with and without
duct firing, Footprint requests that MassDEP determine that its proposed emission limits of 0.0071
lbs/MMBtu are BACT. To support this request, MassDEP has evaluated Footprint's request and agrees
that Footprint needs the flexibility to operate at different levels including the minimum load level and
determined that the proposed limits represent BACT. (See Appendix A,Attachment A-1, Sheets 1, 2 and
3, hiehliehted text).
Footprint's BACT analysis includes the two most recent state PM/PM1o/PM2 5 BACT precedents.
The Brockton Power Company LLC (Plan Approval No. 4B0S015, July 20, 2011) was approved for
0.007 lb/MMBtu for loads down to 60% load. MassDEP concludes that the PM BACT for Brockton
and the SHR Project are comparable for SHR Project's CT loads at 75% and greater. Footprint has
indicated that the turbine vendor performance levels at minimum emissions compliant CT load without
duct firing require a slightly higher lb/MIvlBtu PM limit. MassDEP has evaluated this request and
concludes that the operating flexibility afforded by operating at the minimum load levels warrants the
approval of a PM rate of 0.0071 lb/MMBtu at the minimum load conditions.
Pioneer Valley Energy Center(PVEC) (EPA Final PSD Permit No. 052-042-MAI 5, April 2012)
was approved for a PM/PM10/PM25 emission rate of 0.004 lb/MMBtu for natural gas firing. Footprint
points out that PVEC's ability to meet this limit has not been demonstrated in practice since the PVEC
Project has not yet been constructed and that it is not consistent with recent test data for the same model
turbine. The emission limit for PVEC is based on the MMI 501G turbine, the same turbine used at
Mystic Station. Footprint notes that Mystic Station was approved for 0.011 lb/MMBtu, and that the four
Mystic Station MMI 501G units had tested PM emissions ranging from 0.005 to 0.010 lb/MMBtu.
Footprint contends that the majority of the tested particulate matter was condensable particulates at
Mystic. Footprint concludes that it is not reasonable to expect that the MHI 501G unit at PVEC could
reliably achieve 0.004 lb/MMBtu in practice. MassDEP has determined that the Footprint position
regarding the PVEC emission limit of 0.004 lb/MIVIBtu has merit. MassDEP concludes that the PM
emission rate of 0.0071 lb/MMBtu represents BACT for all operating loads for PM/PM1o/PM25 for the
SHR Project's combined cycle turbines.
Sulfuric Acid Mist(H?SOa)
Emissions of sulfuric acid mist (H2SO4) are generated by the oxidation of sulfur in the fuel. The
only means for controlling sulfuric acid mist emissions from the SHR Project is to limit the sulfur
content of the fuel. By using pipeline natural gas with a sulfur content of 0.5 grains of sulfur per 100
standard cubic feet, Footprint minimizes its H2SO4 emissions and as a result requests an H2SO4 emission
limit of 0.0010 lb/MMBtu. To support this request, Footprint compiled a list of twenty-two projects that
were approved with emission limits for H2SO4. Thirteen of these projects had emission limits less
12
stringent than those proposed by Footprint and nine of these projects had emission limits more stringent
than those proposed by Footprint. Footprint determined that the more stringent limits were based on
unrealistically low assumptions of the oxidation of SO2 to SO3 and unrealistically low assumptions on
the sulfur content of the fuel. Footprint's BACT analysis included the most recent H2SO4 BACT
precedent for a similar Massachusetts project. The Pioneer Valley Energy Center (EPA Final PSD
Permit No. 052-042-NM 15, April 2012) was approved with an H2SO4 BACT limit for natural gas firing
of 0.0019 lb/MMBtu. The Brockton Power Company LLC Project (Plan Approval No. 41308015, July
20, 2011) did not include an H2SO4 BACT limit. Based on this analysis, MassDEP concludes that
Footprint's proposed H2SO4 emission limit of 0.0010 lb/MMBtu is BACT for H2SO4 for the SHR
Project's combined cycle turbines.
Greenhouse Gas Emissions(GHG)
Greenhouse gas emissions for PSD permitting from combustion sources are the aggregate of
three pollutants: carbon dioxide, methane, and nitrous oxide. Since each pollutant has a different
effect on global warming, PSD applicability is based on a carbon dioxide equivalent (CO2,), determined
by multiplying each pollutant by its global warming potential. Like other combustion sources, the main
constituent of GHG for a combined cycle turbine is carbon dioxide. For Footprint's proposed combined
cycle turbines, their carbon dioxide emissions constitute 99.9%of their GHG emissions on a CO2,basis.
Nitrous oxide and methane make up the other 0.1% of the GHG emissions from these combined cycle
turbines and their global warming potential is included on a CO2,basis.
The most stringent control technology for control of GHG from a combustion turbine combined
cycle unit is by means of carbon capture and storage (CCS). Footprint evaluated the feasibility of CCS
based on material published by EPA. CCS is composed of three main components. The first component
is the capture or removal of carbon (i.e., CO2) from the exhaust gas. The second component is transport
of the captured CO2 to a suitable disposal site, and the third component is the actual disposal of CO2,
normally deep underground in geological formations. Footprint pointed out that there is no nearby
existing CO2 pipeline infrastructure (see Figure 4-1, December 11, 2013 Applicant submittal); the
nearest CO2 pipelines to Massachusetts are in northern Michigan and southern Mississippi. Without
such infrastructure,MassDEP agrees that CCS is not feasible at this site.
Footprint proposes to use natural gas, the lowest carbon emitting fuel for a fossil fuel project.
Footprint chose to install two F Class turbines rather than the slightly more efficient but larger G Class
turbines. Footprint selected the F Class turbines because they are compatible with the existing high
voltage switchyard and electrical interconnection infrastructure at the site and because they provide
greater operational flexibility. Footprint selected air cooling rather than a more efficient wet cooling
system to avoid the impingement, entrainment and thermal impacts associated with once through wet
cooling and the visible fog plume associated with mechanical draft cooling.
Footprint proposes an initial design limit of 825 pounds CO2, per net Megawatt hour of power
delivered to the grid (lb CO2,/MWhrg,d), Footprint proposes to demonstrate compliance with this value
by means of an initial performance test, to be conducted within 180 days of facility startup. This test
will be done at CT full (base) 100% load, without duct firing, with the test results corrected to turbine
ISO conditions. Footprint also proposes to meet a 365-day rolling average GHG limit of 895 lb
CO2,/MWhrg,;d, for the life of the facility, with and without duct firing. This 365 day rolling average
13
limit accounts for operation at varying loads, startup and shutdown, varying temperatures, and in
particular unavoidable CT performance degradation between major overhauls and over the life of the
facility. Footprint's proposed limits are identical to the approved GHG BACT limits for the Pioneer
Valley Energy Center(PVEC, EPA Final PSD Permit No. 052-042-MA15, April 2012).
Footprint notes that the PVEC Project used a CO2, emission factor of 116 lb/MMBtu. The SHR
Project CO2e emission factor is 119 lb/MMBtu, of which CO2 emissions comprise 118.9 lb/MMBtu and
the other GHGs comprise 0.1 lb/MMBtu. Footprint claims this makes its proposal to meet the same
limits as PVEC actually 2.6%more stringent than PVEC's approved limits. PVEC obtained their GHG
emission factor from its turbine vendor. Footprint and GE calculated their GHG emission factor from
procedures contained in the Code of Federal Regulations (40 CFR Part 75, Appendix G, and 40 CFR
Part 98, Subparts A and C).
MassDEP notes that Footprint's 365 day rolling average is lower than EPA's proposed New
Source Performance Standard (NSPS) for natural gas fired combined cycle turbines greater than 850
MMBtu/hr (approximately 100 MWe1ectri,.1) of 1,000 lb CO2/MWhr [see Federal Register January 8,
2014 -NSPS for GHGs from New Stationary Sources: Electric Utility Generating Units (EGU)].
Footprint asks that MassDEP adopt its proposed limits as BACT. To support that request,
Footprint compiled a list of PSD BACT determinations for new combustion combined cycle projects in
the past five years. Footprint found no cases in which post combustion controls including carbon
capture and sequestration have been used to control the GHG emissions from large natural gas fired
combined cycle turbines. Footprint did not identify any currently operating facility that has more
stringent limits that: (a) apply under all load conditions, with and without duct firing, and during start up
and shut down, and(b) account for the degradation of energy efficiency over time.
Footprint notes that the Plan Approval for the proposed Brockton Power Plant may contain a
more stringent GHG emission limit (Plan Approval No. 41308015, July 20, 2011). The Brockton Project
was approved for a rolling 12-month CO2 (not CO2.) limit of 842 lb/MWhr, a limit more stringent than
the 895 lb CO2e/MWhr proposed by Footprint. The basis for the 842 lb CO2/1\4Whr limit in the Plan
Application for the Brockton Project is stated "to include operation at a variety of loads, ambient
temperatures, with and without evaporative cooling, and with and without duct firing, and including
starts and stops" (Brockton Power Plan Application at Page 4-30). However, there is no mention of any
allowance for heat rate (efficiency) degradation over the life of the project or between major turbine
overhauls. Footprint notes that the Brockton Project has not yet been constructed, and the 842 lb
CO2/MWhr value therefore has not been demonstrated in practice. In addition, Footprint notes that the
Brockton Project did not specifically undergo a PSD review for GHG BACT.
Footprint also notes that in the Plan Application for the Brockton Project, it is stated that the 842
lb CO21MWhr value is based on a CO2 emission factor of 117 lb/MMBtu. Footprint notes its proposed
limit of 895 lb CO2e/MWhrg,id is based on a CO2e emission factor of 119 lb/MMBtu. Adjusting the
Brockton value of 842 lb CO2/MWhr by 118.9/117, the Brockton rate based on 118.9 lb CO2/MMBtu
would be 856 lb CO2/MWhr. In this case, the SHR Project value (895 lb CO2./MWhrg id) is only 4.6%
higher than the adjusted Brockton value (856 lb CO2/MWhr). hi addition,the Brockton Project design is
based on wet cooling, while the SHR Project will use dry cooling. Projects using dry cooling have
higher heat rates (are less efficient)than wet cooled projects,particularly during the summer months.
14
MassDEP has reviewed the Brockton Plan Approval and has determined that a reasonable
allowance for heat rate (efficiency) degradation over the life of the project and between major turbine
overhauls, as well as the impact of wet vs. dry cooling, explains the proposed GHG BACT for the SHR
Project of 895 lb CO2JMWhrg,id compared to the proposed Brockton limit. Based on Footprint's BACT
Analysis including its evaluation of the Brockton Plan Approval, MassDEP concludes that the 365 day
rolling average GHG emissions of 895 lb CO2,/MWhrg,id, which includes a reasonable allowance for the
various factors affecting long-term GHG emissions, including performance degradation, represents
BACT for GHG emissions. Therefore the SHR Project proposed GHG BACT limits of 825 lb
CO2,/MWhrg,id (initial design limit) and the 895 lb CO2e/MWhrg id (365 day rolling average) are
approved as BACT for GHG.
Startup and Shutdown Emissions
NO, is the only PSD Pollutant that has higher emissions during start up and shut down than
during normal operation of the CTs. Footprint proposes to comply with BACT for startup and shutdown
by employing good operating practices (by following the CT manufacturer's recommendations during
startup) and by limiting startup time. The combustion turbines will be operated in accordance with
manufacturer specifications during startups and shutdowns in order to ensure that emissions are
minimized during these short time periods. Additionally, ammonia injection will be initiated as soon as
the SCR catalyst reaches its vendor-specified minimum operating temperature and all system parameters
are met to minimize NO, emissions during these periods. The proposed startup and shutdown emission
limits for the pollutants subject to PSD review, except GHGs, are presented in Table 3.
Table 3:'•Ttirliine Startup,au8 Sh'utdowngEmission_Limits-,(godnds.p`ereyent);�_.
_Pollutant `, iStai•tup.(duration 45 mihuteW' i 'Shu"td"own(duration 27 minutes)L �
NOx 89 10
PM/PMI0/PM2,5 6.60 3.96
H2SO4 1.3 0.2
Table 4 compares the mass emission limits of the PSD subject pollutants for a startup and
shutdown hour to a normal CT operation hour without duct firing. The BACT mass emission limit of a
normal operation hour with duct firing are higher for these pollutants so the comparison presented in
Table 4 represents a worst case scenario. A startup hour consists of 45 minutes in startup mode and 15
minutes at normal operation. A shutdown hour consists of 33 minutes at normal operation and 27
minutes in shutdown mode.
-
" =
Table,4: Comparison:ofNormal;OperationHourly'E'mission:Lmitt_oStartupandShutdown '.
Pollutant ` ` Normal 1Startup ,1 ' Shfitdo`wn PSD BACTs ""
Operation+ our. ; 'Hour 4 • .
Hour
NO. 17.0 93.2 19.4 Since startup and shutdown emissions
exceed normal operation, BACT for
startup and shutdown NO,emissions
must be established (see Appendix 1)
15
F }:.
Table 4. Compa�isou of Normal Operation HourlyInussion, Ainit`to'SCarknp and'Shutdown
�. i:�:�_.� _:. �HourlyfEmission�l•L'imits'for`.�Eacli .Turbine,(lli's�perh'opr)t ;, �
pPMllutant _ j' Normal ? Startup, s r Shutdown _ 1PSD BACT "
I
�'1 Operatwni . +Hour ` i gpfiour .k
Hour k 'r s �i
PM/PMi0/PM25 8.8 8.8 8.8 Since startup and shutdown emissions
do not exceed normal operation, BACT
H2SO4 2.2 1.9 1.4 for startup and shutdown emissions of
these PSD pollutants need not be
established. BACT for normal operation
applies.
Table 4 indicates an increase in hourly mass emission limits for both startup and shutdown for
NO, only. MassDEP has reviewed Footprint's December 11, 2013 and January 10, 2014 submittals
appended hereto regarding the BACT analysis for startup and shutdown emissions and agrees that these
emission rates contained in Table 4 represent BACT during startup and shutdown periods.
Using the worst case scenario cold starts, Footprint proposes a NO, limit of 93.2 lb for each
startup event and 19.4 lb for each shut down event. Footprint has requested that MassDEP adopt these
limits as BACT. To support this request, Footprint evaluated the PSD BACT determinations for NO,
during start up and shut down at large combined cycle electric generating facilities approved during the
last five years. Footprint found no currently operating facility with a more stringent NO, limit that
applies in all start-up and shut down scenarios including cold starts. Based on this analysis, MassDEP
has determined that Footprint's proposed start-up and shut down NO,limits are BACT.
Auxiliary Boiler
The proposed SHR Project will include the installation of an 80 MMBtu/hr heat input, natural
gas-fired auxiliary boiler. Annual operation of the auxiliary boiler will be limited to the full load
equivalent of 6,570 hours per year. The unit will be equipped with ultra-low NO, burners for NOx
control. Emissions will be controlled through the exclusive use of natural gas as fuel, good combustion
practices and a limit on the annual operations.
Footprint requested that MassDEP adopt a BACT NOx limit of 0.01lb/MMBtu. To support this
request, Footprint evaluated the use of an SCR system to reduce the NO, emissions below its proposed
limit. Footprint determined that although technically feasible, an SCR would remove additional NOx at
an average cost of $19,000 per ton and an incremental cost of $70,000 per ton and thus is not cost
effective. MassDEP concurs in that determination and'finds that the auxiliary boiler NO, limit of 0.011
lb/MMBtu (the limit that will be achieved without an SCR system)represents BACT for NOx.
For PM/PM10/PM2 5 emissions, Footprint proposes a BACT limit of 0.005 lb/MMBtu. Footprint
contends this BACT limit is more stringent than other recent BACT limits for natural gas-fired boilers in
Massachusetts. PM BACT limits, established relatively recently, were 0.007 lb/MMBtu for auxiliary
boilers at Mystic Station and Veolia MATEP, and 0.01 lb/MMBtu for Brockton Power. The PM BACT
limit for the auxiliary boiler at Pioneer Valley Energy Center is comparable at 0.0048 lb/MMBtu.
MassDEP concurs with Footprint's assessment of auxiliary boiler PM BACT.
16
Footprint proposes a limit of 0.0009 lb/MMBtu for H2SO4. Footprint proposes to control its
H2SO4 emissions bycombusting solely natural gas and by limiting the sulfur content of its fuel.
Footprint assumes an approximate 40% molar conversion of fuel sulfur to H2SO4. This conversion rate
is higher than that assumed in connection with other similar units permitted in the last five years.
Footprint notes that the auxiliary boiler will usean oxidation catalyst to control its CO emissions and that
the collateral impact of this oxidation catalyst is an increase in H2SO4 emissions. Footprint identified 5
similar units with more stringent H2SO4 limits. Footprint points out that none of these units have an
oxidation catalyst. MassDEP notes that the Mystic Station auxiliary boiler SO2 emission limit is 0.0023
lb/MMBtu. Based on the natural gas sulfur content restriction of 0.5 grains per 100 ft3, the proposed
SO2 emission limit is 0.0015 Ib/MMBtu. H2SO4 emissions are assumed to be equivalent to
approximately 2/3 of SO2 emissions based on vendor data. No H2SO4 emission limit is cited in Mystic
Station Plan Approval. MassDEP therefore concurs that a limit of 0.0009 Ib/MMBtu is BACT for
H2SO4.
The approved BACT emission limits for the auxiliary boiler are shown in Table 5.
Table 5i„BACT,'Emssiiin=Liitiits fo`r;tfie Aaxiliary_Boiler
I_ . — •Rollufant, _ aErni'ssiori Limttatton___ y; _N_ Control,Teclinology_ ' 3I
I NOx 0.011 lb/MMBtu - Ultra Low NOx Burners (9 ppm)
PM/PM10/PM2 5 0.005 lb/MMBtu - Good combustion practices
-Natural Gas only
I H2SO4 0.0009 lb/MA/Btu Natural Gas only I
GHG, CO2, ' 119.0 lb/MMBtu Natural Gas only
Table 5 Notes:
1. BACT GHG emission limit based on 40 CFR Part 75, Appendix G, and 40 CFR Part 98, Subparts A and C (see
August 20,2013 supplement to the Application).
Emergency Generator and Fire Pump Engines
The SHR Project will include an emergency diesel generator (EDG) engine and a diesel fire
pump (FP) engine. Both engines will operate on ULSD fuel. The proposed EDG will be a Cummins
750DQFAA ULSD-fired engine (or equivalent) with a standby generating capacity of 750 kW. The FP
engine will be a 371 Brake Horsepower (BHP), 2.7 MMBtu/hr ULSD-fired engine. Both engines will
be used in emergency situations only (with the exception of periodic maintenance/testing events) and
will be limited to a maximum of 300 hours per rolling 12-month period of operation. There are no post-
combustion controls that have been demonstrated in practice for small, emergency internal combustion
engines. Footprint provided an analysis that showed that the installation of controls to limit the
emissions from the emergency generator and fire pump engines, although technologically feasible, is not
cost effective. In order to satisfy BACT requirements in these circumstances, Footprint has proposed
that the EDG engine will meet the EPA Tier 2 standards and that the FP engine will meet the EPA Tier 3
standards for off-road diesel engines without the installation of add on controls. These both meet
applicable federal NSPS requirements under 40 CFR Part 60 Subpart I1II, and incidentally, 40 CFR Part
89 as is specified in MassDEP's Air Pollution Control Regulation at 310 CMR 7.26(42)(b). Emissions
will be controlled through the use of ULSD, good combustion practices and limited annual operation.
17
With the exception of emergency situations, the units will typically operate no more than one hour per
week, for testing and maintenance purposes. The specific EDG and FP engines BACT emission limits
are shown in Tables 6 and 7.
-Tal I ''6 jE' niE-ency.Diesel`Generator.,"BACTX-inis'sion
i= Follutan"t Y ' nEPA3Tter;2T IEintssions (Itis/hr) ,f+Emissions 'I Emrssto s(tpy) ..•I
N ' Stariilard (�/kWh)j
' NOx i 6.4 11.60
PM/PMto/PM25 0.2 0.42 ` 0.06`
H2SO4' - 0.0009 I 0.00013
GHG, CO2e - I 162.85 181
Table 6 Notes:
1. EPA Tier 2 standard for NO,and VOC is 6.4 g/kWh,combined. For worst case potential emissions,NO,emissions
assumed equal to this level and VOC emissions assumed equal to the older EPA Tier 1 limit of 1.3 g/kWh.
2. Emission limit reflects the addition of approximately 0.032 g/kWh for condensableP articulate to the EPA Tier 2
standard based on AP-42 ratios.
3. There is no Tier 2 limit for SO2 emissions. SO2 emissions are limited based upon ULSD fuel sulfur content of
0.0015 weight percent. H2SO,emissions assumed equal to 8 weight percent of SO2 emissions.
Table 6 Key:
g/kWh=grams per Kilowatt-hour
Ib/hr=pounds per hour
Ib/MMBtu=pounds per million British thermal units
tpy=tons per 12-month rolling period
�,'-Pollutanb^ i 'EPA'Tter;3 :;Emissions(Ib`s/hr)� Emissions ' .Emissions (tpy)� p
(Standards( /kWh
- P� - --.-_- r—
- NOx r 4.0 2.44 0.4
PM/PMi0/PM2.5 0.2 0.14` 0.022
H2SO4' - 0.0003 I 0.00005
GHG, CO2e - I 162.85 66
Table 7 Notes:
1. EPA Tier 3 standard for NO,and VOC is 4.0 g/KWh,combined. For worst case potential emissions,NO,emissions
assumed equal to this level and VOC emissions assumed equal to the older EPA Tier 1 limit of 1.3 g/kWh.
2. Emission limit reflects the addition of approximately 0.032 g/kWh for condensable particulate to the EPA Tier 3
standard based on AP-42 ratios.
3. There is no Tier 3 limit for SO2 emissions. SO2 emissions are limited based upon ULSD fuel sulfur content of
0.0015 weight percent. H2SO4 emissions assumed equal to 8 weight percent of SO2 emissions.
18
Table 7 Key:
g/kWh=grams per Kilowatt-hour
lb/hr=pounds per hour
lb/MMBtu=pounds per million British thermal units
tpy=tons per 12-month rolling period
The BACT analysis for each PSD pollutant for all proposed emission units may be found in Appendix 1
attached to the PSD Fact Sheet.
VII. Monitoring and Testing
Footprint will install, calibrate, and operate dedicated continuous emission monitoring systems
for measuring NO, emissions, in addition to the diluent oxygen (02), in the flue gas from the combined
cycle turbines. Each system will consist of a probe, analyzer, and data acquisition and handling system.
The NO, monitoring system shall meet the specifications and quality assurance procedures of 40 CFR
Part 75. The 02 monitoring system shall meet the specifications and quality assurance procedures of 40
CFR Part 60 Appendix B, Performance Specification 3. Emission data for NO,will be measured by the
analyzer in ppmvd (parts per million by volume, dry basis). This ppmvd data, corrected for 02, can be
directly compared to the permit emission limits to determine compliance.
Pursuant to 40 CFR 75.13, Footprint will also monitor CO2 emissions in accordance with 40
CFR Part 75, Appendix G. To obtain NO, mass emissions on an hourly basis, Footprint will use EPA
methods contained in 40 CFR Part 75. Footprint will need to measure heat input on an hourly basis and
moisture content to convert the measured ppmvd data to pounds per hour(lbs/hr).
Footprint is required to monitor and keep records of the amount of sulfur in the natural gas that is
combusted in the combined cycle turbines pursuant to New Source Performance Standards 40 CFR Part
60 Subpart KKKK.
Footprint is also required to conduct stack tests for NO., PM, PM10, PM2,5, CO2, and H2SO4
emissions within 180 days after initial firing of the combined cycle turbines.
VIII. Impact Analysis Based on Modeling
As part of its Application, Footprint submitted a dispersion modeling analysis that met the
requirements of 40 CFR Part 51, Appendix W.
Footprint's consultant (Tetra Tech) conducted a refined dispersion modeling analysis to
determine impact concentrations at receptors located along the SHR Project fence line and beyond. The
refined analysis was based on proposed, worst case facility emission rates, and 5 years (2006-2010) of
meteorological conditions. The meteorological data was collected at the Boston Logan Airport National
Weather Service (NWS) station, which is the closest first order NWS station to the SHR Project and is
representative of the SHR Project site area since it is exposed to similar coastal environmental
conditions.
19
The dispersion modeling results for the proposed SHR Project are provided in Table 8 and show
that the SHR Project's impact concentrations are below the corresponding Significant Impact Levels
(SILs) established by EPA for all pollutants except NO2 (1-hour)and PM2,5 (24-hour). Compliance with
the NAAQS and PSD Increments is therefore, according to EPA guidance, demonstrated for all
pollutants and averaging periods for which impacts are below the SILs. Cumulative modeling with
other regional sources was conducted for NO2 and PM2.5-
•Table'8:!'�Project,Mazimuii PfedictediIinpact Concentratio s Compare4,i6 Signifca
Levels'(micrograms/cubic meter•)_
PollufanY• Averaging^ t Masifnu n Predicted Sal&WMArbor '. S1L, i
!. Period, 1 , - _.,RedevelopmerifPro',j'ectImpac'f,
PM10 24-Hour 4.3 5
PM2.5 24-Hour 3.2 1.2
Annual 0.11 0.3
NO2 I-Hour 41.8 7.5
Annual 0.4 1
Backeround Concentrations and Nearbv Sources
Tetra Tech determined ambient background concentrations through the use of existing ambient
monitoring data representative of the SHR Project site area. Ambient background concentrations are
based on the measurements made at the MassDEP monitoring site (ID# 025-009-2006) located in Lynn,
MA. The Lynn monitoring site is located approximately 5.9 miles to the southwest of the project site.
This monitoring site is representative of the SHR Project site since it is located relatively close to the
site. Furthermore, use of data from the Lynn monitoring site is also conservative because Lynn is a
more industrialized and densely populated area than the proposed SHR Project site area, particularly
without the influence of the coal and residual oil fired existing Salem Harbor Station, as will be the
situation when the SHR Project begins operations. The SHR Project site is located adjacent to Salem
Harbor, a significantly large water body where potential emission sources are more limited. The Lynn
monitoring site is also located closer to the metropolitan Boston area than the project site area. Any
potentially elevated ambient background pollutant concentrations from mobile and stationary emission
sources located in and around the Boston metro area that may be transported to the Salem project area
(via predominant south-southwesterly winds, i.e. winds blowing towards the north-northeast), must pass
the Lynn monitoring site, and are therefore represented in the measurement data collected at the Lynn
monitoring site.
The GE Aircraft Engine facility in Lynn and the Wheelabrator Saugus waste-to-energy facility,
two major industrial emission sources modeled cumulatively with the proposed SHR Project, are located
slightly less than 2 miles from the monitoring site but are located about 7 miles from the SHR Project
site. Therefore, the cumulative modeling compliance demonstration, which includes both the
background ambient concentrations and impacts from the interactive existing major sources potentially
double counts the contribution of these sources and therefore, potentially overestimates cumulative
impact concentrations. This is particularly significant because these two major sources are located to the
south-southwest of the Lynn monitoring site which means that they could potentially influence the
measured site concentrations during south-southwesterly winds (winds blowing towards the north
northeast)which is one of the predominant wind directions in the area.
20
Nearby sources that must be considered in cumulative modeling are described in 40 CFR Part 51,
Appendix W as follows:
"Nearby Sources: All sources expected to cause a significant concentrations gradient in the
vicinity of the source or.sources under consideration for emission limit(s) should be explicitly
modeled. The number of expected sources is expected to be small except in unusual situations.
Owing to both the uniqueness of each modeling situation and the large number of variables
involved in identifying nearby sources, no attempt here is made to define the term. Rather,
identification of nearby sources calls for the exercise of professional judgment by the appropriate
reviewing authority (paragraph 3.0(b)). This guidance is not intended to alter the exercise of the
judgment or to comprehensively define which sources are nearby sources."
The term "sources" in EPA's modeling guidance refers to stationary point sources of air
emissions. Air emissions from mobile sources are addressed through the use of ambient background
concentrations as measured by representative monitors. MassDEP reviewed recent emissions source
inventory data for point sources of NO. and PM25 surrounding the project. In accordance with
MassDEP's June 2011 "Modeling Guidance for Significant Stationary Sources of Air Pollution", nearby
sources within 10 kilometers that emit significant emission rates for NO, and PMZ 5 (40 tons per year
and 10 tons per year actual emissions, respectively) may significantly interact with a new or modified
facility.
The sources that were identified for inclusion in the source interaction cumulative modeling
analysis include the General Electric (GE) Lynn, MA and Wheelabrator Saugus, MA facilities for both
NO, and PM2.5 emissions, as well as the Rousselot Peabody facility (formerly Eastman Gelatin Corp.),
Peabody Municipal Light(PML), and Marblehead Municipal Light(MML) facilities, for NO,emissions
only. The GE and Wheelabrator facilities are located approximately 12.1 and 11.6 km (7.5 and 7.2
miles), respectively, to the southwest of the project site. Based on the 2008 MassDEP emission source
inventory data, actual GE emission levels for NOx and PM2,5 are 248.3 and 11.8 tons per year,
respectively. Wheelabrator emission levels for NO, and PM25 are 721.8 and 6.2 tons per year,
respectively. The Rousselot, PML, and MML facilities are located approximately 5.0 km (3.1 miles) to
the east, 4.5 km (2.8 miles) to the northeast, and 2.1 km (1.3 miles) to the southeast of the project site,
respectively. The actual 2008 NO,emission levels for these facilities are 15.0 tons per year (Rousselot),
6.4 tons per year (PML), and 0.34 tons per year (MML). The actual NO, emissions from these three
sources are below the PSD and MassDEP significance level of 40 tons per year of NO., but were
included in the analysis because of their proximity to the proposed SHR Project.
The results of the cumulative impact assessment, presented in Table 9, demonstrate that the
proposed SHR Project's worst case emissions will result in compliance with the National Ambient Air
Quality Standards (NAAQS). Note that while impacts related to secondary PM2.5 emissions have not
been explicitly quantified, sufficient margin is available between the predicted impact concentrations
from direct PM2.5 emissions and the NAAQS, that the NAAQS would not be threatened by additional
PM2.5 emissions. This conclusion is further supported by the fact that the maximum PM2.5 impacts are
predicted very close to the SHR Project fence line, where secondary PM2.5 emissions would not have
sufficient time to develop, and therefore, could only be additive to predicted project impacts where
21
impacts of direct PM2.5 emissions are less than what has been reported for the compliance
demonstration.
Table 9. Salem HarUo_r:Set ion Re_developmen't Project NAAQS Comp'lian_ce 's_e_ssment
1y / p 3 11
_:- - mtc_ro rams/cu'b_r_e.meter)_L_
Io �
�iPollutan f-� Ave aging 1CumulativeImp f 1Backgro0nd11 "Total'Impactnl`rrP.rimary
Petrod ,SHR&%JectPlus,' �' s Plus NAAQS?
s ' - _ _ z - 6t:Exlsting Sources �� - _ k ,_Bac&grouMV
PM25 24-Hour 3.5 18.9 22.4 35
NO2 1-Hour 83.7 s 82.3 166.0 188
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 98"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 8"highest 24-hour average values occurring in each year for the 24-Hour PMZ 5 concentration, and
the 5 year average of the 8'"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
NO,emissions to NO, in the ambient air. "Tier 2" is the Ambient Ratio Method for NO,to NO2 conversion of AERMOD
modeling results.It specifies that the results of NO,modeling be multiplied by an empirically-derived NO /NO,ratio,using a
value of 0.75 for the annual standard and 0.8 for the 1-hour standard. This modeling guidance is contained in USEPA's
Clarification Memo, dated March 1, 2011, "Additional Clarification Regarding Application of Appendix W Modeling
Guidance for the 1-hour NO2 National Ambient Air Quality Standard".
In addition to demonstrating compliance with the NAAQS, Footprint is required to demonstrate
that its emission impacts will not exceed available PSD increments. No increment exists for 1-hour
NO2. On October 20, 2010, EPA published an increment standard for PM2 5, averaged over both annual
and 24-hour basis. In this rulemaking, EPA established the major source baseline date of October 20,
2010 and a requirement that all PSD PM2.5 sources will not consume more than the available increment.
For PM2.5, increment is tracked on a county wide basis in Massachusetts. The SHR Project will be the
first major source permitted in Essex County after this date, and therefore the entire increments of 9
gg/m3 (24-Hour PM2.5) and 4 µg/m3 (Annual PM2_5) are available. As shown in Table 10, the SHR 24-
hour PM2 5 and Annual PM2 5 impacts are 33.3%and 3% of their respective PSD increments.
Tatile;l0. Salem Har"Iior Station'Red_ 'evelopmerif Project PSD Incre_ment Compliance, n
Assessinenfg-
4 = - - --- --(micrograms/cubic me"ter):•_-_
Rollufaut -{ 4 'Averagiog.:PeriodF 'f SIM Project ;. _Maximum AllowaBle"PSD't
Incre'mtr j
en3Increment
ss - --- Corisumptionl
PM2.5 24-Hour 3.0 9
PM2 5 Annual 0.12 4
1. Consistent with EPA modeling guidance for PSD increment compliance assessments, impact concentrations are
based on the highest 2"high value at any receptor in any one for 24-hour PM2,increment consumption and the maximum
concentration at any receptor in any one year for annual increment consumption.
22
Imnairment to Visibilitv. Soils. and Vesetation
40 CFR 52.21(0) requires the Applicant to conduct an analysis of the air quality impact and
impairment to visibility, soils, and vegetation that would occur as a result of the SHR Project and
general commercial, residential, industrial, and other growth associated with the SHR Project. The
VISCREEN model was used by Tetra Tech to assess potential visibility impacts at the closest Class I
Area, the Presidential Range/Dry River National Wilderness Area (185 km away). The SHR Project's
maximum potential emissions were used in the analysis. MassDEP reviewed the analysis and has
determined that the visibility impairment related to the SHR Project's plume will not exceed threshold
criteria.
The EPA guidance document for soils and vegetation, "A Screening Procedure for the Impacts of
Air Pollution Sources on Plants, Soils, and Animals" (EPA Screening Procedure) (EPA 450/2-81-078)
established a screening methodology for comparing air quality modeling impacts to "vegetation
sensitivity thresholds." As an indication of whether emissions from the SHR Project will significantly
impact the surrounding vegetation (i.e., cause acute or chronic exposure to each evaluated pollutant),the
modeled emission concentrations have been compared against both a range of injury thresholds found in
the guidance, as well as those established by the NAAQS secondary standards. Since the NAAQS
secondary standards were set to protect public welfare, including protection against damage to crops and
vegetation, comparing modeled emissions to these standards provides some indication of whether
potential impacts are likely to be significant. Table 11 lists the project impact concentrations and
compares them to the vegetation sensitivity thresholds and NAAQS secondary standards. All pollutant
impact concentrations are below the vegetation sensitivity thresholds.
Table llf'Ve—etat�on=Iin acf Screentn`Tli`restiol
g ._ .i. . . _..P- - -.... . . g'T
P_ ollutants.i , Aveiagiug. ` I Maximum , Secoud"WNAAQS!a TEPA s�1980Scr ninj:,
Periods 4 Prgject (µg/m o)# F ,tConeentrahons:r(µg/m>)w
I Impacts
3
NO2 4-hour 41.8NA 3760
1 month 41.8 r NA 561
Annual 0.4 100 94
PMto 24-hour 4.3 150 None
PM2.5 24-hour 3.2 35 None
Annual 0.11 I 15
1. Conservatively based on shorter term average predicted concentration.
The EPA Screening Procedure also provides a method for assessing impacts to soils. This
assessment evaluates trace elements contamination of soils. Since plant and animal communities can be
affected before noticeable accumulations occur in the soils, the approach used here evaluates the way
soil acts as an intermediary in the transfer of a deposited trace element to the plants. For trace elements,
the concentration deposited in the soil is calculated from the maximum predicted annual ground level
concentrations conservatively assuming that all deposited material is soluble and available for uptake by
plants. The amount of trace element potentially taken up by plants was calculated using average plant to
23
soil concentration ratios. The calculated soil and plant concentrations were then compared to screening
concentrations designed to assess potential adverse effects to soils and plants. Table 12 presents the
results of the potential soil and plant concentrations based on Tetra Tech's analysis and compares them
to the corresponding screening concentration criteria. A calculated concentration in excess of either of
the screening concentration criteria is an indication that a more detailed evaluation may be required.
MassDEP reviewed the analysis and has determined that concentrations as a result of operation of the
proposed SHR Project are all well below the screening criteria.
led2: :SOM Impact SOrej ing Aspesspen't
'+Pollutant Deposited S.oi11,� Soth Percen"t oft► G 'PlantrTissue " 'Plantes `IPerceut T1
+`
IConceutrationi ScreeningJ, I f 'Soil' Concentrations e,Screen'i'ngl ofPl'apti 1
t,(ppmw),� Criteria-� Screening, , , (ppmw)i Criteria t Screening`,
i d I ,-_.
- — .(ppmw):.. Grite�ia _ .__ _ .-. n' ,(pPmw)i ,+Criteria i
Arsenic 3.02E-04 3 0.0 4.23E-05 0.25 0.0
Cadmium 1.63E-03 2.5 0.1 1.74E-02 3 0.6
Chromium 3.78E-03 8.4 0.0 7.56E-05 1 0.0
Copper 1.23E-03 40 0.0 5.76E-04 0.73 0.1
Lead 8.30E-04 1000 0.0 3.73E-04 126 0.0
Mercury 3.71E-04 455 0.0 1.85E-04 NA NA
Nickel 3.31E-03 500 0.0 1.49E-04 60 0.0
Selenium 7.08E-05 13, 0.0 7.08E-05 100 0.0
Vanadium 3.40E-03 2.5 0.1 3.40E-05 NA NA
Note: Based in screening procedures described in Chapter 5 of the EPA guidance document for soils and vegetation, "A
Screening Procedure for the Impacts of Air Pollution Sources on Plants,Soils,and Animals."
IX. Mass Based Emission Limits
To ensure the NAAQS and PSD increment are not violated, a PSD Permit must contain
enforceable permit terms and conditions which ensure the mass flow rates for each modeled pollutant
are not exceeded. This is accomplished by establishing mass-based emission limits for each modeled
pollutant with or without the use of a CEMS. When a CEMS is used,the PSD Permit must establish the
averaging time for each mass-based emission limit that ensures compliance with the NAAQS. Without
a CEMS, the applicable stack test method establishes the averaging time by default. Footprint is
required to install CEMS for NO., therefore averaging times for NO, are specified in the Permit.
i
Table 13'. Mass-]3'asediEmis'sioifLimits ',_T
-
-NO
x _. ...,.__._.h - - - ,PM/AlVI'to/P1VIzs - - i�
Combined Cycle Turbine(maximum capacity) ��
18.1 lb/hr,one hour block average I See Table 2 in PSD Permit
Combined Cycle Turbine(start-up/shutdown)
See Table 2 in PSD Permit See Table 2 in PSD Permit
Auxiliary Boiler
0.88 lb/hr, one hour block 0.4 lb/hr, one hour block average
average
24
� _�. _--.TalSle•13:=Mass;Basgd�Emissiori!Liiriits:"T',_`— �.:_, :-,_.,..�;�-.�__�1�
Emergency Diesel Generator
11.6 lb/hr, one hour block 0.361b/hr, one hour block average
averagez
Diesel Fire Pump Engine
2.44 lb/hr, one hour block 0.12 Ib/hr, one hour block average`
average
z
Table 13 Notes:
1. There are no mass-based emission limits for GHG since there is no NAAQS or increment to protect.
2. Includes VOC(NMHC as CHS 8)but conservatively assumed as all NO,.
Table 13 Kev:
N0,=Nitrogen Oxides
PM=Total Particulate Matter
PM,p=Particulate Matter less than or equal to 10 microns in diameter
PM,,=Particulate Matter less than or equal to 2.5 microns in diameter
Ib/hr=pound per hour
The PSD Permit contains. the mass-based emission limits Footprint used in demonstrating
compliance with the NAAQS and PM2.5 increment, which are therefore enforceable emission limits in
the PSD Permit.
X. Environmental Justice
The PSD Delegation Agreement specifies that MassDEP identify and address, as appropriate,
"disproportionality high and adverse human health or environmental effects of federal programs,
policies, and activities on minority and low-income populations," in accordance with Executive Order
12898 (February 11, 1994). Footprint considered draft federal guidance3 as well as the Massachusetts
Executive Office of Energy and Environmental Affairs (EOEEA) Massachusetts-specific Environmental
Justice (EJ) Policy in preparing an EJ assessment for the SHR Project. MassDEP reviewed the EJ
assessment and agrees that the analysis satisfies both state and federal requirements.
The EPA defines EJ as "the fair treatment and meaningful involvement of all people regardless
of race, color, national origin or income with respect to the development, implementation, and
enforcement of environmental laws, regulations and policies. Fair treatment means that no group of
people, including a racial, ethnic, or socioeconomic group, should bear a disproportionate share of the
negative environmental consequences resulting from industrial, municipal, and commercial operations
or the execution of federal, state, local, and tribal programs and policies."4
3 US EPA,"Draft Technical Guidance for Assessing Environmental Justice in Regulatory Analysis",May 1,2013 Post-
Internal Agency Review Draft.
4 US EPA,Basic Information:Environmental Justice. httD://wivw.et)a.eov/environmentaliustice/basics/index.html
25
As demonstrated in Footprint's Application, Supplements, and as further set forth below, no such
group of people will bear a disproportionate share of negative health or environmental consequences
from the issuance of a PSD Permit to Footprint as (1) the SHR Project will not be located in or abutting
an EJ area; (2) nearby EJ communities have been provided with several opportunities to participate in
the permitting process; and (3) the SHR Project meets all applicable air emissions standards and would
not cause or contribute to a violation of the health-based National Ambient Air Quality Standards.
Moreover,the resulting regional emission reductions will benefit all communities, including EJ areas.
Identification of Environmental Justice Areas
The Commonwealth of Massachusetts Executive Office of Energy and Environmental Affairs
(EOEEA) Geographic Information System (GIS) includes EJ areas divided by block groups based on the
2010 US Census data. The block groups are based on the number of people generally ranging from 500
to 2500 people as opposed to physical boundaries such as streets or rivers. There are three main EJ
classifications in the EOEEA EJ Policy (which is more expansive than the EPA policy) - Minority, Low
Income, and English Isolation (referred to as "Lacking English Language Proficiency" in the EOEEA
Policy):
• "Minorities" under the EOEEA Policy are individuals who refer to themselves on federal census
forms as "non-white" or as "Hispanic,"which is broader than the EPA EJ definition. Any block
group with 25 percent or more minority population is considered to be an EJ area.
• Income of approximately 65% of the median annual household income is considered low
income. In Massachusetts median income is based on the state median household income of
$62,133 per year. Thus, any block group with a median annual household income of$40,673 or
less is considered to be an EJ area.
• English Isolation is any household in which members 14 years old and older speak a non-English
language and also speak English less than "very well" (i.e., are not proficient in English). Any
block group with 25%or more of households as English Isolated is considered to be an EJ area.
Based on EJ mapping completed by EOEEA, the SHR Project does not abut any EJ areas and is
not located within 1 kilometer of any EJ areas. However,the site is within approximately 10 kilometers
of a number of EJ communities in Salem, Lynn, Peabody, Danvers and Beverly. The closest EJ areas
are classified as Minority/Low Income and Minority/Low Income/English Isolation and are located
approximately 1.2 kilometers C/< of a mile) to the southwest of the SHR Project property boundary. A
portion of this area is known as the"Point Neighborhood."
The Point was originally surrounded by water on three sides and was known as Long Point or
Stage Point. There were fish shacks and mill buildings in this area originally. In the mid-1880's the
Naumkeag Steam Cotton Company built its first mill along the South River in the area of current day
Shetland Park. Immigrants, mainly French Canadians, settled in this area and provided the labor force
for the textile mills. The area was filled in to provide housing and more mill buildings. The Great
Salem Fire of 1914 destroyed this area but it was quickly rebuilt. The area thrived until the 1950's when
5 2010 census data is the latest demographic data available. httD:H%vww.mass.eov/mgis/ei boston metro.odf
26
the textile industry moved to the south. Over the past few decades, many Spanish-speaking immigrants
have settled in this area.
There are several additional areas in Salem located further than 10 km from the SHR Project
property and these are classified as containing low income and minority populations.
Public Participation
MassDEP published the Notice of Public Hearing and Public Comment Period on the Draft PSD
Permit in English, Spanish, and Portuguese. A translator was provided at the Public Hearing. Upon
request, copies of the public record would be provided in Spanish and Portuguese.
Footprint has conducted informational meetings, answered questions, and translated
presentations in non-English languages, in response to public interest and to encourage public
participation. The following is a summary
of the public outreach, including outreach to EJ communities,
conducted over the past year.
Notification of Filing an Environmental Notification Form (ENF) under the Massachusetts
Environmental Policv Act(MEPA)—August. 2012
A legal notice of the availability of the ENF was published in the Salem News in English,
Spanish and Portuguese on August 8, 2012. It was also published in the Marblehead Reporter in English
on August 9, 2012. Additional publication of the Legal Notice of Environmental Review was published
in English, Spanish and Portuguese in the Boston Globe on August, 18, 2012, the Lynn Daily Item on
August 21, 2012 and in the Danvers Herald, the Beverly Citizen and the Peabody-Lynnfield Weekly
News on August 23,2012.
• Enerev Facilities Siting Board(EFSB)Public Hearing. Salem MA— Sentember 19, 2012
The following actions were taken by Footprint for the EFSB Hearing:
- Placed Notification advertisements in both English and Spanish in the Boston Globe, Salem
News, and Spanish Paper EI Mundo.
- Placed English and Spanish Legal Notice of the of EFSB Petition, stating Footprint's
Development plans and the date/location of upcoming EFSB hearings, in the following
locations: Salem Public Library, City Clerk's Office, North Shore Community Development
Coalition, Salem Housing Authority, and ABE/ESOL Training Resources of America(Salem
Office). English copies of the EFSB Petition were also placed in these locations.
Notification of the placement of these EFSB documents in both English and Spanish was
placed in the EFSB advertisements in all three papers.
- Mailed EFSB Notice to abutters of existing Salem Harbor Station.
- Retained services of Spanish translator for EFSB hearings, to both translate information as it
was presented, and to translate questions presented from the public in Spanish.
27
Offered to meet with interested members of the public along with Spanish translator.
• Presentation to Historic Derbv Street Neiehborhood Association,November 12. 2012
In addition to the presentation, Footprint offered to Linda Haley, Chairperson, that its
representatives would meet with individual residents to answer questions if requested.
• Draft Environmental Imoact Renort,December 2012
Notice of the public scoping meeting and site visit was sent to Beverly, Lynn, Salem, Peabody,
Marblehead, and Danvers. Notification of the availability of the Draft Environmental Impact Report
was published in the Boston Globe, the Salem News, the Marblehead Reporter, the Beverly Citizen, the
Danvers Herald, the Lynn Daily Item and the Peabody-Lynnfield Weekly News in English, Spanish and
Portuguese. These notices appeared on December 19 and December 20, 2012 with the exception of the
Marblehead Reporter notice which appeared on December 27, 2012.
• Presentation to the Salem Harbor Power Plant Stakeholders Grown.January 22. 2013
Members have been appointed by Salem Mayor Kim Driscoll. The Stakeholders are those
individuals who represent abutters to the plant, city officials whose position speaks for abutters (e.g.,
City Councilors, state elected officials, etc.). Footprint has made a pledge to respond to all requests for
information(English or Spanish), and to openly discuss Community needs and requests.
• Presentation to The Point Neiehborhood Association,February 25. 2013
Lucy Curchado, Chairperson. Footprint provided a Spanish Translator. The presentation was
translated to Spanish sentence for sentence by the translator. Much of the Point leadership attended the
meeting and many questions were asked. The translator obtained questions from the Point membership,
translated those questions into English so they could be answered by Footprint representatives, and then
translated back into Spanish in response to the questioner. Footprint offered to either meet with any
members and provide a Spanish interpreter, or to respond in writing(Spanish)to questions if submitted.
• Public Presentation at the Bentlev Elementary School.February 26, 2013
At Mayor Driscoll's request, Footprint made a presentation to the general public. The public
was invited to ask questions and/or request additional information.
• Final Environmental Imnact Renort. Aoril 4. 2013
Notification of the availability of the Draft Environmental Impact Report was published in the
Boston Globe, the Salem News, the Marblehead Reporter, the Beverly Citizen, the Danvers Herald, the
Lynn Daily Item and the Peabody-Lynnfield Weekly News in English, Spanish and Portuguese on April
4, 2013.
28
• Salem Plannine Board Meetines.Mav 2.2013, Mav 6. 2013. and June 6. 2013
These meetings were continued to June 20, 2013 and were held at Bentley Elementary School.
They were open to the public.
• Onr?Oiniz coordination with Lucv Curchado, Chairperson of the Point Neiehborhood Association
Footprint is in the process of translating its most recent/complete power point presentation into
Spanish for distribution to the membership. Footprint has offered to translate, provide information,
and/or respond to any other issues, questions or concerns of the Neighborhood Association.
Impact Analvsis
Prior to 1949 the site was used for commercial purposes related to the handling of coal and oil.
The first power plant built on the site was a coal-fired unit that commenced operation in 1951. A second
coal-fired generation unit commenced operation in 1952, and a third coal-fired unit was added in 1958.
In 1978 a fourth, oil-fired, unit was added. The existing facility has operated as a grandfathered facility
(that did not have to meet emissions standards applied to new power plants) for many years and may not
have been able to be built under today's environmental regulations. However, the existing facility did
provide a significant economic value to the residents of Salem in tax payments. The proposed SHR
Project will result in significant decreases of air pollutant emissions, not just as compared with the
existing facility,but also regionally,while providing a tax benefit to the City of Salem and its residents.
Once operational, the SHR Project will be among the most efficient fossil-fueled fired electric
generators in the Northeast Massachusetts (NEMA)zone and is expected to provide 5.1 million MWh of
electricity annually. This additional supply will reduce the need for generation from other power plants
with lower efficiency and higher operating costs, primarily fueled by natural gas, oil, and coal. Charles
River Associates, a consultant to Footprint, has conducted an analysis projecting the operation of the
New England bulk power system over the period 2016-2025, for scenarios with and without the SHR
Project in service, and quantified the expected changes in air emissions by the project directly and the
associated reductions of emissions at competing plants elsewhere in New England and, in particular,
Massachusetts. MassDEP has reviewed the CRA study and agrees that because the SHR Project would
displace other, less efficient generation on the New England grid, operation of the SHR Project would
reduce regional GHG emissions.
Health Risk Assessment
Footprint commissioned a health risk assessment (HRA)to assess the potential for human health
risk associated with the SHR Project 6 Gradient Corporation prepared the human health risk assessment
evaluating the likelihood of both acute non-cancer health risks and chronic non-cancer and cancer health
risks that may result from people's inhalation of airborne pollutants for SHR Project stack air emissions.
Gradient also collected relevant background health information for Salem and surrounding communities
to determine if any types of disease (e.g., cancer and asthma) were higher than expected compared to
Massachusetts as a whole.
6 Gradient Corporation,"Health Risk Assessment(HRA)for the Salem Harbor Redevelopment(SHR)Project",January 4,
2013.
29
Footprint states that the HRA indicates that maximum predicted air levels of specific substances
associated with SHR Project air emissions would not be expected to contribute to adverse health effects
among potentially affected populations. Footprint states that several separate lines of evidence from the
HRA support the conclusion that the potential air emissions from the SHR Project are not expected to
have an adverse effect on public health in the Salem area. Footprint states that these include the
following:
- The maximum cumulative air concentrations (project impact plus existing background) of the
criteria pollutants of concern, which include SO2, CO, NO2, and PM, are well below the
health-protective NAAQS. NAAQS are set to protect human health with a wide margin of
safety even for sensitive populations. Stack emissions of criteria air pollutants are thus not
expected to lead to impacts on human health (e.g", asthma, cardiovascular and respiratory
diseases) in nearby communities,even in sensitive populations.
- For possible non-cancer effects, all hazard quotients (HQs), calculated for an off-site resident
exposed to maximum modeled incremental SHR Project stack impacts, were well below
unity (HQ = 1), with none being higher than HQ = 0.01. The overall summed HI for SHR
Project stack emissions is also well below 1.0, i.e., HI = 0.08. These results help assure that
non-cancer, adverse health effects are not to be expected from the non-criteria air-pollutant
emissions.
- Conservatively projected cancer risks for maximum modeled SHR Project stack impacts of
possible carcinogenic chemicals were well below the 1 in 10,000 to 1 in 1,000,000 lifetime
risk range, which is considered to be acceptably low by EPA. The overall summed cancer
risk from the SHR Project was about 1 in 10,000,000 over a lifetime, which is well below the
EPA de minimis risk level. The individual pollutant cancer risks were each even lower than
the de minimis level, between about 1 in 10,000,000,000 and about 4 in 100,000,000. These
results support de minimis cancer risk from worst-case chronic exposures to maximum
modeled SHR Project stack impacts.
- Based on the air-modeling results, short-term SHR Project air emissions impacts are not
expected to give rise to acute health effects. SHR Project-related maximum short-term
concentrations of NO2 were compared to short-term exposure guidelines and standards,
including the short-term NAAQS for NO2 which were specifically designed to protect against
asthma exacerbation and respiratory irritation. The comparisons show that the cumulative
impact (maximum 1-hour plus ambient background) for NO2 is well below the 1 hour health-
protective NAAQS as well as other short-term exposure guideline levels.
- Gradient stated that review of community health data for Salem and nearby communities
confirms that the Salem area has overall similar rates of asthma, cardiovascular conditions,
and cancer compared with the state as a whole. In combination with the results of the HRA,
Gradient concluded that air emissions from operation of the proposed SHR Project are not
expected to significantly alter any of these baseline health statistics.
30
Additional Analvsis of Surroundine Areas
The maximum criteria air pollutant impacts from the SHR Project were also compared to the
EPA- and MassDEP-adopted significant impact levels (SILs). SILs are impact levels set at only a few
percent of the ambient air quality standards and below which the regulatory agencies consider impacts to
be.insignificant.7 Impacts above the SILs are not considered significant, per se, but rather additional
P g
modeling is required to demonstrate that the proposed project will not exceed the NAAQS. A
significant impact area (SIA) is the area of a circle having the radius of the maximum distance from a
source to the point at which concentrations drop below the SIL. The SIA is used as a basis for analysis
not because of any concern that emissions impacts inside the SIA are adverse - since they are below the
NAAQS, they are by definition not adverse - but rather because impacts outside the SIA are so
insignificant as to be de minimis. In EJ analyses,the SIA is often presented on a direction specific basis
and represents all receptors with projected impacts above the SIL.
The dispersion modeling completed for the SHR Project and described elsewhere in this Fact
Sheet, demonstrates that the predicted maximum impacts from the SHR Project for the majority of
criteria air pollutants are below the SILs at all locations and therefore, represent no adverse human
health or environmental effects to Salem and outlying communities. The predicted impacts of the SHR
Project result in slight to moderate exceedances of SILs for only PM2 5 (24-hoar average
concentrations), and NO2 (1-hour concentrations). Since the SILs are set considerably lower than the
NAAQS, the modeled emissions do not necessarily mean a project's impacts would be unhealthy or
would have an adverse effect on any population. Footprint evaluated these as a way to determine if an
EJ area would be disproportionately subject to higher air impacts than other segments of the community
at large.
The following sections describe the maximum modeled impacts for the only two pollutants with
maximum impacts exceeding their respective SIL with specific reference to the SIAs in reference to
nearby EJ areas versus other nearby areas.
NO, Analvsis
The 1-hour NO2 SIL is 7.5 gg/m3. The 1-hour NO2 isopleths (i.e., maximum pollutant impact
concentration contours associated with emissions from the SHR Project) were prepared for the Salem
region and these isopleths show the following:
• There are two small areas of isolated peak NO2 one-hour concentrations (in the range of 36 to 42
gg/m3 and well below the NAAQS of 188 gg/m3). These are located very close to the SHR
Project site to the northeast and southwest of the power plant stack. These areas are not close to
any EJ areas. (How far are they from an EJ area?)
• Maximum concentrations beyond approximately 1 kilometer from the SHR Project's main stack
are less than approximately 16 pg/m and thus are all less than 10%of the health based NAAQS.
However, the SIA of 7.5 pg/m3 extends as far as 14 kilometers beyond the Footprint property
7 For example,the 1-hour NO2 SIL is 7.5 microgram per cubic meter versus the health based standard of 188 micrograms per
cubic meter and the 24 hour PM2 5 SIL is 1.2 microgram per cubic meter versus the health based standard of 35 micrograms
per cubic meter. These SIL concentrations are only 3 to 4 percent of the NAAQS.
31
line extending into Salem, Beverly, Marblehead, Middleton, Wenham, Danvers, Peabody, Lynn,
and Swampscott. While this encompasses all of the EJ areas in Salem as well as some in
Beverly, Danvers, Middleton and Lynn, the population associated with the EJ areas within the
SIA is a small percentage of the total population within the SIA.
The results of this assessment demonstrate that the SHR Project's NO2 impact concentrations
will not have disproportionately high human health or environmental effects on EJ areas.
PM,5 Analysis
Isopleths of maximum 24-hour average predicted concentrations from the SHR Project were also
prepared. These isopleths show the following:
• The highest 24-hour PM2.5 concentrations are only a small fraction of the health based NAAQS
(3 to 4 µg/m3 compared to the 35 gg/m3 NAAQS). These areas of highest impact are localized
and generally occur either on plant property, in areas immediately adjacent to the site, or in
Salem Harbor adjacent to the Salem shoreline.
• The 24-hour PM2.5 SIL is 1.2 µg/m3 and this SIA encompasses a two city block area of a low
income EJ area just south of the South River. However, the vast majority of the SIA is within
Salem Harbor or consists of residences and businesses in the Salem downtown area along Derby
Street. It also encompasses Winter Island and a portion of the Salem Willows Park. The EJ area
represents a very small percentage of the total population within the SIA.
The results of this assessment demonstrate that the SHR Project's PM2.5 emissions will not have
disproportionately high human health or environmental effects on EJ areas.
COQ Benefits
The EPA's May 1, 2013 Draft EJ Guidance states, "The U.S. Climate Change Science Program
stated as one of its conclusions: The United States is certainly capable of adapting to the collective
impacts of climate change. However, there will still be certain individuals and locations where the
adaptive capacity is less and these individuals and their communities will be disproportionally impacted
by climate change. Therefore, these specific population groups may receive benefits from reductions in
greenhouse gas (GHG) emissions." Operation of the SHR Project is actually projected to reduce (on a
net basis) annual regional GHG emissions.
Conclusion
The proposed SHR Project is not located in or adjacent to an EJ area, and MassDEP hereby finds
that there will be no disproportional adverse health or environmental impact to any such community.
Footprint has demonstrated that emissions from the proposed SHR Project itself will be well within the
NAAQS, which are designed to be health-protective of the most sensitive populations.
32
The above-discussed analyses and actions fulfill MassDEP's obligations under the Delegation
Agreement and fulfill all obligations under Executive Order 12898 and EPA Environmental Justice
Policy.
XI. National Historic Preservation Act,Endangered Species Act,Tribal Consultation
Section IV of the PSD Delegation Agreement contains the requirements for Applicants (e.g.,
Footprint), MassDEP, and EPA with regards to the PSD Program. Under the PSD Delegation
Agreement, EPA must engage in consultation as required by federal law before MassDEP issues PSD
Permits.
Section IV.H.3. states that "If EPA requires more time to consult with an Indian tribe before
issuance of a Draft PSD Permit, refrain from issuing the Draft PSD Permit until EPA informs MassDEP
that it may do so." In addition, Section IV.H.4. states that "In all cases, MassDEP will refrain from
issuing any Final PSD Permit until EPA has notified MassDEP that EPA has satisfied its NHPA, ESA,
and Tribal consultation responsibilities with respect to that Permit."
In an April 18, 2013 letter from Tetra Tech to EPA Region 1, Tetra Tech asked EPA to notify
MassDEP that EPA has satisfied its consultation responsibilities for the proposed SHR Project's PSD
Permit. The letter included several attachments sent to various State, Federal and Tribal agencies
responsible for their respective National Historic Preservation Act (NIIPA), Endangered Species Act
(ESA), and Tribal programs. EPA Region 1 reviewed Tetra Tech's letter and attachments and
concluded in its September 5, 2013 letter to MassDEP that it had satisfied its NHPA, ESA, and Tribal
consultation responsibilities with respect.to Footprint's PSD Permit.
The following sections outline how the NEPA, ESA, and Tribal consultation requirements
identified under the PSD Delegation Agreement have been met.
National Historic Preservation Act
On August 18, 2013, Tetra Tech submitted a letter to the Massachusetts Historic Commission
(MHC) notifying the MHC of Footprint's submittal of a PSD Permit Application for the proposed SHR
Project. The letter explained that Tetra Tech reviewed the National and State Register files and the
Inventory of Historic and Archaeological Assets of the Commonwealth at the MHC. The file search did
not identify any previously identified historic or archaeological resources within the proposed SHR
Project site.
The proposed SHR Project was also subject to a full Massachusetts Environmental Policy Act
(MEPA) review. As part of the MEPA review, a MEPA Environmental Notification Form (ENF) was
distributed to the MHC in August 2012. The MHC did not submit comments on the ENF to the MEPA
office. Accordingly, EPA found that NHPA consultation requirements for the proposed SHR Project
have been satisfied.
33
Endangered Species Act
Section 7 of the Endangered Species Act (ESA) requires that certain federal actions such as
federal PSD Permits address the protection of endangered species in accordance with the ESA.
On April 18, 2013, Tetra Tech submitted a letter to Thomas R. Chapman, Supervisor, New
England Fish and Wildlife Service (FWS) field office notifying the FWS office of Footprint's submittal
of the PSD Permit Application for the proposed SHR Project. The letter stated that Footprint is aware of
and understands current ESA consultation procedures outlined on the FWS website. The website
provides an endangered species consultation process in which the Applicant conducts the initial
consultation. Tetra Tech reviewed the data for Essex County and identified two endangered species,the
small whorled Pogonia plant and the piping plover. Tetra Tech determined the presence of the two
species is limited to either the woodlands or the coastal beaches and are not present in the City of Salem
where the proposed SHR Project will be located. Tetra Tech concluded that the proposed SHR Project
does not pose a threat to any currently identified or proposed endangered species or their habitats in the
area subject to FWS jurisdiction and as a result, no further ESA impact analysis is required. In a
November 28, 2012 letter from Thomas R. Chapman, FWS, to Lisa Carrozza, Tetra Tech, FWS
confirmed that no federally listed, proposed, threatened or endangered species or critical habitat are
known to occur in the proposed SHR Project area and that no further ESA coordination is necessary.
In addition, on April 18, 2013, Tetra Tech submitted a letter to John Bullard, Regional
Administrator, National Oceanic and Atmospheric Administration (NOAA) National Marine Fisheries
Service (NMFS), Northeast Regional Office, which notified (NMFS) of the PSD Permit Application
submittal. The letter described the proposed SHR Project and its location at the existing Salem Harbor
Station and concluded that the changes will reduce net regional emissions of air pollutants due to
displacement of other, less efficient electrical generation on the New England electric grid.
Based on the letters to FWS and NMFS, EPA found that ESA consultation requirements for the
proposed SHR Project had been satisfied.
Tribal Consultation
On April 18, 2013, Footprint submitted separate letters to the Tribal Environmental Directors
and the Tribal Historic Preservation Officers for the Wampanoag Tribe of Gay Head (Aquinnah) and
Mashpee Wampanoag Tribe. The letters notified the Tribes of the proposed SHR Project's PSD Permit
Application and described how the proposed SHR Project will reduce net regional emissions of air
pollutants due to displacement of other, less efficient electrical generation on the New England electric
grid. In addition, EPA notified the tribes about Footprint's proposed SHR Project in a follow-up E-mail
message. As of this date, neither Tetra Tech nor EPA has informed MassDEP of receipt of any
comments from the Tribes.
XII. Comment Period,Hearings and Procedures for Final Decisions
All persons, including Applicants, who believed any condition of the Draft Permit was
inappropriate were required to raise all issues and submit all available arguments and all supporting
34
material for their arguments in full by the close of the public comment period, November 1, 2013, to
Cosmo Buttaro of MassDEP at the address listed in Section XIII of this Fact Sheet.
A public hearing was held during the public comment period. MassDEP extended the public
comment period for three additional weeks to November 1, 2013. In reaching a final decision on the
PSD Permit, MassDEP has responded to all significant comments and is issuing a Response to
Comments (RTC)document concurrently with this PSD Fact Sheet and the PSD Permit.
MassDEP is forwarding a copy of the PSD Permit, PSD Fact Sheet and RTC to the Applicant
and each person who has submitted comments or requested notice.
Along with the PSD Permit, each person is being notified of their right to appeal, in accordance
with 40 CFR 124.15 and 124.19 via the following language:
1. Within 30 days after the final PSD Permit decision has been issued under 40 CFR 124.15,
any person who filed comments on the Draft Permit or participated in any public hearing
may petition EPA's Environmental Appeals Board to review any condition of the Permit
decision.
2. The effective date of the Permit is 30 days after service of notice to the Applicant and
commenters of the final decision to issue, modify, or revoke and reissue the Permit, unless
review is requested on the Permit under 40 CFR 124.19 within the 30 day period.
3. If an appeal is made to the EAB, the effective date of the Permit is suspended until the appeal
is resolved.
XIII. MassDEP Contacts
Additional information concerning the PSD Permit may be obtained between the hours of 9:00
a.m. and 5:00 p.m.,Monday through Friday, excluding holidays from:
Cosmo Buttaro
MassDEP Northeast Regional Office
205B Lowell Street
Wilmington, MA 01887
(978) 694-3281
Cosmo.ButtaCOnd State.MA.US
35
APPENDIX I
BEST AVAILABLE CONTROL ANALYSIS
(BACT)
APPENDIX A
EMISSIONS CALCULATIONS
36
1.0 CONTROL TECHNOLOGY ANALYSIS
This section presents an updated PSD BACT analysis for the Project. This updated analysis addresses
comments made on the draft permit and reflects additional information and corrections. The Project
exceeds PSD significant emission thresholds for NO., PM/PM10/PM25, H2SO4, and GHG, and thus is
subject to PSD BACT for these pollutants. The Project does not exceed PSD significant emissions
thresholds for CO.
The Project remains subject to MassDEP BACT for all pollutants. The MassDEP BACT analysis as
reflected in the prior application materials and the MassDEP draft permit documents remains valid and is
not addressed here.This section specifically addresses PSD BACT requirements.
PSD BACT is defined in 40 CFR 52.21 means "an emissions limitation (including a visible emission
standard) based on the maximum degree of reduction for each pollutant subject to regulation under Act
which would be emitted from any proposed major stationary source or major modification which the
Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts
and other costs, determines is achievable for such source or modification through application of
production processes or available methods, systems, and techniques, including fuel cleaning or treatment
or innovative fuel combustion techniques for control of such pollutant. In no event shall application of
best available control technology result in emissions of any pollutant which would exceed the emissions
allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Administrator determines that
technological or economic limitations on the application of measurement methodology to a particular
emissions unit would make the imposition of an emissions standard infeasible, a design, equipment,work
practice, operational standard, or combination thereof, may be prescribed instead to satisfy the
requirement for the application of best available control technology. Such standard shall, to the degree
possible, set forth the emissions reduction achievable by implementation of such design,equipment,work
practice or operation, and shall provide for compliance by means which achieve equivalent results."
Typically,PSD BACT follows a five step "top-down" approach: (1) identify all control technologies; (2)
eliminate technically infeasible options; (3)rank remaining control technologies by control effectiveness;
(4) evaluate most effective controls and documents results; and(5)select BACT.
However, a key exception to the strict, five-step "top-down" approach is described in page B-8 of the
EPA's October 1990 draft New Source Review Workshop Manual (the "NSR Manual," as cited in the
EPA comment letter):
If the applicant accepts the top alternative in the listing as BACT, the applicant proceeds to
consider whether impacts of unregulated air pollutants or impacts in other media would justify
selection of an alternative control option. If there are no outstanding issues regarding collateral
environmental impacts, the analysis is ended and the results proposed as BACT. In the event that
the top candidate is shown to be inappropriate, due to energy, environmental, or economic
impacts, the rationale for this finding should be documented for the public record. Then the next
most stringent alternative in the listing becomes the new control candidate and is similarly
evaluated. This process continues until the technology under consideration cannot be eliminated
by any source-specific environmental, energy, or economic impacts which demonstrate that
alternative to be inappropriate as BACT.
37
1.1 Combined Cycle Combustion Turbines
1.1.1 Fuel Selection
Fuel selection is an important consideration with respect to all pollutants subject to PSD review for the
facility (NO., PM/PM10/PM25, H2SO4, and GHG). Therefore, fuel selection for the combustion turbine
combined cycle units is initially discussed here,prior to the PSD BACT evaluation for the individual PSD
pollutants, instead of repeating this under the evaluation for each pollutant.
The Applicant proposes to use natural gas only for the combined cycle turbines.
Step l:Identify all control technologies(fuel types)..
Identified control technologies(fuel types)for combustion turbine combined cycle units are:
1. Use of natural gas only.
2. Primarily natural gas with liquid fuel as a backup fuel. Liquid fuel could be ultra-low sulfur
distillate(ULSD),biodiesel or a mixture of these.
Step 2:Eliminate technically infeasible options
Both above fuel options are technically feasible. An acceptable mixture for ULSD/biodiesel is subject to
confirmation by turbine suppliers.
Step 3:Rank remaining control technologies by control effectiveness.
Natural gas is the lowest emitting commercially available fuel for combustion turbine combined cycle
units. ULSD and biodiesel have higher emissions than natural gas for NO., PM/PM10/PM2,5 and GHG.
H2SO4 emissions depend on the maximum sulfur content of the fuel. ULSD and biodiesel are normally
specified at 15 ppm sulfur by weight, and pipeline natural gas is defined by USEPA in 40 CFR 72.2 to
have a maximum sulfur content of 0.5 grains/100 scf. These values are effectively identical in the amount
of sulfur per MMBtu of fuel. However, natural gas as delivered is likely to have a lower actual sulfur
content per MMBtu of fuel compared to ULSD or biodiesel.
Since natural gas is a lower emitting fuel than ULSD or biodiesel, it ranks higher in terms of control
effectiveness and is considered the top BACT alternative.
Step 4.Evaluation of Collateral Impacts
Energy Impacts
Within the past decade,natural gas has become increasing abundant in the New England, due to increased
availability of domestic sources of gas. However, concerns have been raised regarding the lack of
regional fuel diversity and potential overreliance on natural gas for energy supplies. In particular,pipeline
infrastructure to deliver gas into New England can become constrained during cold weather as space
heating and electric production compete for available gas supplies. These issues have resulted in
considerations for more energy diversity and backup liquid fuel supplies for electric generation facilities.
Since the Applicant has committed to use natural gas exclusively in the combustion turbine combined
cycle units, potential energy concerns with exclusive natural gas use are an important consideration. The
Project will obtain natural gas from its direct connection to Algonquin's HubLine interstate natural gas
pipeline near HubLine's interconnection with the Maritimes & Northeast Pipeline. This unique
interconnection point permits the Project to access supplies of natural gas from both Canadian sources as
38
well as from domestic sources the south and west. The Maritimes & Northeast Pipeline has not had the
same physical delivery constraints as the heavily relied-upon pipelines delivering natural gas into New
England exclusively from the south and west. Therefore, energy concerns due to exclusive natural gas use
are not problematic for this Project.
Economic Impacts
Natural gas is currently a much more favorable economically compared to liquid fuels, and this situation
is expected retain this current pattern into the foreseeable future. With Footprint's access to Canadian
Maritime gas, potential short-term price spikes due to physical supply constraints are not expected to be
problematic. Therefore, there are no economic considerations that would dictate that backup provisions
for liquid fuel are necessary.
Environmental Impacts
In addition to being a higher emitting fuel for air emissions, liquid fuel has other significant collateral
impacts compared to natural gas. The most significant collateral impact is associated with the truck
delivery of liquid fuel to the site. Although liquid fuel could be delivered by barge as well, the local
community has expressed its strong opposition to the continued storage and combustion of liquid fuel on
the site for power generation. These impacts are of significant concern to the local Salem community, and
in fact have led to a commitment by the Applicant not to use liquid fuel for the combustion turbine
combined cycle units at the site.
The other collateral environmental impact of note is the fact that NO,control for liquid fuel requires the
use of water or steam injection to the turbine combustor. The use of water/steam injection would result in
a significant consumptive water use and an associated discharge of water that is not needed for dry low-
NOx combustors,which are available for natural gas.
Step 5:Select BACT
Use of natural gas as the exclusive fuel for the combustion turbine combined cycle units is clearly
justified as PSD BACT. Natural gas is lower emitting, has significantly lower collateral environmental
impacts,and collateral energy and economy impacts have been determined to be acceptable.
1.1.2 PSD Best Available Control Technology Assessment for NO,
Step 1:Identify Candidate Technologies
NO,control technologies identified for new large> 100 MW combined cycle turbines are as follows:
• Dry-low NO, (DLN) Combustion: Turbine vendors offer what is known as lean pre-mix
combustors for natural gas firing which limit NOx formation by reducing peak flame
temperatures.
• Water or Steam hijection: Water or steam injection has been historically used for both gas and oil
fire turbines,but for new turbines is generally only used for liquid fuel firing.
• Catalytic Combustors: A form of catalytic combustion to limit firing temperature has been under
development using the trade name XONON.
• SCONOx: This is an oxidation/absorption technology using hydrogen or methane as a reactant.
This technology is currently marketed as EMx.
39
• SCR: This is a catalytic reduction technology using ammonia as a reactant that has been in
widespread use on new combined cycle turbines for over 20 years.
Step 2:Eliminate Infeasible Technologies
Catalytic combustors are not currently technically feasible for large turbines. The only known application
is on a 1.4 MW test turbine.The largest turbine to which SCONOx has been successfully demonstrated is
a 43 MW turbine in California. There are significant SCONOx scale up questions for a new turbine larger
than 100 MW,but for the sake of argument SCONOx will be assumed to be technically feasible here. The
other technologies are all technically feasible.
Step 3:Rank Control Technologies by Control Effectiveness
The ranking of these technologies is as follows:
1. SCR: Widely demonstrated to have achieved 2.0 ppmvd NO, at 15% 02 for gas firing. This is
documented in the LAER analysis presented in the December 21, 2012 Application and First
Application Supplement(April 12,2013).
2. SCONOx: Demonstrated to have achieved 2.5 ppmvd NO, at 15% OZ at the 43 MW California
unit.
3. DLN: Generally recognized to achieve 9 ppmvd NO,at 15%OZ. Commonly used in conjunction
with SCR to achieve 2.0 ppmvd NO,at 15%02-
4. Steam/Water Injection:Less effective than DLN.
Step 4:Evaluate Controls
Since Footprint is proposing the"top" level for NO,BACT (SCR),the BACT analysis can proceed to the
consideration of whether any collateral energy or environment impacts would indicate other than the top
demonstrated technology be selected.
The one collateral impact that has been identified for SCR is due to the use of ammonia as a reagent, and
the resulting emissions of ammonia"slip"that can occur. SCONOx does not require the use of ammonia.
While SCONOx will eliminate the use of ammonia, the lower NO, emissions demonstrated in practice
with SCR(2.0 ppmvdc vs. 2.5 ppmvdc for SCONOx) and the very high additional cost documented with
SCONOx does not justify a finding that SCONOx is BACT. This same conclusion is found in the EPA
Analysis for the Pioneer Valley Energy Center (PVEC), in the Fact Sheet published in December 2011.
SCONOx is not justified as BACT. In addition, as documented in the Application and supplements, the
predicted ambient air quality impacts for ammonia are well below the MassDEP air toxics guidelines.
Aqueous ammonia will be stored in a 34,000 gallon above ground tank located within a concrete dike
designed to contain 110% of the total tank volume. Passive evaporative controls will be used inside the
dike to control evaporation in the event of a release, and the tank and dike will be in a fully enclosed and
sealed structure except for roof vents. Evaluation of a hypothetical worst case release indicates that
ammonia concentrations at and outside the Project perimeter will be less than the ERPG-I level. ERPG-1
is defined as the maximum airborne concentration below which nearly all individuals could be exposed
for up to one hour without experiencing other than mild transient adverse health effects or perceiving a
clearly defined,objectionable odor.
Step 5.Select BACT
The Footprint Project will meet the same 2.0 ppmvdc NO, limit as determined to be BACT for PVEC.
The Project will also meet a stringent emission limit for ammonia slip (2.0 ppmvdc on a 1-hour basis),
which is the most stringent ammonia limit achieved in practice for facilities of thise. This stringent
ent g
40
ammonia limit assures that collateral impacts are adequately minimized for the use of SCR for the
Footprint Project,and that this represents BACT for NO..
1.1.3 PSD Best Available Control Technology Assessment for PM/PMIO/PM2.e
Emissions of particulate matter result from trace quantities of ash (non-combustibles) in the fuel as well
as products of incomplete combustion. Conservatively, all particulate matter (PM) emissions for the
combustion turbines are assumed to be less than 2.5 microns in size(PM2.5)-
Pursuant to identifying candidate control technologies under the "top-down" procedure, Footprint has
compiled all the PSD BACT determinations in the last five years for new large (> 100 NM combustion
turbine combined cycle project. This compilation is based on the USEPA RBLC (RACTBACT/LAER
Clearinghouse). Several recent projects not included in RBLC have also been included in this
compilation. The Brockton Energy Center Project in Brockton MA is also included, since it is a similar
recent project in Massachusetts, even though it did not receive a PSD permit. This review confirms that
the only BACT technology identified for large natural gas fired combined cycle turbines is use of clean
fuel(i.e.,natural gas) and good combustion practices.
For PM/PMIo/PM2.5, this evaluation does not identify and discuss each of the five individual steps of the
"top-down" BACT process, since there are no post-combustion control technologies available for
PM/PMio/PM2.5. Post-combustion particulate control technologies such as fabric filters (baghouses),
electrostatic precipitators, and/or wet scrubbers, which are commonly used on solid fuel boilers, are not
available for combustion turbines since the large amount of excess air inherent to combustion turbine
technology would create adverse backpressure for turbine operation.
The "top-down" procedure does require selection of BACT emission limits, which is addressed in the
following paragraphs.
Table 1-1 presents the results of RBLC compilation for PM/PMIo/PM2.5. A review of Table 1-1 indicates
that PM/PMIo/PM2_5 emission limits are expressed strictly in lbs/hr or Ib/MDBtu, or in both lb/hr and
lb/MMBtu. This review also indicates that different emission limits can be associated with different
turbine suppliers. This is illustrated by some projects which have one set of limit for one supplier and
another set of limits for another supplier.
It is Footprint's conclusion based on review of available information that differences in PM/PMIo/PM2.5
emission limits among various projects are due to different emission guarantee philosophies of the
various suppliers, and are not actual differences in the quantity of PM/PM,o/PMZ 5 emissions inherently
produced by the supplier of the turbine. The different emission guarantee philosophies are influenced by
the overall uncertainties of the PM/PMIo/PM25 test procedures, especially given reported difficulties in
achieving test repeatability, and concerns with artifact emissions introduced by the general inclusion of
condensable particulate emissions(as measured by impinger based techniques) in permit limits in the last
decade.
41
Table 1-1. Summary of Recent Particulate PSD BACT Determinations for Large (>1001VIW) Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine PM/PM10/PMz5
Carroll County Washington 11/5/2013 2 GE 7FA 12.4 Ib/hr/unit and 0.0108 Ib/MMBtu without DF
Energy Twp., OH 2045 MMBtu/hr/unit plus 566 MMBtu/hr DF 19.8 Ib/hr and 0.00781b/MMBtu with DF
Renaissance Carson City, MI 11/1/2013 4 Siemens 501 FD2 units 9.0 Ib/hr/unit and 0.0042 Ib/MMBtu(with and without DF)
Power 2147 MMBtu/hr/unit each with 660 MMBtu/hr
DF
Langley Gulch Payette, ID 08/14/2013 1 -Siemens SGT6-5000F 12.55 Ib/hr(w/and w/o DF)
Power 2134 MMBtu/hr/unit with 241.28 MMBtu/hr DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or Mitsubishi: 11.3 Ib/hr/unit and 0.00384 Ib/MMBtu without DF
Energy 2 Siemens SCC6-8000H Mitsubishi: 10.1 Ib/hr and 0.00373 Ib/MMBtu with DF
2932 MMBtu/hr/unit plus 300 MMBtu/hr DF Siemens: 14.0 Ib/hr/unit and 0.0055 Ib/MMBtu without DF
Siemens: 13.3 Ib/hr and O.OD47 Ib/MMBtu with DF
Green Energy Leesburg,VA 04/3D/2013 2 GE 7FA.D5 GE: 0.00334 Ib/MMBtu at full load(w/and w/o DF)
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr DF or 9.6 Ib/hr/unit without DF
Stonewall 2 Siemens SGT6-5000F5 16.2 Ib/hr with DF
2260 MMBtu/hr/unit plus 450 MMBtu/hr OF Siemens: 0.003741b/MMBtu at full load (w/and w/o DF)
10.1 Ib/hr/unit without DF
14.5 Ib/hr with DF
Hickory Run New Beaver 04/23/2013 GE7FA, Siemens SGT6-5000F, Mitsubishi 11.0 Ib/hr/unit without DF
Energy LLC Twp., PA M501 G, or Siemens SGT6-8000H. 18.5 Ib/hr/unit with DF
2 combined cycle units Emissions based on Siemens SGT6-8000H
Sunbury I Sunbury, PA 104/01/2013 I "F Class"with DF 0.0088 Ib/MMBtu
Generation 2538 MMBtu/hr/unit
Brunswick County Freeman, VA 03/12/2013 3 Mitsubishi M501 GAC with DF 9.7 Ib/hr/unit and 0.0033 Ib/MMBtu without DF
Power Combined GT and DF 16.3 Ib/hr and 0.0047 Ib/MMBtu with DF
3442 MMBtu/hr/unit
Moxie Patriot LLC Clinton Twp, PA 01/31/2013 12.472 oE458 MW compF not specifiedcycle blocks with 0.0057 Ib/MMBtu
Centeon Energy I Dover, DE 1 309 MW01/30/2013 I I 32.1 Ib/hr
St. Joseph EnergyI New Carlisle, IN 112/03/2012 I 4-"F Class"1345 MW or Siemens) I 15 Ib//hlb/hrtand 0.0092 and 0.0078 IIb1 MBtuuw without
h DF DF
Center
Hess NewarkI Newark, NJ 11/01!2012 I 2320 MMBtu/hr/unit Dlus 2015 MMBtu/hr DF I 1113.2 lb/hrwthout DFDF
Channel Energy
Energy Houston, TX 10/15/2012 I501 F
I 27.0 Ib/hr
Center, LLC 425 0 MW plus
hrDF
42
Table 1-1. Summary of Recent Particulate PSD BACT Determinations for Large (>100MW)Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine' PM/PM1a/PM2.6
Moxie Liberty LLC Asylum Twp., 10/10/2012 Siemens"H Class" 0.0057 Ib/MMBtu for 454 MW block
PA 2-468 or less MW combined cycle blocks 0.0040 Ib/MMBtu for 468 MW block
GT<2890 MMBtu/hr/unit
DF<3870 MMBtu/hr/unit
Cricket Valley Dover, NY 09/27/2012 - 3-GE 7FA.05 0.005 Ib/MMBtu without DF
2061 MMBtu/hr/unit Dlus 379 MMBtu/hr OF 0.006 Ib/MMBtu with DF
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 27.0 Ib/hr
Center LLC 180 MW plus
725 MMBtulhr DF
ES Joslin Power Calhoun, TX 09/12/2012 3-GE 7FA 18.0 Ib/hr
195 MW per unit
No DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501GAC 9.8 Ib/hr
Energy Center 2542 MMBtu/hr/unit; no OF 0.004 Ib/MMBtu
(PVEC)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA 8.46 lb/hr/unit and 0.0048 Ib/MMBtu without DF
Power 154 MW(1736 MMBtu/hr)per unit plus 11.3 Ib/hr and 0.0049 Ib/MMBtu with DF
500 MMBtulhr DF
Thomas C. Llano,TX 09/01/2011 2-GE 7FA 18.0 Ib/hr
Ferguson Power 195 MW per unit
No DF
Entergy Ninemile Westwego, LA 08/16/2011 Vendor not specified 26.23 Ib/hr/unit without DF
Point Unit 6 Sinqle unit 550MW 33.16 Ib/hr with DF
Brockton Power Brockton MA 07/20/2011 1 Siemens SGT6-PAC-5000F 17.4 lb/hr
(MA Plan 2227 MMBtu/hr plus 641 MMBtu/hr DF 0.007 Ib/MMBtu
Approval)
Avenal Power Avenal, CA 05/27/2011 2-GE 7FA 8.91 Ib/hr/unit without DF
Center 1856.3 MMBtu/hr/unit plus 562.26 MMBtu/hr 11.78 Ib/hr with DF
DF
Portland Gen. Morrow, OR 12/29/2010 1 -Mitsubishi M501GAC 0.0083lb/MMBtu
Electric Carty Plant 2866 MMBtu/hr
Dominion Warren Front Royal,VA 12/21/2010 3-Mitsubishi M501 GAC 8.0 Ib/hr/unit and 0.0027 Ib/MMBtu without DF
County 2996 MMBtu/hr/unit_plus 500 MMBtu/hr DF 14.0 Ib/hr and 0.0040 Ib/MMBtu with DF
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE: 19.80 lb/hr/unit(w/and w/o DF)
Power Station 2430 MMBtu/hr/unit GT plus OF or Siemens: 11.1 Ib/hr/unit(w/and w/o DF)
4 Siemens SGT6-5000F5 -
_ 2693 MMBtu/hr/unit GT Dlus DF
Live Oaks Power Sterling, GA 03/30/2010 Siemens SGT6-5000F No emission limits specified.
_ PSD BACT for PM10/PM2.5 use of ppeline quality natural qas
Victorville 2 Hybrid Victorville, CA 03/11/2010 2 GE 7FA 12.0 Ib/hr/unit without DF
154 MW per unit plus 18.0 Ib/hr with DF
424.3 MMBtu/hr DF
43
Table 1-1. Summary of Recent Particulate PSD BACT Determinations for Large (>100MW) Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine' I PM/PMIo/PMze
Stark Power/Wolf Granbury,TX 03/03/2010 2 GE 7FA GE: 12.0 Ib/hr/unit(w/and w/o DF)
Hollow 170 MW/unit plus Mitsubishi:20.0 Ib/hr/unit(w/and w/o DF)
570 MMBtu/hr DF or
2 Mitsubishi M501G
254 MW/unit plus
230 MMBtu/hr DF
Panda Sherman Grayson, TX 02/03/2010 2 GE 7FA or GE: 12.0 Ib/hr/unit(without DF)
Power 2 Siemens SGT6-5000F115.4
27.0 Ib/hr with DF
with 468 MMBtu/hr/unit DF Siemens: 11.0 lb/hr/unit without DF
_ 1b/hrwith DF _
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F 7.5 Ib/hr/unit
Energy Center 2238.6 MMBtu/hr/unit plus 0.0036 Ib/MMBtu
200 MMBtu/hr DF
Lamar Power Paris, TX 06/22/2009 4-GE 7FA with 200 MMBtu/hr DF 18.0 Ib/hr/unit without DF
Partners II LLC 20.3 Ib/hr with DF
Pattillo Branch Savoy,TX 06/17/2009 4—GE 7FA, GE7FB, or 20.8 lb/hr/unit(each option)
Power LLC Siemens SGT6-5000F
With DF
Entergy Lewis The 05/19/2009 2-GE 7FA with 362 MMBtu/hr DF 27.14 Ib/hr/unit
Creek Plant Woodlands, TX
' DF refers to duct firing
2 Includes front(filterable)and back-half(condensable) PM. Limits obtained from agency permitting documents when not available in RBLC. Short-term emission
limits only are provided.
44
GE has historically guaranteed particulate emissions on constant Ib/hr basis, regardless of turbine load.
Thus, as shown in Table 1-1,many of the GE turbines have PSD BACT limits expressed strictly in lb/hr.
Footprint has calculated lb/MMBtu values inclusive of minimum emission compliance load (MECL).
(Note that duct-firing will not occur at MECL, so the MECL-based limit is only for unfired conditions).
Footprint has determined that the flexibility to operate at MECL is important to the Project's mission of
providing a flexible and quick response to the future system power needs. Footprint's draft PSD permit
and Plan Approval also require PM/PMr0/PM2.5 emission testing at MECL. MECL turbine operation
therefore results in Footprint's highest lb/MMBtu rate of 0.0071 lb/MMBtu. It is important to note that a
number of the lb/MMBtu emission rates in Table 1-1 correspond to(just)the full load heat input rate. For
comparative purposes, the Footprint full load lb/MMBtu/hr PM/PMio/PM2.5 emission rate (without duct
firing)ranges from 0.0038 to 0.0047 lb/MMBtu.
Table 1-1 lists 34 projects with PSD BACT limits for PM/PMI0/PM25 approved in the last 5 years. Over
half of these projects (18) clearly have PM/PMr0/PM2,5 limits less stringent than the Footprint limits
discussed above. Of the remaining 16 projects, most of these are for turbine suppliers other than GE, and
generally have lower PM/PMro/PMZ 5 limits expressed on a lb/MMBtu basis. The lb/MMBtu comparison
allows PM/PMio/PM2.5 rates for projects of different sizes to be more readily compared. The most
stringent lb/MMBtu limit identified is for the Dominion Warren County (VA) project, which is 0.0027
lb/MMBtu without duct firing. The Dominion Warren County project is based on 3 Mitsubishi 501GAC
turbines. Mitsubishi in particular has recently taken a more aggressive approach to PM/PMIo/PM25
guarantees, as reflected by the Warren County Project as well as the Brunswick County (VA) project
(0.0033 lb/MIVIBtu without duct firing and 0.0047 lb/MMBtu with duct firing),the Oregon(Ohio)project
(0.00384 lb/MMBtu without duct firing and 0.00373 lb/MMBtu with duct firing) and PVEC (0.004
lb/MMBtu without duct firing as noted in the CLF comment letter to MassDEP on the Footprint project).
With respect to the PM/PMI0/PM2.5limits achievable for the Mitsubishi 501 GAC turbine, it is significant
to note that an email from George Pyros of Mitsubishi Power Systems dated October 7, 2013, which was
submitted to MassDEP in comments concerning Footprint Power, indicates that Mitsubishi has "not yet
conducted stack PM emissions testing for our M501GAC gas turbine in combined cycle. However, we
have M501GAC units that will be commissioned next year in combined cycle that will provide such
data." (The Mitsubishi 501GAC project that is closest to commissioning is the Dominion Warren County
project.) The email from Mitsubishi actually supports Footprint's position, as provided in supplemental
material submitted to MassDEP on August 20,2013, insofar as the fact that ultra-low particulate rates for
the 501GAC turbine are not demonstrated in practice. In the August 20, 2013 submission, Footprint
questioned whether the 0.004 lb/MMBtu emission rate for the PVEC was achievable in practice. This is
based on the fact that four Mitsubishi 501G units at Mystic Station (Everett MA), had tested PM
emissions (in 2003) ranging from 0.005 — 0.010 lb/MMBtu. While the 501GAC turbine has a newer
generation combustion system, the majority of the tested particulate matter at Mystic was condensable
particulates. It is not at all clear how a newer generation combustion system would achieve better control
of condensable particles. While careful adherence to particulate testing procedures can minimize testing
variably and artifact condensable emissions, Footprint remains convinced that the Mitsubishi's recent
501GAC limits,particularly those for the Warren County project,present undue project risk.
In addition, for Mitsubishi and Siemens projects with PM/PMro/PM2_5 lb/MMBtu limits, these limits
appear to be approved as constant across the operating load range. This represents a different guarantee
philosophy than used by GE.Again,Footprint believes this is a guarantee philosophy difference and does
not reflect actual differences in the quantity of PM/PM,o/PM2,5 emissions due to the type of turbine. As
noted in Footprint's comment letter to MassDEP dated November 1,2013, at full load unfired conditions,
Footprint's Ib/IVfMBtu rates for PM/PM10/PM2 5 range from 0.0038 to 0.0047 lb/MMBtu. These full load
rates compare favorably to many of the lb/MMBtu rates for Siemens and Mitsubishi in Table 1-1.
45
Several Siemens "F Class" PM/PMIo/PM2.5 limits in Table 1-1 (Renaissance, Langley Gulch, Pondera
King)have lb/hr limits higher than the Footprint unfired value of 8.8 Ib/hr, but do not incorporate higher
duct firing limits (as is typically found to be necessary by available duct burner guarantees). Again,
Footprint believes this is a guarantee philosophy difference and does not reflect actual differences in the
quantity of PM/PMio/PM2 5 emissions due to the type of turbine and whether duct firing is present or not.
The Russell City Energy, Center Project is based on 2 Siemens 501F turbines, and was approved with
PM/PMio/PM25limits of 7.5 lb/hr and 0.0038 1b/MMBtu. Again, Footprint believes this is a guarantee
philosophy difference and does not reflect actual differences in the quantity of PM/PMio/PM2_5 emissions.
However, one item of particular note in the Russell City Energy Center PSD Permit is that the permit
allows the facility to propose alternate measuring techniques to measure condensable PM, such as the use
of a dilution tunnel. A dilution tunnel is expected to result in lower (and more realistic) tested emissions
compared to typical stationary source impinger techniques for measuring condensable PM.Therefore,this
permit provision may explain in part the rationale for the Russell City Energy Center strategy for
accepting lower permit limits. Dilution tunnel based measurements for condensable PM are expected to
more accurately simulate the process by which condensable PM forms compared to impinger techniques,
which still present concerns with artifact emissions.
There is one other GE 7FA unit noted in Table 1-1 that has PM/PMIo/PM2.5 limits of comparative note.
This is the Green Energy (VA)project. This project is approved for either GE 7FA or Siemens turbines.
For GE 7FA,the lb/hr limits are less stringent than Footprint but the lb/MMBtu limits are more stringent.
The Green Energy lb/MMBtu limits appear to be incorrectly calculated (too low), even based on the full
load firing rates.
In summary, the available evidence clearly indicates that PSD,BACT for PM/PMIo/PM2.5 emissions is to
use of state of the art combustion turbines,with good combustion practices and the use of natural gas. The
actual guarantees for PM/PMIo/PM2 5 emissions vary by manufacturer, and permit limits within the range
of recently approved projects for a given turbine supplier are justified as PSD BACT limits.
1.1.4 PSD Best Available Control Technology Assessment for Sulfuric Acid Mist(H2SO4)
Emissions of H2SO4 from natural gas-fired combined cycle units result from oxidation of trace quantities
of sulfur in natural gas. Normally, fuel sulfur oxidizes to SO2. A generally small portion of fuel sulfur
may initially oxidize directly to S03 rather than SO2. Also, a portion of the fuel sulfur which initially
oxidizes to SO2 may subsequently oxidize to S03 prior to being emitted. For purposes of emission
calculations,all S03 is assumed to combine with water vapor in the flue gas to form H2SO4.
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of natural gas as the BACT fuel,this is the lowest sulfur content fuel available.
Key considerations in the development of a specific H2SO4 emission rate for a natural gas-fired combined
cycle unit are the sulfur content of natural gas, and the appropriate allowance for oxidation of fuel sulfur
and SO2 to S03. For the sulfur content of natural gas,the Project has used the EPA definition of"pipeline
natural gas" in 40 CFR 72.2. This definition is that pipeline natural gas has a maximum sulfur content of
0.5 grains of sulfur per 100 standard cubic feet (sct). Based on data from GE, up to 5%of the fuel sulfur
is expected to convert directly to S03 in the turbine combustor/duct burners. Then, up to 35% of the
(remaining) SO2 is expected to convert to S03 in passing through the oxidation catalyst, and up to an
additional 5% of the (remaining) SO2 is expected to convert to S03 in passing through the SCR system.
As documented in the Project supplemental data submitted to MassDEP on August 20,2013,the resulting
46
H2SO4 emission rate is 0.0010 lb/MMBtu. This corresponds to a maximum emission rate of 2.3 lb/hr of
H2SO4 per unit.
Pursuant to identifying candidate control technologies under the"top-down"procedure,the Applicant has
compiled all the PSD BACT determinations for H2SO4 in the last five years for new large (> 100 MW)
combustion turbine combined cycle projects. This compilation is based on the USEPA RBLC
(RACTBACT/LAER Clearinghouse). Several recent projects not included in RBLC have also been
included in this compilation. This review confirms that the only H2SO4 BACT technology identified for
large natural gas fired combined cycle turbines is use of clean fuel (i.e., natural gas). There are no cases
where any post combustion controls have been used to control H2SO4 emissions from large natural gas
fired combined cycle turbines..Therefore, the PSD BACT analysis for H2SO4 does not require any
evaluation of alternative control technologies.
The "top-down"procedure does require selection of BACT emission limits. Table 1-2 presents the results
of RBLC compilation for H2SO4. As for PM/PMio/PM25, BACT emissions for H2SO4 can be expressed
either as lb/MMBtu or Ib/hr, or both. Table 1-2 lists 22 projects with PSD BACT limits for H2SO4
approved in the last 5 years,More than half of these projects(13) have H2SO4 limits equal or less stringent
than the Footprint limits discussed above. Of the remaining 9 projects,the lower H2SO4 rates appear to be
due to either unrealistically low assumptions on SO2 to S03 oxidation, low assumed natural gas sulfur
contents, or both. One of the projects listed in Table 1-2 (Panda Sherman) was approved without a CO
oxidation catalyst, which explains the low H2SO4 rate for this project. As noted above, a CO oxidation
catalyst oxidizes some of the SO2 to SO3/H2SO4. However, the other projects in Table 1-2 with lower
H2SO4 rates appear to have assumed a very stringent natural gas sulfur content and/or did not take into
account the unavoidable incremental oxidation of SO2 to S03 from a CO catalyst. Footprint does not
believe it is prudent to ignore the SO2 to S03 oxidation from a CO catalyst,or assume a natural gas sulfur
content lower than EPA's definition for"pipeline natural gas"(0.5 grains of S/100 sco.
In summary, the available evidence clearly indicates that PSD BACT for H2SO4 for combustion turbines
is use of clean low sulfur fuel (e.g., natural gas). The H2SO4 emission calculation needs to allow for a
reasonable variation in the sulfur content of pipeline natural gas, which is outside the control of a given
generation facility, and oxidation of SO2 to SO3 oxidation from a CO catalyst. The Applicant proposes a
H2SO4 limit for the Project (0.0010 lb/MMBtu), which is consistent with recent PSD BACT precedents
which properly account for these variables.
47
Table 1-2. Summary Of Recent H2SO4 PSD BACT Determinations for Large (>100MW) Gas Fi •ed Combined-Cycle Generating Plants
Facility Location Permit Turbine' Emission Limits`
Date Sulfuric Acid Mist(H2SO4)
Carroll County Washington Twp., OH 11/5/2013 2 GE 7FA 0.0012 Ib/MMBtu without DF
Energy 2045 MMBtu/hr/unitplus 566 MMBtu/hr DF 0.0016 Ib/MMBtu with DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens SCC6- Mitsubishi: 0.00041 Ib/MMBtu without DF
Energy 8000H Mitsubishi: 0.00044 Ib/MMBtu with DF
2932 MMBtu/hr/unit plus 300 MMBtu/hr DF Siemens: 0.0006 Ib/MMBtu without DF
Siemens: 0.0007 Ib/MMBtu with DF
Hickory Run New Beaver Twp., PA 04/23/2013 GE7FA, Siemens SGT6-5000F, Mitsubishi 0.92 Ib/hr/unit without DF
Energy LLC M501 G, or Siemens SGT6-8000H. 1.08 Ib/hr/unit with DF
2 combined cycle units Emissions based on Siemens SGT6-8000H
Sunbury Sunbury, PA 04/01/2013 "F Class"with DF 0.0018 Ib/MMBtu
Generation 2538 MMBtu/hr/unit 4.4 Ib/hr/unit without DF
4.7 Ib/hr/unit with DF
Brunswick County Freeman, VA 03/12/2013 3 Mitsubishi M501 GAC with DF 0.00058 Ib/MMBtu without DF
Power Combined GT and DF 0.00067 Ib/MMBtu with DF
3442 MMBtu/hr/unit
Moxie Patriot LLC Clinton Twp, PA 01/31/2013 Equipment type not specified 0.0005 Ib/MMBtu
2-472 or 458 MW combined cycle blocks with
DF
Garrison Energy Dover, DE 01/30/2013 GE 7FA 6.5lb/hr
Center 309 MW
St.Joseph Energy New Carlisle, IN 12/03/2012 4-"F Class" (GE or Siemens) 0.75 grains S/100 scf of natural gas
Center _ 1345 MW total
Hess Newark Newark, NJ 11/01/2012 2-GE 7FA.05 1.36 Ib/hr/unit without DF
Energy 2320 MMBtu/hr/unit plus 211 MMBtu/hr DF 1.33 lb/hr/unit with DF
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 4.8 Ib/hr/unit
Center, LLC 180 MW plus
425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., PA 10/10/2012 Equipment type not specified 0.0002 Ib/MMBtu
2—468 or less MW combined cycle blocks 1.4 Ib/hr for 454 MW block
GT<2890 MMBtu/hr/unit 1.5lb/hr for 468 MW block
DF<3870 MMBtu/hr/unit
Cricket Valley Dover, NY 09/27/2012 3-GE 7FA.05 0.5 grains S/100 scf of natural gas
2061 MMBtu/hr/unit plus 379 MMBtu/hr DF
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 4.89 Ib/hr/unit
Center LLC 180 MW plus
725 MMBtu/hr DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501 GAC 0.0018 Ib/MMBtu
Energy Center 2542 MMBtu/hr/unit; no OF 3.6 Ib/hr
tPVEC)
Thomas C. Llano, TX 09/01/2011 2-GE 7FA 13.68 Ib/hr
Ferguson Power _ 195 MW per unit
No DF
48
Table 1-2. Summary Of Recent H2SO4 PSD BACT Determinations for Large (>100MW) Gas Fi-ed Combined-Cycle Generatinq Plants
Facility Location Permit Turbine' Emission Limits`
Date Sulfuric Acid Mist(H2SO4)
Portland Gen. Morrow, OR 12/29/2010 1 -Mitsubishi M501 GAC 1.5 Ib/MMcf(0.0015 Ib/MMBtu)
Electric Carty Plant 2866 MMBtu/hr
Dominion Warren Front Royal,VA 12/21/2010 3-Mitsubishi M501 GAC 0.00013 Ib/MMBtu without OF
County 2996 MMBtu/hr/unit Dlus 500 MMBtu/hr OF 0.00025 Ib/MMBtu with OF
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE: 3.37 Ib/hr/unit(w/and w/o DF)
Power Station 2430 MMBtu/hr/unit GT plus DF or Siemens: 3.77 Ib/hr/unit(w/and w/o DF)
4 Siemens SGT6-5000F5
2693 MMBtu/hr/unit GT Dlus DF
Live Oaks Power Sterling, GA 03/30/2010 Siemens SGT6-5000F No emission limits specified.
PSD BACT for H2SO4 use of pipeline quality
natural qas with <0.5 qrains S/100 scf
Panda Sherman Grayson, TX 02/03/2010 2 GE 7FA GE: 0.56 Ib/hr/unit(w/and w/o DF)
Power 170 MW/unit plus Mitsubishi: 0.62 Ib/hr/unit(w/and w/o DF)
570 MMBtu/hr DF or
2 Mitsubishi M501G
254 MW/unit plus
230 MMBtu/hr DF
Pattillo Branch Savoy, TX 06/17/2009 4—GE 7FA, GE7FB, or GE: 1.9 Ib/hr/unit(w/and w/o DF)
Power LLC Siemens SGT6-5000F Mitsubishi: 2.0 Ib/hr/unit(w/and w/o DF)
With OF
Entergy Lewis The Woodlands, TX 05/19/2009 2-GE 7FA with 362 MMBtu/hr OF 4.03 Ib/hr/unit
Creek Plant
' DF refers to duct firing
2 Limits obtained from agency permitting documents when not available in RBLC. Short-term emission limits only are provided.
49
1.1.5 Best Available Control Technology Assessment for Greenhouse Gases
Step 1:Identify Potentially Feasible GHG Control Options
In Step 1,the applicant must identify all"available" control options which have the potential for practical
application to the emission unit and regulated pollutant under evaluation, including lower-emitting
process and practices. In assessing available GHG control measures, we reviewed EPA's
RACTBACT/LAER Clearinghouse, the South Coast Air Quality Management District's BACT
determinations, and the Pioneer Valley Energy Center permit information found on the EPA Region 1
website (Pioneer Valley is a recently permitted 431 MW combined cycle turbine project in Westfield,
Massachusetts). EPA stated generally that BACT for the Pioneer Valley project is energy efficient
combustion technology and additional energy savings measures at the facility, if possible. Specifically,
BACT was cited as installation of a combined cycle turbine and GHG emission limits were developed.
For the proposed Project,potential GHG controls are:
1. Low carbon-emitting fuels;
2. Carbon capture and storage(CCS); and
3. Energy efficiency and heat rate.
Step 2: Technical Feasibility of Potential GHG Control Options
Low Carbon-Emittine Fuels
Natural as combustion generates significantly lower carbon dioxide emission rates per unit heat g g gn y p t than
0 0
distillate oil (approximately 27/0 less) or coal (approximately 50% less). Use of biofuels would reduce
fossil-based carbon dioxide emissions, since biofuels are produced from recently harvested plant material
rather than ancient plant material that has transformed into fossil fuel. However, biofuels are in liquid
form, and the Project is not being designed for liquid fuel. In addition, combined cycle turbines have
technical issues with biofuels that have yet to be resolved. It is likely that distillate fuel would need to
have a limited percentage of biofuel added to be feasible. In this case, natural gas would still have lower
fossil-based carbon emissions compared a distillate oil/biofuel mixture. For these reasons, biofuels have
been eliminated from consideration. Therefore, natural gas represents the lowest carbon fuel available for
the Project.
Enerev Efficiencv and Heat Rate
EPA's GHG permitting guidance states,
"Evaluation of [energy efficiency options] need not include an assessment of each and
every conceivable improvement that could marginally improve the energy efficiency of
[a] new facility as a whole (e.g., installing more efficient light bulbs in the facility's
cafeteria), since the burden of this level of review would likely outweigh any gain in
emissions reductions achieved. EPA instead recommends that the BACT analyses for
units at a new facility concentrate on the energy efficiency of equipment that uses the
largest amounts of energy, since energy efficient options for such units and equipment
(e.g., induced draft fans, electric water pumps)will have a larger impact on reducing the
facility's emissions...."
EPA also recommends that permit applicants "propose options that are defined as an overall category or
suite of techniques to yield levels of energy utilization that could then be evaluated and judged by the
50
permitting authority and the public against established benchmarks...which represent a high level of
performance within an industry." With regard to electric generation from combustion sources, the
combined cycle combustion turbine is considered to be the most efficient technology available.Below is a
discussion of energy efficiency and a comparison to other common combustion-based electric generation
technologies.
GHG emissions from electricity production are primarily a function of the amount of fuel burned;
therefore, a key factor in minimizing GHG emissions is to maximize the efficiency of electricity
production.Another way to refer to maximizing efficiency is minimizing the heat rate. The heat rate of an
electric generating unit is the amount of heat needed in BTU (British Thermal Units) to generate a
kilowatt of electricity (kW), usually reported in Btu/kW-hr. The more efficient generating units have
lower heat rates than less efficient units. Older, more inefficient boilers and turbines consume more fuel
to generate the same amount of electricity than newer, more efficient boilers and turbines. This is due to
equipment wear and tear, improved design in newer models as well as the use of higher quality
metallurgy. In general, a boiler-based steam electric unit is less efficient than a combustion turbine
combined cycle unit. This is because the combustion energy from a combustion turbine is directly
imparted onto the turbine blades, and a combined cycle unit then uses the waste heat from the combustion
turbine exhaust to generate additional power,utilizing a HRSG and subsequent steam cycle.
In addition to the efficiency of the electricity generation cycle itself, there are a number of key plant
internal energy sinks (parasitic losses) that can improve a plant's net heat rate (efficiency) if reduced.
Measures to increase energy efficiency are clearly technically feasible and are addressed in more detail in
Step 4 of the BACT process.
Carbon Caoture and Storage
With regard to CCS, as identified by US EPA, CCS is composed of three main components: CO2 capture
and/or compression, transport, and storage. CCS may be eliminated from a BACT analysis in Step 2 if it
can be shown that there are significant differences pertinent to the successful operation for each of these
three main components from what has already been applied to a differing source type. For example, the
temperature, pressure,pollutant concentration, or volume of the gas stream to be controlled, may differ so
significantly from previous applications that it is uncertain the control device will work in the situation
currently undergoing review. Furthermore, CCS may be eliminated from a BACT analysis in Step 2 if the
three components working together are deemed technically infeasible for the proposed source,taking into
account the integration of the CCS components with the base facility and site-specific considerations
(e.g., space for CO2 capture equipment at an existing facility, right-of-ways to build a pipeline or access
to an existing pipeline, access to suitable geologic reservoirs for sequestration, or other storage options).
While CCS is a promising technology, EPA does not believe that at this time CCS will be a technically
feasible BACT option in certain cases.
As identified by the August 2010 Report of the Interagency Task Force on Carbon Capture and Storage
(co-chaired by US EPA and the US Department of Energy), while amine-or ammonia-based CO2 capture
technologies are commercially available, they have been implemented either in non-combustion
applications (i.e., separating CO2 from field natural gas) or on relatively small-scale combustion
applications(e.g., slip streams from power plants,with volumes on the order of what would correspond to
one megawatt). Scaling up these existing processes represents a significant technical challenge and
potential barrier to widespread commercial deployment in the near term. It is unclear how transferable the
experience with natural gas processing is to separation of power plant flue gases, given the significant
differences in the chemical make-up of the two gas streams. In addition, integration of these technologies
with the power cycle at generating plants present significant cost and operating issues that will need to be
addressed to facility widespread,cost-effective deployment of CO2 capture. Current technologies could be
51
used to capture CO2 from new and existing fossil energy power plants; however, they are not ready for
widespread implementation primarily because they have not been demonstrated at the scale necessary to
establish confidence for power plant applications.
Regarding pipeline transport for CCS, there is no nearby existing CO2 pipeline infrastructure (see
Figure 1-1); the nearest CO2 pipelines to Massachusetts are in northern Michigan and southern
Mississippi. With regard to storage for CCS, the Interagency Task Force concluded that while there is
currently estimated to be a large volume of potential storage sites, "to enable widespread, safe, and
effective CCS, CO2 storage should continue to be field-demonstrated for a variety of geologic reservoir
classes" and that "scale-up from a limited number of demonstration projects to widescale commercial
deployment may necessitate the consideration of basin-scale factors (e.g., brine displacement, overlap of
pressure fronts,spatial variation in depositional environments, etc.)".
Based on the abovementioned EPA guidance regarding technical feasibility and the conclusions of the
Interagency Task Force for the CO2 capture component alone (let alone a detailed evaluation of the
technical feasibility of right-of-ways to build a pipeline or of storage sites), CCS has been determined to
not be technically feasible.
Step 3:Ranking of Technically Feasible GHG Control Options by Effectiveness
Based on the results of Step 2, the only option being carried further into the analysis is the evaluation
energy efficiency and heat rate. The Project is already using the lowest carbon fuel and carbon capture
and storage is not currently feasible.
Step 9:Evaluation of Energy Efficiency and Heat Rate
Improvements to energy efficiency and "heat rate" are important GHG control measures that can be
employed to mitigate GHG emissions. Heat rate indicates how efficiently power is generated by
combustion of a given amount of fuel. Heat rate is normally expressed in units of British thermal units
(Btu) combusted per net kilowatt-hour (kw-hr) of energy produced. A higher value of "heat rate"
indicates more fuel (i.e., Btu) is needed to produce a given amount of energy (lower or less favorable
efficiency), while a lower value of heat rate indicates less fuel (i.e., Btu) is needed to produce a given
amount of energy(higher or more favorable efficiency).
The Proposed Project is using advanced combustion turbine combined cycle technology, which is
recognized as the most efficient commercially available technology for producing electric power from
fossil fuels. Improvements to the heat rate typically will not change the amount of fuel combusted for a
given combustion turbine installation, but it will allow more power to be produced from a given amount
of fuel(i.e.,improve the heat rate) so that more GHG emissions will be displaced from existing sources.
Key factors addressed in the evaluation of energy efficiency and heat rate are the core efficiency of the
selected turbines and the significant factors affecting overall net heat rate in combined cycle operating
mode.
52
Figure 1-1. CO2 Pipelines in the United States
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' '(�'''�i4,1:ai ..P;�' '� l: ✓�' NPetro Svuroo
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10
From:"Report of the Interagency Task Force on Carbon Capture and Storage,"August 2010,
Appendix B.
The design basis of the proposed project is to install approximately 630 MW of electric, generation which
is equivalent to two "F" Class turbines in combined cycle configuration. "G" class turbines are slightly
more efficient and thus have a lower heat rate;however,"G"class turbines generate approximately 380 to
400 MW per turbine(or 760 to 800 MW for two turbines). In addition, "G"class turbines generally have
a higher low operating limit (the lowest MW output at which the facility can operate in compliance with
its permits) than the proposed "F" class turbines. Although "G" class turbines are slightly more energy
efficient that the proposed"F" Class turbines, "G"Class turbines would alter the scope of the project due
to their size. The "F" Class design size provides the compatible size match to the existing high voltage
switchyard and electrical interconnection infrastructure associated with the exiting Salem Harbor
Generating Station site. The "F" class design also provides greater operational flexibility and therefore
lower overall emissions. The expected heat rate or efficiency differential between"F"and"G"combined
cycles, comparably configured and equipped is less than 1 percent at ISO conditions, in unfired mode,
when both plants are comparably equipped for quick start-up. When site specific conditions are accounted
for, this apparent efficiency difference between "F" and "G" class machines is further reduced by the
higher parasitic power consumption of the fuel gas compressors for the "G" machines, which require
53
higher natural gas supply pressures compared to "F" class. For these reasons, "G" class machines have
been eliminated from consideration for the Proposed Project.
The advanced generation of"F" class machines have upgraded performance with increased MW output
and improved heat rate compared to prior designs. These machines also represent the current state-of-the-
art for the evolving "F" class technology that is now been in operation for greater than 20 years with
thousands of machines in operation. This provides a conservative and predictable basis to formulate
financial plans and to project future reliability and costs. The steam cycle portion of the plant (HRSG,
piping, & steam turbine generator) as designed with two smaller units in the "I on 1" configuration will
exhibit superior operational flexibility, ability to deal with rapid thermal transients and exhibit acceptable
and foreseeable long term O&M cost impacts.
With regard to energy efficiency considerations in combined cycle combustion turbine facilities, the
activity with the greatest effect on overall efficiency is the method of condenser cooling. As with all
steam-based electric generation, combined cycle plants can use either dry cooling or wet cooling for
condenser cooling. Dry cooling uses large fans to condense steam directly inside a series of piping,
similar in concept to the radiator of a car. Wet cooling can either be closed cycle evaporative cooling
(using cooling towers),or"once-through"cooling using sea water.
Total fuel heat input to the combined cycle combustion turbine (fuel burned in the combustion turbines
and in the HRSG duct burners) and thus total steam flow available to the steam turbine, is fixed. The
efficiency of conversion of the fixed steam flow to electrical output of the steam turbine generator is then
primarily a function of the backpressure at which the low pressure turbine exhausts.A wet cooling system
consisting either of a mechanical draft cooling tower with circulating water pumps and a shell and tube
condenser, or a once-through system directly circulating sea water to the condenser, are capable of
providing significantly lower condensing pressures compared to an all dry ACC system. Wet cooling
performance is superior for efficiency purposes because of the basic thermodynamics of cooling, which
allows either the cooling tower or once through system to produce colder water compared to dry cooling.
As a result, operation of a dry cooling system requires approximately 1-5% more energy than a wet
cooling system depending on ambient conditions (difference between wet and ACC systems gets smaller
with lower ambient temperatures).
However,there are significant drawbacks to either a once-through system or wet mechanical draft cooling
tower system. Once-through cooling involves use of large quantities of sea water that is returned to the
ocean at a higher temperature. The impingement and entrainment associated with intake of the necessary
large quantities of sea water, and the thermal impacts of discharges of once-through cooling, have been
recognized to have negative environmental impacts and once-through cooling has therefore been
eliminated from consideration.
Wet mechanical draft cooling towers also require a significant quantity of water,most of which is lost to
evaporation to the atmosphere. Seawater can potentially be used for makeup to a wet evaporative system,
but this is is a very challenging application. The most likely candidate source for the volumes of cooling
tower makeup water required would be the SESD sewage.treatment plant. It is technically feasible to use
effluent from a public sewerage treatment facility as make-up to a wet, evaporative cooling system.
However the presence of typical chemical constituents in the effluent and the likely highly variable
concentrations of certain of these constituents would place a burden on the Project. The effluent
transferred from SESD would require further treatment to make it suitable and safe to use in the cooling
system. Even after further treatment the concentrations of certain dissolved minerals in the circulating
water would impact the design; most likely require a high degree of cooling tower blowdown to maintain
acceptable chemistry and requiring the upgrade of the metallurgy of the piping, condenser tube, pumps
54
and other components that would be exposed to the more corrosive action of the treated and concentrate
effluent.
An additional burden imposed of wet, evaporative cooling is dealing with the creation of visible fog
plume,which discharges from the cooling tower fans. With the typical New England, coastal site weather
conditions, a standard mechanical draft cooling tower would produce a very visible and persistent plume
for many hours of the year. It is possible to use a so-called "plume abated" mechanical draft tower. But
this feature can double the cost of the cooling tower and increase the total fan power consumption and
pumping head on the system. Basically the "plume abatement" feature works by using heat from the hot
condenser discharge water to preheat additional ambient air admitted above the normal cooling tower wet,
evaporative heat exchange zone. This hotter air has a lower relative humidity; such that as it mixes with
the wet, almost saturated air discharged from the evaporative cooling surface, the combined air mixture
reaches a moisture content below the saturation point. As this hotter, dryer air mixture is discharged by
the tower fans it can then mix with the cool, damp ambient air without crossing the saturation line and
producing small water droplets which form the visible plume.
The bottom line is that a wet, evaporative mechanical draft cooling tower with plume abatement features
has a doubled capital cost, higher fan power consumption and higher pumping head than a standard
cooling tower. These latter two factors greatly reduce any potential benefit from reduced parasitic load
from the wet cooling system.
Therefore, Footprint has determined that the marginal heat rate improvement that could be achieved with
a plume abated mechanical draft tower does not outweigh the drawback of the technical issue associated
with use of the SESD sewage effluent, as well as the fact that a visible plume will still be present at times
with a plume abated tower. The use of dry cooling has therefore been selected over either wet cooling
option.
The Administration Building has been designed to meet the U.S. Green Building Council's Leadership in
Energy and Environmental Design (LEED) at the Platinum level. The Administration Building, as well
as the Operations Building, among various energy conservation features, incorporate green roofs,
geothermal heat pumps for heating and cooling, building energy management systems, and a 10%
reduction in lighting power density.
Step 5:Select BACT
The Project has proposed GHG limits as follows for the combined cycle units:
• Initial test limit of 825 Ib CO2e/MWhr(net to grid),full load, ISO corrected,without duct firing
• Rolling 365-day GHG BACT limit(life of facility)of 895 lb CO2e/MWhr(net to grid)
For purposes of comparison, the initial test GHG limit of 825 lb CO2e/MWhr(net to grid) corresponds to
a "heat rate" of 6,940 Btu HHV/kWhr (net). On a "gross" energy basis, these values are 795 lb
CO2e/MWhr(gross) and 6,688 Btu HHV/kWhr(gross). The rolling 365-day GHG BACT limit of 895 lb
CO2e/MWhr (net to grid)'corresponds to a "heat rate" of 7,521 Btu HHV/kWhr (net). On a "gross"
energy basis,these values are 862 lb CO2e/MWhr(gross)and 7,247 Btu HHV/kWhr(gross).
Note that"gross" energy is based on the full electric energy output of the generation equipment, without
consideration of internal plant loads (parasitic losses such as for pumps and fans). Net energy is based on
the amount of electric energy after internal plant demand is satisfied, and reflects the amount of energy
actually sold to the electric grid.
55
For purposes of comparison with other projects, Footprint's design thermal efficiency is 57.9%. This is .
based on ISO full load operation, without duct firing or evaporative cooling, without any degradation
allowance, and reflects gross energy output fuel energy input based on LHV. This is the most typical way
that thermal efficiency is reported. This is not as meaningful for purposes of GHG BACT limits compared
to measures based on net power production, since those based on net power account for the project
internal energy consumption. Footprint considers the proposed rolling 12-month COZC limit for the life of
the project as the most meaningful limit since it reflects actual long-term emissions, and actual power
delivered to the grid.
Pursuant to supporting these proposed limits consistent with the "top-down" procedure, Footprint has
compiled PSD BACT determinations for GHG in the last five years for new large (> 100 MW)
combustion turbine combined cycle projects. This compilation is based on all entries during this time
period listed in the USEPA RBLC (RACTBACT/LAER Clearinghouse). Several recent projects not
included in RBLC have also been included in this compilation. This review confirms that the only BACT
technology identified for large natural gas fired combined cycle turbines is use of low carbon fuel (i.e.,
natural gas) in high efficiency combined cycle units. There are no cases where any post combustion
controls (carbon capture and sequestration) have been used to control GHG emissions from large natural
gas fired combined cycle turbines.
Table 1-3 presents the results of RBLC compilation for GHG. GHG BACT emissions are expressed in
varying units, including mass emission (tons or pounds per unit time), lb COZe per MWhr, and/or "heat
rate" (Btu/kWhr). The energy-based limits are expressed as either "gross" or"net". Energy units (MWhr
or kWhr) or more meaningful than mass emission limits since they relate directly to the efficiency of the
equipment, which is a key available BACT technology (in addition to low carbon fuel). The mass
emissions are specific to the fuel firing rate of a given project and the carbon content of the fuel, but do
not incorporates the project efficiency.
Table 1-3 lists 15 projects with PSD BACT limits for GHG approved in the last 5 years which have
energy based GHG limits_(The mass limit projects are not considered since they are not meaningful for
GHG BACT comparison). Accounting for the different units for these limits, the Footprint Project
proposed GHG limits are clearly more stringent than most of the energy based limits in Table 1-3. For
limits where this comparison is not clear,the following clarifications are made:
• The basis for Oregon(OH)Clean Energy project limits(840 and 833 lb/MWhr gross)is not clear,
but the context of this actual permit suggests these limits are intended for ISO conditions without
duct firing which makes them less stringent than the Footprint limits.
• The Brunswick County limit of 7,500 Btu/kWhr net atfull load with duct firing does not directly
correspond to either of the Footprint conditions. However, Footprint's limit of 895 Ib
CO2e/MWhr corresponds to a rolling 365-day value of 7,521 Btu/kWhr net which accounts for all
operation on an annual basis including starts, stops, and part load in addition to duct firing.
• The Palmdale project limits of 774 Ib/MWhr and 7,319 Btu/kWhr (source wide net 365 day
average limits)are more stringent than the Footprint limits.However,the Palmdale project is a
56
Table 1-3. Summary Of Recent^=HG PSD BACT Determinations for Larpe (>100MW)Gas Fired Combined-Cycle Generatiny Plants
Emission Limits
Permit Greenhouse Gas(GHG)as CO2e unless otherwise
Facility Location Date Turbine' noted
Carroll County Washington 11/5/2013 2 GE 7FA 859 Ib/MWhr gross at ISO conditions without duct firing
Energy Two., OH 2045 MMBtu/hr/unit plus 566 MMBtu/hr DF
Renaissance Carson City, MI 11/1/2013 4 Siemens 501 FD2 units. 1000 lb/MWhr gross 12-month rolling average
Power I 2147 MMBtu/hr/unit each with 660 MMBtu/hr DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens SCC6-8000H Mitsubishi: 840 Ib/MWhr gross
Energy 2932 MMBtu/hr/unit plus 300 MMBtu/hr OF Siemens:833 Ib/MWhr qross
Green Energy Leesburg, VA 04/30/2013 2 GE 7FA.05 Heat rate of 7,340 Btu HHV/kWhr gross without DF
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr DF or Heat rate of 7,780 HHV Btu/kWhr gross with DF
Stonewall 2 Siemens SGT6-5000F5
2260 MMBtu/hr/unit plus 450 MMBtu/hr DF
Hickory Run New Beaver 04/23/2013 GE7FA, Siemens SGT6-5000F, Mitsubishi M501 G, 3,665,974 tpy both units
Energy LLC Twp., PA or Siemens SGT6-8000H. Emissions based on Siemens SGT6-8000H
2 combined cycle units
Sunbury I Sunbury, PA 04/01/2013 "F Class"with DF 281,727 Ib/hr without OF
Generation 2538 MMBtu/hr/unit 298,106 Ib/hr with DF
Brunswick CountyI Freeman,VA 03/12/2013 I 3'Mitsubishi M501 GAC with DF Heat rate of 7,500 Btu(HHV)/kWhr net;tested at full load
Power Combined GT and OF 3442 MMBtu/hr/unit and corrected to ISO conditions with DF
Garrison EnergyI Dover, DE 01/30/2013 I GE 7FA with DF Heat rate of 7,717 Btu HHV/kWhr net 12-month rolling
Center 309 MW average
St. Joseph Energy New Carlisle, IN 12/03/2012 4-"F Class" (GE or Siemens) Heat rate of 7,646 Btu/kWhr. Further detail not specified
cent 1 1345 MW total
Hess Newark Newark, NJ 11/01/2012 2-GE 7FA.05 887 Ib/MWhr gross 12-month rolling average
Energy 2320 MMBtu/hr/unit plus 211 MMBtu/hr DF Heat rate of 7,522 Btu(HHV)/kWhr; net basis at full load
and corrected to ISO conditions without OF
Channel Energy Houston,TX 10/15/2012 2-Siemens 501 F 920 Ib/MWhr net
Center, LLC 180 MW plus
425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., 10/10/2012 Equipment type not specified 1,368,540 tpy for 454 MW block
PA 2—468 or less MW combined cycle blocks 1,480,086 tpy for 468 MW block
GT<2890 MMBtu/hr/unit
OF<3870 MMBtu/hr/unit
Heat rate of 7,605 Btu HHV/kWhr ISO without DF
Cricket Valley Dover, NY 09/27/2012 3-GE 7FA.05 57.4%design thermal efficiency
2061 MMBtu/hr/unit plus 379 MMBtu/hr DF 3,576,943 tpy all 3 units
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 920 Ib/MWhr net
Center LLC 180 MW plus
725 MMBtu/hr OF
57
Table 1-3. Summary Of Recent^HIG PSD BACT Determinations for Large (>1001AW)Gas Fired Combined-Cycle Generating Plants
Emission Limits`
Permit Greenhouse Gas(GHG)as CO2e unless otherwise
Facility Location Date Turbine' noted
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501 GAC 825 Ib/MWhr net(initial full load test corrected to ISO
Energy Center 2542 MMBtu/hr/unit; no OF conditions)
(PVEC) _ 895 Ib/MWhr net(rollinq 365-day average)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA 774 Ib/MWhr source wide net 365 day rolling average
Power 154 MW(1736 MMBtu/hr)per unit plus (CO2)
500 MMBtu/hr OF Heat rate: 7,319 Btu/kWhr source wide net 365 day rolling
average
Thomas C. Llano,TX 09/01/2011 2-GE 7FA 908,957.6 Whir 30-day rolling average
Ferguson Power 195 MW per unit
No DF
Brockton Power Brockton MA 07/20/2011 1 Siemens SGT6-PAC-5000F 870 Ib CO2e/MWhr monthly average
(MA Plan 2227 MMBtu/hr plus 641 MMBtu/hr DF 842 Ib/MWhr rolling 12-month average
Approval) .. 1,094,900 toy _
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F Heat rate of 7,730 Btu HHV/kWhr
Energy Center 2238.6 MMBtu/hr/unit plus 242 metric tons of CO2e/hr/both units
200 MMBtu/hr OF 5,802 metric tons of CO2e/day/both units
1,928,102 metric tons of CO2e/year/both units
119 Ib CO2e/MMBtu
' OF refers to duct firing
2 Limits obtained from agency permitting documents when not available in RBLC
58
hybrid solar/gas turbine project, and the Palmdale GHG limits appear to account for the solar
energy production component. The Footprint Project's available land and Massachusetts climate
restrictions preclude a solar component which could achieve the Palmdale limits.
• The Brockton(MA)Project was approved for a rolling 12-month CO2 limit of 842 lb/MWbr, and
a monthly maximum of 870 lb/MWhr. The basis for the 842 lb/MWhr limit in the Massachusetts
Plan Application for the Brockton Project is stated to include operation: at a variety of loads,
ambient temperatures, with and without evaporative cooling, and with and without duct firing,
and including starts and stops(Brockton Power Plan Application at page 4-30). However,there is
no mention of any allowance for heat rate (efficiency) degradation over the life of the project or
between major turbine overhauls. This is a significant consideration which renders this value of
842 lb CO2/MWhr as inappropriate as a GHG BACT precedent. Footprint notes that the Brockton
Project has not been constructed,and the 842 lb/MWhr value therefore has not been demonstrated
in practice. In addition,the Footprint notes that the Brockton Project did not specifically undergo
a PSD review for GHG BACT. Footprint also notes that in the Plan Application for the Brockton
Project, it is stated that the 842 lb/MWhr value is based on a CO2 emission factor of 117
Ib/MMBtu. Footprint notes its proposed limit of 895 lb/net MWhr is based on a CO2e emission
factor of 119 lb/MMBtu. Adjusting the Brockton value of 842 Ib/MWhr by 119/117, the
Brockton rate (based on 119 lb CO2/MMBtu) would be 856 Ib/MWhr. In this case, the Footprint
Project value (895 lb/MWhr) is only 4.6% higher than the adjusted Brockton value (856
Ib/MWhr). In addition, the Brockton Project design is based on wet cooling, while the Footprint
Project will use dry cooling. Projects using dry cooling have higher heat rates (are less efficient)
than wet cooled projects, particularly during the summer months. Reasonable allowance for heat
rate (efficiency) degradation over the life of the project and between major turbine overhauls, as
well as the impact of wet vs. dry cooling, explains the proposed GHG BACT for the SHR Project
of 895 lb/net MWhr compared to the proposed Brockton limit.
CLF comments dated November 1, 2013 on the Footprint public review documents indicate that the
Newark Energy Center has a combined cycle mode heat rate limit of 6005 Btu/kWhr, corresponding to a
thermal efficiency of 58.4%. The CLF comments further note that the Russell Energy Center Project in
CA has proposed to achieve a thermal efficiency of 56.4%, and the Cricket Valley Project(NY)proposed
to achieve 57.4% efficiency. These values are taken from a letter written by Steve Riva dated April 17,
2012.
The Newark Energy Center quoted values of 6005 Btu/kWhr and 58.4%thermal efficiency appear to be
preliminary values, since they do not match the actual New Jersey PSD Permit as discussed below. When
comparing heat rate and efficiency values, these may be quoted with varying assumptions, and it is
important to ensure an "apples to apples" comparison is made. The heat rate used to calculate thermal
efficiency is typically specified based on full load ISO operation, no duct firing, gross output, and on an
LHV basis. That is why it is commonly a lower value than "real world" rolling 12-month, net, HHV
values. These two values (6005 Btu/kWhr and 58.4%thermal efficiency) are actually not consistent with
each other, since thermal efficiency is calculated as 3412 Btu/kW-hr/6005 Btu/kW-hr = 56.8% thermal
efficiency. In any event,the"real"numbers for the Newark Energy Center GHG BACT limits in Table 1-
3 are taken from the actual New Jersey PSD permit dated November 1, 2012, so these represent more
recent information for the Newark Energy Center Project. The actual Newark Energy Center permit has
net "heat" rate limit (without duct firing at base load corrected to ISO conditions) of 7,522 Btu/kWhr
based on the Higher Heating Value (HHV) of the fuel. As indicated above, the Footprint Project has a
nearly numerically identical rolling 365-day GHG limit which corresponds to a net heat rate of 7,521
Btu/kWhr, but that reflects all annual operation and not just base load without duct firing. The Newark
Energy Center also has a direct GHG limit of 887 Ib/MWhr, gross basis, rolling 12-month average. The
59
Footprint rolling 365-day GHG limit of 895 lb/MWhr net basis is clearly more stringent than the actual
Newark Energy Center GHG limit.
The Russell Energy Center PSD Permit has a heat rate limit of 7,730 Btu/kW-hr, with the key
assumptions for calculating compliance not specified. In any event,this limit is clearly less stringent than
Footprint's rolling 365-day GHG limit which corresponds to a net heat rate of 7,521 Btu/kWhr.
Footprint's design thermal efficiency of 57.9% is also better than the quoted Russell proposal of 56.4%
(not referenced in the Russell's actual PSD permit).
Cricket Valley's PSD permit does contain the quoted 57.4% thermal efficiency, and well as a heat rate
limit of 7,605 Btu/kW-hr. The Cricket Valley PSD permit indicates this heat rate is at ISO conditions,
HHV without duct firing. Gross or net electric output is not specified.As with Russell,this limit is clearly
less stringent than Footprint's rolling 365-day GHG limit which corresponds to a net heat rate of 7,521
Btu/kWhr. Footprint's design thermal efficiency of 57.9% is also better than the Cricket Valley value
57.4%.
CLF suggests that the GHG limits should also be expressed on a thermal efficiency basis. As stated
above, thermal efficiencies for gas turbines are normally based on the lower heating value (LHV) of the
fuel, on a gross energy basis. The only PSD Permit we identified containing a thermal efficiency value is
the Cricket Valley PSD permit. As MassDEP has done, Footprint concurs it is more appropriate to
propose GHG limits directly as COZe on a net energy basis, accounting for actual emissions of GHG and
overall project efficiency including parasitic plant loads.
In summary,the available evidence clearly indicates that PSD BACT for GHG for combustion turbines is
use of low carbon fuel (e.g., natural gas) in high efficiency combustion combined cycle turbines.
Footprint's proposed GHG limits are as or more stringent than any PSD BACT determinations, except for
a hybrid solar facility, and the Brockton Power Project, which has a rolling 12-month limit which does
not properly account for degradation over the life of the equipment. It is concluded that Footprint's
proposed GHG limits represent PSD BACT.
1.1.6 Combustion Turbine Startup and Shutdown BACT
This section supplements the PSD BACT analysis for the combustion turbine startup and shutdown
(SUSD) limits. Combustion turbine combined cycle units require warm up time to achieve proper
operation of the dry-low NO,combustors discussed above, and also to achieve system warm-up to allow
proper function of the SCR catalysts. Combustion turbine combined cycle units require higher mass
emission limits during SUSD operations for NO., CO and VOC. Since CO and VOC are not subject to
PSD review, this SUSD BACT assessment only addresses NO.. The other pollutants subject to PSD
review are PM/PM10/PM25, 112SO4, and GHG, as these pollutants have lower mass emissions than for
normal operation and thus are not included in this PSD SUSD BACT evaluation. GHG also has the
rolling 12-month limit(lb/MWhr)encompassing all operation including SUSD.
This evaluation does not identify and discuss each of the five individual steps of the "top-down" BACT
process, since the only available control for SUSD are procedures to warm up the systems and begin
operation of the temperature-dependent emission control systems as quickly as practical, consistent with
all system constraints. The Project incorporates new "quick start" technology which minimizes SUSD
emissions significantly compared to prior startup procedures in widespread use. Table 1-4 presents the
proposed NOx SUSD BACT limits for the Project:
60
Table 14. Combustion Turbine NOx SUSD PSD BACT Limits
Pollutant Startup(Ib/event) Shutdown(Ib/event)
NOx 89 10
In addition to these limits, the Project has a limit for startup duration of< 45 minutes and for shutdown
duration of<27 minutes. Also, the project is required to begin SCR operation (inject ammonia) as soon
as the systems attain the minimum temperatures as specified by the control equipment system vendors,
and other system parameters are satisfied for SCR operation.
As part of the review of these proposed NO, SUSD BACT limits under the "top-down" procedure,
Footprint has compiled all the NO, SUSD PSD BACT determinations in the last five years for new gas'
fired large (> 100 MW) combustion turbine combined cycle projects. This compilation is presented in
Table 1-5. This compilation is based on the USEPA RBLC (RACT/BACT/LAER Clearinghouse).
Several recent projects not included in RBLC have also been included in this compilation. This review
confirms that the only SUSD NO,BACT technologies identifiedare procedures to warm up the systems
and begin operation of the SCR as quickly as practical consistent with other constraints. Table 1-5
contains 28 new large (> 100 MW) combustion turbine combined cycle projects with NO, SUSD PSD
BACT determinations. These limits are generally expressed as either lb/hr or lb/event. Some units do not
have numerical SUSD limits for NO.,but only requirements to minimize SUSD emissions.
For purposes of comparing the Project limits to determinations only expressed in lb/hr, Footprint's worst
case ]b/hr is calculated as 45 minutes for a cold start (at 89 pounds) plus 15 minutes at full load
(18.1 lb/hr)/4 = 93.5 lb/hr. Also, while the Project's proposed NO, SUSD limits for a start are only for a
worst-case cold start, for comparison purposes the Project's values for a warm and hot start, as provided
in the August 6,2013 Application Supplement,are 54 and 28 pounds,respectively.
All the NO, SUSD BACT limits in Table 1-5 are less stringent than the Footprint limits, except for the
warm start limits at two CA projects (Palmdale and Victorville), and startup/shutdown limits for the
Brockton MA Project. Palmdale and Victorville each have the same limit for a warm and hot start of 40
lbs/event, while the Footprint values are 54 lbs for a warm start and 28 lbs for a hot start. It is logical that
a warm start would have higher emissions than a hot start,and the average of the two Footprint values(54
lbs and 28 lbs)is 41 lbs/event, effectively identical to the Palmdale and Victorville value.
The Brockton project is based on a"quick start" Siemens SGT6-PAC-5000F combined cycle installation,
and has approved SUSD limits of 31.6 lb/hr(startup)and 29.8 lb/hr(shutdown).The startup time is stated
as 0.47 hours and the shutdown time is 0.40 hours.Thus,the lb/event values are calculated as 14.9 pounds
for a start and 11.9 pounds for a shutdown. Footprint did consider a very similar Siemens turbine
subsequent to the approval data of the Brockton permit, and this more recent data for the same basic
"quick start" Siemens machine (5000F) now has 83 lbs NO,over 45 minutes. For a combined cold start
and shutdown, Footprint now has (89 +10 = 99) lbs NO, while the Siemens data provided to Footprint
reflects(83 +20= 103)lbs NO.. GE has lower NO,emissions for both the warm and hot start. So, based
on the latest information, there is no advantage to selecting Siemens over GE for NO. startup/shutdown
emissions based on more recent data.
61
Table 1-5. Summary Of Recent NOx SUSD BACT Determinations for Large (>100MW) Gas Fired Combined-Cycle Generatinq Plants
Emission Limits`
Permit SUSD NOx
Facility Location Date Turbine' (values are for a single unit at multiple unit facilities)
Carroll County Washington 11/5/2013 2 GE 7FA Cold Start:476 lbs/event
Energy Twp., OH 2045 MMBtu/hr/unit plus 566 MMBtu/hr Warm Start: 290 lbs/event
DF Hot Start: 160 lbs/event
Shutdown 77 lbs/event
Values calculated from approved Ib/hr and event durations
Renaissance Carson City, MI 11/1/2013 4 Siemens 501 FD2 units 176.9 Whir SU and 147.3 Whir SD
Power 2147 MMBtu/hr/unit each with 660 _
MMBtu/hr DF -
Langley Gulch Payette, ID 08/14/2013 1 -Siemens SGT6-5000F 96 ppm; 3 hr rolling average
Power 2134 MMBtu/hr/unit with 241.28 (for the amount of fuel firing during SUSD for a GE 7FA, 96
MMBtu/hr DF ppm corresponds to approximately 450 lbs over a 45 minute
quick start)
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens Mitsubishi: Cold Start: 108.9 lbs/event
Energy SCC6-8000H Warm Start: 86 lbs/event
2932 MMBtu/hr/unit plus 300 MMBtu/hr Hot Start:47.2 lbs/event
DF Shutdown: 35 lbs/event
Siemens:—Cold Start: 188 lbs/event
Warm Start: 126 lbs/event
Hot Start: 108 lbs/event
Shutdown: 46 lbs/event
Values calculated from approved Ib/hr and event durations
Green Energy Leesburg,VA 04/30/2013 2 GE 7FA.05 Minimize emissions, No numeric limits
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr
Stonewall DF or
2 Siemens SGT6-5000F5
2260 MMBtu/hr/unit plus 450 MMBtu/hr
DF
Brunswick County Freeman,VA 03/12/2013 3 Mitsubishi M501 GAC with DF Minimize emissions, No numeric limits
Power Combined GT and DF
3442 MMBtu/hr/unit
Garrison Energy Dover, DE 01/30/2013 GE 7FA Cold Start/: 500 lbs/event
Center 309 MW Warm/Hot Start/: 200 lbs/event
Shutdown: 23 lbs/event
St.Joseph Energy New Carlisle, IN 12/03/2012 I 4-"F Class"(GE or Siemens) 443 Ib/event
Center 1 1345 MW total -
Hess Newark Newark, NJ 11/01/2012 I 2-GE 7FA.05 Cold Start: 140.6 lbs/event
Energy Center 2320 MMBtu/hr/unit plus 211 MMBtu/hr Warm Start: 96.8 lbs/event
DF Hot Start: 95.2 lbs/event
Shutdown: 25 lbs/event
62
Table 1-6. Summary Of Recent JOx SUSD BACT Determinations for Large (>100MW) Gas Fired Combined-Cycle Generating Plants
Emission Limits`
Permit SUSD NOx
Facility Location Date Turbine' (values are for a single unit at multiple unit facilities)
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 350 Ib/hr
Center, LLC 180 MW plus
425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., 10/10/2012 Siemens"H Class" No SUSD listed in RBLC
PA 2—468 or less MW combined cycle
blocks
GT<2890 MMBtu/hr/unit
DF<3870 MMBtu/hr/unit _ _
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 350 Ib/hr
Center LLC 180 MW plus
725 MMBtu/hr DF
ES Joslin Power Calhoun, TX 09/12/2012 3-GE 7FA 99.9 Ib/hr
195 MW per unit
No DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501GAC 62 Whir
Energy Center 2542 MMBtu/hr/unit; no DF (310 lbs/event for cold start)
(PVEC) (124 lbs/event for warm start
(62 lbs/event for shutdown)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA Cold Start: 96 lbs/event
Power 154 MW(1736 MMBtu/hr)per unit plus Warm/Hot Start:40 lbs/event
500 MMBtu/hr DF __Shutdown: 57 lbs/event
Thomas C. Llano, TX 09/01/2011 2-GE 7FA 111.56 Ib/hr
Ferguson Power 195 MW per unit
No DF
Entergy Ninemile Westwego, LA 08/16/2011 Vendor not specified No SUSD in RBLC
Point Unit 6 Sinqle unit 550MW
Brockton Power Brockton MA 07/20/2011 (MA 1 Siemens SGT6-PAC-5000F Start: 31.6 Ib/hr
Plan Approval) 2227 MMBtu/hr Dlus 641 MMBtu/hr DF ___ _ Shutdown: 29.8 Ib/hr
Avenal Power Avenal, CA 05/27/2011 2-GE 7FA Each unit: 160 Ib/hr
Center 1856.3 MMBtu/hr/unit plus 562.26 Both units:240 Ib/hr
MMBtu/hr DF
Portland Gen. Morrow, OR 12/29/2010 1 -Mitsubishi M501 GAC 150 Ib/hr;3-hr rolling average
Electric Carty Plant 2866 MMBtu/hr
Dominion Warren Front Royal,VA 12/21/2010 3-Mitsubishi M501 GAC Minimize emissions, No numeric limits
County 2996 MMBtu/hr/unit plus 500 MMBtu/hr
____ OF __ ___ _
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE: 216 Ib/hr/unit
Power Station 2430 MMBtu/hr/unit GT plus DF or Siemens:220 Ib/hr/unit
4 Siemens SGT6-5000F5
2693 MMBtu/hr/unit GT Dlus DF _
Live Oaks Power Sterlinq, GA 03/30/2010 Siemens SGT6-5000F Minimize emissions, No numeric limits
63
Table 1-5. Summary Of Recent JOx SUSD BACT Determinations for Large(>100MW)Gas Fired Combined-Cycle Generating Plants
Emission Limits`
Permit SUSD NOx
Facility Location Date Turbine' (values are for a single unit at multiple unit facilities)
Victorville 2 Hybrid Victorville, CA 03/11/2010 2 GE 7FA Cold Start: 96 lbs/event
154 MW per unit plus Warm/Hot Start:40 lbs/event
424.3 MMBtu/hr DF Shutdown: 57 lbs/event
Stark PowerANolf Granbury, TX 03/03/2010 2 GE 7FA GE:420 Ib/hr/unit
Hollow 170 MW/unit plus Mitsubishi: 239 Ib/hr/unit
570 MMBtu/hr DF or
2 Mitsubishi M501
254 MW/unit plus
230 MMBtu/hr DF
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F Cold Start: 480 lbs/event/unit
Energy Center 2238.6 MMBtu/hr/unit plus Warm Start: 125 lbs/event/unit
200 MMBtu/hr DF Hot Start:.95 lbs/event/unit
Shutdown:40 lbs/eve nt/u n i t
Panda Sherman Grayson, TX 02/03/2010 2 GE 7FA or GE: 242 Ib/hr/unit
Power 2 Siemens SGT6-5000F Mitsubishi: 148.5 Ib/hr/unit
with 468 MMBtu/hr/unit DF
Lamar Power Paris, TX 06/22/2009 4-GE 7FA with 200 MMBtu/hr DF No SUSD limits in RBLC or TX permit
Partners II LLC
Pattillo Branch Savoy, TX 06/17/2009 4—GE 7FA, GE7FB, or 650 Ib/hr/unit(each option)
Power LLC Siemens SGT6-500017
With DF
Entergy Lewis The 05/19/2009 2-GE 7FA with 362 MMBtu/hr DF 200 Ib/hr
Creek Plant Woodlands, TX
DF refers to duct firing: `Short-term i.mits only. Limits obtained from agency permitting documents when not available in RBLC.
64
PVEC does have a somewhat more stringent NO, SUSD BACT limit on an hourly basis (62.0 lbs per
hour) compared to the equivalent Footprint lb/hr value of 93.5 lbs/hr.However, PVEC has longer startup
and shutdown times, with up to 5 hours for a cold start, 2 hours for a warm start, and 1 hour for a
shutdown. On a pound per event basis,PVEC has greater SUSD emissions compared to Footprint.
Footprint will achieve the lowest practical emissions achievable for SUSD, and the proposed PSD permit
allows the MassDEP to reset the SUSD BACT limits if different values are demonstrated to be
achievable.
1.2 Auxiliary Boiler
This section supplements the PSD BACT analysis for the auxiliary boiler to address public comments
made on the draft permit documents. The Project is subject to PSD review for NO., PM/PMIo/PM2.5,
H2SO4, and GHG, and thus the auxiliary boiler is subject to PSD BACT for these pollutants.
The Project includes an 80 MMBtu/hr auxiliary boiler that will have natural gas as the only fuel of use.
Table 1-6 presents the proposed BACT limits for the auxiliary boiler for pollutants subject to PSD review.
Table 1-6. Auxiliary Boiler Proposed PSD BACT Limits
Pollutant Emission Limitation Control Technology
NOx 9 ppmvd at 3%02 Ultra Low NOx Burners(9 ppm)
0.011 lbs/MMBtu Good combustion practices
PM/PM10/PM25 0.005 lbs/MMBtu I Natural gas
H2SO4 0.0009 lbs/Ml Natural Gas
GHG as CO2e 119.0 lb/MME tu Natural Gas
(Jote:the H2SO4 value is revised to reflect the inclusion of a CO oxidation catalyst)
In order to inform the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for auxiliary boilers at new large (> 100 MW) combustion turbine combined cycle
projects. This compilation is based on the USEPA RBLC (RACTBACT/LAER Clearinghouse). Several
recent projects not included in RBLC have also been included in this compilation.Table 1-7 provides this
compilation.Table 1-7 will be referred to in the individual pollutant discussion below.
1.2.1 Fuel Selection
Step 1:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible.
Step 3:Rank Control Technologies by Control Effectiveness
Natural gas boilers can achieve lower emissions compared to ULSD.
Step 4.Evaluate Controls
Footprint has chosen the lowest emitting fuel for the auxiliary boiler, natural gas. Therefore, a detailed
evaluation of alternate fuels is not required.
Step 5:Select BACT
Natural gas is proposed as the BACT fuel for the auxiliary boiler.
65
Table 1-7. Summary Of Recent PSD BACT Determinations for Natural Gas Auxiliary Boilers at Large (>100MW)Gas Fired Combined-Cycle
Gererating Plants for NO., PM, H2SO4, GHG
Auxiliary Emission Limits'(Ib/MMBtl,except where noted)
Permit Boiler Size
Facility Location Date MMBtu/hr NOx PM/PM10/PM2.5 H2SO4 GHG
Carroll County Washington 11/5/2013 99 0.02 0.008 0.00022- 26,259.76 tpy
Energy Two., OH
Renaissance Carson City, 11/1/2013 (2)-40 0.035 0.005 — 11,503.7 tpy(both
Power MI units)
Oregon Clean Oregon, OH 06/18/2013 99 0.02 0.008 0.00011 11,671 tpy
Energy
Green Energy Leesburg, 04/30/2013 75 9 ppmvd at 3% 02 Pipeline natural gas<0.1 — Pipeline natural
Partners/ VA (=0.011 Ib/MMBtu) gr S/100scf gas
Stonewall
Hickory Run New Beaver 04/23/2013 40 0.011 0.005 0.0005 13,696 tpy
Energy LLC Twp., PA
Sunbury Sunbury, PA 04/01/2013 Not provided 0.036 0.008 — —
Generation (repowered
unit)
Brunswick Freeman, 03/12/2013 66.7 9 ppmvd at 3%02 Pipeline natural gas<0.4 Pipeline natural gas< Pipeline natural
County Power VA (=0.011 Ib/MMBtu) qr S/100scf 0.4 qr S/100scf qas
St. Joseph New 12/03/2012 (2)-80 0.032 0.0075 — 81,996 tpy; 80%
Enerqy Center Carlisle, IN efficiency
Hess Newark Newark, NJ 11/01/2012 66.2 0.66 lb/hr 0.33 Ib/hr 0.006 Ib/hr 7,788 Ib/hr
Energy Center (based on 0.010 (based on 0.005 (=0.0001 Ib/MMBtu at
Ib/MMBtu) Ib/MMBtu) full load)
Channel Energy Houston, TX 10/15/2012 (3)-430 21.6 Ib/hr/unit 7.8 Ib/hr/unit 1.0 Ib/hr/unit —
Center, LLC (=0.05 Ib/MMBtu at full (=0.018 Ib/MMBtu at full (=0.002 Ib/MMBtu at full
load) load) load)
Cricket Valley Dover, NY 109/27/2012 I 60 0.011 0.005 — —
Pioneer Valley Westfield, 04/05/2012 21 - 0.029 0.0048 0.0005 --
Energy Center MA
(PVEC)
Palmdale Hybrid Palmdale, 10/18/2011 110 9 ppmvd at 3%02 0.33 Whir — Annual tuneup
Power CA (=0.011 Ib/MMBtu) (=0.003 Ib/MMBtu at full
load)
Entergy Nine- Westwego, 108/16/2011 I 338 — 7.6 Ib/MMscf — 117 Ib/MMBtu
mile Point Unit 6 LA (=0.0076 Ib/MMBtu)
Brockton Power Brockton 07/20/2011 60 0.011 0.01 — —
MA (MA Plan
ADDroval)
66
Table 1-7. Summary Of Recent PSD BAST Determinations for Natural Gas Auxiliary Boilers at Large (>100MW)Gas Fired Combined-Cycle
Gererating Plan`s for NO., P N, H2SO4, GHG
Auxiliary Emission Limits' (Ib/MMBtr except where noted)
Permit Boiler Size
Facility Location Date MMBtu/hr NOx PM/PM10/PM2.5 H2SO4 GHG
Avenal Power Avenal, CA 05/27/2011 37.4 9 ppmvd at 3%02 0.34 grains S/100 dscf — --
Center (=0.011 Ib/MMBtu) and pipeline quality gas
Portland Gen. Morrow, OR 12/29/2010 91 50 Ib/MMscf 2.5 Ib/MMscf — —
Electric Carty (=0.05 Ib/MMBtu) (=0.0025 Ib/MMBtu)
Plant
Dominion Front Royal, 12/21/2010 88.1 0.011 Ib/MMBtu 0.44 lb/hr — —
Warren County VA (=0.005 Ib/MMBtu at full
load)
Pondera/King Houston, TX 08/05/2010 (2)-45 0.45 Ib/hr/unit 0.32 Ib/hr/unit — —
Power Station (=0.01 Ib/MMBtu at full (=0.007 Ib/MMBtu at full
load) load)_
Victorville 2 Victorville, 03/11/2010 35 9 ppmvd at 3%02 0.2 grains S/100 dscf and — --
Hybrid CA (=0.011 Ib/MMBtu) pipeline auality gas
Stark Granbury, 03/03/2010 142 1.42 lb/hr/unit 1.06 lb/hr/unit — --
Power/Wolf TX (=0.01 Ib/MMBtu at full (=0.0075 Ib/MMBtu at full
Hollow load) load)
Panda Sherman Grayson,TX 02/03/2010 53 0.53 Ib/hr/unit 0.53 Ib/hr/unit — —
Power (=0.01 Ib/MMBtu at full (=0.01 Ib/MMBtu at full !i
load) load)
Pattillo Branch Savoy, TX 06/17/2009 (4)-40 1.4 Ib/hr/unit 0.3 Ib/hr/unit -- —
Power LLC (=0.01 Ib/MMBtu at full (=0.0075 Ib/MMBtu at full
load) load)
'Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC
67
1.2.2 NOx
Step 1:Identify Candidate Control Technologies
• Selective Catalytic Reduction
• Ultra-Low NOx burner
• Low NOx burner,typically with flue gas recirculation
Step 2:Eliminate Infeasible Technologies
All these technologies are technically feasible, although application of SCR is unusual for natural gas
boilers in this size range.
Step 3:Rank Control Technologies by Control Effectiveness
The ranking of these technologies is as follows:
1. SCR: Demonstrated to have achieved less than 5.0 ppmvd NO, at 3% 02 for gas fired boilers.
Can be used as supplemental control with a low NO,burner but not demonstrated with an ultra-
low-NO,burner.
2. Ultra-Low NOx burner: Demonstrated to have achieved 9 ppmvd NO,at 3%02
3. Low NOx burner, typically with flue gas recirculation: Generally recognized to achieve
30 ppmvd NO,at 3%OZ.
Step 4:Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-8. The capital cost estimate for an SCR system
and an ultra-low NO, burner are based on information provided by Cleaver Brooks. The SCR has been
conservatively assumed to control 90% of the potential NO, emissions (to 3 ppmvdc at 3% 02) even
though 5 ppmvdc has been approved in past projects. Control to this NO,level is likely to correspond to
an ammonia slip level of 10 ppm at 3% 02. Table 1-8 indicates that the average and particularly the
incremental cost effectiveness of an SCR are excessive, at over $19,000 per ton for average cost of
control, and nearly $70,000 per ton on an incremental basis. The ultra-low-NOx burner is cost effective
and is the proposed BACT. There are no energy or environmental issues with ultra-low NO,burners that
would indicate selection of SCR as BACT,given the unfavorable SCR economics.
Step 5:Select BACT
With respect to NO,the lowest limit identified for any of the power plant auxiliary boilers in Table 1-7 is
consistent with the standard guarantee for ultra-low-NOx burners, which is 9 ppmvd at 3% OZ. This
corresponds to 0.011 lb/MMBtu. There are several boilers with BACT limits for NOx in lb/hr calculated
with 0.01 rather than 0.011 Ib/MMBtu, but this is considered effectively the same limit at full load and is
actually less stringent at part-load, since the limits expressed as 9 ppmvd at 3%02/0.011 lb/NMtu apply
throughout the load range. The Project auxiliary boiler meets this most stringent limit found for natural
gas-fired auxiliary boilers at new large (> 100 MW) combustion turbine combined cycle projects.
68
Table 1-8. Summary of Auxiliary Boiler Top-D)wn BACT Analysis for NOx
NOx Emissio is Econor iic Impacts Environmental Impacts
Emissions Installed Total Energy
Control Reduction Capital Annualized Incremental Impacts Toxics Adverse
Alternative ppmvd @ Tons per Compared Cost Cost Average Cost Cost (compared Impacts Environmental
3%02 year(tpy) to Baseline (differential (differential Effectiveness Effectiveness
to
(Yes/No) Impacts
(ase over over baseline) (Yes/No)
baseline) baseline)
SCR 3 0.95 8.51 $414,750 $162,668 $19,115 $69,786 Small Yes No
ULN 9 2.89 6.57 $134,400 $27.283 $4,153 — negligible No No
LN 30 9.46 — — — — —
(baseline)
SCR—Selective Catalytic Reduction
ULN—Ultra low-NOx burner
LN—Low NOx burner
See Appendix A, Calculation Sheets 8 and 9, for calculation of cost values.
69
1.2.3 PM/PMso/PM2.5
For PM/PMIo/PM2,5,this evaluation does not identify and discuss each of the five individual steps of the
"top-down" BACT process, since there are no post-combustion control technologies available for
PM/PMIo/PM25. The "top-down" procedure does require selection of BACT emission limits, which is
addressed in the following paragraphs.
Table 1-7 presents the review of BACT precedents for auxiliary boilers. With respect to PM/PMIo/PM2,5,
for limits expressed in mass units (lb/MMBtu or lb/hr converted to lb/MMBtu at full load), only two of
the auxiliary boilers listed in the Table 1-7 have PM/PMI0/PM25 limits that are more stringent than the
Project auxiliary boiler limit of 0.005 lb/MMBtu. One of these boilers is at the Palmdale Hybrid Power
facility,with a limit of 0.33 lb/hr,which corresponds to 0.003 lb/MMBtu at full load. However, this lb/hr
limit could be met by reducing the boiler load, if the actual emissions exceed 0.003 lb/MMBtu. So at
lower loads it is actually less stringent than the Project limit of 0.005 lb/MMBtu, which applies
throughout the load range. The other boiler listed in the RBLC with a lower lb/MMBtu emission limit is
at the Portland (OR) General Electric Carty Plant. This limit of 2.5 lb/MMcf of natural gas (which
corresponds to 0.0025 lb/MMBtu) is considered unrealistically low for a guarantee for a boiler of this
type. This is because of uncertainty and variability with available PM/PMIo/PM2.5 test methods, and the
risk of artifact emissions resulting in a tested exceedance. All new gas-fired boilers,properly operated,are
expected to have intrinsically low PM/PMIo/PM2.5 emissions. A limit of 0.005 lb/MMBtu is within the
range of recent PSD BACT levels and is justified as PSD BACT.
Several of the boilers listed in Table 1-7 have PM/PMIo/PM25 PSD BACT limits expressed as the sulfur
content of the natural gas. These values range from 0.1 grains/100 scf to 0.4 gains/100 scf. All of these
values are lower than what USEPA defines as the maximum sulfur content of pipeline natural gas
(0.5 grains/100 scf). The Applicant does not believe it is prudent to assume a natural gas sulfur content
lower than EPA's definition for pipeline natural gas. Therefore, these sulfur limits for PM/PMi0/PM2.5
PSD BACT limits are not appropriate.
1.2.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content.Based
on the selection of natural gas as the BACT fuel, this is the lowest sulfur content fuel suitable for the
auxiliary boiler.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 40%molar conversion of fuel sulfur to H2SO4. This is because Footprint has incorporated a CO
oxidation catalyst to reduce CO emissions. One of the collateral impacts of this oxidation catalyst is an
increase in H2SO4 emissions. With respect to H2SO4, none of the 6 of the projects in Table 1-7 with
numeric H2SO4 limits have oxidation catalysts. Therefore,the proposed Project limit is less stringent than
5 of these 6 limits. The proposed Project limit of 0.0009 lb/MMBtu H2SO4 is justified as PSD BACT with
the addition of a CO catalyst.
1.2.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT.
70
With respect to GHG, most of the auxiliary boilers listed in Table 1-7 with GHG limits for PSD BACT
are expressed as a mass emission value, which is a project specific number reflecting the particular size
and gas throughput limits of the specific project unit.For its proposed GHG limit for the Auxiliary Boiler,
the Project has chosen a conservative value based on the USEPA Part 75 default emission factor (119
lb/MMBtu). Another unit listed in the RBLC has an 80% efficiency specified in addition to an annual
mass limit. This is the only auxiliary boiler approved with this type of limit. The Project will install an
auxiliary boiler with a nominal efficiency of 83.7%. The Applicant proposes a GHG PSD BACT limit
expressed in the units of lb/MMBtu(119 lb/NffvIBtu)as most appropriate PSD BACT limit.
1.3 Emergency Diesel Generator
This section supplements the PSD BACT analysis for the emergency diesel generator to address public
comments made on the draft permit documents. The Project•is subject to PSD review for NO.,
PM/PMIO/PM2.5, H2SO4, and GHG, and thus the emergency diesel generator is subject to PSD BACT for
these pollutants.
The Project includes a 750 kW emergency diesel generator that will have ultra-low sulfur diesel (ULSD)
as the only fuel of use. Table 1-9 presents the proposed BACT limits for the emergency diesel generator
for pollutants subject to PSD review.
Table 1-9. Emergercy Diesel Generator Proposed PSD BACT Limits
Pollutant Emission Limitation Emission Limitation
(grams/kWhr) (grams/hphr)
NOx 6.4 4.8
PM/PM10/PM2.5 0.20 0.15
H2SO4 0.0009 Ib/hr(0.00012 Ib/MMBtu)
GHG as CO2e 162.85 Ib/MMBtu
The proposed PSD BACT limits for NO,and PM/PMIO/PM2 5 are based on compliance with the EPA New
Source Performance Standards (NSPS), 40 CFR 60 Subpart IIII. For a 750 kW engine, Subpart IIII
requires what is referred to as a Tier 2 engine. For H2SO4, the PSD BACT limit is based on use of ultra-
low sulfur diesel (ULSD) fuel, and conversion of 5% of the fuel sulfur on a molar basis to H2SO4. The
GHG limit is based on EPA emission factors for ULSD.
In order to inform the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for emergency generators at new large(> 100 MW)combustion turbine combined cycle
projects. This compilation is based on the USEPA RBLC (RACT/BACT/LAER Clearinghouse). Several
recent projects not included in RBLC have also been included in this compilation. Table 1-10 provides
this compilation. Review of Table 1-10 indicates that only one emergency generator is fired with natural
gas, and all the others are fired with ULSD. The gas-fired engine, at Avenal Power Center in CA, does
have SCR to control NOx. All other emergency generators in Table 1-10 do not have any post
combustion controls for PSD pollutants. Table 1-10 will be referred to in the individual pollutant
discussion below.
71
Table 14 0.Summary Of Recent PSD BACT Determinations for Emergency Generators at Large(>100MW) Gas Fired Combined-Cycle
Generating Plants for NO,,, PM, H,SO,, GHG
Facility Location Permit Emergey Emission Limits'
Date Gem
a
r
atoncr Size NOx I PM/PM10/PM2.5 H2SO4 GHG
Carroll County Washington 11/5/2013 1112 kW Subpart IIII 0.000132 433.96 tpy
Energy Twp., OH qrams/kWhr
Renaissance Carson City, 11/1/2013 (2)—1000 kW —
Power MI Subpart IIII 1731.4 tpy(both units)
LangPoweley Gulch Payette, ID 08/14/2013 750 kW Subpart IIII
Oregon Clean Oregon, OH 06/18/2013 2250 kW Subpart IIII 877 0.000132
Energy qrams/kWhr tpy(87)
Green Energy Leesburg, 04/30/2013 1500 kW _ Low carbon fuel and
Partners/ VA Subpart IIII
Stonewall efficient operation
Hickory Run New Beaver 04/23/2013 750 kW 6.0 grams/kWhrI 0.25 grams/kWhr -- 80.5 tpy
Enerqy LLC Twp., PA
Brunswick Freeman, 03/12/2013 2200 kW Subpart IIII ULSD Low carbon fuel and
County Power VA p efficient operation
Moxie Patriot Clinton Twp 01/31/2013 1472 hp 4.93 grams/hp-hrI 0.02 grams/hp-hr — _
LLC PA
St.Joseph New 12/03/2012 (2)—1006 hp Subpart IIII — 1186 tpy
Enerqy Center Carlisle, IN
Hess Newark Newark, NJ 11/01/2012 1500 kW Subpart IIII — —
Energy Center p
Moxie Liberty Asylum 10/10/2012 4.93 grams/hp-hr 0.02 grams/hp-hr — _
LLC Two, PA
Cricket Valley Dover, NYI 09/27/12 4 Black Start Subpart IIII — —
EDGs 3000 kW
each
ES Joslin Power I Calhoun, TX 1 09/12/2012 (2)-EDG 14.11 Ib/hr/unit I 0.44 Ib/hr/unit — —
Pioneer Valley Westfield, 04/05/2012 2174 kW
Energy Center MA Subpart IIII
(PVEC)
Power almdale Hybrid I Paallmdale, I 10/18/2011 110 Subpart IIII — --
Thomas C. I Llano,TX09/01/2011 1340 hp 16.52 lb/hr 0.55 Ib/hr — 15,314 Ib/hr 30 day
Ferguson Power (5.5 grams/hp-hr) rolling average
765.7 tpy 365 day
I
rolling average
Entergy Nine- I Westwego, I 08/16/2011 1250 hp - — Subpart IIII -- CO2e 163.6 Ib/MMBtu,
mile Point Unit 6 LA
72
Facility Location Permit Emergency Emission Limits'
Date Generator Size NOx PM/PM101PM2.5 H2SO4 GHG
Avenal Power Avenal, CA 05/27/2011 550 kW natural SCR to 1 gram/hp- 0.34 gram/hp-hr — —
Center gas engine hr
Dominion Front Royal, 12/21/2010 2193 hp Subpart IIII
Warren Countv VA
Pondera/King Houston,TX 08/05/2010 Size not given 26.61 Ib/hr 1.88 Ib/hr — --
Power Station
Brockton Power Brockton 07/20/2011 3-2000 kW each — —
MA (MA Plan 5.45 gm/hp-hr 0.032 gm/hp-hr
Approval)
Victorville 2 Victorville, 03/11/2010 2000 kW Subpart 1111
Hvbnd CA
Stark Granbury, 03/03/2010 750 hp 23.25 Ib/hr 1.65 Ib/hr — —
PowerNVolf TX (14 grams/hp-hr) (1.0 grams/hp-hr)
Hollow
Panda Sherman Grayson, TX 02/03/2010 Size not given 35.24 Ib/hr 0.17 Ib/hr — —
Power
Pattillo Branch Savoy, TX 06/17/2009 Size not given 18.0 Ib/hr 0.5 Ib/hr — —
PowerLLC
'Generators are diesel generators except where noted.
2 Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC.
73
1.3.1 Fuel Selection
Step l:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although use of natural gas is unusual for an emergency
Y
engine.
Step 3:Rank Control Technologies by Control Effectiveness
Natural gas engines can achieve lower emissions compared to ULSD.
Step 4:Evaluate Controls
Normally, for an emergency generator, it is very important to have the fuel supply directly available
without the possibility of a natural gas supply interruption making it impossible to operate the emergency
generator in an emergency. The purpose of the emergency generator is to be able to safely shut the plant
down in the event of an electric power outage. So in order to maintain this important equipment
protection function, ULSD, which can be stored in a small tank adjacent to the emergency generator, is
the fuel of choice. Footprint is not aware of the specific circumstance for the emergency generator fuel
selection at Avenal, but Footprint does not believe a natural gas fired generator for the Salem Project is a
prudent choice.
Step 5.Select BA CT
ULSD is proposed as the BACT fuel for the Project emergency generator.
1.3.2 NO.
Step 1:Identify Candidate Control Technologies
• Selective Catalytic Reduction
• Low NO, engine design in accordance with EPA NSPS, 40 CFR 60 Subpart IIII (Tier 2 engine
for 750 kW unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible,although application of SCR is unusual for an emergency
engine.
Step 3:Rank Control Technologies by Control Effectiveness
SCR can normally achieve 90% remove of NO, emissions, so it is more effective than the Tier 2 engine
design which is based on low-NO, engine design. However, for an emergency generator, if this unit is
used just for short period of test and facility shutdown in an actual emergency, the ability of the SCR to
74
control emissions will be significantly reduced since the engine/SCR takes time to warm up to achieve
good NO,control.
Step 4:Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-11. The capital cost estimate for an SCR
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. The SCR has been conservatively assumed to control 90%of the potential
NO, emissions even though this is unlikely in this application. Table 1-11 indicates that the cost
effectiveness of an SCR is over $33,000 per ton of NO.. This cost is excessive, even if the emergency
generator runs the maximum allowable amount of 300 hours per year(unlikely) and 90%NOx control of
the full potential to emit is achieved.
There are no energy or environmental issues with a Tier 2 generator that would indicate selection of SCR
as BACT, given the unfavorable SCR economics.
Step 5:Select BACT
With respect to the selection of a PSD BACT for NO,for the emergency generator,Table 1-10 indicates
that compliance with Subpart I111 is the most common limit. Several BACT determinations contain
gram/kWhr or gram/hp-hr limits that approximate the Subpart III1 values but do not specifically reference
Subpart I1I1. Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output.
Overall, with the elimination of SCR on economic grounds, the review of other RBLC precedents
supports the selection of Subpart 1II1 compliance as BACT.
1.3.3 PM/PM101PM2.5
Step l:Identify Candidate Control Technologies
• Active Diesel Particulate Filter(DPF)
• Low PM engine design in accordance with EPA NSPS,40 CFR 60 Subpart 1111(Tier 2 engine
for 750 kW unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of a DPF is unusual for an
emergency engine.
Step 3:Rank Control Technologies by Control Effectiveness
An active DPF can achieve up to 85% particulate removal (CARB Level 3), so it is more effective than
the Tier 2 engine design which is based on low-emission engine design.
Step 4:Evaluate Controls
Since a DPF is technically feasible, an economic analysis of the cost effectiveness for emission control
was conducted. This economic analysis is presented in Table 1-12. The capital cost estimate for an active
system is based on information provided by Milton Cat Power Systems. The other factors are from the
75
OAQPS Cost Control Manual. Table 1-12 indicates that the cost effectiveness of an active DPF is over
$600,000 per ton of PM/PMIo/PM2_5. This cost is excessive, even if the emergency generator runs the
maximum allowable amount of 300 hours per year(unlikely).
76
TABLE 1-11 750 KW EMERGENCY GENERATOR
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION-
iia�si:I�te• : : iq.961s: e�allneNga�rols�lynxpM�4o cpi9�os�npgeEuRE�pv}. " . .:" ! %d:
Ch'aaief rtecare+�%FacwricFiFi:::=:::ot8i
Equipment Cost(EC) (Factor) capital Recovery $4o,atsa
a. SCR Capital Cost Estimate(Per Milton Cat) $150,000 Direct Operating Costs
b. Instrumentation(0.10A) Included a. Ammonia $2,256
C. Taxes and Freight (EC'0.05) $7,500 b Operating Labor (01y.(0.5 hr/ahi0)($25.6)hr) $480
C. Maintenance Labor (ML):(O.S hr/shi0)($25.6Ihr) $480
Total Equipment Cost(rEC) $167,600 d Maintenance Materials=Maintenance Labor $480
Direct Installation Costs Total Direct Operating Cost $960
a. Foundation (TEC-0.08) $12,600
b. Erection and Handling (TEC-0.14) $22,050 Catalyst Replacement isnot included since the emergency generator
C. Electrical (TEC-0.04) $6,300 win only operate a maximum of 300 hours in any year
d. Piping (TEC-0.02) $3,150
e. Insulation (TEC-0.01) $1.575
I. Painting (TEC-0.01) $1,575
Total Direct Installation Cost $17,260
Indirect Operating Costs
a. Overhead(60%of OL-ML) $576
b. Property Tax:(TCC'0.01) $2,489
Indirect Installation Costs C. Insurance:(TCC-0.01) $2,489
a. Engineering and Supervision (TEC-0.1) $15,750 d. Administration.(TCC-0.02) $4,977
b. ConsbuctiordField Expanses (rEC'0.05) $7,875
-a Construction Fee (TEC-0.1) $15,750 Total Indirect Operating Cost $10,531
d: Startup (rEC'0.02) $3,150
e. Performance Test ITEC-0.01) $1,575
!Total Annual Cost $52,054
Total Indirect Installation Cost $44,100
lNOx Reduction (tons/yr) 1.57
Total Capital Coat(TCC) $7+16,860
(Cost of Control($/ton-NOx) $33,230
Note 1: Ammonie.cost based on estimated as delivered cost for 19%aqueous ammonia of$0.60 per pound of ammonia,and 12 lbs of NH3 Injected
per pound of Nos removed
77
TABLE 1-12 750 KW EMERGENCY GENERATOR
ECONOMIC ANALYSIS-ACTIVE DIESEL PARTICULATE RLTER
10;yt)eiti::::::::::::::::::::::.:�:::::;:::::::;:�:::�:::::::;:;:;:::�:�:::::::::;:::;:::;:::�:=:::::_::::
:E
PNiriidefene:pb*e4CFReQ8n6 ' fTail: }::: :isi:::::::::b b(i
. . . . . . . - . . . . . . . P° . . EI.PY... .
EFgnt)ajty Fay[¢pi fftijO;NTa4"eQ4P;Fonc1'fY4: ..... ..�. ..........:. .
i
PT+mment Cost(EC) (Factor) Capital Hacovery $PA.11m
a. DPF Capital Cost Estimate(penMmoo Cal) $90,000
b, Iostrumenudon(0.10A) Inducted Direct Operating Comb
c Taxes.nd Freight (EC-0.05) $4,500 a Operalmg Labor (OL).(0.25 M/ahia)($256/hr) -$240
b Maintenance Labor (ML):(0.25 m/shi0)($25.6/hr) $240
Total Equipment Cost(TEC) $94,500 C. Maintenance Materials= Maintenance Labor $240
Direct Installation Costs Total Direct Operating cost $720
Foundation (TEC-0.08) $7.560
b. Erection and Handling (TEC-0.14) $13,230
e. Electrical (TEC-0.04) $3.780 DPF Replacement is not Included since fie emergency generator
d. Piping ITEC-0.02) $1,890 -10 only oPerate a maximum of 300 hams in any year
e. Insulalton (TEC-0.01) $945
L Paineng (TEC-0.01) $945
Total Direct Installation Cost $29,9$0
Indirect Operating Costs
o. Ovedlead(60%of OL+ML) $288
Indirect Installation Costs b. Property,Tmc(TCC-0.01) $1,493
e. Engineering and Supervision (TEC-0.1) $9,450 Insumrrc:(TCC'0.01) $1.493
b. ConslructionlField Expenses (TEC-0.05) $4.725 d. Administration:(TCC-0 02) $2,986
C. Construction Fee (TEC-0:1) $9,450
d. Start up (TEC-0.02) $1.890 Total Indirect Operating Cost
$8,2 0
e. Pedortnance.Test (TEC-0:03) $945
-Total.Indirect Installation Cost $26.460 (Total Annual Cost $31 i318-
Total Capital Coat(TCC) $149,310 IPM Heductlon(tons/Yr) 0.05
ICost of Control($/ton-PM) $614,080
78
- I
There are no energy or environmental issues with a Tier 2 generator that would indicate selection of a
DPF as BACT,given the unfavorable economics.
Step 5.Select BACT
With respect to the selection of a PSD BACT for PM/PMIo/PM2.5 for the emergency generator,
Table 1-10 indicates that compliance with Subpart I1I1 is the most common limit. There are two BACT
determinations for PA projects (Moxie projects) that both have very low PM/PMI0/PM25 limits of
0.02 gram/hp-hr. Footprint suspects that this limit is a mistaken entry for the Subpart III1 value of
0.2 grams/kWhr. Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output. Brockton (MA) also has a very low PM limit, much lower than the Subpart 11I1
requirements. Footprint does not consider a PM limit less than the Subpart I1II requirements to be an
appropriate BACT.
Overall, with the elimination of a DPF on economic grounds, the review of other RBLC precedents
supports the selection of Subpart II11 compliance as BACT.
1.3.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of ULSD as the BACT fuel, this is the lowest sulfur content fuel suitable for the
emergency generator.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 5%molar conversion of fuel sulfur to H2SO4.Most of the emergency generators in Table 1-]0 do
not have an H2SO4 limit. The only numerical limits for H2SO4 identified for an emergency generator are
those for the two recent Ohio PSD permits (Oregon and Carroll County). The limit in each case is
0.000132 grams/kWhr. Both these project are approved with ULSD as the emergency generator fuel.
Conversion of the Footprint limit to grams/kWhr indicates that 5% molar conversion of the fuel sulfur to
H2SO4 yields 0.0005 grams/kWhr, or about 4 times the Ohio limits. Review of the Ohio approvals
indicates this factor is based on an EPA toxics emission factor which apparently allows for a much lower
molar conversion of fuel sulfur to H2SO4. While this factor may be suitable for estimating actual
emissions, Footprint believes this factor is not appropriate for setting an emission limit. Therefore, given
that most agencies do not even regulate emergency generator H2SO4, Footprint believes the PSD BACT
emission rate based on 5%molar conversion of fuel sulfur to H2SO4 is justified as BACT. This 5% molar
conversion of fuel sulfur to H2SO4 is a reasonable upper limit permit limit assumption for fuel combustion
sources that do not have an SCR or oxidation catalyst.
1.3.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT. Given that emergency generators operate so little,
agencies have not required review of generator efficiency as part of GHG BACT.
With respect to GHG, most of the emergency generators listed on the RBLC with GHG limits for PSD
BACT are expressed as a mass emission value,which is a project specific number reflecting the particular
size and gas throughput limits of the specific project unit. Therefore, these GHG equipment-specific
limits are not automatically transferrable as comparable limits for this Project. One unit listed in
Table 1-10 has a lb/MMBtu limit based on ULSD corresponding to 163.6 lb CO2C/MMBtu. For its
79
proposed GHG limit for the emergency generator, the Project has chosen a value based on the USEPA
Part 75 default emission factors (162.85 lb/MvlBtu), incorporating both CO2, C114, and N20. The
Applicant proposes a GHG PSD BACT limit expressed in the units of lb/MMBtu (162.85 lb/MMBtu) as
most appropriate PSD BACT limit.
1.4 Emergency Fire Pump
This section supplements the PSD BACT analysis for the emergency diesel fire pump to address public
comments made on the draft permit documents. The Project is subject to PSD review for NO,
PM/PMIo/PM25, H2SO4, and GHG, and thus the emergency diesel fire pump is subject to PSD PACT for
these pollutants.
The Project includes a 371 hp emergency diesel fire pump that will have ultra-low sulfur diesel (ULSD)
as the only fuel of use. Table 1-13 presents the proposed BACT limits for the emergency diesel fire pump
for pollutants subject to PSD review.
Table 1-13. Emergency Diesel Fire Pump Proposed PSD BACT Limits
Pollutant Emission Limitation Emission Limitation
(gramslkWhr) (gramslhphr)
NOx 4.0 3.0
PM/PM10/PM2s 0.20 0.15
H2SO4 0.0003 Ib/hr(0.00012 Ib/MMBtu)
GHG as CO2e 162.85 Ib/MMBtu
The proposed PSD BACT limits for NO,and PM/PMIo/PM2 5 are based on compliance with the EPA New
Source Performance Standards (NSPS), 40 CFR 60 Subpart IIII. For a 371 hp fire pump engine, Subpart
IIII requires what is referred to as a Tier 3 engine. For H2SO4, the PSD BACT limit is based on use of
ultra-low sulfur-diesel (ULSD) fuel, and conversion of 5% of the fuel sulfur on a molar basis to H2SO4.
The GHG limit is based on EPA emission factors for ULSD.
In order to infonn the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for emergency fire pumps at new large (> 100 M4) combustion turbine combined
cycle projects. This compilation is based on the USEPA RBLC (RACT/BACT/LAER Clearinghouse).
Several recent projects not included in RBLC have also been included in this compilation. Table 1-14
provides this compilation. Review of Table 1-14 indicates that all emergency fire pumps are fired with
ULSD. All emergency fire pumps in Table 1-14 do not have any post combustion controls for PSD
pollutants.Table 1-14 will be referred to in the individual pollutant discussion below.
80
Table 1-14.Summary of Recent PSD BACT Determinations for Reciprocating Fire Pump Engines at Large (>100MW) Gas Fired Combined-
Cycle
Gererating Plants for NO., PM, H2SO4, GHG
Permit Fire Pump Engine Emission Limits'
Facility Location Date Size NOx I PM/PM10/PM2.5 H2SO4 GHG
Carroll County Washington 11/5/2013 400 hp Subpart IIII 0.000132 115.75 tpy
Energy Two., OH qrams/kWhr
Oregon Clean Oregon, OH 06/18/2013 300 hp Subpart IIII 0.000132 87 tpy
Energy qrams/kWhr
Green Energy Leesburg, and
a
Low carbon_ fuel a
Partners/ VA 04/30/2013 330 hp Subpart IIII efficient operation
Stonewall p n
Hickory Run New Beaver 04/23/2013 450 hp 1.9 gm/hp-hr I 0.15 grams/hp-hr 0.00012 33.8 tpy
Energy LLC Two., PA prams/hp-hr
Brunswick Freeman, 03/12/2013 305 hp Subpart IIII ULSD Low carbon fuel and
County Power VA efficient operation
M Cie Patriot Clinton Twp 01/31/2013 460 hp 2.6 grams/hp- I 0.09 grams/hp-hr — —
PA
St.Joseph New 12/03/2012 (2)—371 hp `Subpart IIII — 172 tpy
Energy Center Carlisle, IN
Hess Newark Newark, NJ 11/01/2012 270 hp Subpart 1111 — --
Ene rqv Center
MCie Liberty AAssylum Twp 10/10/2012 Size not given 2.6 grams/hp- I 0.09 grams/hp-hr — —
PA
Cricket Vallev Dover, NY 09/27/2012 460 hp `Subpart IIII — —
ES Joslin Power Calhoun, TX 09/12/2012 Size not given 2.08 Ib/hr I 0.10 Ib/hr — —
Pioneer Valley Westfield, 270 hp
Energy Center MA 04/05/2012 Subpart IIII — —
(PVEC)
Palmdale Hybrid Palmdale, 10/18/2011 182 hp Subpart IIII
Power CA — —
Thomas C. Llano, TX 617 hp 3.81 Ib/hr 0.20 Ib/hr — 7,027.8 Ib/hr 30 day
Ferguson Power 09/01/2011 rolling average
351.4 tpy 365 day rolling
___ average
Entergy Nine- Westwego, 08/16/2011 350 hp — Subpart IIII -- CO2e 163.6 lb/MMBtu,
mile Point Unit 6 LA
Brockton Power Brockton 07/20/2011 100 hp - — —
MA (MA Plan 5.45 gm/hp-hr 0.032 gm/hp-hr
Approval)
81
Permit Fire Pump Engine Emissir:r Limits'
Facility Location Date Size NOx PM/PM10/PM2.5 H2SO4 GHG
Avenal Power Avenal, CA 05/27/2011 288 hp
Center 3.4 grams/hp- 11LSD —
hr
Portland Gen. Morrow, OR 12/29/2010 265 — —
Electric Carty Subpart IIII
Plant
Dominion Front Royal, 12/21/2010 2,3 MMBtu/hr Subpart IIII — —
Warren County VA
Pondera/King Houston, TX 08/05/2010 Size not given 1.54 lb/hrI 0.55 Ib/hr — --
Power Station
Victorville 2 Victorville, 03/11/2010 182 hp — _
Hybrid CA Subpart IIII
Panda Sherman Grayson, TX 02/03/2010 Size not given 7.75 Ib/hrI 0.55 Ib/hr — —
Power
Pattillo Branch Savoy, TX 06/17/2009 Size not given 9.3 Ib/hr 0.7 Ib/hr — —
PowerLLC
'Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC
82
1.4.1 Fuel Selection
Step 1:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although use of natural gas would be unusual for an
emergency fire pump engine.
Step 3:Rank Control Technologies by Control Effectiveness
Natural gas engines can achieve lower emissions compared to ULSD.
Step 4.Evaluate Controls
Normally, for an emergency fire pump, it is very important to have the fuel supply directly available
without the possibility of a natural gas supply interruption making it impossible to operate the emergency
fire pump in an emergency. The purpose of the emergency fire pump is to be able to pump water in the
event of a fire. So in order to maintain this important emergency function, ULSD, which can be stored in
a small tank adjacent to the emergency fire pump, is the fuel of choice.
Step 5.Select BACT
ULSD is proposed as the BACT fuel for the Project emergency fire pump.
1.4.2 N%
Step 1:Identify Candidate Control Technologies
• Selective Catalytic Reduction
• Low NOx engine design in accordance with EPA NSPS, 40 CFR 60 Subpart IIIl (Tier 3
engine for 371 hp fire pump unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of SCR is unusual for an emergency
fire pump.
Step 3:Rank Control Technologies by Control Effectiveness
SCR can normally achieve 90% remove of NO,emissions, so it is more effective than the Tier 3 engine
design which is based on low-NO, engine design. However, for an emergency fire pump, if this unit is
used just for short period of test and facility shutdown in an actual emergency, the ability of the SCR to
control emissions will be significantly reduced since the engine/SCR takes time to warm up to achieve
good NOx control.
83
Step 4.Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-15. The capital cost estimate for an SCR
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. The SCR has been conservatively assumed to control 90%of the potential
NO, emissions even though this is unlikely in this application. Table 1-15 indicates that the cost
effectiveness of an SCR is over$90,000 per ton of NO.. This cost is excessive,even if the emergency fire
pump runs the maximum allowable amount of 300 hours per year(unlikely) and 90%NO,control of the
full potential to emit is achieved.
There are no energy or environmental issues with a Tier 3 fire pump that would indicate selection of SCR
as BACT,given the unfavorable SCR economics.
Step 5:Select BACT
With respect to the selection of a PSD BACT for NO, for the emergency fire pump, Table 1-14 indicates
that compliance with Subpart IIII is the most common limit. Several BACT determinations contain
gram/kWhr or gram/hp-hr limits that approximate the Subpart IIII values but do not specifically reference
Subpart IIII. Several Texas projects have Ib/hr limits but do not provide the engine size to determine
limits per unit of output.
With the elimination of SCR on economic grounds, the review of other RBLC precedents supports the
selection of Subpart IIII compliance as BACT.
1.4.3 PM/PM10/PM2.5
Step 1:Identify Candidate Control Technologies
• Active Diesel Particulate Filter(DPF)
• Low PM engine design in accordance with EPA NSPS,40 CFR 60 Subpart 111I(Tier 3 engine
for 371 hp unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of a DPF is unusual for an
emergency engine.
Step 3:Rank Control Technologies by Control Effectiveness
An active DPF can achieve up to 85% particulate removal (CARB Level 3), so it is more effective than
the Tier 3 engine design which is based on low-emission engine design.
Step 4.Evaluate Controls
Since a DPF is technically feasible, an economic analysis of the cost effectiveness for emission control
was conducted. This economic analysis is presented in Table 1-16. The capital cost estimate for an active
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. Table 1-16 indicates that the cost effectiveness of an active DPF is over
$1,000,000 per ton of PM/PM10/PM25. This cost is excessive, even if the emergency fire pump runs the
maximum allowable amount of 300 hours per year(unlikely)
84
TABLE 1-15 371 HP EMERGENCY FIRE PUMP
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION-
eACTAAtssassm4ra ...
lraer�af:rzaitei;:;:;:;:;:: �149c4sa061 DOE :EiflIW o'Fctr40:CP?5asdbaeadlt :::;a.3i:
.... :::::::::::::::::::::::::::::::::::::::
Equipment cost(ec) (Factor) Capital Recovery 51.2,955
a. SCR Capital Cost Estmato(per Milton Cat) $85,000 Direct Operating Costs
b Instrumentation(O.tOA) Included a. Ammonia $477
C. Taxes and Freight (EC-0.05) $4,250 b Operating Labor (OL)(0.5 Wshift)($25.6ft) $480
C. Maintenance tabor (101.):(0.5 b/shift)($25.6 r) $480
Total Equipment Coat(TEC) 589,250 d Maintenance Materials= Maintenance Labor $480
Direct Installation Costs Total Direct Operating Cost $1,440
a. Foundation (TEC•0.08) $7,140
b. Erection and Handling (TEC-0.14) $12.495
C. Electrical (TEC•0.04) $3,6/0 Catalyst Replacement is not included since the emergency fire pump
d. Piping (TEC•0.02) $1,785 will only operate a maximum of 300 hours in any year
e. Insulation (TEC•0.01) $893
I. Painting (TEC•0.01) $893
Total DI act Installation Cost $28;775
Indirect Operating Costs
a. Cwrhead(60%of OL+ML). $576
Indirect Installation Costs b. Property Tax:(TCC-0.01) $1,410
a. Engineering and Supervision (TEC'0.1) $8.925.00 C. Insurance.(TCC-0.01) $1,410
b ConstrucSarJField Expenses (TEC•0.05) $4,463 d. Administration:(TCC-0 02) $2,820
C. Construction Fee (TEC-0.1) $&925
d. start up (TEC•0.02) $1,785 Total Indirect Operating Cost $8,215
e. Performance Test (TEC-0.01) $893
Total Indirect installation Coat 524,990 ITotal Annual Cost $30,641
INOX Reduction-(tons/yr) 0.33
Total Capital Coat(TCC) $747,015
(Cost of Control($Ron-NOx) $92,502
Note 1: Ammonia coat based on estimated as delivered met for 19%aqueous ammonia of EaW per pound of ammonia,and 1.2Ice at NH3 Infected
per pound of NOx removed
85
TABLE 1-16 371 HP EMERGENCY DIESEL FIRE PUMP
ECONOMIC ANALYSIS-ACTIVE DIESEL PARTICULATE FILTER
EcQ:0ilt1aF:4tgiei'lom�:ltie:[iQ�F:oY1n:9W➢i'!S?$A6?::::::::::::::: CPF;cmio-uf ETncieiiey(4CE::::::;:;:;:;:;::::::::::::::::;:;:;:;:;:;:;:86.%
Egmpmenl Coet(EC) (Factor) Qepitai Recover, S12,16)
a. DPF Capital Cost Entrants $45,000 - Direct Operating Costs
b. Insnumensdion(0.10A) Included
c Taxes and Freight (EC-0 05) $2,250 a Operating Labor(OL).(0.25 hr/shi0)($25.6Mr) $240
b Maintenance Labor (ML):(0.25 hr/shia)($25.64nt) $240
Total Equipment Coat(TEC) $47,2M c. Maimanrarce Materials= Maintenorxe Labor $240
Direct Installation Costs Total Direct Operating Coat $720
a. Founde0on (TEC'0.08) $3,780
b, Erection and Handlin0 (rEC-0.14) $6,615
C Electrical (TEC-0.04) $1;890 DPF RaPlacement is not included since Ne emergency fire p.,
d. Piping (TEC-0,02) $945 will only operate a maximum or 300 hours N any year
a, Insulation (rEC'001) $473
f. Painting (rec-0.01) $473
Total Dlrxt installation Cost $14,17$
Indi eel Operating Costs
e. Overhead(60%of OL+ML) $288
Indirect Installation Caere b Property Tom(TCC'001) $747
a. Engineering and Supervision (TEC'0.1) $4.72500 C. Insurance:(TCC-0.01) $747
b. Construction/F(eld Expenses (rEC'0.05) $2,363 d. Administration:(TCC'0 02) $1,493
c. Construction Fee (TEC'0.1) $4,725
d. Stan up (TEC-0,02) $945 Total Indirect Operating Coat $9,275
e. Pedormanm Test (TEC-0.03) $473
Total Incilreet Installation Coat $1$,290 'Total Annual Cost $16;i6a
Te 'PM Reduction(tonsNr) 0.
Total Capital cost(TCC) $74,$55 -
02
ICost of Control($/ton-PM) $1,033.319
86
There are no energy or environmental issues with a Tier 3 fire pump that would indicate selection of a
DPF as BACT,given the unfavorable economics.
Step 5:Select BACT
With respect to the selection of a PSD BACT for PM/PMI0/PM25 for the emergency fire pump,
Table 1-14 indicates that compliance with Subpart IIII is the most common limit. There are two BACT
determinations for PA project (Moxie projects) that both have very low PM/PMio/PM2,5 limits of
0.02 gram/hp-hr. Footprint suspects that this limit is a mistaken entry for the Subpart IIII value of
0.2 grams/kWhr. Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output. Brockton(MA) also has a very low PM limit, much lower than the Subpart IIII
requirements. Footprint does not consider a PM limit less than the Subpart 11II requirements to be an
appropriate BACT.
With the elimination of a DPF on economic grounds, the review of other RBLC precedents supports the
selection of Subpart IIII compliance as BACT.
1.4.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of ULSD as the BACT fuel, this is the lowest sulfur content fuel suitable for the
emergency fire pump.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 5%molar conversion of fuel sulfur to H2SO4-Most of the emergency fire pumps in Table 1-14 do
not have an H2SO4 limit. The only numerical limits for H2SO4 identified for an emergency fire pump are
those for the two recent Ohio PSD permits (Oregon and Carroll County), and the Hickory Run (PA)
project. The limit for the Ohio cases is 0.000132 grams/kWhr, and for Hickory Run is 0.00012 grams/hp-
hr(0.00016 grams/kW-hr). All these projects are approved with ULSD as the emergency fire pump fuel.
Conversion of the Footprint limit to grams/kWbr indicates that 5%molar conversion of the fuel sulfur to
H2SO4 yields 0.0005 grams/kWhr, or about 4 times the Ohio limits and three times the Hickory Run limit.
Review of the Ohio approvals indicates this factor is based on an EPA toxics emission factor which
apparently allows for a much lower molar conversion of fuel sulfur to H2SO4- While this factor may be
suitable for actual emissions, Footprint believes this factor is not appropriate for setting an emission limit.
Therefore, given that most agencies do not even regulate emergency fire pump H2SO4, Footprint believes
the PSD BACT emission rate based on 5%molar conversion of fuel sulfur to H2SO4 is justified as BACT.
As noted above for the emergency diesel generator, this 5%molar conversion of fuel sulfur to H2SO4 is a
reasonable upper limit permit limit assumption for fuel combustion sources that do not have an SCR or
oxidation catalyst.
1.4.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT. Given that emergency fire pumps operate so little,
agencies have not required review of fire pump efficiency as part of GHG BACT.
With respect to GHG,most of the emergency pumps listed on the RBLC with GHG limits for PSD BACT
are expressed as a mass emission value, which is a project specific number reflecting the particular size
and gas throughput limits of the specific project unit. Therefore,these GHG equipment-specific limits are
87
not automatically transferrable as comparable limits for this Project. One unit listed in
Table 1-14 has a lb/MMBtu limit based on ULSD corresponding to 163.6 lb CO2e/Nmtu. For its
proposed GHG limit for the emergency pumps, the Project has chosen a value based on the USEPA Part
75 default emission factors (162.85 ib/MMBtu), incorporating both CO2, CH4, and N2O. The Applicant
proposes a GHG PSD BACT limit expressed in the units of lb/MMBtu (162.85 Ib/MMBtu) as most
appropriate PSD BACT limit.
1.5 Auxiliary Cooling Tower
This section provides a PSD BACT analysis for the auxiliary mechanical draft cooling tower. The
primary function for the auxiliary cooling tower is to provide necessary equipment cooling for the gas
turbine itself, which is not possible to provide using the Air Cooled Condenser (ACC) used to condense
steam discharged from steam turbines. The auxiliary mechanical draft cooling tower planned for use is a
3-cell commercial scale tower, with a total circulating water flow (all 3 cells) of 13,000 gallons per
minute (gpm).
In general, mechanical draft cooling towers provide cooling of the circulating water by spraying (warm)
circulating water over sheets of plastic material known as fill. This exposes the circulating water to
ambient air being drawn in through the sides of the tower towards a fan generally located above the fill.A
fraction of the circulating water evaporates into this air, warning it and causing it to become saturated
with moisture. A small portion of the circulating water may be entrained into this air flow. These droplets
of circulating water contain dissolved solids. Specially designed drift eliminators are typically located
above the water sprays to remove most of these droplets and return them to the fill.But a small fraction of
these droplets can escape into the fan discharge into the atmosphere. These droplets then evaporate, and
the particulates in these droplets are a source of particulate (PM/PMI0/PM2 5) emissions. PM/PMIo/PM2.5
are the only PSD pollutants emitted from the auxiliary cooling tower.
The Footprint auxiliary cooling tower is being designed to limit the drift rate to 0.001% of the circulating
water flow (0.13 gpm). The design dissolved solids concentration for the circulating water is 1,500
milligrams per liter (mg/1) As documented in Appendix B of the December 2012 PSD Application,
Calculation Sheet 6, the potential PM/PM10 emissions from the auxiliary cooling tower are 0.43 tpy, and
the potential PM2.5 emissions are 0.17 tpy.
Step I:Identify Candidate Technologies
Particulate control technologies identified for cooling towers at new large > 100 MW combined cycle
turbines are as follows:
• Air-Cooled Condensers'(ACCs): This eliminates the use of circulating water for cooling and thus
eliminates drift for large towers used for steam turbine condenser cooling
• High efficiency cooling tower drift eliminators.
• Reduction in the dissolved solids concentration in circulating water.
Step 2:Eliminate Infeasible Technologies
ACCs are technically feasible for steam turbine condenser cooling large combined cycle units. However,
use of an ACC is not technically feasible for the auxiliary equipment cooling required for a GE Frame
7FA.05 combustion turbines since ACCs cannot achieve the degree of cooling performance required.
High efficiency cooling tower drift eliminators are also technically feasible for mechanical draft cooling
towers. The total dissolved solids concentration (TDS) in circulating water is a function of the makeup
88
water TDS, which depends on the makeup water source, and the TDS at which the tower is operated.
Removing TDS from the makeup water is considered technically infeasible for a small auxiliary
mechanical draft cooling tower. However, the TDS in the circulating water can be decreased by
increasing the amount of"blowdown" from the tower. Blowdown is a stream of wastewater continuously
discharged from the tower to remove TDS from the circulating water. Increasing blowdown reduces the
TDS and is technically feasible.
Step 3:Rank Control Technologies by Control Effectiveness
The ranking of the technically feasible technologies is as follows:
1. High efficiency cooling tower drift eliminators: Generally recognized to be capable of
achieving a drift rate of 0.0005% of circulating water flow for large cooling tower used for
power plant steam turbine condenser cooling. However, for small commercial mechanical
draft cooling towers being used in this application,the standard design is for 0.001%drift.
2. Reduce the TDS in circulating water: Mechanical draft cooling towers are operated with
circulating water TDS as low as 1000 milligrams/liter(mg/1).
Step 4:Evaluate Controls
Footprint has compiled all the PSD BACT determinations in the last five years for mechanical draft
cooling towers at new large (> 100 MW) combustion turbine combined cycle projects. This compilation
is based on the USEPA RBLC(RACT/BACT/LAER Clearinghouse). Several recent projects not included
in RBLC have also been included in this compilation. Table 1-17 provides this compilation.
Review of Table 1-17 indicates that the available cooling tower BACT determinations are almost
exclusively for large towers used for steam turbine condenser cooling. These towers are commonly
specified for 0.0005% drift. Texas project determinations typically do not have the size of the tower
indicated,and only have lb/hr emissions indicated which does not provide a meaningful comparison.
The smallest tower identified with a PM PSD BACT determination is the 12,000 gpm chiller tower at the
Entergy Ninemile Point project in Louisiana. This tower in fact has drift specified at 0.001%, which
agrees with our finding that small towers are designed for 0.001% drift. Therefore, it is concluded that
0.001%drift is justified as BACT for the small auxiliary mechanical draft cooling tower for Footprint.All
towers identified with drift limits of 0.0005%are significantly larger than the Footprint auxiliary tower.
With respect to the circulating water total dissolved solids (TDS) concentration, for projects where this
value is identified, these values range from 1000 to 6200 mg/l. Only two projects have design values <
Footprint's 1500 mg/1. A collateral environmental impact of increasing the blowdown to decrease TDS is
increasing consumption of water. Footprint has selected 1500 mg/1 as a reasonable TDS value balance to
drift emissions and water conservation.
Step 5:Select BACT
The Footprint Project will meet 0.001% drift and limit the potential PM/PMio emissions from the
auxiliary cooling tower to 0.43 tpy, and the potential PM25 emissions to 0.17 tpy. These values are
justified as BACT.
89
Table 1-17.Summary of Recent Cooling Tower Particulate BACT Determinations for Large(>100MW) Gas Fired Combined-Cycle
Generating Plants
Cooling Tower Description(total
Permit circulating water flow rate in gallons BACT�
pM/BACT'Mz.s
Facility Location Date per minute unless otherwise specified)
Renaissance Power Carson City, MI 11/1/2013 10 cell tower 0.0005%drift
Langley Gulch Power Payette, ID 08/14/2013 76,151 gpm Drift Eliminators(not limit specified); 5000 mg/I
Oregon Clean Energy Oregon, OH 06/18/2013 322,000 qpm 0.0005%drift; 2030.5 mq/1
Green Energy Partners/ Leesburg, VA 04/30/2013 187,400 gpm 0.0005%drift; 5000 mg/I
Stonewall
Brunswick County Power Freeman, VA 03/12/2013 46,000 gpm (towers for turbine inlet air 0.0005%drift; 1000 mg/I
chillers)
St. Joseph Energy Center New Carlisle, IN 12/03/2012 2 towers at 170,000 qpm each 0.0005%drift
Hess Newark Energy Newark, NJ 11/01/2012 220,870 qpm 0.0005%drift,4150 mq/I
Channel Energy Center, Houston, TX 10/15/2012 Size not specified 1.33 lb/hr PM10
LLC
Pioneer Valley Energy Westfield, MA 04/05/2012 Full wet cooling for 431 MW combined 0.0005%drift
Center(PVEC) cycle facility_—circulatinq flow not qiven
Deer Park Energy Center Deer Park, TX 09/26/2012 Cooling tower size not specified PM—3.13 Ib/hr
LLC PM10/PM2,5 1.75lb/hr
Entergy Ninemile Point Westwego, LA 08/16/2011 Chiller cooling tower 12,000 gpm Chiller cooling tower 0.001%drift
Unit 6 Unit 6 cooling tower 115,847 qpm Unit 6 cooling tower 0.0005%drift
Brockton Power Brockton MA 7/20/2011 92,500 qpm 0.0005%drift; 3235 mq/I
Portland Gen. Electric Morrow, OR 12/29/2010 Cooling tower circulating water flow rate 0.0005%drift; 1200 mg/I
Carty Plant - 85,000 qpm
Pondera/King Power Houston,TXI 08/05/2010 2 towers-size not specified 1.28 Ib/hr/tower
Station
Victorville 2 Hybrid Victorville, CA 1 03/11/2010 1 130,000 qpm 0.0005%drift; 5000 mu/I
Stark Power/Wolf Hollow Granbury, TX 03/03/2010 1 Coolinq tower size not specified 0.0005%drift
Russell Energy Center Hayward, CA 02/03/2010 1 141,352 qpm 0.0005%drift; 6200 mq/I
Panda Sherman Power Grayson, TX 02/03/2010 Cooling tower sizes not specified Main tower 4.68 lb/hr PM, inlet air chiller tower
0.27 Ib/hr PM
Both 0.0005%drift
Lamar Power Partners II Paris, TXI 06/22/2009 I Cooling tower size not specified 2.4 Ib/hr PMto
LLC
Pattillo Branch Power LLC Savoy, TXI 06/17/2009 I 4 towers-size not specified 1.0 Ib/hr/tower PM
0.3 Ib/hr/tower PM10
'Mass emissions(Ib/hr)are only specified if comparable units across projects(%drift, total dissolved solids)are not provided.
90
r.
Appendix A
Updates to Footprint Air Emissions Calculations
Updated GE performance data is provided as Attachment A-1 (3 sheets). These sheets update
the performance data previously provided.
Items that have changed subsequent to the public review drafts issued by MassDEP are
highlighted in yellow on all the sheets that are updates of prior sheets.
Calculation Sheet 1 presents the potential to emit (PTE) calculations for one turbine. Two
operating cases are used to calculate potential emissions (PTE) are 100% load at 50 OF for
baseload operation (8,040 hours/year) and 100% load at 90 OF with the duct burners and
evaporative coolers on (720 hours per year). GE Case 7 is 100% load at 50 OF, with a heat input
of 2,130 MMBtu/hr. GE Case 12 is 100% load at 90 OF with the duct burners and evaporative
coolers on with a heat input of 2,449 MMBtu/hr. The PTE values are based on the direct
calculation with the exact Ib/MMBtu values shown on Calculation Sheet 1.
For CO, Calculation Sheet 1 shows the PTE based on 8,760 hours of operation, but the worst
case PTE is based on separate calculations using startup and shutdown (SUSD) emissions and
an assumed operating scenario. These calculations are provided on Calculation Sheet 2 for GE
and reflect a higher PTE for CO compared to those in Calculation Sheet 1. Therefore, the
maximum SUSD scenario value for CO PTE is used. Calculation Sheet 1 shows the revised
emissions for CO for both the turbine (based on a maximum rate of 8.0 Ib/hr/turbine) and the
auxiliary boiler with the CO catalyst. The auxiliary boiler CO emission rate with the oxidation
catalyst is 10% of the prior rate (0.035 Ib/MMBtu)(0.10) = 0.0035 Ib/MMBtu.
Calculation Sheet 3 in the December 21, 2012 application had been for Siemens SUSD and is
now dropped. Calculation Sheets 4, 5, and 6 presented emission calculations for the
emergency generator, emergency diesel fire pump, and auxiliary cooling tower respectively.
These have not changed and are not repeated here.
Calculation Sheet 7 presents the updated overall summary of potential-to-emit (PTE) for the
facility.
Calculation Sheets 8 and 9 are new, and are the NOx BACT cost spreadsheets for the auxiliary
boiler, supporting the values in Table 1-8.
91
Attachment A-1(Sheet 1 of 3)
GE Energy 107F Series 5Rapid Response Combined Cycle Plant-Emissions Data-Natural Gas
GE Energy Performance Data-Site Conditions
]Operating Point 1 2 3 4 5 6 7 ] 8 9 SO 11 12 13
Case Description 1
Unfired Unfred Unfired Unfired Unfired Unfired Unfired I firing firing
Unfired Unfired Unfired 50%DB 100%DB Unfired'
]Ambient Temperature 'F 0. ] 0 0 20 I 20 20 50 1 50 50 90 90 90 90 ]
(Ambient Pressure psia 14.7 I 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 I
IAmblent Relative Humidity % 60 I 60 60 60 I 60 60 60 60 60 I 60 60 60 60
GE Energy Performance Data-Plant Status
I HRSG Duct Burner(On/Off) I ( Unfired Unfired Unfired Unfired Unfired Unfired Unfired Unfired Unfired ( Unfired Fired Fired Unfired]
I Evaporative Cooler state(On/Off) Off Off- Off Off. Of( Off Off Oft Off On On On Off 1
]Gas Turbine Load I % BASE 75% 50% BASE 75% 46% BASE 75% 46% 1 BASE PEAK PEAK BASE 1
IGas Turbines Operating I 1 1. 1 1 1 1 { 1 1 1 1 1 1 1 1 I
GE Energy Performance Data-Fuel Data
IGT Heat Consumption MMBtu/hr 2300 1850 I 1460 2250 1790 1360 2130 1700 I 1310 2040 ] 2082 2082 1980 {
1 Duct Burner Heat Consumption MMBtu/hr 0 D 0 0 0 0 0 0 0 0 I 183 367 0 1
{Total (GT+DB) MMBtu/hr 2300 1850 1460 2250 1790 1360 2130 1700 1310 2040 1 2265 2449 1980 ]
GE Energy Performance Data-HR5G Exit Exhaust Gas Emissions
1VOC ppmvdc 1 1 1 1 1 1 1 1 1 1 2 2 1 )
]NH3 ppmvdc 2 2 -2 2 1 2 ( 2 2 2 2 2 2 2 2
IND% Ib/MMBtu 0.0074 1 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 I 0.0074 0.0074 0.0074 0.0074 1
ICO �Ib/MMBtu 0.0045 0.0045 0.0045 0.0045 '0.0045 0.0045 O.45 0.0045 0.0045 I 0.0045 0.0045 0.0045 0.0045
VOC
b 0013 0.0013 0.0013
13
113 111122
22
INH3 Iib/MMBtu 0.0027 0.0027 0,0027 0.0027. 0.0027 0.0027 01:,111
027 0.0027 0.0027 I 0.0027 0.0027 0.0027 0.0027
Particulates-Filterable+ 0,0038 0.0048 0.0060 0.0039 0.0049 0,0065 0.0041 0.0052 0.0067 0.0043 0.0057 0.0053 0.0044
Condensible,Including Sulfates 116/MMBtu
]NO. Ib/hr 17.0 13.7 10.8 16.7 13.2 10.1 15.8 12.6 9.7 15.1 16.8 18.1 14.7
ICO Ib/hr 8.0 8.0 6.6 8.0 80 6.1 8.0 7.7 5:9 8.0 8.0 8.0 8.0
INOH3 Ib/hr 62 5.0 3.9 6.1 4.8 3 7 5.8 4.6 3.5 5.5 6.1 6.6 5.3
(Particulates-Plterabie+
Condensible,Including Sulfates Ib/hr 8.8 8.8 8.8 8.8 1 8.8 8.8 8.8 9.8 8.8 8.8 13.0 13.0 8.8
ppmvtic%pats per irilllon by volume,dry basis•Corrected to 15%02
MMBto Is on a Higher Hexing Mue(HWI basis
`JL y
Attachment A-1(Sheet 2 of 3)
GE Energy 107E Series 5 Rapid Response Combined Cycle Plant- Emission Data-Natural Gas
GE Energy Performance Data-Site Conditions
(Operating Point 14 15 ] 16 17 18 19 20 21 22 23 24 25 1
50%DB 100%Di Unfired Unfired Unfired 50%DB 100%DB Unfired 50%D8 100%DB Unfired Unfired
(Case Description firing firing firing firing firing firing
]Ambient Temperature -F 90 90 90 90 105 105 105 105 105 105 105 105 1 -
IAmblent Pressure psia 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 14.7 I
]Ambient Relative Humidity % 60 60 60 60 50 50 50 50 50 50 50 50 1
GE Energy Performance Data-Plant Status
IHRSG Duct Burner(On/Off) ], Fired Fired Unfired Unfired Unfired Fired Fired I Unfired Fired Fired Unfired Unfired I
I Evaporative Cooter state(On/Off) I Off Off Off Off On On On Off Off Off Off Off I
IGas Turbine Load I % I PEAK PEAK 75% 47% I BASE I PEAK _ PEAK BASE PEAK PEAK 75% 49% I
IGas Turbines Operating I I 1 1 1 1 1 1 1 1
BE Energy Performance Data-Fuel Data
IGT Heat ConsumptionI MMBtu/hr 2017 2017 1590 1260 1990 I 2005 2005 1 1880 1928 1928 1520 ] 1240 I
(Duct Burner Heat Consumption MMBtu/hr 183 377 0 0 0 183 377 I 0 183 377 0 0 I
ITotal Heat Consumption(GT+DI MMBtu/hr 2201 2394 1590 1260 1990 2188 2382 I 1880 2112 2305 1520 1 1240 I
GE Energy Performance Data-HRSG Exit Exhaust Gas Emissions
INOx
1COppmvdc 2 2 2 2 2 2 2 2 1 2 2 2 2 ]
IVOC ppmvdc 1
INH3 ppmvdc 2 1 7 7 7 7
2 2 2 2 ( 2 I 2 2 2 2 I 2 2
I
INOx Ib/MMBtu 0:0074 0:0074 0.0074 0.0074 0.0074 0.0074 0.0074 -0.00741 0.0074 0.0074, 10.o0741 0.0074 1
1CO Ib/MMBtu 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.00451 0.0045 0.0045 0.00451 0.0045 ]
IVOC Ib/MMBtu 0.0022 0.0022 0.0013 0.0013 0.0013 0.0022 0.0022 0.00131 0.0022 0.0022 0'00131 0.0013 ]
INH3 Ib/MMBtu 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0:0027 0.0027
Particulates-Filterable+
Condensible,Including Sulfates Ib/MMBtu 0.0059 0.0054 0.0055 0.0070 0.0044 0.0059 0.0055 0.0047 0.0062 0.0056 IO.00SB 0.0071
INOx Ib/hr 16.3 17.7 11.8 9.3 14.7 16.2 17.6 13.9 ] 15.6 17.1 11.2 9.2 I
1CO Ib/hr 8.0 8.0 7.2 5.7 8.0 8.0 8.0 8.0 8.0 8.0 6.8 5.6 1
VOC Ib/hr 4.8 5.3 2.1 1.6 2.6 4.8 5.2 2.4 4.6 5.1 2.0 1.6 I
INH3 Ib/hr 5.9 6.5 4.3 3.4 5.4 5.9 6.4 5.1 5.7 6.2 4.1 3.3 I
Particulates-Filterable+ 13.0 13.0 8.8 8.8 8.8 13.0 13.0 8.8 13.0 13.0 8.8 8.8
Condensible,Including Sulfates Ib/hr 111
ppmvdc Is parts per million by wherne,any basrs,corrected to 15%02
MMgtu Is on a Higher Heabng Value IHHV)basis
Attachment A-1(Sheet 3 of 3)
GE Energy 107FA.05 Rapid Response Combined Cycle Plant
Manufacturers Emissions Data-Natural Gas-Startup and Shutdown Conditions-Single Unit Basis
NOx(Ib) CO(Ib) VOC(Ib) I PM10(lb) Duration(min)
Cold Start(GT Fire to HRSG Stack Emissions Compliance with Base Load Hold) I 89 285 23 I 7.3 45
Warm Start(GT Fire to HRSG Stack Emissions Compliance with Base Load Hold) 54 129 13 5.0 32
Not Start(GT Fire to HRSG Stack Emissions Compliance with Base Load Hold)- 28 121 12 2.6 18 I
Shutdown(HRSG Stack EC to GT Flame Off) 10 151 29� I 5.8' 27 I
94 -
� r
Calculation Sheet 1
. Annual Potential Emissions for Combustion Turbines and Auxiliary Boller
One Combustlon Turbmeal100% Auxiliary Boiler
Load
1 50 deg F 90 deg F Annual Gas Annual 1
No DF DF,EC tpy Ib/MMBtu tpy
Hours per Year 8040 720 6570(FLE) 6570(FLE) 1
I MMBtu/hr 2130 2449 80
I � �
I NOx(lb/MMBtu) 0.0074 0.0074 699 0011 29 I
I �
CO 8.0IWhr 35.0 00035 09 1
I I I
VOC(IWMMBtu) 00013 0.0022 131 0005 1.3
I
1 802(Ib/MMBtuI 00015 0.0015 142 0.0015 04 1
I � �
PM/PM-10IPM-2.5 8.8 lb/hr 13.0lb1hr 1 40.1 0005 13
NH3(Ib/MMBtu) 00027 00027 25.5 - -- 1
H2SO4(iWMMBlu) 0.001 0.001 . 9.4 00009 0.24 1
I Lead(Ib/MMBtu) ) - - - 4.90E-07 000013
Formaldehyde(lb/MMBtu) ( 0.00035 0.00035 1 33 7.40E-05 0.019
Total HAP(IWMMBtu) 10.000667 0.000667 63 1.90E-03 0.5
I I I
1 CO2(IWMMBtu) 1 118.9 118.9 11,122,920 1189 31,247 1
I I I I
CO2e (IWMMBtu) I 119.0 1190 11,124,003 1190 31,277 I
Notes:
1. DF=Duct Firing
2. EC=Evaporative Coolers 1
3. FLE=Ful, I_Load Equivalent
4.Annual potential emissions per turbine for all pollutants except CO and PM are based on
[(2130 MMBtu/hr)(Ib/MMBtu no DFI(8040 hrs)+(2449 MMBtulhr)(IWMMBto DF)(720 hrs)[/2000lblton
5. Annual potential emissions shown here per turbine for CO are based on 8IWhr for 8760 hours.
However,the worst case PTE for CO Includes the starluplshutdown scenario as shown in
Calculation Sheet 2.
6. Annual potential emissions per turbine for PM/PM-10/PM-2.5 are based on
[(8.8 lbrhr)(B040 hrs).(13.0 IWhr)(720 hrs)]/2000 lb/ton
7. H2SO4 emisslons for the aux boiler are based on 40%molar conversion of fuel sulfur to H2SO4
Correcting for molecular weight,the HZSO4 emission rate is:
(0.0015 lb S021MMBtu)(0.4)(98 Ib/mole H2SO4J/(641Wmole SO2)=0.00091b/MMBtu
a. Annual potential emissions for the aux boiler are based on:
180MMBtu/hr)(IWMMBtu)(6570 hours FLE)/(2000lb/ton)
95
Calculation Sheet 2
GE Emissions for CO and VOC Including Startup Shutdown Scenario
Emissions for Normal used Cases
MMBtu/hr CO(Ib/hr) VOC llb/hrl I
Spring/Fall Normal Load Case 7(50 deg) 2130 8.0 2.8
Summ ser Case 13 except for 720 hours 1980 8.0 2.6
Summer Case 12 for 720 hours(SO deg) 2449 8.0 5.4
Winter Cased (20 deg) 2250 8.0 2.9
I ASSUMED OPERATING SCENARIOS GE STARTUP/SHUTDOWN EMISSIONS
Assumed Operating Profile
Normal Loads starts/wk stns/yr CO VOC
days/ hm/ hrs/ Weeks/ Normal Load Cases
week day week yr hu/yr Emissions for Each Season
cold warm hot cold warm hot cold warm ha cold warm hot
I Combined startup/shutdown pounds ofern aloin persingle ew:nt 436 280 272 52 42 41
Annual SUSD emissions for each category and season(Ibs)
Spring/Fa11 5 12 60 20 1200 0.25_4.75] 0 5495 0 } 2180 26600 0 ,_260 3990_j 0
Case 9600 3323
Summer 7 24 168 2 336 0 2 0 0 4 0 0 1120 0 0 168 0
5 16 80 8 640 0 5 0 0 40 0 0 11200 0 0 1680 0
5 12 60 2 120 0 5 0 0 10 0 0 2800 0 O 420 0
1096 Case 13 3008 968
Case 12 5760 3879
Winter 7 24 168 2 336 0 1 0 0 2 0 0 560 0 0 84 0
5 16 80 8 640 0.25 4.75 0 2 38 0 872 10640 0 104 1596 0
976 Cased 7808 2855
TOTALRUN HRS42 3272
Planned outage 7 24 168 4 672 6 2616 0 '0 312 0 0
Not Dispatched(includes time In SI1SD) 4437
Unplanned FO 4.1% ,359 4 1088 164
ANNUALHRS 8760
Total Tons in Each Category I 29.8 4.4 13.1 I 5.5
CO VOC
Total Emissions per unitll 42.9 9.9. }
Note: The startup/shutdown cycling scenario is no longer controlling for annual VOC emissions.
a
Calculation Sheet 7
Summary of Facility Potential to Emit(PTE)In tons per year(tpy)
Annual emissions,tons/year
CT Unit 1(GT+ Cr Unit 2(GT+ Emergency Aux Cooling
Pollutant
DB) OB) Aux Boller Generator Fire Pump Tower Facility Totals
NO, 69.9 69.9 2.9 1.7 0.4 0 144.8
CO 42.9 42.9 0.9 1.0 0.3- 0 88.0
VOC 13.1 13.1 1.3 0.35 0.12 0 28.0
so, '14.2 14.2 0.4 0.0017 0.0006 0 28.8
PMio 40.1 40.1 1.3 0.1 0.0 0.4 82.0
PM2.1 40.1 40.1 1.3 0.1 0.0 0.2 81.8
NH, 25.5 25.5 0 0 0 0 51.0
H2SO4 mist 9.4 9.4 0.24 1.33E-04 4.84E-OS 0 19.0
Lead 0 0 0.00013 8.54E-07 3.10E-07 0 0.00013
Formaldehyde 3.3 3.3 0.019 8.76E-05 4.76E-04 0 6.6
Total HAP 6.3 6.3 0.5 1.76E-03 1.57E-03 0 13.1
CO, 1,122;920 1,122,920 31247 180 66 0 2,277,333
CO,e 1,124,003 1,124,003 31277 181 66 0 2,279,530
97
Calculation Sheet 8
80 MMBtu/hr Auxiliary Boller
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION
Contiol:Sybteln:Elle: : :Td'yeare;:;:;:;:
ti??iF?i:F�3ei:::: :::::::::::i0.'4G`X:�: :: ::: ::: ::: WinCEmte9ivRs 6t:3a:BPiovife y?neGted lte3%02(WyL :: :::::::::g :
t?eorieaifo f6et'dt'gtieM?a[aesD ?;Fu?oj:e!�i'P�R<xeiict:: :;: : : : 5cB Eloiesjo[ts ei3 VFirivaacgieciaaiaa1s O;Lia9j6t?76
CaIiof Rice✓e r�cwrlcpfi: : : .o,Td3. . . . . . : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Equipment cost(EG) (Factor) Capital Recovery $67,6U4
a. SCR Capital Cost Estimate(Cleaver Brooks) $250,000 Direct Operating Costs
b Taxes and Freight (EC'0.05) $12,500 a. Ammonia $12,261
b. Operating Labor (OL).(0.5 hrlshift)($25.6Ihr) $10,512
Total Equipment Cost(TEC) $262,500 c. Maintenance Labor (ML):(0.5 Irdshift)($25.6av) $10,512
d. Maintenance Material=Maintenance Labor $10,512
Direct Installation Costs
Total Direct Operating Cost $43,797
. a. Foundation (TEC'008) 121,000
b. Erection and Handling (TEC-014) $36,750 Catalyst Replacement
c Electrical (TEC-0.04) $10,500
d. Piping (TEC-0.02) $5,250 e: 33%of TEC required at year 3.33 and year 6.67,plus
e. Insulation (7EC'0.01) $2,625 erection and indirect costs(0.25 of replacement)
I. Painting (TEC-0.01) $2,625 b. 10-year annualized cost for catalyst replacement $22,062
.Total Direct Installation Cost $76,75 Indirect Operating Costs
Indirect Installation Costs a. Overhead(60%of OL-ML) $12,614
b. Property Tax:(TCC'0.01) $4,148
a. Engineering and Supervision (TEC'0.1) $26,250 C. Insurance:(TCC-0.01) $4,148
b. Construction/Field Expenses (TEC'0.05) $13,125 d. Administration.(fCC'002) $8,295
o. Construction Fee QEC0.1) $26,250
d. Startup (TEC-0.02) $5,250 Total Indirect Operating Coat $29,2.05
e. Performance Test (TEC'001) $2,625
Total Indirect Installation Cost $73,58 ITotal Annual Cost $162,668
INOx Reduction(tons/yr) 8.51
Total Capital Cost(TCC) $414,750
]Cost of Control($/ton-NOx) $19,115
Note 1: Ammonia wet based on estimated as delivered cost for 19%aqueous ammonia of$0.5 per pound of ammonia,and 1.2 The of NH3 Injected
per pound'of box removed
Calculation, Sheet 9
80 MMBtu/hr Auxiliary Boller
ECONOMIC ANALYSIS-ULTRA LOW NOx(ULN)BURNER COMPARED TO STANDARD LOW NOx BURNER
)tt[ofdet Ratw YO.W9& - BasalfoBEmleEloa$8130 ppmvticcorTMeg1o39ft 02(ip� 9.N�'
EoonamlaFedom from MesalJE?FonrtaWPAO-BAC7' -Contrallei Embatone-aF SpprmMs aor[ecled fa 3%02 d1i 289:
tel:Reriover-:Faelbr:CCSP..F:ry
Equipment CosL(EC) (Factor) Capital Recovery $21,907
a. Capital Cost Estimate(Differential Cost of ULN
compared to standard low NOx bumer) $100,000
(per Cleavar Brooks) Direct Operating Costs
b Texas and Freight (EC-0 05) $5,000
Direct Operating Costs are assumed to be the
Total Equipment Cost ITEC) $105,000 same for ULN compared to standard low-NOx burner
Direct Installation Costs
Direct Installation Costs are assumed to be the
some for ULN compared to standard low-NOx burner Indlrset Operating Coats(based on differential cost)
Inditscrt Installation Coats(based on differential cost) a. Overhead(60%of OL*ML) S0
b. Property Tax,(TCC'0.01) $1,344
a Engineering and Supervision (TEC-0.1) $10,500 C. Insurance:(TCC'0.01) $1,344
b. Construction/Field Expenses (TEC'0 05) $5,250 d. Administration:(TCC-0.02) $2,688
C Construction Fee (TEC-0.1) $10,500
d. Startup (TEC-002) $2,100 Total Indirect Operating Cost $5,876
e. Performance Test (TEC-0.01)- $1,050
Total indirect Instaliatlon Cost MAW
Totes Capital Coat Differential for ULN $134,400
Compared to standard Low NOS Sumer ITotal Annual-Cost $27,283
(NOx Reduction(tons/yr) 6.57
(Coat of Control($/ton-NOx) $4,153
99
v
Footprint Power Salem Harbor Development LP
Salem Harbor Redevelopment Project
Prevention of Significant Deterioration Permit
Response to Comments on
Draft Permit Number NE-12-022, Transmittal Number X254064
Introduction
On September 9, 2013, notices were published in the Salem Evening News and the Boston Globe
for public review and comment on the Draft Prevention of Significant Deterioration (PSD)
Permit for the Footprint Power Salem Harbor Development LP's Salem Harbor Redevelopment
(SHR) Project in Salem, Massachusetts. The comment period was extended to November 1,
2013. MassDEP also held a public hearing at the Bentley Elementary School in Salem, MA on
Thursday, October 10, 2013. Comments were submitted by various parties during the public
comment period.
After careful review of all comments received, MassDEP has made a final decision to issue the
PSD Permit. As required by 40 CFR part 124 (Procedures for Decision making), MassDEP has
prepared this document, known as the "response to comments" (RTC) that describes and
addresses any significant issues raised during the comment period and describes the provisions
of the Draft PSD Permit that have been changed and the reasons for the changes. The PSD Fact
Sheet has also been changed,to reflect changes that were made to the Draft PSD Permit.
MassDEP's decision making process has benefitted from the various comments and additional
information submitted. All changes to the Draft PSD Permit are described in detail below and
are contained in the Final PSD Permit. The analyses underlying these changes are explained in
the PSD Fact Sheet and the responses to comments that follow.
The Final PSD Permit and RTC are available on MassDEP's website at
httn://www.mass.eov/eea/agencies/massdeo/air/aonrovals/foott)rint.html . MassDEP is
providing copies (electronic or hard copy) of the Final PSD Permit and RTC to everyone who
commented on the Draft Permit or who requested copies of these documents. Copies of the Final
PSD Permit also may be obtained by writing or calling MassDEP between the hours of 8:45 AM
and 5:00 PM; Monday through Friday, excluding holidays:
Cosmo Buttaro, Environmental Engineer
MassDEP,Northeast Regional Office
205A Lowell Street
Wilmington, MA 01887
Telephone number: (978) 694-3200
Cosmo.Buttaro@ state.ma.us
MassDEP reviewed the significant comments received from commenters and in many cases
grouped related comments together. Comments expressing general opposition to, or general
support of, the proposed facility have been noted and deemed subsumed into more specific
comments, to which MassDEP has responded below.
In some cases, MassDEP has included original comments nearly verbatim for the reader's
convenience. In others, MassDEP has included brief summaries of those comments to remind
the reader of the topics being discussed. Even though each comment submitted has not been
reproduced here in its entirety, and many of the details of each comment were not repeated in the
summary comments, please be assured that MassDEP has carefully read and considered every
comment in its entirety. The form of this RTC is simply designed to structure MassDEP's
responses and make them more accessible to the general public. No significance should be
attached to the form in which MassDEP cited or summarized the original comment in this RTC.
The complete text of every comment as submitted, and a complete copy of the transcript from
the public hearing, is in the administrative record and available by request.
TESTIM NY_AMYCOMNMENTS —" J
NAME'&AFFILIATION- 'DATE RECEIVED!
1. Ida E. McDonnell, United States 110/30/13 emailed letter
Environmental Protection Agency 11/1/13 hard copy letter
2. John Keenan, Massachusetts State I Oral testimony at hearing
Representative
3. George W. Atkins, Patricia Maguire 10/31/13 hard copy letter
Meservey, The Salem Partnership J
4. Jeff Barz-Snell, Salem Resident, Salem Oral testimony at hearing
Alliance for the Environment(SAFE)
5. Jane Bright,HealthLink Oral testimony at hearing
11/1/13 emailed letter and email comment
6. Jeff Brooks, Salem Resident Oral testimony at hearing
10/14/13 and 11/1/13 emails, and 10/17/13
letter
7. Paul R. Campbell, Pipe Fitters Local Oral testimony at hearing,
537
8. Shanna Cleveland, Conservation Law 11/1/13 emailed letter
Foundation(CLF) and Elizabeth
Michaud, Michel Beheshti, Jeff Brooks,
Andrea Celestine, William Dearstyne,
Linda Haley,Douglas Haley,
HealthLink, Clean Water Action, Jane
Bright, Martha Dansdill,Rosalind
Nadeau, Sue Kirby(350
Massachusetts), Dorian Williams(a
Better Future Project-350
Massachusetts), Jody Howard,Marlene
Faust
2
}
9. Dominic Cucinotti, Salem Resident 10/21/13 email
10. Sonia Cucinotti, Salem Resident 10/18/13 email
11. William E. Dearstyne, Salem Resident 11/1/13 emailed letter
12. Rob DeRosier, Salem Resident, Salem Oral testimony at hearing
Chamber of Commerce President,
Footprint Power Salem Harbor
Operations LLC Environmental Health
and Safety Manager
13. Elise Desmond, Milton Resident 10/5/13 email
14. George Economides, Salem Resident 10/13/13 email
15. Ken Eisenberg, Cambridge Resident 10/24/13 email
16. Meghan Emmers Oral testimony at hearing
17. Timothy Fandel, Plumbers and Gas Oral testimony at hearing
Fitters Local 12
18. Pat Gozemba, Salem Alliance for the Oral testimony at hearing
Environment(SAFE) Written testimony at hearing
19. Linda Haley,Marblehead Resident Oral testimony at hearing
11/1/13 emailed letter
20. Susan Kirby, Salem Resident, 350 Oral testimony at hearing
Massachusetts 11/1/13 emailed letter
21. Robert Liani, Jr., Coffee Time Bake Oral testimony at hearing
Shop, Salem, Salem Chamber of
Commerce
22. Lauren A. Liss, Rubin and Rudman 11/1/13 emailed letter
LLP on behalf of Footprint Power 11/4/13 hard copy letter
Salem Harbor Development LP
23. Alison Miller, Salem Resident 11/1/13 emailed letter
24. Lynn Nadeau, HealthLink Oral testimony at hearing
11/1/13 emailed letter
25. George Pyros, Mitsubishi Power 10/1/13 emailed letter, 10/7/13 email
Systems Americas Inc.
26.Nancy Ramsden, Salem Resident 10/21/13 email
27. Sue Reid, Conservation Law Oral testimony at hearing
Foundation (CLF)
28. Wallace and Clare Ritchie, Salem 10/19/13 email
Residents
29. Stan Rogowski 10/20/13 email
30. Scott Silverstein, Footprint Power Oral testimony at hearing
Salem Harbor Development LP Presentation Slides received in 10/11/13 e-mail
31. Robert J. Wengronowitz, Boston 10/14/13 email
College Student
32. Dorian Williams, Medford Resident, A Oral testimony at hearing
Better Future Project
33. Ed Wolfe, Salem Resident I Oral testimony at hearing
34. Patricia Zaido, The Salem Partnership I Oral testimony at hearing
3
Changes to the PSD Permit
The following is the list of revisions that MassDEP made from the Draft PSD Permit to the final
PSD Permit based upon comments received. The list includes a brief description of the revision,
and the location in the RTC document and PSD Fact Sheet where MassDEP provides a more
detailed description of the revision.
• The Best Available Control Technology (BACT) analyses for all subject PSD pollutants,
for all emission units contained in the Applicant's PSD permit application have been
attached to the PSD Fact Sheet as Appendix 1 (pages 42— 105, below).
• All references to Lowest Achievable Emission Rate (LAER) have been removed from the
PSD permit and the PSD Fact Sheet, with exception that the reader is directed to the
MassDEP CPA Approval for an explanation of the LAER determination. LAER and
Nonattainment' review is a state regulated program, administered at 310 CMR 7.00
Appendix A. An explanation of these issues can be found in the MassDEP CPA Approval
concurrently issued with the PSD Permit for the SHR Project.
• Since all references to LAER have been removed from the PSD Permit and PSD Fact
Sheet, any comparison of LAER to BACT is no longer germane to the PSD Permit or
PSD Fact Sheet. However, a comment was received regarding the LAER and BACT
emission limits and associated control strategies. As such, this issue is addressed within
the BACT and LAER sections of this Response to Comments (RTC) document.
• MassDEP utilized the EPA October 1990 draft New Source Review Workshop Manual
and the MassDEP June 2011 BACT guidance document for the evaluation of BACT for
this project including the evaluation of energy, environmental and economic impacts of
all control options in its selection of BACT for each pollutant. Additional discussion of
this issue can be found in the BACT sections of this RTC document and the PSD Fact
Sheet.
• MassDEP does not have the electronic capability at this time to provide a "hyperlink" as
was suggested, to the Applicant's modeling analysis. MassDEP can provide CD/DVD
copies of the modeling analysis for the proposed SHR Project upon request.
• To ensure that the National Ambient Air Quality Standards (NAAQS) and PSD
increments are protected in all instances, MassDEP has compiled information on the
applicable background concentration levels, the NAAQS and applicable Significant
Impact Levels (SILs). This information can be found in the RTC document page 18,
Table B. The Applicant provided comment (November 1, 2013) and also provided
technical information (December 11, 2013 supplemental application submittal) to
MassDEP from the combustion turbine vendor, General Electric (GE), pertaining to
emissions of particulate matter (PM) and carbon monoxide (CO). The turbine vendor
indicated that PM emissions, project wide, could be reduced by approximately 25 percent
from the levels contained in the Draft PSD Permit. Specific PM emission reductions
could be obtained at various operating scenarios. (See Attachment 1, Table A-1,
highlighted text.) The turbine vendor has also supplied new performance data that show
that CO will be controlled to less than 2.0 parts per million by volume, dry basis,
corrected to 15% 02 (ppmvdc) at the minimum emission compliance load and that with
greater loads the CO emissions will not exceed 8.0 lbs/hr with and without duct firing.
4
This emission cap is achievable because the turbines are able to operate more efficiently
under higher load conditions. The Applicant also corrected an error in its calculation of
CO emissions during start up and shut down. The Applicant incorrectly assumed that if
the plant were shut down on Friday night and restarted on Monday morning this would
result in a cold start(a startup after a shutdown of more than 72 hours) rather than a warm
start (a start up after a shutdown of approximately 60 hours). Since warm starts result in
lower CO emissions than cold starts, this correction reduced the plant's annual CO
emissions. In addition,-in response to public comments, MassDEP required the Applicant
to include an oxidation catalyst on its proposed auxiliary boiler (EU3), further reducing
facility wide CO emissions. Taken together, these actions have resulted in the reduction
of facility-wide CO emissions, to 88 tons per year (tpy), a level that is below the PSD
significance level of 100 tpy. This 88 ton per year limit on CO emissions is set forth in
the CPA Approval issued concurrently with the PSD Permit and is a federally
enforceable limit. As a result, CO emissions are no longer subject to PSD review and the
PSD Permit no longer contains limits for CO emissions.
• Pollutants listed in the Draft PSD Permit and Draft PSD Fact Sheet have changed. The
Draft PSD Permit and Fact Sheet listed all PSD pollutants and included other non-PSD
pollutants. All non-PSD pollutants have been removed from the PSD Permit and PSD
Fact Sheet. Furthermore, the reduction in CO emissions to 88 tons per year (tpy), below
CO PSD significance level of 100 tpy, eliminated CO from PSD review. In addition,both
SO2 and VOC are proposed to be emitted at less than their PSD Significance levels; thus
SO2 and VOC have also been removed from the PSD Permit. PSD Applicability for the
proposed SHR Project is now limited to regulating nitrogen oxides (NO.), particulate
matter(PM/PMIe/PM2 5), sulfuric acid mist(H2SO4) and Greenhouse Gases (GHG).
• As mentioned above, the BACT analyses are attached to the PSD Fact Sheet and
identified as Appendix 1. Each emission unit's PSD applicable pollutants have been
reviewed and evaluated for BACT. MassDEP has reaffirmed its acceptance of BACT for
each PSD applicable pollutant for the proposed SHR Project.
• The Draft PSD Fact Sheet erroneously contained the startup and shutdown emission
limits of 23 and 29 lbs, per event, respectively, for PM/PM10/PM2.5 which are actually
the startup and shutdown emission limits for VOC (see August 6, 2013 supplement to
Application, Plan Approval, and PSD Permit). This has been corrected in the PSD Fact
Sheet.An error was also found with respect to the BACT emission limits for the auxiliary
boiler. The Draft PSD Fact Sheet erroneously contained a BACT H2SO4 emission limit of
0.0010 lb/MMBtu instead of 0.0001 lb/MMBtu as stated in the Draft PSD Permit and
Proposed Plan Approval (See December 21, 2012 Application, Appendix B and August
20, 2013 supplement to the Application). This has been corrected in the PSD Permit and
PSD Fact Sheet.
• With the addition of the oxidation catalyst on the auxiliary boiler (EU3) come collateral
impacts on H2SO4 emissions. The oxidation catalyst has the potential to convert an
additional quantity of SO2 to H2SO4_ Therefore, there is an increase in the sulfuric acid
(H2SO4) emission limit for the auxiliary boiler from 0.0001 lb H2SO4 pounds per million
British thermal units (Ib/mmBtu) to 0.0009 lb H2SO4/mmBtu. This H2SO4 emission limit
has been reviewed by MasDEP and determined to be BACT for H2SO4 for EU3. This is
reflected in the PSD Permit emission limit table and the PSD Fact Sheet related to H2SO4
BACT emission limit.
5
• The PM/PMIo/PM2.5 BACT emission limit for the combustion turbines has been reduced
from 0.0088 lb/mmBtu to 0.0071 lb/mmBtu. The Applicant has provided 25 potential
operating scenarios at various seasonal conditions (differing ambient temperature,
ambient pressure and ambient humidity) during which the PM/PMIo/PM2 5 emission rate
varies from 0.0038 lb/mmBtu to 0.0071 lb/mmBtu. The Applicant states that at 0 degree
Fahrenheit the gas turbines can achieve the PM/PMIo/PM25 rate of 0.0038 lb/mmBtu and
at a high temperature of 105 degree Fahrenheit can achieve the PM/PMIo/PM2.5 of 0.0047
Ib/mmBtu. MassDEP has reviewed all of the submitted annual projected operating
scenarios for the proposed SHR Project, and all combustion turbine operating conditions
(duct burner firing and duct burner not firing) and as stated above, has determined that
0.0071 lb/mmBtu is BACT for PM/PMIo/PM2 5. This discussion may be found in the PSD
Fact sheet, the RTC below and in the PSD Permit emissions Table 2.
• BACT emissions limits for PM/PMIo/PM25 start-ups and shutdowns have increased from
the Draft PSD Permit. However, the PM/PMIo/PM2.5 emissions during start-up and
shutdown will never exceed the steady-state, non start-up/shutdown PM/PMIo/PM25
BACT emission limit in pounds per hour. Therefore, the modified PM/PMIO/PM2 5 start-
up/shutdown emission limits are determined to be BACT by MassDEP. The issue is
further explained in the PSD Fact Sheet and RTC sections pertaining to start-
up/shutdown emissions.
• Specific changes to the Draft PSD Permit are identified below.
o Section I. Reference to the EPA and MassDEP Delegation Agreement have been
removed.
o Section II. An oxidation catalyst was added to EU3 and is identified as PCD8.
o Section II. All reference to CO is removed from Table 1.
o Section III. Table 2. CO emission limits have been removed.
o Section III. Table 2. PM/PMIo/'M2.5 emission limits have been reduced.
o Section III. Table 2. VOC, SO2,NH3,smoke and opacity have been removed.
o Section III. Table 2. Start-up/shutdown PM/PMIo/PM2 5 emission limits have been
increased per event. (However, at no time will these emissions exceed
PM/PMIo/PM25 BACT governing steady state combustion turbine operations.)
o Section III. Table 2. Note 7. CO emissions have been eliminated.
o Section III. Table 2. Note 11. Additional information has been supplied regarding
PVEC CO2 emission factor verses proposed SHR Project CO2, and CO2 emission
factor.
o Section III. Table 2. Note 13. Discussion of BACT verses LAER stringency
removed.
o Section III. Tables 2, 3, 4 and 5. All references to VOC, CO, NH3, smoke and
opacity have been removed.
6
r
Responses to Comments
Prevention of Significant Deterioration (PSD)
A comment was received pertaining to PSD:
• "...a total of six pollutants emitted from this proposed gas power plant will be classified
....as having a significant emission rate....also classified as a `major source'...."
Response:
Under the PSD Regulations at 40 CFR 52.21, if the proposed source is one of twenty eight (28)
specific source categories listed at 40 CFR 52.2 1(b)(23), and it has the potential to emit 100 or
more tons per year (tpy) of one or more PSD pollutants, the applicant must obtain a PSD Permit.
Footprint's emission units fall under one of those 28 listed PSD categories. As such, the project
is classified as a major source on the basis of potential nitrogen oxides (NO.) emissions
exceeding 100 tpy and Greenhouse Gas (GHG) emissions exceeding 100,000 tons carbon
dioxide equivalent (CO20 per year. Therefore, the project must undergo the PSD review
process.
Once under PSD review as a major source, the substantive PSD review requirements, including
compliance with Best Available Control Technology (BACT), apply to the pollutants emitted at
major rates (NOx and GHG), as well as the other PSD-regulated pollutants which would be
emitted at or above their respective significant rates, as follows: PM (25 tpy), PM10 (15 tpy),
PM2.5 (10 tpy) and sulfuric acid mist(7 tpy).
Best Available Control Technologv (BACT)Analvsis
Several comments were received pertaining to the BACT analysis, including:
• "The Fact Sheet's BACT analysis only provided the results of the BACT analysis but not
the analysis itself."
• "...EPA recommends the MassDEP attach the applicant's BACT analysis as an appendix
to the Fact Sheet or include a hyperlink that links the Fact Sheet to the applicant's BACT
analysis."
• "...while Lowest Achievable Emission Rate (LAER) and BACT may result in similar
emissions rates for the pollutant under review, LAER and BACT are separate technology
standards used in different permitting programs with different policy and regulatory
requirements."
• "...a BACT analysis requires the, permitting agency to evaluate the energy,
environmental and economic impacts for any control option to determine if any
significant collateral impact exists that would preclude a control option to be selected as
BACT..."
• "the permit and application do not properly conduct BACT analyses..."
• "...PSD Permit establishes CO BACT without conducting the proper BACT analysis..."
7
• "...permit applications with lower CO and VOC permit limits are under review (2013
Cove Point LNG project)..."
• "...no explanation for VOC emissions increase during duct firing while CO does not
increase..."
• "...auxiliary boiler emission limits: 9 ppm NOx, 47 ppm CO, 11.8 ppm VOC; proposed
emission limits high, Delegation Agreement not followed for boiler BACT..."
• "...SCR would be BACT for the auxiliary boiler and consistent with MassDEP's 2011
BACT Guideline Document, Delegation Agreement not followed..."
• "...the Delegation Agreement was not followed re: PM BACT..."
• "...the draft/proposed permits establish a BACT limit for greenhouse gas emissions, ...,
it is unclear whether the project will achieve the same levels of efficiency and the heat
rate limits of recently permitted projects..."
• "...the permit references additional greenhouse gas emissions from nitrous oxide and
methane, but it does not appear to account for the methane and nitrous oxide emissions in
determining compliance with the emission limit for total GHGs..."
Response:
MassDEP has modified the appropriate section of the PSD Fact Sheet by removing reference to
LAER, since LAER is a separate technology standard that is not used in the PSD permitting
program.
The applicant performed a project-specific top-down BACT analysis in accordance with the
BACT analysis procedures cited in the PSD regulations at 40 CFR 52.21 and the "Agreement for
Delegation of the Federal Prevention of Significant Deterioration (PSD) Program by the United
States Environmental Protection Agency, Region I to the Massachusetts Department of
Environmental Protection" ("Delegation Agreement") with USEPA Region 1 (signed April 11,
2011).
The applicant's top-down BACT analysis is appended to the final PSD Fact Sheet as
Appendix 1. Based on MassDEP review, the analysis conforms to USEPA Guidance and results
in BACT determinations and emissions limitations consistent with the Draft PSD Fact Sheet and
Draft PSD Permit. The PSD Fact Sheet now refers to MassDEP's review of this analysis as the
basis for MassDEP's BACT, determinations. Please note that the applicant has obtained
emissions guarantees from the turbine manufacturer for carbon monoxide (CO) and particulate
matter (PM) emissions that are lower than those contained in the Draft PSD documents. The
final PSD Permit and PSD Fact Sheet reflect the revised lower PM values as enforceable BACT
emissions limitations. Since each turbine's hourly not-to-exceed CO value has been reduced, and
Footprint has been required to install, operate and maintain an oxidation catalyst on the Auxiliary
Boiler, allowable CO emissions from the Footprint proposal will now be less than the PSD
Significance level of 100 tpy; therefore, CO has been removed from the PSD Permit. In
addition, sulfur dioxide (SO2) and volatile organic compounds (VOC) have been removed from
the PSD Fact Sheet and PSD Permit since neither criteria pollutant will be emitted at or above its
applicable PSD significance level. Finally, since ammonia (NH3) is not a PSD pollutant, it has
also been removed from the PSD Permit. All of these air contaminants are however regulated by
the 310 CMR 7.02 Plan Approval which is being issued concurrently with the PSD Permit.
8
}
As stated above, MassDEP has added the applicant's BACT analysis to the final PSD Fact Sheet.
Please note, however, that MassDEP follows the guidance contained in the October 1990
USEPA draft New Source Review Workshop Manual at page B.B. It states that "...an applicant
proposing the top control alternative need not provide cost and other detailed information in
regard to other control options. In such cases the applicant should document, to the satisfaction
of the review agency and for the public record that the control option chosen is, indeed, the top,
and review for collateral environmental impacts." The USEPA Guidance goes on to state that
"[i]f the applicant accepts the top alternative in the listing as BACT, the applicant proceeds to
consider whether impacts of unregulated air pollutants or impacts in other media would justify
selection of an alternative control option. If there are no outstanding issues regarding collateral
environmental impacts,the analysis is ended and the results proposed as BACT."
BACT for CO and BACT for VOC are outside the scope of this PSD Permit,but are addressed in
the state issued 310 CMR 7.02 CPA Approval.
The Cove Point CO-and VOC emission limits referenced by commenters are only proposed
values, and are not permitted limits. Furthermore, each gas turbine has its own unique emissions
profile. The proposed Cove Point project would be subject to lower CO and VOC emissions
limits; however, the NOx limit is 25 percent higher than the proposed SHR Project (the Cove
Point NOx BACT of 2.5 ppm versus the SHR Project NOx BACT of 2.0 ppm). For the SHR
project,this increased NOx emission limit would equate to a potential NOx emissions increase of
36.2 tons per year(tpy)compared to the claimed potential increase of more than 20 tpy CO and 8
tpy VOC. More importantly, NOx emissions from the Footprint proposal must comply with
LAER as well as BACT; and MassDEP has determined that NOx LAER is 2.0 ppm, not 2.5 ppm
as required for the Cove Point proposal. Furthermore, if Cove Point were required to reduce its
NOx BACT from 2.5 to 2.0 ppm—as required by the SHR PSD Permit—it is a likely
consequence that the Cove Point CO and VOC emissions would increase. Given the case-by-
case nature of the BACT process, MassDEP has chosen to require a stringent NOx emission rate
as NOx BACT for the SHR Project at the expense of marginally higher CO and VOC BACT
limitations. The Applicant's BACT analysis evaluated the energy, environmental and economic
impacts of the interrelated control options for each pollutant. Upon review, MassDEP concluded
that the particular combination of emissions limitations contained in the PSD Permit is justified.
Please further note that, as a result of comments submitted by the applicant concerning CO
emissions from the GE turbines, the hourly, not-to-exceed CO emission limitation for each
turbine has been reduced from 11 pounds to 8.0 pounds. This revised limit results in less CO
emissions from the SHR project while maintaining the stringent NOx BACT emissions
limitation.
VOC emission limits increase during duct firing operation, as opposed to non-duct firing
operation, primarily due to the firing of additional fuel and the efficiency of the oxidation
catalyst. The applicant has provided data from their equipment vendor GE that VOC emissions
increase during duct firing operation because duct firing results in larger increases in the VOC
mass emission rate and concentration than in the CO emission rate and concentration. Oxidation
catalysts are less efficient for controlling VOC emissions than for CO emissions. Also as noted
9
above, VOC has been removed from the PSD Permit since allowable VOC emissions are below
the VOC PSD significance level.
Regarding the auxiliary boiler, a combined cycle gas turbine is not analogous to a standalone
boiler with respect to exhaust characteristics, technical feasibility of particular emissions
controls, or quantitative emissions concentrations or emissions factors. For example, each has
different combustion air demands, which lead to different volumetric flows through each type of
machine and therefore different achievable BACT emissions limits on a part per million (ppm)
basis. BACT for boilers (the SHR auxiliary boiler) was evaluated in accordance with the
Delegation Agreement, guidance contained in the October 1990 USEPA draft New Source
Review Workshop Manual and MassDEP's 2011 BACT Guideline Document.
GHG BACT has been addressed in the updated PSD BACT analysis for GHG emissions (Section
4.1.5 of the Applicant's December 11, 2013 submital) and that analysis has been appended to the
PSD Fact Sheet. The Footprint design thermal efficiency is 57.9 percent. Concern that this value
exceeds the proposed thermal efficiency values cited in a letter written by USEPA's Steven Riva
(Chief, Permitting Section, Air Programs Branch) addressing recently approved PSD Permits
concerning GHG emission values and thermal efficiencies is misplaced. The use of thermal
efficiencies is not a recommended regulatory requirement due to heat rate degradation, duct
firing operation/no duct firing operation, ambient temperature, cooling technology, and number
of start-ups and shutdowns. Thus the GHG BACT for the SHR Project is expressed in pounds of
CO2e per megawatt hour.
Furthermore, the GHG BACT emission limit is expressed as "CO2," rather than CO2. CO2,
incorporates all federally enforceable GHGs emitted from emission units at the proposed SHR
Project the including CO2, methane and nitrous oxide.
Particulate Matter(PM/PM,n/PM,0
Several comments were received pertaining to Particulate Matter emissions, including:
• "...MassDEP is forcing I million people to take on avoidable health risks every year for
the next 40 years to cover one to two years of a power shortfall that can be met with
existing power plants..."
• "... there is *no* safe level of particulate matter for atmosphere humans will be
breathing..."
• "...GE will now guarantee [lower] filterable plus condensable particulate stack emissions
for operating loads greater than MECL...this results in a 25% reduction in potential to
emit particulate matter..."
• "...distinguish between filterable and condensable limits for PM..."
• "...MassDEP has determined that the Footprint position regarding the PVEC (Pioneer
Valley Energy Center) emission limit of 0.004 lb/MMBtu has merit and concludes that
the PM emission rate of 0.0088 lb/MMBtu represents BACT for PM/PM10/PM2.5."
10
}
Response:
The Footprint ambient air quality impacts study documented that worst case PM25 emissions
from the proposed SHR Project (plus a conservative background value, plus interactive sources
located nearby to the proposed SHR Project Site) will comply with the health based PM25
National Ambient Air Quality Standards (NAAQS). Also, please note that Footprint requested a
"25 percent lower" PM2,5 emission limitation as BACT for PM2 5 for its turbines. This lower
PM2.5 BACT emission limit is contained in the PSD Permit.
All of the PM/PM10/PM2 5 emissions limitations contained in the Plan Approval and PSD Permit
include filterable and condensable PM. Filterable PM will be measured via USEPA Reference
Test Method 201A and condensable PM will be measured by USEPA Reference Test Method
202. As long as the sum total of both PM species is at or below the PM2,5 BACT emission
limitation, the facility will be in compliance with that standard.
MassDEP has evaluated the PM emission limits and guarantees for the Pioneer Valley Energy
Center (PVEC) provided by Mitsubishi Power Systems Americas, Inc. (MPSA) for the
M501GAC gas turbine utilizing ultra dry low NOx (DLN) combustors. To date, there is no
empirical data available to MassDEP supporting the 0.004 Ib/mmBtu emission limit. A review of
the recently available GE combustion turbine data indicates that the PM/PMI0/PM25 emission
rate at various operating scenarios and ambient temperatures varies from a low of 0.0038
lb/mmBtu to 0.0071 lb/mmBtu. For the reasons more fully set out in the PSD Fact Sheet,
MassDEP has lowered the PM/PM10/PM2.5 BACT value in the PSD Permit and the Plan
Approval to 0.0071 lb/mmBtu based on its GE Energy 107G Series 5 Rapid Response Combined
Cycle Plant emission data.
Footprint expects to operate the gas turbines in various operational configurations throughout the
calendar year experiencing seasonal fluctuations in ambient temperature, pressures and humidity,
all of which have an effect upon gas turbine performance and emissions. To be responsive to the
Independent System Operator (ISO) —New England (NE) requirements to generate electricity,
the SHR Project.
must be capable of operating at all seasonal conditions and responsive to various electric ower
P P g P p
demands. As such, GE Energy provided updated performance data for the GE Energy 107F
Series 5 Rapid Response CCP. The PM/PM10/PM2.5 emissions data across the entire operating
range at various seasonal atmospheric conditions will vary from a low of 0.0038 lb/mmBtu to
0.0071 Ib/mmBtu. MassDEP believes that the PM/PM10/PM25 emissions range of 0.0038 to
0.0071 Ib/mmBtu represents an accurate PM emissions profile for the gas turbine under the
proposed operational scenarios and anticipated seasonal conditions in the Salem area.
Footprint's gas turbine vendor, GE, has indicated that there are operating scenarios where the
PM emissions are less than the PVEC PM emission limit of 0.004 lb/mmBtu. However, there
are other operating scenarios having PM emissions greater than 0.004 Ib/mmBtu. Based upon a
review of available PM/PM10/PM2 5 emissions data from the EPA's RBLC (RACTBACT/LAER
Clearinghouse), the PVEC PSD permit and application and the emissions data provided by GE
Energy, MassDEP has determined that the PM/PMio/PM25 emission limit of 0.0071 lb/mmBtu
11
represents BACT for PM. This PM/PMIO/PM2,5 BACT emission limit properly governs these
emissions over all proposed SHR project operational scenarios.
Lowest Achievable Emission Rate (LAER)
(Outside the Scone of PSD Permit-Pertains Solely to State CPA Approval)
Two comments were received pertaining to the LAER technology standard, including:
• "...the auxiliary boiler has an ultra low NOx burner on it but it doesn't look like LAER
was considered when they were selecting the burners..."
• "...Lowest Achievable Emission Rate (LAER) and BACT may result in similar
emissions rates for the pollutant under review, LAER and BACT are separate technology
standards used in different permitting programs with different policy and regulatory
requirements..."
Response:
MassDEP has supplied ambient ozone monitoring data to USEPA demonstrating that the
Commonwealth is attaining the 75 ppb ozone NAAQS. Though having data showing attainment
would normally mean that LAER was no longer required in permitting decisions, MassDEP has
retained the provisions requiring LAER in our regulations and therefore, SHR is subject to
LAER.
The NOx emission limits for the auxiliary boiler and emergency RICE (reciprocating internal
combustion engine/generator set and fire pump) represent LAER. There were no more stringent
applicable SIP emission limitations, no projects found with lower emissions performance
achieved in practice, or lower emissions limits set in permits on the basis of LAER for RICE.
The Plan Approval language regarding LAER has been clarified as stated above.
MassDEP has modified the appropriate section of the PSD Fact Sheet by removing any reference
to LAER, since LAER is a separate technology standard that is not used in the PSD permitting
program. LAER is a technology standard utilized in the new source review permitting program
that exclusively reviews non-attainment pollutant permitting of major stationary sources. The
non-attainment review program is administered by MassDEP through the plan approval
permitting process (pursuant to Regulations 310 CMR 7.02 and 310 CMR 7.00 Appendix A).
Startup/Shutdown Operations (SU/SD)
Several comments were received pertaining to SU/SD operations, including:
• "...starting and stopping of the turbines which leads to significant amounts of emissions
to be dispersed into our neighborhoods... until the exhaust heats up to operating
temperature and the ammonia starts injecting into the selective catalyst during start-up..."
12
• "...during startups, the SCR system cannot be turned on until the temperature inside the
Heat Recovery Steam Generator (HRSG) at the SCR grid reaches a temperature of
approximately 575 deg F... combined-cycle units can often take as long as 180 minutes
to reach this temperature..."
• "...the Siemens SGT6-5000F turbine emits up to 24 lb of NOx over a 12 minute start-up
period and 15.44 lb/hr after the MECL is reached and therefore, 36.4 lb/hr of NOx during
an hour that includes a startup..."
• Elevated amounts of emissions during start-up and shutdown of these turbines differ
between submittals provided in charts by the Energy Facilities Siting Board (EFSB) dated
July 12, 2013 and MassDEP's, Table 3 of the PSD Draft Fact Sheet.
• "...Gas turbine start-up and shutdown NOx emissions, Delegation Agreement not
followed re: BACT for start-up and shutdown emissions..."
Response:
Combustion turbine NO, emission rates during startup are affected by the temperature of the
SCR catalyst. In order for the SCR catalyst to be effective in controlling NO,emissions, it has to
reach and maintain a temperature in the range of approximately 550 to 650 Degrees Fahrenheit
prior to the introduction of ammonia to control NO, emissions and to minimize emissions of
unreacted ammonia. Prior to this point, called the minimum emissions compliance load (MECL)
which is the point when the SCR catalyst temperature and other SCR system parameters are
satisfied for SCR operation, NO, emissions are essentially emitted uncontrolled. Therefore, it is
advantageous from an emissions standpoint to have rapid response turbines with quick-start
capability like the GE and Siemens turbines that were under consideration for the Footprint
project, i.e.,turbines that reach the MECL in a minimum amount of time.
MassDEP acknowledges that the GE 7FA turbines proposed for the Footprint project emit up to
93.5 pounds (lb) of NO, during an hour that includes a startup, given restricted NO, emissions of
no more than 89 lb per startup event over a period not to exceed 45 minutes. However, note that
this emission rate is only true for a "cold" startup. The applicant has indicated in their plan
submittal that there will be no more than 13 cold startups per year. Startups may be cold,
"warm", or"hot" with diminishing emission rates and duration,respectively, before the MECL is
reached and the turbine would then be allowed to emit NO, at no more than 18.1 pounds per
hour(lb/hr)for the GE 7FA turbines.
The comment states that the Siemens SGT6-5000F turbine emits up to 24 lb of NO, over a 12
minute start-up period and 15.44 lb/hr after the MECL is reached and therefore, 36.4 lb/hr of
NO, during an hour that includes a startup. The comment does not state whether this NO,
emission rate for the Siemens turbine is for a cold, warm, or hot startup. Based on MassDEP's
review of the information submitted in Footprint's application, the Siemens 5000F turbine
cannot achieve the 36.4 lb/hr of NO, for any startup condition. Expected emission rates and
durations for warm and hot turbine startups, and shutdowns, are lower than the emission rate and
duration for cold startups. Similarly, the emission rates and durations of a simple cycle turbine
startup are not comparable to those of a combined cycle turbine like the GE 7FA turbines
proposed for the SHR Project. MassDEP requested that Footprint provide a comparison of the
startup emission rates and durations for the GE and Siemens combined cycle turbines, as
13
addressed in the August 6, 2013 supplement to the Footprint Application. A comparison of the
GE and Siemens NO, startup and shutdown emission data is provided in Table A below. Only
the cold start conditions mean the GE turbine emits higher NO.. However, if one would evaluate
a "full cycle," that being a shutdown and cold startup, the GE turbine is lower emitting for NO,
than the Siemens unit.
TABLE A
Comparison of,GE and'Siemens� 7T
NO. Startup/Shutdown Emissions Data
(PouMs of NOx per Event)
EVENT GE 7FA 'Siemens 5060F' Difference
Cold Start 89 83 6
Warm Start 54 79 -25
Hot Start 28 58 -30
Shutdown 10 20 -10
Older generations of combined cycle gas turbine power plants could take as long as two to three
hours to complete a "cold" startup. However, Footprint has chosen to use the newest generation
of GE turbines. GE guarantees that these turbines will meet the following parameters: a cold
startup takes no longer than 45 minutes to complete; a "warm" startup takes no longer than 32
minutes to complete; a "hot" startup takes no longer than 18 minutes to complete; and a
shutdown takes no longer than 27 minutes to complete. The shorter startup and shutdown periods
reduce emissions substantially.
The conservative ambient air quality impact analysis protocol required under the state and
federal air quality permitting processes must include consideration of worst case air pollutant
emissions during turbine startup and shutdown periods. Footprint demonstrated, via use of
computer dispersion models which have been approved by USEPA, that combustion turbine
startup and shutdown emissions would not result in an exceedance of any applicable, health
based NAAQS.
MassDEP environmental engineers reviewed the original Footprint Power plan application and
the several supplemental submittals which were made to MassDEP in detail, including
information related to the SHR Project's turbines regarding startups, shutdowns and associated
emissions. MassDEP based the PSD Fact Sheet and PSD Permit SU/SD numbers on our review
of all of the data which was submitted to MassDEP. MassDEP received data from the applicant
14
y
on August 6, 2013 comparing the difference between GE and Siemens turbines for SU/SD
operations. Additional SU/SD emissions data was submitted by the Applicant on January 10,
2014. All of this SU/SD data was more recent than the data provided to EFSB.
Stack Height
Several comments were received pertaining to the stack height, including:
• "...they lowered the stack height from the initial plans from 250 feet to 230 feet to save
money."
• "...the proposed stacks will be 230 feet high, much lower than the current stack heights
or even the best practices recommendation of over 300 feet..."
• "...the stack would be 20 feet lower then specs called for, which would also impact area
residents,particularly the children at the Bentley School..."
Response:
The federal PSD regulations at 40 CFR 52.21 and the Massachusetts Plan Approval Regulations
at 310 CMR 7.02 require that any applicant must, among several other things, demonstrate that
the worst case air emissions from their proposed emission unit(s) would result in compliance
with all applicable, health based, National Ambient Air Quality Standards (NAAQS). This
ambient air quality analysis requires the use of computer dispersion models which have been
reviewed and approved by USEPA. The inputs to these models include the use of: facility
parameters such as stack height, stack velocity, stack temperature, etc., representative
background concentrations of each NAAQS attainment pollutant as measured by the
Massachusetts ambient air monitoring network, representative meteorological parameters, and
the actual emissions of certain large emitters of those pollutants which are located in the area
proximate to the proposed facility's location. Footprint originally anticipated constructing a 250
foot stack for the proposed SHR project. However, Footprint's interactive, ambient air quality
impact analysis demonstrated that its worst case emissions from the 230 foot stack, plus
representative background concentrations, plus emissions from certain nearby large emitters of
these pollutants, demonstrates compliance with all applicable, health based NAAQS. Footprint
asserted in their Energy Facilities Siting Board (EFSB) filings that they would prefer a 230 foot
stack since it would represent an appropriate balance between air emissions impacts and visual
impacts.
Air Oualitv Disaersion Modeling and Ambient Monitorine
Several comments were received pertaining to the air quality dispersion modeling analyses and
ambient monitors, including:
• "...the air monitoring station (Lynn, MA.), that is being used as a model is not adequate
in representing the air quality for the area where the gas plant is to be built in Salem..."
15
• "...propose that MassDEP set up a sampling station, prior to issuing an air permit, in our
Salem neighborhood that both abut the power plant and the South Essex Wastewater
Treatment plant..."
• The Footprint modeling "...[did] not take into consideration anything regarding wind
shift..."
• "...very concerned that the proposed project will cause undo harm to those of us living
within the plume radius of such a gas plant..."
• "The June 2013 Second Supplement from Tetra Tech shows in Table 6-11 that the
predicted maximum 1 hr concentration for NO2 is 188 µg/m3: exactly equal to the
NAAQS for NO2. This value is higher than that of the September 9, 2013 PPA which
shows a predicted value of 166 µg/m3"
• "...there appears to have been a significant change to the analysis with respect to NO2. In
one of the earlier scenarios, the cumulative impact of the facility along with the
interactive sources appears to reach the 1-hour NAAQS for NO2, 188 µg/m3. See June
2013 revision with modeling for cumulative impacts at Table 6-11 shows that NO2
reaches 188 which is the NAAQS for NO2. They also appear to have changed the tons
[of NOJ per year from 150 to 148.8. However, the final Table 2 of the Proposed Plan
Approval shows a maximum impact of 166 ug/m3."
• "...the predicted ambient concentrations are so close to the NAAQS forces a scrutiny of
the modeling assumptions made..."
• "...reference to using an urban or rural designation relates to an outdated methodology
used in the predecessor model to AERMOD, ISCST..."
• "...disallow the conclusion presented by Footprint for the NO2 1 hour NAAQS based on
the misuse of EPA interpretations..."
• "... The interaction source impacts dominate the maximum total concentrations, so the
results were reviewed to confirm that the proposed SHR facility does not significantly
contribute to any modeled concentration at or above 105.7 ug/m3. This evaluation uses
the EPA default 80%conversion of NOx to NO2 ."
• "...the cumulative impacts (maximum 1-hour plus ambient background) for NO2 and
SO2 are well below the 1 hour health-protective NAAQS as well as other short-term
exposure guideline levels..."
• "...there are two small areas of isolated peak NO2 one-hour concentrations (in the range
of 36 to 42 gg/m3 and well below the NAAQS of 188 µg/m3). These are located very
close to the SHR Project site to the northeast and southwest of the power plant stack.
These areas are not close to any EJ areas..."
• "...the dispersion model used rural coefficients..."
• "...there was a release model for ammonia, and it looks like it uses the exact same model
to show the dispersion of the accidental release. And it seems a little weird to me to use
the same model..."
• "...the Draft PSD Fact Sheet only provided the results from the modeling analysis but not
the analysis itself..."
• "The use of Significant Impact Levels (SILs) alone as a screening tool to show
compliance with the National Ambient Air Quality Standards (NAAQS) and PSD
increments may not be adequate."
16
p
• "...why preconstruction monitoring as provided for through the PSD regulations was not
undertaken, why the monitors from Lynn and Harrison Avenue were considered
appropriate for estimating the impacts of this facility..."
• "...the modeling analysis is defective due to its use of Logan Airport meteorological data.
The specific geographic, wind, and other feature differences as between Logan airport
and the site that render it inappropriate for use in the modeling..."
• "The PPA states that a 3km radius surrounding the facility was used to determine
dispersion coefficients for use in AERMOD and states that rural coefficients were used.
In fact, EPA requires that the surface conditions (roughness length, albedo and Bowen
Ratio) within a 1 km radius of the anemometer used for dispersion analyses (in this case,
Logan Airport), be used as the basis for determining the roughness length used in the
model algorithms. The reference to using an urban or rural designation relates to an
outdated methodology used in the predecessor model to AERMOD, ISCST."
Response:
MassDEP's response to comments concerning air quality dispersion modeling and ambient
monitoring are presented in three sections below:
A. Responses concemine Ambient Backeround Concentrations/Monitors/Monitorine
Given its location on the southeast perimeter of the Lynn Woods Reservation, the immediate
surroundings of the Lynn air monitoring station are somewhat more rural than the immediate
surroundings of the SHR Project Site. However, the Lynn station measures regional air pollution
being transported to it from highly populated and industrialized areas located upwind within and
beyond Lynn, in a sector from the south to southwest of the station. This sector is the same as
the predominant prevailing winds in the area that would transport pollution into the Lynn area.
From a local perspective, as described in the PSD Fact Sheet, the data from the Lynn monitoring
site is considered to be conservative (i.e., has the potential to measure higher pollution
concentrations) because Lynn is a more industrialized and densely populated area than the
proposed project site area, particularly without the influence of the existing Salem Harbor
Station. Furthermore, the SHR Project Site is located adjacent to Salem Harbor, a large water
body where potential sources of air pollution are more limited. Therefore, MassDEP required the
applicant to use ambient monitoring data from the Lynn station for the most recently available
three calendar years 2010, 2011 and 2012.
Concerning the locations of the GE and Wheelabrator Plants with respect to the Lynn monitoring
station, these plants are south-southwest of the Lynn monitor. This location places the plants
within the south to southwest wind sector that would transport their emissions toward the Lynn
monitor. In addition, the GE and Wheelabrator plant emissions were included in the modeling
analysis, which means they have been explicitly accounted for over the distribution of possible
meteorological conditions. Also, the emissions from existing Salem Harbor Station for calendar
years 2010 and 2011 impacted the Lynn monitor when north and northeast winds prevailed
during those time periods.
17
a,
The South Essex Sewerage facility, located adjacent to the proposed SHR Project site, houses
several small boilers, emergency generators, water heaters, etc. Total air emissions from the
South Essex facility are less than 10 tons per year (tpy). Actual PMIo/PM25 emissions for
calendar year 2012 were 0.14 tpy, sulfur dioxide (SO2) emissions were 0.29 tpy, nitrogen oxides
(NO.) emissions were 3.3 tpy, and carbon monoxide (CO) emissions were 2.7 tpy. The South
Essex Sewerage facility is a minor source and has an insignificant contribution to the overall
impacts on ambient air quality concentrations in Salem.
MassDEP has compiled Table B (below) listing background ambient concentrations, the
applicable NAAQS, background minus NAAQS, and the applicable SIL. The table is presented
to address concerns that the initial modeling to determine impact significance/insignificance, and
therefore compliance with NAAQS/PSD Increments in the case of insignificant impact findings,
might not be adequate.
TABLE B
Difference BetweemNAAOS and Back round Concentrations
in Comaarison.to An6licalile SIL
Pollutant Averaging National Background Significant Difference
Time Ambient Air Concentration, -Impact Level l Between•
QualityBackground
Standard's f and NAAQS
(NAAQS)•,
PM2 5 - 24-hr -- 35 -- - 18.9 - 1.2 - - 16.1 -
Annual 12 7.2 0.3 4.8
PM10 24-hr 150 41 5 109
NO2 1-hr 188 82.3 7.5 105.7
Annual 100 19.3 1 - _80.7
Note: All concentrations are in micrograms per cubic meter.
In all cases, the difference between the NAAQS and background ambient concentration levels is
greater than the applicable SIL value. As such, EPA guidance notes that it would be sufficient in
most cases for permitting authorities to conclude that sources with impacts below the SIL values
will not cause or contribute to a violation of the NAAQS, and additional cumulative modeling is
not needed. MassDEP has taken the above approach, i.e. determined that there is no need for
additional modeling, in this case.
As described above, ambient monitoring data from MassDEP's Lynn monitoring site for the
three (3) year period of 2010 through 2012 were used to characterize background levels of
criteria pollutant ambient air concentrations. 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 modeled 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 C below, dispersion modeling conducted by the Permittee
18
predicted maximum proposed SHR Project impact concentrations well below corresponding
SMC levels for all pollutants for which SMCs exist.
TABLE C
1 Preconstruction,MonitoringAnalysis
Pollutant 'Averaging Period' Signiricant Monitoring- Mixiriium•PredictedYacility,
s 'Averaging
Impact(uglin');
(U�Iin 3j
NO2 Annual 14 0.4
SO2 24-Hour 13 0.7
PM10 24-Hour 10 4.3
CO _ 8-Hour 575 112.4
Table C Kev:
ughr'—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 PM25 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
PM25 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 SHR
Project, is representative of the proposed SHR Project 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 SHR
Project site, particularly without the influence of the existing Salem Harbor Station
after its shutdown and prior to the proposed SHR Project commencing operation. The
proposed SHR Project 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 SHR Project
19
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 SHR Project site via
predominant winds from the south or southwest, typically pass 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 SHR Project 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 SHR Project site. Therefore, the cumulative
modeling compliance demonstration, which includes 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.
B. Resnonses concerning Meteorological/Surface Characteristics/Land Use Model hinuts
The required air dispersion modeling analysis performed by Footprint regarding the SHR Project
is central to the overall air quality impact assessment performed for the Project. The modeling
work was thoroughly reviewed by MassDEP and found to be compliant with our Modeling
Guidance for Significant Stationary Sources of Air Pollution, as well as with EPA modeling
requirements for PSD Permit applications. The modeling addressed the impacts of pollutants
required under MassDEP and USEPA regulations and had the proper inputs to provide results
within the accuracy limits of the model. One input to the model is a 5 year meteorological data
set. The meteorological data used in the SHR Project analysis consisted of data collected over
the 5 year period from 2006 to 2010. The data set included surface-based measurements and
upper air measurements as required by the USEPA-approved meteorological preprocessor
(AERMET) to develop a suitable data input file for the USEPA-approved computer dispersion
model (AERMOD). The surface data was collected at the Logan Airport station in Boston,
which is the closest first order National Weather Station (NWS) to the SHR project, while the
corresponding upper air data was collected at the Gray, Maine NWS station. These locations are
considered representative of the project area and use of data from these locations is consistent
with MassDEP and USEPA guidelines. Once processed via AERMET, the meteorological data
included in the input files consisted of wind speed, wind direction, and ambient temperature as
well as other directly measured and derived variables. The data in these files are an hour-by-
hour representation of the meteorological conditions in the SHR Project area for the entire 5 year
period and reflect the hour by hour changes in conditions including varying wind directions (i.e.,
20
"wind shift'). Use of the developed meteorological data input files as required to run the
AERMOD model means that wind shift was in fact taken into account.
Regarding dispersion coefficients based on AERSURFACE parameters, certain inputs are
mandatory to properly execute the AERMOD model. These include the rural/urban designation
as well as the calculation of surface roughness length, Bowen Ratio, and albedo. The comment
is correct that surface roughness length, Bowen Ratio, and albedo are calculated by the
application of the utility program AERSURFACE to the, area centered on the location of the
meteorological data collection station (i.e., where the anemometer is located). In particular,
surface roughness length is determined based on land use out to a radius of 1 km from this
location. Bowen ratio and albedo are determined based on land use and other AERSURFACE
inputs over a 10 km by 10 km area centered on this location.
The 3 kilometer (km) radius and I km radius references are for two different types of inputs to
AERMOD. The urban versus rural designation is used to employ the correct dispersion
coefficients in the model; and it is a current methodology. The urban or rural designation is
required to properly execute AERMOD,just as it was for the predecessor model ISCST, and is
an option that is used directly in the model (in this case AERMOD). The designation of urban or
rural is based on land use within a radius of 3 km from the proposed new facility being analyzed.
The 1 km radius refers to land use in the area around the location of the meteorological data
collection station (in this case at Logan Airport) and is used to determine the surface roughness
length, as correctly mentioned in the comment. However, this is an input used in the utility
program AERSURFACE, which is a program that allows for the objective determination of
surface roughness, bowen ratio, and albedo in the area of the meteorological station. The output
data generated by AERSURFACE is used as input to the meteorological preprocessor AERMET.
Bowen ratio and albedo are objectively determined by AERSURFACE based on land use
classifications over a 10 by 10 kilometer area centered on the meteorological station, as well as
other inputs related to moisture conditions and precipitation types and amounts.
Due to the effects that urban areas have on meteorological conditions especially at night(e.g., the
urban heat island effect), the land area within 3 km of a proposed project must be assessed using
the Auer method in order to classify it as an urban or rural land use designation. This
designation is mandatory to correctly run the proper dispersion model and obtain accurate,
useable results. In the Auer method, certain land use classifications are associated with the urban
designation, and all the others default to rural. Bodies of water are considered to be rural. Using
the Auer method, the designation for the entire SHR Project area is based on whether the 3 km
area is 50%or more urban. If it is,the urban option is selected in the model and urban dispersion
coefficients are used in the modeling. Otherwise, the rural dispersion option is selected. Based
upon the Auer method and the actual land use in the area within 3 km of the proposed SHR
Project,rural dispersion was properly selected for use in the modeling.
C. ReSDonses concemina Modeline Process and Results
The Application included a conservative predictive analysis of the maximum ambient
concentrations of criteria pollutants (i.e., pollutants regulated by a health based National
21
Ambient Air Quality Standard or NAAQS) and'air toxics (pollutants regulated by MassDEP's
Air Toxics Guidelines), which are used to evaluate potential human health risks from exposures
to chemicals in ambient air that might result when the SHR Project operates. The analysis
shows, and MassDEP concurs, that worst case emissions from the SHR Project will not violate
any of the applicable NAAQS or MassDEP's air toxics long-term Allowable Ambient Limits
(AALs) for carcinogens or short-term Threshold Effects Exposure Limits (TELs) air toxics
guidelines for non-carcinogens.
The 188 ug/m3 impact value incorrectly reported in the June 2013 Second Supplement was based
on the most conservative approach that assumes 100% conversion of NO.to NO2 in the ambient
air (the Footnote for Table 6-11 in the June Supplement incorrectly stated that an 80%
conversion rate was used). A 100% conversion assumption is overly conservative and not
realistic. The 166 ug/m3 NO2 concentration in the Proposed PSD Permit is the predicted impact
shown by the dispersion modeling analysis and relied on for the demonstration of compliance
with the 1-hour NO2 NAAQS. The modeled cumulative impacts represent an EPA-approved Tier
2 approach reflecting an 80 percent conversion of NO, emissions to NO2 in the ambient air.
"Tier 2" is the Ambient Ratio Method for NO, to NO2 conversion of AERMOD modeling
results. It specifies that the results of NO,modeling be multiplied by an empirically-derived
NO2/NO,ratio, using a value of 0.75 for the annual standard and 0.8 for the 1-hour standard.
This modeling guidance is contained in USEPA's Clarification Memo, dated March 1, 2011,
"Additional Clarification Regarding Application of Appendix W Modeling Guidance for the 1-
hour NO2 National Ambient Air Quality Standard". When considering how the 166 ug/m3
impact was derived (project impacts plus interactive source impacts plus ambient air background
concentration), the value of 105.7 ug/m3 has, no meaning. It is associated only with the
incorrectly reported 188 ug/m3 impact.
MassDEP properly accepted the conclusion presented by Footprint for the 1-hour NO2
compliance demonstration since the modeling was correctly performed in accordance with EPA
policies and guidance.
The change in the final cumulative impact of the proposed facility for 1-hour NO2 is not related
to the slight change in the expected potential to emit. The basis for the revision is explained
above in detail.
The nature of modeling as part of an air quality impact assessment for regulatory compliance is
such that many assumptions and elements of the overall analysis lead to results that are overly
conservative. Another way of saying this is that due to the conservatism of the analysis, the
margin of compliance with the NAAQS will actually be greater than shown because the real
world impacts will be lower. One example of the conservatism applied in the analysis is the
assumption used for the conversion of NO, to NO2 as previously described. Another element of
conservatism, also previously described, is the inclusion of GE Lynn and Wheelabrator Saugus
as interactive sources in the modeling while also using background ambient air concentrations
from the Lynn ambient monitor, which itself is impacted by emissions from these two facilities.
Furthermore, additional interactive sources were included in the modeling assuming that they
operate continuously at their maximum allowed emission rates when in reality they only operate
for a fraction of the total hours in a year.
22
,
One comment also mentions the possibility that increased emissions from the SHR Project or
from any of the interactive sources (or increased emissions from newly constructed nearby
sources) could result in a situation where the NAAQS are violated. The way the proposed SHR
Project will be allowed to operate and the way the interactive sources are currently allowed to
operate under their existing operating permits is already fully reflected in the impact assessment
by virtue of modeling the maximum allowable emission rates. If any of these facilities adds a
new emission source or modifies an existing source that results in an increase of emissions then
there are MassDEP and USEPA regulations in place to address this. This might include
additional project modeling to show that any new emissions do not have significant impacts on
existing air quality or cumulative modeling to demonstrate compliance with the NAAQS. The
regulations in place and the modeling requirements associated with them are there to ensure that
NAAQS violations do not occur, while at the same time allowing facilities the flexibility to make
necessary operating and business decisions as long as they comply with all applicable Air
Pollution Control Regulations.
When the term "significantly contribute" is used in assessing model-predicted impacts of NOZ, it
refers to whether or not the SHR Project is contributing over or under the Significant Impact
Level (SIL) of 7.5 ug/m3. Only the total impacts from the SHR Project plus interactive sources
that contain a contribution of 7.5 ug/m3 or more from the SHR Project need to be considered
when evaluating whether the SHR Project will cause or contribute to a NAAQS violation.
Notably, the test for "significance" can often come into play twice in an air quality impact
assessment for a pollutant such as NO2 that has a 1-hour NAAQS. The first test of significance
is always employed as it is used to define the significant impact area (SIA) of a proposed new
facility on a pollutant by pollutant basis. The SIL for 1-hour NO2 is 7.5 ug/m3 and it is assessed
based on the maximum impact at each individual receptor in the modeled receptor,grid. If the
impact is 7.5 ug/m3 or greater, that receptor then becomes part of the SIA. Once the SIA is
defined, that area is subject to a cumulative modeling analysis that includes appropriate
interacting sources and background air quality data. In order to receive a permit or plan
approval, a proposed project's air impacts must be documented to be in compliance with the
appropriate NAAQS. This second phase of modeling is assessed against the NAAQS using the
form of the standard, which for 1-hour NO2 is based on model-predicted daily maximum impacts
at the 98th percentile value for each receptor (in the model this represents the 8th high value as
opposed to the maximum value).
The second test of significance comes into play when the total impacts are dominated by the
interacting sources rather than those of the proposed facility. So the second test of significance is
not always used. In this case it was used, because the existing interacting sources dominated the
overall impacts. Given that, the results from the cumulative modeling analysis must be reviewed
to determine whether the proposed SHR Project is contributing to the cumulative impacts at a
level equal to or higher than the NO2 SIL (7.5 ug/m3). If determined to be above the SIL
cumulative impacts are assessed against the 1-hour NO2 NAAQS. For this modeling analysis,
with the assumption of an 80% conversion rate, this amounted to a single receptor where the
total impact was 166 ug/m3. The SHR Project's contribution to this cumulative impact is 7.8
ug/m3.
23
The description of the model-predicted 1-hour NO2 concentrations with respect to impacts in
Environmental Justice or EJ areas and health effects, as contained in the PSD Fact Sheet and as
reproduced in one of the comments MassDEP received, is factually based. The modeling was
performed in accordance with all applicable MassDEP and USEPA guidelines for this type of air
quality impact assessment.
With respect to the accidental release of ammonia, the ammonia emission rate was appropriately
determined via the Areal Locations of Hazardous Atmospheres (ALOHA) accidental release
model. The comment is referring to the AERMOD model. AERMOD was also used to assess
the dispersion of ammonia in the air in the unlikely event that there is an accidental release. The
maximum amount of ammonia that could be released into the air (as opposed to the amount
staying in the diked area within the enclosure) is the emission rate used in AERMOD.
MassDEP has made available copies of the complete cumulative dispersion modeling analysis in
electronic format (CD/DVD) as part of the public record, they may be obtained by request; this
has been noted within the PSD Fact Sheet.
Non-Attainment Review—310 CMR 7.00 ADDendix A- Offsets
(Outside the Scone of PSD Permit-Pertains Solely to State CPA ADDroval)
Two comments were received pertaining to the NOx emissions offsets, including:
• "Allowing Footprint Power to use these credits to produce electricity does not mitigate
the fact that they will be emitting tons of toxic emissions from their exhaust stacks on a
local level into our neighborhoods."
• "...Footprint is purchasing credits from Rhode Island for a plant already slated for
shutdown... it is illustrative of the problems Footprint faces to comply with disease-
causing emissions and does not address local exposure to ozone and resulting illnesses
ozone causes to our community..."
Response:
The use of emission offsets for a proposal such as Footprint's is a legal and regulatory
requirement. Instead of being allowed to net out of the requirements for emission offsets,
Footprint is using emissions offsets for its worst case NOx emissions, at a 1.26 to 1.0 emission
offset ratio, as required by Regulation 310 CMR 7.00-Appendix A.Use of emission offsets at the
above ratio is required so that the affected airshed experiences a net air quality benefit.
24
Greenhouse Gas (GHG) and Global Warmine Solutions Act(GWSA)
(Outside the Scone of PSD Permit Pertains Solely to State CPA ADorovah
Numerous comments were received pertaining to Greenhouse Gas (GHG) emissions and the
Global Warming Solutions Act(GWSA), including:
• CO2 is a pollutant because of its role in anthropogenic global warming. CO2 is known to
have considerable negative effects as we increase its atmospheric concentration (as well
as in oceans).
• Proposed plant will emit 2.5 million TPY of CO2 and will be a "major contributor" in
violating the GWSA.
• Proposed plant is "essentially against the law......will "generate more pollutants than
allowed by a state law mandate......will run for 40 to 60 years.
• Allowing construction of the plant with its CO2 and methane emissions "cannot be
justified with the goals and hopes of the GWSA"
• Concern re: guarantees that the plant will meet the conditions of the GWSA.
• There is no evidence in the record to support MassDEP's proposed Section 61 Findings
that this project is consistent with the GWSA. Only analysis MassDEP appears to rely on
is the CRA analysis, which covered only through 2025 and was riddled with flawed
assumptions. No indication that Footprint presented any information on GHG impacts
through 2050.
• MassDEP has a special obligation under GWSA because of requirement to promulgate
regulations establishing declining annual aggregate emission limits for sources/categories
of sources by January 1, 2012,to go into effect by January 1. 2013 through December 31,
2020. G.L. c. 2IN, § 3d; St. 2008, c. 298, § 16. MassDEP's failure to promulgate
regulations does not excuse sources of categories from being required to meet mandates
of GWSA.
• Footprint is not thinking about the 2050 deadline and has not provided adequate
information depicted in any way to comply with emission reduction targets that we need
in 2050.
• Constructing a $900 million natural gas plant keeps funding and focus away from
investment in green energy technologies ... much of the $900 million "will be
contributed by the ratepayers" ... use the $900 million to build renewable energy sources
such as windmills on the Cape.
• Given the climate change trajectory which we are on, building a new natural gas plant is
"insignificant and insufficient" to meet the crisis we face. We must invest in
conservation, efficiency and alternates such as solar and wind.
• Proposed plant should be compared with conservation and energy reduction.
• Request to see studies review by EFSB that indicates that the proposed plan will reduce
the grid's reliance on higher emitting fossil plants, thereby reducing regional CO2 by
450,000 TPY, the equivalent of 103,000 cars.
• Massachusetts is a leader in the U.S. on reducing GHG, but being the best in the U.S.
does not relieve us of our responsibility globally.
• It is time for Massachusetts to finally take a pledge of "no new fossil-fired electric
generation".
25
• Concern that too large a percentage of New England grid is powered by natural gas units.
• Science is telling us that 40 years down the road, effects of global warming may include
agricultural drought, rising tides, etc.; "burden" will be placed on younger generation.
Consider your children when deciding whether to issue air permits that allow more GHG
to be put into the atmosphere.
• I support the proposed project because of the national and international emergency of
,climate change. Based on what we have seen, newer generation fast start combined cycle
gas turbine plants like this are really singularly the most important transitional technology
we have in the next thirty years, forty years, to get us where we need to go in terms of
reducing our carbon emission and decarbonizing our grid.
• Proposed plant will allow us to scale up renewables.
• Will take 25 years to build national high voltage DC infrastructure required to transmit
renewable energy all over the US, and to really scale up renewable energy sources.
• If we only have the older generation natural gas plants running, that is worse, given the
climate emergency.
Response:
MassDEP notes the many comments and concerns that have been submitted during the public
hearing and public comment process regarding GHG emissions from the proposed plant and
compliance with the GWSA. MassDEP agrees that global warming and climate change impacts
are serious concerns and is dedicated to fulfilling all its obligations under the GWSA.
Since 2008, Massachusetts has been a national leader with respect to global warming and climate
change.' In December, 2010, then Secretary of Executive Office of Energy and Environmental
Affairs (EEA) Ian Bowles established a legally binding statewide GHG emission limit of 25 (%)
percent below statewide 1990 GHG emission levels by 2020. In the Determination of
Greenhouse Gas Emission Limit for 2020, issued on December 28, 2010, Secretary Bowles'
2020 Determination outlined a portfolio of policies designed to achieve the 2020 statewide
emission limit. Since the adoption of the 2020 emission limit, the EEA and its agencies have
implemented numerous policies to ensure that the 25%reduction is reached.
MassDEP encourages interested persons to follow the Commonwealth's progress under the
GWSA by following the GHG Dashboard which can be found at http://www.mass.Qov/eea/air-
water-climate-chan ue/cl imate-change/massachusetts-global-warming-solutions-act/elobal-
warming-solutions-act-dashboard.html. Among other information, this site provides periodic
updates on the state's progress under the GWSA, including progress toward meeting the 2020
goals, GHG trends and related information. In addition, EEA recently released the five year
progress report on the GWSA which can be found at
http://www.mass.gov/eea/docs/eea/gwsa/ma-pwsa-5vr-progress-report-1-6-14.ndf
'In 2008,Governor Deval Patrick signed the GWSA into law,making Massachusetts one of the first states in the nation
to move forward with a comprehensive program to address climate change. In addition,several other clean energy laws
were enacted in Massachusetts in 2008,including the Green Communities Act,Oceans Management Act,Clean Energy
Biofuels Act and the Green Jobs Act.
26
Pursuant to Section 7 of the GWSA and G.L. c. 30, § 61, the proposed project has been reviewed
extensively and comprehensively with respect to GHG emissions and GWSA compliance by the
Massachusetts Environmental Policy Act (MEPA) unit of EEA, the Energy Facilities Siting
Board (EFSB), and MassDEP. The MEPA environmental review process and the EFSB
proceedings have resulted in determinations and findings that the proposed project's GHG
emissions are in compliance with applicable state laws and requirements, including the GWSA.
MassDEP agrees that when issuing permits, licenses or other approvals for projects that require
an Environmental Impact Report (EIR), MassDEP is required to consider reasonably foreseeable
climate change impacts, including GHG emissions, and effects such as predicted sea level rise.
G.L. c. 30, § 61. In this case, MassDEP considered the reasonably foreseeable climate change
impacts of the proposed facility by actively participating in the MEPA environmental review
process. See MassDEP Comments on the Environmental Notification Form dated August 28,
2012, MassDEP Comments on the Draft Environmental Impact Report(DEIR) dated January 28,
2013, and MassDEP Comments on the Final Environmental Impact Report (FEIR) dated
May 13, 2013. In these comments, MassDEP pointed out the need for the SHR Project
Proponent to ensure that there will be additional on-site and off-site mitigation as the remainder
of the site is developed. To ensure that this need is addressed, MassDEP recommended that the
Secretary require that the Notices of Project Change (NPCs) for such future development of the
site include an analysis of the impacts of GHG emissions. MassDEP also recommended that the
SHR Project Proponent include mobile sources in its greenhouse gas analysis. The FEIR, the
MEPA Certificate on the FEIR, the Public Benefits Determination, and the SHR Project
Proponent's Proposed Section 61 Findings reflect, among other things,MassDEP's comments.
On June 10, 2013, the SHR Project Proponent revised its Proposed Section 61 Findings and
submitted them to the Secretary as required by the Secretary's Certificate on the FEIR. MassDEP
incorporated the SHR Project Proponent's Revised Section 61 Findings in its Proposed Plan
Approval.
To respond to the public comments on the SHR Project's GHG emissions and compliance with
the GWSA, MassDEP carefully examined the detailed applications for a Plan Approval and a
PSD Permit, the ENF, the DEIR, the FEIR, the MassDEP comments and the Secretary's
Decision on the SHR Project Proponent's MEPA filings, the SHR Project Proponent's Revised
Section 61 Findings incorporated in the Proposed Plan Approval, and the EFSB Decision in the
Approval to Construct Proceeding EFSB 12-2. As a result of this review, MassDEP has
incorporated all the GHG mitigation measures needed to ensure compliance with the GWSA as
determined by the Secretary and the EFSB in the Section 61 Findings in the Plan Approval.
MassDEP concludes that the SHR Project as authorized by the Plan Approval including the
GHG mitigation measures set forth in the Modified Section 61 Findings is consistent with the
GHG reduction targets established by the GWSA.
Secretary Richard K. Sullivan, Jr. issued several documents that summarize and reflect the
extensive GHG-related review that took place during the MEPA Environmental Review and the
Public Benefits Determination Process including: the August 28, 2012 Certificate on the ENF,
the January 26, 2018 Certificate on the DEIR, the May 17, 2013 FEIR Certificate and the
June 17, 2013 Public Benefits Determination. The Secretary discussed the GHG analysis in the
27
FEIR Certificate (at pages 10-13) and stated that the SHR Project Proponent's GHG analysis is
consistent with Massachusetts GHG Policy. In addition, required mitigation measures to address
GHG emissions are summarized in the FEIR Certificate (at pages 21-22). The FEIR Certificate
also required the SHR Project Proponent to submit a revised summary of GHG emissions
(referred to as Table 3-1). On June 10, 2013, the SHR Project Proponent submitted the revised
Table 3-1 as required.
Subsequently, consistent with the provisions of An Act Relative to Licensing Requirements for
Certain Tidelands, Secretary Sullivan issued the Public Benefits Determination, finding that the
proposed SHR Project will have a public benefit. Among other considerations, the Secretary
considered environmental protection and preservation, specifically determining that the proposed
SHR Project has been designed to avoid, minimize and mitigate associated impacts including the
impacts of GHG emissions by inter glia its choice of fuel and technology, installation of a solar
photovoltaic (PV) array, and incorporation of energy efficiency measures into the design of the
Administration and Operation Buildings.
The Public Benefits Determination (at pages 6-7) sets forth a summary of the measures that the
SHR Project Proponent will implement to avoid, minimize and mitigate GHG emission impacts.
These measures include compliance with the Regional Greenhouse Gas Initiative (RGGI). To
comply with RGGI, the SHR Project Proponent is required to obtain and retire one CO2
allowance for each ton of CO2 the SHR Project emits. Massachusetts auctions nearly 100% of
the RGGI allowances and is required to invest at least 80% of those auction proceeds in energy
efficiency measures in the Commonwealth. These energy efficiency measures will yield GHG
emission reductions. The Public Benefits Determination estimates that the SHR Project
Proponent would be required to pay$4,000,000 per year for the necessary allowances.
The Public Benefits Determination states that in addition to obtaining the RGGI allowances, the
SHR Project Proponent will implement the following measures to mitigate the impact of its GHG
emissions:
• Use of combined cycle natural gas turbines;
• Solar PV array with potential to offset 175 tons per year of GHG emissions;
• Measures designed to ensure that 56.5 tons of GHG reductions will be achieved
each year, or 29%, from Administrative Building and Operations Building:
■ 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
z This amount may underestimate the yearly cost of such allowances. It is estimated that the Proponent will have to
obtain 2,000,000 allowances per year. The current cost of each allowance is approximately$3.00. At a cost of$3.00 per
allowance,the Proponent will have to pay approximately$6,000,000 per year for the required allowances. The cost of
allowances is projected to increase in response to the promulgation of new regulations which reduce the cap on
greenhouse emissions. See 310 CMR 7.70.
28
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), and water conserving fixtures; and
■ Submission to the MEPA Office of a Certification by the SHR Project Proponent
indicating that all of the measures proposed to mitigate GHG emissions or
measures to achieve equivalent GHG reductions have been implemented.
Some comments suggest that Massachusetts should take a pledge of"no new fossil-fired electric
generation." MassDEP acknowledges those comments, but notes that such comments are
beyond the scope of the Department's review in this matter. MassDEP further notes that the
GWSA does not prohibit the construction of new fossil fuel facilities. Indeed, M.G.L. c. 21N, §
9 expressly provides; "Nothing in this chapter shall preclude,prohibit or restrict the construction
of a new facility or the expansion of an existing facility if all applicable requirements are met
and the facility is in compliance with regulations adopted pursuant to this chapter." Consistent
with this provision, the Massachusetts Clean Energy and Climate Plan for 2020 (CECP)
assumes that the existing coal burning facility in Salem would be shut down and the energy
previously generated by Salem would come from natural gas fired plants located somewhere in
Massachusetts.3
The Secretary's FEIR Certificate determined that the proposed SHR Project is consistent with
the CECP for 2020 and the GWSA. In the FEIR Certificate,the Secretary specifically noted that
the CECP for 2020 expressly relies on RGGI and the replacement of the energy generated by the
existing coal burning plants in Salem and Somerset with energy generated by natural gas fired
plants to help meet the state's goal of reducing GHG emissions by 25%by 2020. The Secretary
pointed out that DE1R included an analysis that showed that by displacing energy generation by
dirtier plants, the SHR Project would reduce regional GHG emissions by 457,626 tons per year
(tpy)4.
Like the Secretary, the EFSB concluded that the proposed SHR Project would lead to an overall
reduction of GHG emissions by displacing less efficient sources. The EFSB recognized that the
CECP for 2020 envisioned the possibility that the existing coal burning plant in Salem could be
replaced by a natural gas fired plant and that natural gas could be a bridge to a clean energy
future. Thus, the EFSB determined that construction of the proposed SHR Project is consistent
with the 2020 goal.
' The 2020 Climate Plan further assumed that this change in energy production would reduce CO2 emissions by
872,262 metric tons per year.
4 In the DER the Proponent stated that the proposed facility would reduce CO2 emissions by 457,626 tons per year.
This number is based on a study done by Charles River Associates provided as Appendix C of the DEIR. In its
comments on the DEK the Department of Energy Resources questioned this number. In the Final Decision in the
Approval to Construct Proceeding,EFSB 12-2,the EFSB concluded that that the proposed facility would result in a net
reduction of regional GHG emissions,but acknowledged that the exact amount of the reduction is uncertain.
29
The EFSB further noted that the CECP for 2020 includes two scenarios for achieving the goal of
reducing GHG emissions by 80% by 2050. Scenario One is based primarily on eliminating the
use of fossil fuels. Scenario Two is based on maximizing efficiency and conservation. The
EFSB noted that Scenario Two represents a plausible scenario in which the proposed SHR
Project could operate into the future without preventing the Commonwealth from meeting the
2050 goal.
The EFSB also recognized that additional measures may be required to ensure that the
Commonwealth meets the 2050 goal. Accordingly, the EFSB put the SHR Project Proponent on
notice that it would have to comply with evolving regulations to meet the GWSA targets. The
EFSB stated its commitment to ensure that evolving GHG policies and regulations are addressed
fully.
Some comments point to, or appear to rely on, a specific section of the GWSA (G.L. c. 21N,
§ 3d; St. 2008, c. 298, § 16) to oppose the issuance of a Final Plan Approval or PSD Permit for
the proposed SHR Project. In pertinent part,the GWSA provides at c. 21N, § 3(d):
The department shall promulgate regulations establishing a desired level of
declining annual aggregate emission limits for sources or categories of sources
that emit greenhouse gas emissions(emphasis added).
In the context of reviewing whether the'proposed SHR Project meets applicable state and federal
requirements that govern issuance of a Plan Approval and issuance of a PSD Permit, the
commenters' reliance on § 3(d) is misplaced. In any event, MasDEP has fully complied with
section 3(d). Among other things, on December 9, 2013, MassDEP has issued final regulations
that impose a new regional cap on carbon dioxide emissions from fossil fuel fired electric
generation. See 310 CMR 7.70. Under these regulations, emissions of CO2 will be limited to 91
million tons in 2014. The annual cap will be reduced 2.5% per year from 2015 through 2020.
This will result in an annual regional cap of 78 million tons in 2020. These regulations, and
similar regulations and statutes in the other eight RGGI states, will ensure that emissions from
power plants in 2020 are approximately half of their 2005 totals. These declining annual
aggregate limits ensure that power plants will comply with the reduction goals in the CECP for
2020, and that reductions within the electric generating sector are much steeper than the overall
25%reduction called for in the CECP for 2020.
30
Non-Attainment Review—310 CMR 7.00 ADDendix A
Public Benefits and Alternatives Review
(Outside the Scone of PSD Permit.Pertains Solelv to State CPA ADDroval)
Several comments were received pertaining to Public Benefits and Alternatives Review,
including:
• "...Footprint repeatedly and erroneously attempts to compare the added emissions [from]
this new plant to a plant that will have been closed for two years. Correctly compared to
the baseline of zero emissions, the added pollutants and greenhouse gases are a threat to
the community..."
• "...Removing the old plant facility, remediating the property and reusing the site such
that tax revenues and jobs are replaced has total support... there is considerable local
disagreement that the way to meet those economic goals is to burden Salem and the
region environmentally with a new fossil fuel plant..."
• "Given the high volatility of natural gas prices, occasional restricted availability in winter
months, the warnings in the study that financing, costs of demolition and remediation
alter the economic viability of such a power plant, the touted economic benefits of tax
revenues and jobs must be disallowed as reasons to support this proposal."
• "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... Footprint falsely presents this proposed plant as a replacement for the
coal plant..."
• "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...no wind development
under proposal is dependent on this plant being built..."
• "Footprint makes no attempt to measure the cost burden for citizens to deal with the
health costs from exposure to PM2.5 and ozone."
• "...Footprint has made no plans to develop the rest of the site, an economic drain on the
city."
• There will not be an increase in jobs associated with the Footprint project, but rather a
decrease local long term employment opportunities. Gas plants employ far fewer
employees than office buildings and other industrial uses for the same amount of land
needed for the Footprint project.
• MassDEP accepted the CRA analysis of the potential greenhouse gas emissions impacts
of the facility without examining the underlying assumptions... MassDEP should have
conducted a more thorough analysis of the claims and studies provided by the project
proponent..."
Response:
MassDEP has treated the Footprint proposal as a new facility. With regard to emissions of NOx,
Footprint will fully comply with all applicable Nonattainment New Source Review requirements
31
including the requirement to obtain offsets at a 1.26 to 1.0 offset ratio and Lowest Achievable
Emission Rate. MassDEP has not allowed Footprint to obtain credit for any reductions in
emissions that result from the shutdown of the existing coal burning power plant in 2014. As set
forth in the CPA Approval, MassDEP determined that Footprint adequately demonstrated that
the "benefits of the proposed source significantly outweigh the environmental and social
costs..."
Footprint's demonstration that the benefits of the proposed Facility outweigh its costs is
supported by the determinations made by the Secretary of EEA and the EFSB with regard to the
SHR Project. On May 17, 2013, Secretary Sullivan, pursuant to the MEPA (G.L.c.30, ss.61-62I)
and Section 11.08 of the MEPA regulations (301 CMR 11.00), issued the Certificate for the
FEIR No. 14937 for the SHR Project. In addition, on June 17, 2013, Secretary Sullivan issued a
Public Benefits Determination concluding that the SHR Project will have a positive public
benefit. Furthermore, EFSB issued a Decision on October 10, 2013 for the SHR Project
approving the petition of Footprint Power Salem Harbor Development LP to construct a 630 MW
natural gas-fired, quick-start, combined-cycle facility at the present location of the Salem Harbor
Station in Salem, Massachusetts. For the reasons set forth in the foregoing documents, the SHR
Project adequately demonstrates that the "benefits of the proposed source significantly outweigh
the environmental and social costs."
Health Imnacts
Several comments were received pertaining to Health Impacts, including:
• "...studies often fail to be reflective of the real risks of pollutants and particulate
matter..."
• "...do not believe the models offered to date provide a true picture of the risks the
proposed 690MW gas burning plant poses for our community..."
• "...[Footprint] claims improvements compared to the existing plant..."
• Several other collateral health impacts comments may be found in sections addressing
startup/shutdown operations, stack height, modeling, offsets, public benefit/alternatives
review,particulate matter,BACT and LAER.
Response:
The federal PSD regulations at 40 CFR 52.21 and the Massachusetts Plan Approval Regulations
at 310 CMR 7.02 require that any applicant must, among several other things, demonstrate that
the worst case air emissions from their proposed emission unit(s) would result in compliance
with all applicable, health based, attainment National Ambient Air Quality Standards(NAAQS).
This ambient air quality analysis requires the use of computer dispersion models which have
been reviewed and approved by USEPA. The inputs to these models include the use of:
representative background concentrations of each NAAQS attainment pollutant as measured by
the Massachusetts ambient air monitoring network, representative meteorological parameters,
and the actual emissions of certain, large emitters of those pollutants which are located in the
area proximate to the proposed facility's location, and the worst case air emissions from the SHR
32
r
Project. Footprint's interactive, ambient air quality impact analysis demonstrated that its worst
case emissions, plus representative background concentrations, plus emissions from certain
nearby large emitters of these pollutants, would result in compliance with all applicable, health
based NAAQS.
With respect to possible harm to public and environmental health and welfare, the application
included a conservative predictive analysis of the maximum ambient concentrations of criteria
pollutants (i.e.,pollutants regulated by a National Ambient Air Quality Standard or NAAQS) and
air toxics (pollutants regulated by MassDEP's Air Toxics Guidelines) that might result when the
project operates. The analysis shows, and MassDEP concurs,that worst case emissions from the
SHR Project will not violate any of the applicable NAAQS or MassDEP's air toxics long-term
Allowable Ambient Limits (AALs) for carcinogens or short-term Threshold Effects Exposure
Limits (TELs) air toxics guidelines for non-carcinogens. (Please see pages 15-17 of 60 inclusive
of the Footprint CPA Approval.)
Environmental Justice(EJ) Evaluation
Several comments were received pertaining to Environmental Justice, including:
• Based on the statement from Footprint, "The dispersion modeling completed for the SHR
Project demonstrates that the predicted maximum impacts from the Facility for the
majority of criteria air pollutants are below the SILs at all locations and therefore,
represent no adverse human health or environmental effects to Salem and outlying
communities..... Footprint evaluated these as a way to determine if an EJ area would be
disproportionately subject to higher air impacts than other segments of the community at
large. "
• "...there is no safe level of PM2.5 and they themselves point out exceedances of PM2.5,
it is clear there are health impacts."
• Based on the statement from Footprint, "The Proposed SHR Facility is not located in or
adjacent to an EJ area, and Footprint has demonstrated that there will be no
disproportional impact to any such community. Indeed, the proposed facility will be an
improvement over emissions from the existing facility, and will reduce regional
emissions of NOx, SO2 and CO2 to the benefit of all area residents. Footprint has
demonstrated that emissions from the proposed SHR facility itself will be well within the
NAAQS,which are designed to be health-protective of the most sensitive populations."
• "..the proposed facility is adjacent to an EJ community..."
• "...compare the increased emissions to a plant that will have been closed for two years
such that the baseline for comparison should be zero emissions.......At 188 NAAQS with
the proposed facility contributing 22.2% of the total 188, they are hardly "well within"
NAAQS."
Response:
The 166 ug/m3 NO2 concentration in the Proposed Plan Approval is the actual predicted impact
shown by the dispersion modeling analysis and relied on for the demonstration of compliance
33
with the 1-hour NO2 NAAQS. It reflects a modeling methodology whereby NO2 is assumed to
be formed by an 80% conversion of the Project stack emissions of oxides of nitrogen (NO.). In
reality, the conversion of NOx to NO2 in the atmosphere is something that changes hour by hour
and is significantly controlled by the amount of ozone available in the air to allow the conversion
to occur. The actual conversion rate can be higher or lower than 80% and is often lower, so
assuming a constant conversion of 80% for all hours in an analysis yields a conservative result.
The 188 ug/m3 impact value reported in the June 2013 Second Supplement was based on the
most conservative approach that assumes 100% conversion of NOx to NO2 in the ambient air.
(The Footnote for Table 6-11 incorrectly stated that an 80% conversion rate was used). This
assumption is overly conservative and does not reflect the actual atmospheric chemistry that
occurs. Therefore, the original result was not an accurate reflection of what the analysis revealed
when the more realistic level of conservatism was applied.
The nature of modeling as part of an air quality impact assessment for regulatory compliance is
such that many assumptions and elements of the overall analysis lead to results that are overly
conservative. Another way of saying this is that due to the conservatism of the analysis, the
margin of compliance with the NAAQS will actually be greater than shown because the real
world impacts will be lower. One example of the conservatism applied in the analysis is the
assumption used for the conversion of NO,to NO2 as previously described. Another element of
conservatism, also previously described, is the inclusion of GE Lynn and Wheelabrator Saugus
as interactive sources in the modeling while also using background ambient air concentrations
from the Lynn ambient monitor, which itself is impacted by emissions from these two facilities.
Furthermore, additional interactive sources were included in the modeling assuming that they
operate continuously at their maximum allowed emission rates when in reality they only operate
for a fraction of the total hours in a year.
The comment also mentions the possibility that increased emissions from the SHR Project or
from any of the interactive sources (or increased emissions from newly constructed nearby
sources) could result in a situation where the NAAQS are violated. The way the proposed SHR
Project will be allowed to operate and the way the interactive sources are currently allowed to
operate under their existing operating permits is already fully reflected in the impact assessment
by virtue of modeling the maximum allowable emission rates. If any of these facilities adds a
new emission source or modifies an existing source that results in an increase of emissions then
there are MassDEP and USEPA regulations in place to address this. This might include
additional project modeling to show that any new emissions do not have significant impacts on
existing air quality or cumulative modeling to demonstrate compliance with the NAAQS. The
regulations in place and the modeling requirements associated with them exist to ensure that
NAAQS violations do not occur,while at the same time allowing facilities the flexibility to make
necessary operating and business decisions as long as they comply with all applicable Air
Pollution Control Regulations.
Furthermore, MassDEP has treated the Footprint proposal as a new facility, which it is.
MassDEP has not allowed Footprint to claim credit for any emission reductions that may result
from the shutdown of the existing coal burning plant in 2014. With regard to the emissions of
NOx from the SHR Project, Footprint must provide emission offsets, at a 1.26 to 1.0 offset ratio,
and keep its emissions at or below the Lowest Achievable Emission Rate as required by 310
34
CMR 7.00-Appendix A. Indeed, Footprint must fully comply with all applicable Nonattainment
New Source Review requirements. As a result, Footprint has, demonstrated to the satisfaction of
MassDEP that the "benefits of the proposed source significantly outweigh the environmental and
social costs."
Footprint properly modeled the impacts of the facility and determined that the emissions of the
facility would not contribute to a violation of the NAAQS or PSD increments. (See RTC section
Air Quality Dispersion Modeling and Ambient Monitoring Subsection C). As set forth in the
PSD Fact Sheet, the modeling demonstrates that the SHR Project's emissions of PM2.5 and NO2
will not have disproportionately high human health or environmental effects on EJ areas. As set
forth in the PSD Fact Sheet, EJ populations may,benefit from the reductions in regional GHG
emissions that will result from the SHR Project. As set forth in the CPA Approval, Footprint has
demonstrated to the satisfaction of MassDEP that the benefits of the SHR Project outweigh its
social and environmental costs.
Natural Gas (NG)
Several comments were received pertaining to Natural Gas, including:
• "Will the price of natural gas change the procedural protocol on how this plant will
operate?"
• "[bringing natural gas into Salem Harbor] would open up Salem Harbor to cruise ships; a
gas line would go under Fort Street - (a residential area) also that the pipe line is smaller
than the amount of gas that needs to go through it..."
• "[natural gas extraction via tracking technology]... addressing the threat of well-water
and groundwater contamination posed by fracking-related injections..."
• "...when I think of ships containing LNG coming into the busy harbor, I get so
frightened..."
• "A gas line would go under the residential area of Fort Street I understand, and the pipe
line is smaller than the amount of gas that needs to go through it."
• "There is no natural gas capacity currently at that site."
• "Will a pipeline need to be drilled under residential neighborhoods?"
• "Will LNG tankers need to deliver fuel through the harbor? Is Salem being targeted to
become an LNG port?"
• "With health and environmental risks associated with extracting natural gas via fracking,
we are clearly not ready for this plant!"
• "We do not have enough supply of natural gas."
Response:
The analysis of Footprint's application, which resulted in issuance of the Proposed Plan
Approval and Draft PSD Permit, was based upon combustion of natural gas only in the two
combined cycle gas turbines. Both documents contain enforceable conditions requiring that
solely natural gas be combusted in those turbines. Any change to the approved fuel of use would
35
require an entirely new filing, a new analysis, and if merited, the issuance of significant
modifications to the Plan Approval and PSD Permit.
The issues related to hydro-fracking, LNG storage and transport, and any natural gas supply or
pricing or delivery issues, are beyond the scope of MassDEP's review of the applications for
the Footprint PSD permit and CPA approval applications.
Use of Urea verses Ammonia
Two comments were received pertaining to the use of urea verses ammonia, including:
• "...tried several times to bring up the facts about using urea as opposed to aqueous
ammonia for emissions controls... tried to explain the dangers of using, transporting and
storing aqueous ammonia..."
• "...there is an alternative to ammonia by using a harmless urea solution..."
Response:
Neither the federal PSD Regulations nor the MA Plan Approval Regulations require MassDEP
to dictate the reagent to be used, in conjunction with Selective Catalytic Reduction, to control
NOx emissions from a proposed power plant. MassDEP is charged with ensuring that those
emissions will comply with Best Available Control Technology and Lowest Achievable
Emission Rate as applicable. MassDEP required Footprint to analyze the effects of a worst case
ammonia (NH3) spill involving the entire contents of the proposed NH3 storage tank. The details
of this analysis can be found on pages 20-22 of 60 inclusive of the Footprint CPA Approval,
section entitled "Accidental Release Modeling of Aqueous Ammonia (NH3)". Furthermore,
Footprint is subject to federal risk management planning and accidental release prevention
requirements for any on-site quantities of flammable and extremely hazardous chemicals listed
under 40 CFR 82, and under the General Duty Clause of the federal Clean Air Act, Section
112(r).
MassDEP has established health based ambient air guidelines for a variety of chemicals (air
toxics). These air guidelines establish two maximum impact limits for each chemical listed: an
Allowable Ambient Level (AAL), which is based on an annual average concentration; and a
Threshold Effects Exposure Limit (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. AALs and TELs are
expressed in micrograms per cubic meter (ug/m3). MassDEP required Footprint to demonstrate
that the worst case NH3 stack emissions from its proposal would not exceed MassDEP's air
toxics guidelines for NH3. Using the same USEPA reviewed and approved computer dispersion
models employed during the NAAQS analysis, Footprint's worst case NH3 emissions were
predicted to be: 0.034497 ug/m3 on an annual basis, versus an AAL of 100 ug/m3; and a worst
case 24 hour NH3 concentration of 1.093673 ug/m3 versus a TEL of 100 ug/m3.
36
Appeal Procedures and Venue
Two comments were received pertaining to the appeal procedures, including:
• A citizen requested to be informed regarding their rights to appeal the decision of the
Footprint air permit.
• "The Draft Prevention of Significant Deterioration Fact Sheet (the "Fact Sheet")
misstates the law regarding appeals of air permits.... MassDEP needs to clarify the venue
and procedure for appeals of its final PSD Permit Decision in a manner which conforms
to its codified enabling authority."
Response:
The final Plan Approval (for State Issued Permits and Approvals ONLY) includes the following
information regarding the applicable Appeal Process.
APPEAL PROCESS
This Plan Approval is an action of MassDEP. If you are aggrieved by this action, you
may request an adjudicatory hearing. A request for a hearing must be made in writing and
postmarked within twenty-one (21) days of the date of issuance of this Plan Approval.
Under 310 CMR 1.01(6)(b), the request must state clearly and concisely the facts, which
are the grounds for the request, and the relief sought. Additionally, the request must state
why the Plan Approval is not consistent with applicable laws and regulations.
The hearing request along with a valid check payable to the Commonwealth of
Massachusetts in the amount of one hundred dollars($100.00)must be mailed to:
Commonwealth of Massachusetts
Department of Environmental Protection
P.O.Box 4062
Boston, MA 02211
This request will be dismissed if the filing fee is not paid, unless the appellant is exempt
or granted a waiver as described below. The filing fee is not required if the appellant is a
city or town (or municipal agency), county, or district of the Commonwealth of
Massachusetts, or a municipal housing authority.
MassDEP may waive the adjudicatory hearing-filing fee for a person who shows that
paying the fee will create an undue financial hardship. A person seeking a waiver must
file, together with the hearing request as provided above, an affidavit setting forth the
facts believed to support the claim of undue financial hardship.
37
The PSD Permit is subject to requirements of the Delegation Agreement with US EPA, Region 1
to implement and enforce the federal Prevention of Significant Deterioration (PSD) regulations
as found in 40 CFR 52.21, the Code of Federal Regulations (CFR), 7-1-10 Edition, with
amendments.
The provisions in 40 CFR 124.19 will apply to all appeals to the EPA Environmental Appeals
Board (EAB) on PSD permits issued by MassDEP under the April 4, 2011 Delegation
Agreement, except with respect to permit conditions that do not derive from federal PSD
requirements, for which applicable Massachusetts administrative procedures apply. If a PSD
permit issued by MassDEP is appealed to the EAB, MassDEP has the primary responsibility for
defending the permit before the EAB and the discretion to withdraw the permit under 40 CFR
124.19(d).
MassDEP will notify the applicant and each person who has submitted written comments or
requested notice of the final permit decision of their right to appeal, and this notice is required to
state that for federal PSD purposes and in accordance with 40 CFR 124.15 and 124.19:
• Within 30 days after the final PSD permit decision has been issued under 40 CFR 124.15,
any person who filed comments on the draft permit or participated in any public hearing
may petition EPA's EAB to review any condition of the permit decision.
• The effective date of the permit is 30 days after sevice of notice to the applicant and
commenters of the final decision to issue, modify, or revoke and reissue the permit,
unless review is requested on the permit under 40 CFR 124.19 within the 30 day period.
• If an appeal is made to the EAB, the effective date of the permit is suspended until the
appeal is resolved.
A petition for review shall include a statement of the reasons supporting that review including
documentation that any issues being raised were raised during the public comment period
(including any public hearing)to the extent required by the PSD Program regulations, and when
appropriate a showing that the condition in question is based on (i) a finding of fact or
conclusion of law which is clearly erroneous or (ii) an exercise of discretion or an important
policy consideration which the EAB should review.
Procedures for appealing permits can be found at 40 CFR 124. More information on the appeals
process and the EAB can be found at http;//www.epa.gov/eab. The EAB Practice Manual can be
found at httn://www.ena.2ov./eab/nmanual.Ddf. The EAB website and the Practice Manual
should be carefully reviewed prior to filing an appeal.
Monitorine,Record Keeaine,and Reoortine
Several comments were received pertaining to monitoring, record keeping and reporting,
including:
• "Require PM CEMS instead of parametric monitoring for PM,"
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• "Limit of 0.5 grains/100 sef sulfur content in natural gas, but no particular method to
ensure continuous monitoring,reporting and compliance."
• "...recommend requiring that those monthly records be submitted to MassDEP on a
quarterly basis in addition to the semi-annual reporting requirement..."
Response:
Mt. Tom Station, a coal fired power plant, is required to install and operate PM CEMS as part of
a settlement agreement and not as a Plan Approval or Permit requirement; final technical details
concerning the operation of this PM CEMS have been resolved and the PM CEMS has just
recently become operational. Brayton Point, also a coal fired power plant, employs parametric
PM monitoring, not a PM CEMS. Palmer Renewable Energy (PRE) was originally proposed as
a construction and demolition (C&D) waste fired power plant. The PM CEMS was originally
required due to the proposed combustion of C&D waste and to also be used as a surrogate for the
heavy metals emissions that would have occurred as a result of combusting C&D waste. The
PRE proposal has subsequently been changed to combust clean biomass and is currently in
litigation concerning local zoning issues. The PRE facility has not yet been built, and therefore a
PM CEMS has not been installed nor operated. As opposed to the coal fired Mt. Tom power
plant and the proposed, but not yet built PRE biomass fired power plant listed above, the
proposed SHR Project is a natural gas only, combined cycle turbine, power generating facility.
The actual filterable and condensable, in-stack PM concentrations that a PM CEMS installed on
a natural gas turbine would measure is thus extremely small; and significantly smaller than the
in-stack PM-fine concentration that would be emitted by either a coal fired or biomass fired
emission unit. Natural gas fired combustion turbines with low PM emission concentrations
provide a challenging emissions monitoring environment. These exhaust streams are extremely
high volume, low concentration gas streams. MassDEP is of the opinion that the current PM
CEMS on the market have not demonstrated an ability to adequately measure PM over the long
term that enable them to be used in Massachusetts as a direct compliance monitor,particularly on
a natural gas fired only combustion turbine. Therefore, MassDEP did not require PM CEMS for
the proposed SHR Project. In addition, both the proposed PVEC and Brockton combined cycle
combustion turbine projects are not required to install PM CEMS.
With respect to sulfur content of fuel, Footprint Power is required by federal regulations to
comply with the monitoring requirements concerning the sulfur content of natural gas as
contained in 40 CFR 60 Subpart KKKK.
As the owner/operator of a major source of certain criteria air pollutants the SHR Project
owner/operator shall be required to submit semi-annual and annual compliance reports pursuant
to 310 CMR 7.00-Appendix C. hi addition, any facility which is required to install, operate and
maintain continuous emissions monitoring systems (CEMS). Footprint must employ NOx, CO
and ammonia CEMS, and an 02 CEMS as a reference gas. Footprint is also required to submit
quarterly CEMS excess emissions reports to MassDEP.
39
Noise
(State Only Renuirement—Not PSD Subiect)
One comment was received pertaining to noise:
• "How noisy would plant operation be for nearby neighbors? These gas burning units can
be as loud as jet engines. How will that impact our neighborhoods?"
Response:
The proposed SHR project is required to comply with the MassDEP noise guidance and ensure
the facility is not having an impact of greater than 10 dbA over existing ambient conditions. In
addition, Footprint was required to evaluate and incorporate best sound migration controls and/or
strategies to all sound producing activities associated with the proposed project. Please see
Section C-NOISE (State-Only Requirement) pages 47-51 of 60 inclusive of Plan Approval,
Application No. NE-12-022, which addresses all noise-related issues. The SHR project is
projected to increase sound by not more than 6 decibels above ambient background (where
background does not include operation of the existing coal and oil fired Salem facility.)
Article 97,
97`h Amendment to the Massachusetts Constitution
(State Only Renuirement—Not PSD Subiect)
Two comments were received pertaining to Article 97, including:
• "...the 97th Amendment to the State Constitution. The amendment reads: The people
shall have the right to clean air and water, freedom from excessive and unnecessary
noise, and the natural, scenic, historic, and esthetic qualities of their environment."
• "The people shall have the right to clean air and water, freedom from excessive and
unnecessary noise, and the natural, scenic, historic, and esthetic qualities of their
environment; and the protection of the people in their right to the conservation,
development and utilization of the agricultural, mineral, forest, water, air and other
natural resources is hereby declared to be a public purpose. The general court shall have
the power to enact legislation necessary or expedient to protect such rights."
Response:
The [Massachusetts] Department of Environmental Protection is the state agency responsible for
ensuring clean air and water, the safe management of toxics and hazards, the recycling of solid
and hazardous wastes, the timely cleanup of hazardous waste sites and spills, and the
preservation of wetlands and coastal resources. (This is MassDEP's Mission Statement).
40
To ensure a clean environment for the citizens of Massachusetts, MassDEP utilizes its regulatory
authority to review permit applications and issue approvals/permits that comply with state and
federal regulations/laws that protect and preserve the public health and welfare of the citizens of
the Commonwealth.
Opposition to the Proposed Footorint SHR Project
Several comments were received that pertain to opposition for the Proposed Footprint SHR
project, including:
• Approximately 22 parties/commenters provided comments and/or testimony in
opposition of the Proposed Footprint SHR Project.
Response:
MassDEP duly notes the opposition to the Footprint SHR project.
Support and Conditional Support for the Proposed Footprint SHR Project
Several comments were received pertaining to support and conditional support of the Proposed
Footprint SHR Project, including:
• Approximately 8 parties/commenters provided comments and/or testimony in support
and/or conditional support of the Footprint SHR project.
Response:
MassDEP duly notes the support and conditional support for the Footprint SHR project.
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APPENDIX
BEST AVAILABLE CONTROL ANALYSIS
(BACT)
APPENDIX A
EMISSIONS CALCULATIONS
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1.0 CONTROL TECHNOLOGY ANALYSIS
This section presents an updated PSD BACT analysis for the Project. This updated analysis addresses
comments made on the draft permit and reflects additional information and corrections. The Project
exceeds PSD significant emission thresholds for NO., PM/PM10/PM25, H2SO4, and GHG, and thus is
subject to PSD BACT for these pollutants. The Project does not exceed PSD significant emissions
thresholds for CO.
The Project remains subject to MassDEP BACT for all pollutants. The MassDEP BACT analysis as
reflected in the prior application materials and the MassDEP draft permit documents remains valid and is
not addressed here.This section specifically addresses PSD BACT requirements.
PSD BACT is defined in 40 CFR 52.21 means "an emissions limitation (including a visible emission
standard) based on the maximum degree of reduction for each pollutant subject to regulation under Act
which would be emitted from any proposed major stationary source or major modification which the
Administrator, on a case-by-case basis, taking into account energy, environmental, and economic impacts
and other costs, determines is achievable for such source or modification through application of
production processes or available methods, systems, and techniques, including fuel cleaning or treatment
or innovative fuel combustion techniques for control of such pollutant. In no event shall application of
best available control technology result in emissions of any pollutant which would exceed the emissions
allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Administrator determines that
technological or economic limitations on the application of measurement methodology to a particular
emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work
practice, operational standard, or combination thereof, may be prescribed instead to satisfy the
requirement for the application of best available control technology. Such standard shall, to the degree
possible, set forth the emissions reduction achievable by implementation of such design, equipment,work
practice or operation, and shall provide for compliance by means which achieve equivalent results."
Typically, PSD BACT follows a five step "top-down" approach: (1) identify all control technologies; (2)
eliminate technically infeasible options; (3)rank remaining control technologies by control effectiveness;
(4)evaluate most effective controls and documents results; and(5)select BACT.
However, a key exception to the strict, five-step "top-down" approach is described in page B-8 of the
EPA's October 1990 draft New Source Review Workshop Manual (the "NSR Manual," as cited in the
EPA comment letter):
If the applicant accepts the top alternative in the listing as BACT, the applicant proceeds to
consider whether impacts of unregulated air pollutants or impacts in other media would justify
selection of an alternative control option. If there are no outstanding issues regarding collateral
environmental impacts, the analysis is ended and the results proposed as BACT. In the event that
the top candidate is shown to be inappropriate, due to energy, environmental, or economic
impacts, the rationale for this finding should be documented for the public record. Then the next
most stringent alternative in the listing becomes the new control candidate and is similarly
evaluated. This process continues until the technology under consideration cannot be eliminated
by any source-specific environmental, energy, or economic impacts which demonstrate that
alternative to be inappropriate as BACT.
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1.1 Combined Cycle Combustion Turbines
1.1.1 Fuel Selection
Fuel selection is an important consideration with respect to all pollutants subject to PSD review for the
facility (NOx, PM/PM10/PM2.5, H2SO4, and GHG). Therefore, fuel selection for the combustion turbine
combined cycle units is initially discussed here,prior to the PSD BACT evaluation for the individual PSD
pollutants, instead of repeating this under the evaluation for each pollutant.
The Applicant proposes to use natural gas only for the combined cycle turbines.
Step 1.Identify all control technologies(fuel types).
Identified control technologies(fuel types)for combustion turbine combined cycle units are:
1. Use of natural gas only.
2. Primarily natural gas with liquid fuel as a backup fuel. Liquid fuel could be ultra-low sulfur
distillate(ULSD),biodiesel or a mixture of these.
Step2.Eliminate technically infeasible options
Both above fuel options are technically feasible. An acceptable mixture for ULSD/biodiesel is subject to
confirmation by turbine suppliers.
Step 3.Rank remaining control technologies by control effectiveness.
Natural gas is the lowest emitting commercially available fuel for combustion turbine combined cycle
units. ULSD and biodiesel have higher emissions than natural gas for NO, PM/PM10/PM25 and GHG.
H2SO4 emissions depend on the maximum sulfur content of the fuel. ULSD and biodiesel are normally
specified at 15 ppm sulfur by weight, and pipeline natural gas is defined by USEPA in 40 CFR 72.2 to
have a maximum sulfur content of 0.5 grains/100 scf. These values are effectively identical in the amount
of sulfur per MMBtu of fuel. However, natural gas as delivered is likely to have a lower actual sulfur
content per MMBtu of fuel compared to ULSD or biodiesel.
Since natural gas is a lower emitting fuel than ULS D or biodiesel, it ranks higher in terms of control
effectiveness and is considered the top BACT alternative.
Step 4:Evaluation of Collateral Impacts
Energy Impacts
Within the past decade,natural gas has become increasing abundant in the New England, due to increased
availability of domestic sources of gas. However, concerns have been raised regarding the lack of
regional fuel diversity and potential overreliance on natural gas for energy supplies. In particular, pipeline
infrastructure to deliver gas into New England can become constrained during cold weather as space
heating and electric production compete for available gas supplies. These issues have resulted in
considerations for more energy diversity and backup liquid fuel supplies for electric generation facilities.
Since the Applicant has committed to use natural gas exclusively in the combustion turbine combined
cycle units, potential energy concerns with exclusive natural gas use are an important consideration. The
Project will obtain natural gas from its direct connection to Algonquin's HubLine interstate natural gas
pipeline near HubLine's interconnection with the Maritimes & Northeast Pipeline. This unique
interconnection point permits the Project to access supplies of natural gas from both Canadian sources as
44
well as from domestic sources the south and west. The Maritimes & Northeast Pipeline has not had the
same physical delivery constraints as the heavily relied-upon pipelines delivering natural gas into New
England exclusively from the south and west. Therefore, energy concerns due to exclusive natural gas use
are not problematic for this Project.
Economic Impacts
Natural gas is currently a much more favorable economically compared to liquid fuels, and this situation
is expected retain this current pattern into the foreseeable future. With Footprint's access to Canadian
Maritime gas, potential short-term price spikes due to physical supply constraints are not expected to be
problematic. Therefore, there are no economic considerations that would dictate that backup provisions
for liquid fuel are necessary.
Environmental Impacts
In addition to being a higher emitting fuel for air emissions, liquid fuel has other significant collateral
impacts compared to natural gas. The most significant collateral impact is associated with the truck
delivery of liquid fuel to the site. Although liquid fuel could be delivered by barge as well, the local
community has expressed its strong opposition to the continued storage and combustion of liquid fuel on
the site for power generation. These impacts are of significant concern to the local Salem community, and
in fact have led to a commitment by the Applicant not to use liquid fuel for the combustion turbine
combined cycle units at the site.
The other collateral environmental impact of note is the fact that NO,control for liquid fuel requires the
use of water or steam injection to the turbine combustor. The use of water/steam injection would result in
a significant consumptive water use and an associated discharge of water that is not needed for dry low-
NO,combustors, which are available for natural gas.
Step 5.•SelectBACT
Use of natural gas as the exclusive fuel for the combustion turbine combined cycle units is clearly
justified as PSD BACT. Natural gas is lower emitting, has significantly lower collateral environmental
impacts,and collateral energy and economy impacts have been determined to be acceptable.
1.1.2 PSD Best Available Control Technology Assessment for NO,
Step 1.Identify Candidate Technologies
NO,control technologies identified for new large> 100 MW combined cycle turbines are as follows:
• Dry-low NO, (DLN) Combustion: Turbine vendors offer what is known as lean pre-mix
combustors for natural gas firing which limit NO, formation by reducing peak flame
temperatures.
• Water or Steam Injection: Water or steam injection has been historically used for both gas and oil
fire turbines,but for new turbines is generally only used for liquid fuel firing.
• Catalytic Combustors: A form of catalytic combustion to limit firing temperature has been under
development using the trade name XONON.
• SCONOx: This is an oxidation/absorption technology using hydrogen or methane as a reactant.
This technology is currently marketed as EMx.
45
• SCR: This is a catalytic reduction technology using ammonia as a reactant that has been in
widespread use on new combined cycle turbines for over 20 years.
Step 2:Eliminate Infeasible Technologies
Catalytic combustors are not currently technically feasible for large turbines. The only known application
is on a 1.4 MW test turbine. The largest turbine to which SCONOx has been successfully demonstrated is
a 43 MW turbine in California. There are significant SCONOx scale up questions for a new turbine larger
than 100 MW, but for the sake of argument SCONOx will be assumed to be technically feasible here.The
other technologies are all technically feasible.
Step 3:Rank Control Technologies by Control Effectiveness
The ranking of these technologies is as follows:
1. SCR: Widely demonstrated to have achieved 2.0 ppmvd NO, at 15% 02 for gas firing. This is
documented in the LAER analysis presented in the December 21, 2012 Application and First
Application Supplement(April 12,2013).
2. SCONOx: Demonstrated to have achieved 2.5 ppmvd NO, at 15% 02 at the 43 MW California
unit.
3. DLN: Generally recognized to achieve 9 ppmvd NO,at 15%Oz. Commonly used in conjunction
with SCR to achieve 2.0 ppmvd NO,at 15%02.
4. Steam/Water Injection: Less effective than DLN.
Step 4.•Evaluate Controls
Since Footprint is proposing the"top" level for NO,BACT(SCR),the BACT analysis can proceed to the
consideration of whether any collateral energy or environment impacts would indicate other than the top
demonstrated technology be selected.
The one collateral impact that has been identified for SCR is due to the use of ammonia as a reagent,and
the resulting emissions of ammonia"slip"that can occur. SCONOx does not require the use of ammonia.
While SCONOx will eliminate the use of ammonia, the lower NO, emissions demonstrated in practice
with SCR(2.0 ppmvdc vs. 2.5 ppmvdc for SCONOx)and the very high additional cost documented with
SCONOx does not justify a finding that SCONOx is BACT. This same conclusion is found in the EPA
Analysis for the Pioneer Valley Energy Center (PVEC), in the Fact Sheet published in December 2011.
SCONOx is not justified as BACT. In addition, as documented in the Application and supplements, the
predicted ambient air quality impacts for ammonia are well below the MassDEP air toxics guidelines.
Aqueous ammonia will be stored in a 34,000 gallon above ground tank located within a concrete dike
designed to contain 110% of the total tank volume. Passive evaporative controls will be used inside the
dike to control evaporation in the event of a release, and the tank and dike will be in a fully enclosed and
sealed structure except for roof vents. Evaluation of a hypothetical worst case release indicates that
ammonia concentrations at and outside the Project perimeter will be less than the ERPG-1 level.ERPG-1
is defined as the maximum airborne concentration below which nearly all individuals could be exposed
for up to one hour without experiencing other than mild transient adverse health effects or perceiving a
clearly defined,objectionable odor.
46
Step 5.•Sect BACT
The Footprint Project will meet the same 2.0 ppmvdc NO, limit as determined to be BACT for PVEC.
The Project will also meet a stringent emission limit for ammonia slip (2.0 ppmvdc on a 1-hour basis),
which is the most stringent ammonia limit achieved in practice for facilities of this type. This stringent
ammonia limit assures that collateral impacts are adequately minimized for the use of SCR for the
Footprint Project,and that this represents BACT for NO..
1.1.3 PSD Best Available Control Technology Assessment for PM/PM,01PM2.e
Emissions of particulate matter result from trace quantities of ash (non-combustibles) in the fuel as well
as products of incomplete combustion. Conservatively, all particulate matter (PM) emissions for the
combustion turbines are assumed to be less than 2.5 microns in size(PM,,).
Pursuant to identifying candidate control technologies under the "top-down" procedure, Footprint has
compiled all,the PSD BACT determinations in the last five years for new large (> 100 MW) combustion
turbine combined cycle project. This compilation is based on the USEPA RBLC (RACTBACT/LAER
Clearinghouse). Several recent projects not included in RBLC have also been included in this
compilation. The Brockton Energy Center Project in Brockton MA is also included, since it is a similar
recent project in Massachusetts, even though it did not receive a PSD permit. This review confirms that
the only BACT technology identified for large natural gas fired combined cycle turbines is use of clean
fuel(i.e.,natural gas)and good combustion practices.
For PM/PMio/PM25, this evaluation does not identify and discuss each of the five individual steps of the
"top-down" BACT process, since there are no post-combustion control technologies available for
PM/PM10/PM2.5. Post-combustion particulate control technologies such as fabric filters (baghouses),
electrostatic precipitators, and/or wet scrubbers, which are commonly used on solid fuel boilers, are not
available for combustion turbines since the large amount of excess air inherent to combustion turbine
technology would create adverse backpressure for turbine operation.
The "top-down" procedure does require selection of BACT emission limits, which is addressed in the
following paragraphs.
Table 1-1 presents the results of RBLC compilation for PM/PM10/PM2 5. A review of Table 1-1 indicates
that PM/PMio/PM25 emission limits are expressed strictly in lbs/hr or lb/MMBtu, or in both lb/hr and
lb/M Utu. This review also indicates that different emission limits can be associated with different
turbine suppliers. This is illustrated by some projects which have one set of limit for one supplier and
another set of limits for another supplier.
It is Footprint's conclusion based on review of available information that differences in PM/PMIp/PM2.5
emission limits among various projects are due to different emission guarantee philosophies of the
various suppliers, and are not actual differences in the quantity of PM/PMIOTMZ 5 emissions inherently
produced by the supplier of the turbine. The different emission guarantee philosophies are influenced by
the overall uncertainties of the PM/PM10/PM2.5 test procedures, especially given reported difficulties in
achieving test repeatability, and concerns with artifact emissions introduced by the general inclusion of
condensable particulate emissions (as measured by impinger based techniques) in permit limits in the last
decade.
47
Table 1-1. Summary of Recent Particulate PSD BACT Determinations for Large(>100MW)Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine' PM/PMIo/PM2.5 _
Carroll County Washington 11/5/2013 2 GE 7FA 12.4 lb/hr/unit and 0.0108 Ib/MMBtu without DF
Energy Twp., OH 2045 MMBtu/hr/unit plus 566 MMBtu/hr DF 19.8 Ib/hr and 0.0078 Ib/MMBtu with DF
Renaissance Carson City, MI SII 11/1/2013I 4 Siemens 501 FD2 units 9.0 Ib/hr/unit and 0.0042 Ib/MMBtu (with and without DF)
Power 2147 MMBtu/hr/unit each with 660 MMBtu/hr
DF
Langley Gulch Payette, IDI 08/14/2013 I 1 -Siemens SGT6-5000F 12.55 Ib/hr(w/and w/o DF)
Power 2134 MMBtu/hr/unit with 241.28 MMBtu/hr DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or Mitsubishi: 11.3 Ib/hr/unit and 0.00384 Ib/MMBtu without OF
Energy 2 Siemens SCC6-8000H Mitsubishi: 10.1 Ib/hr and 0.00373 Ib/MMBtu with DF
2932 MMBtu/hr/unit plus 300 MMBtu/hr DF Siemens: 14.0 Ib/hr/unit and 0.0055 Ib/MMBtu without DF
Siemens: 13.3 Whir and 0.0047 Ib/MMBtu with DF
Green Energy Leesburg,VA 04/30/2013 2 GE 7FA.05 GE: 0.00334 Ib/MMBtu at full load (w/and w/o DF)
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr DF or 9.6 Ib/hr/unit without DF
Stonewall 2 Siemens SGT6-5000F5 16.2 Ib/hr with DF
2260 MMBtu/hr/unit plus 450 MMBtu/hr DF Siemens:0.00374 Ib/MMBtu at full load (wl and w/o DF)
10.1 Ib/hr/unit without DF
14.5 Ib/hr with DF
Hickory Run New Beaver 04/23/2013 GE7FA, Siemens SGT6-5000F, Mitsubishi 11.0 lb/hr/unit without DF
Energy LLC Twp., PA I M501G, or Siemens SGT6-8000H. I 18.5 lb/hr/unit with DF
2 combined cycle units Emissions based on Siemens SGT6-8000H
SunburyI Sunbury, PA 04/0112013 I 2"F Class"
las "with/Dunit 0.00881b/MMBtu
Generation
WBrunswick County Freeman,VA 03!12/2013 3 Mitsubishi
Comb Combined GT and DF with
DF I 9.7
lb/hr/unit and 0.0033 lb/MMBtu without
DF
16.3 Ib/hr and 0.0047 Ib/MMBtu with DF
Powe
3442 MMBtu/hr/unit
Moxie Patriot LLCI Clinton Twp, PA 01/31/2013 2 472 oE458 MW combined spyecified le blocks with I 0.0057 Ib/MMBtu
DF
Garrison EnergyI Dover, DE 101/30/2013 I GE 7FA I 32.1 Ib/hr
Center 309 MW
St. Joseph EnergyI New Carlisle, IN + 12/03/2012 I 4 F Class"1345 MW or Siemens) I 15 Ib//hlb/hrtand and 0. 0 78 Ilb/ MBtuuwiwithout
h DF DF
Center
Hess NewarkI Newark, NJ 111/01/2012 I 2320 MMBtu/hr/un plus 2011 MMBtu/hr DF I 11 13 2rlb/hr without
with DF F
Energy
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 27.0 Ib/hr
Center, LLC I 180 MW lus
425 MMBtu/phr DF
48
Table 1-1. Summary of Recent Particulate PSD BACT Determinations for Large(>100MW)Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine PM/PMIO/PM2.5
Moxie Liberty LLC Asylum Twp., 10/10/2012 Siemens"H Class" 0.0057 Ib/MMBtu for 454 MW block
PA 2—468 or less MW combined cycle blocks 0.0040 Ib/MMBtu for 468 MW block
GT:s 2890 MMBtu/hr/unit
DF< 3870 MMBtu/hr/unit
Cricket Valley Dover, NY 09/27/2012 3-GE 7FA.05 0.005 Ib/MMBtu without DF
2061 MMBtu/hr/unit Dlus 379 MMBtu/hr DF 0.006 Ib/MMBtu with DF
Deer Park Energy Deer Park,TX 09/26/2012 1 -Siemens 501 F 27.0 Ib/hr
Center LLC 180 MW plus
725 MMBtu/hr DF
ES Joslin Power Calhoun, TX 09/12/2012 3-GE 7FA 18.0 Ib/hr
195 MW per unit
No DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501GAC 9.8 Ib/hr
Energy Center 2542 MMBtu/hr/unit; no DF 0.004 lb/MMBtu
(PVEC)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA 8.46 Ib/hr/unit and 0.0048 Ib/MMBtu without DF
Power 154 MW(1736 MMBtu/hr)per unit plus 11.3 Ib/hr and 0.0049 Ib/MMBtu with DF
500 MMBtu/hr DF
Thomas C. Llano,TX 09/01/2011 2-GE 7FA 18.0 Ib/hr
Ferguson Power 195 MW per unit
No DF
Entergy Ninemile Westwego, LA ( 08/16/2011 Vendor not specified 26.23 Ib/hr/unit without DF
Point Unit 6 Sinqle unit 550MW 33.16 Ib/hr with DF_ _
Brockton Power Brockton MA 07/20/2011 1 Siemens SGT6-PAC-5000F 17.4 Ib/hr
(MA Plan 2227 MMBtu/hr plus 641 MMBtu/hr DF 0.007 Ib/MMBtu
ADDroval)
Avenal Power Avenel, CA 05/27/2011 2-GE 7FA 8.91 Ib/hr/unit without DF
Center 1856.3 MMBtu/hr/unit plus 562.26 MMBtu/hr 11.78 Ib/hr with DF
J DF
E Portland
Carty Plant I Morrow, OR 12/29/2010 I 1 - Mitsubishi2866 M501 GAC 0.0083 Ib/MMBtu
Dominion WarrenI Front Royal, VAI 12/21/2010 I 2996 MMBtulh/unit pll M5 us 00 MMBtu/hr DF 01 GACB 014.0 lb/hr and 0.0040lb/MMBtu with DFDF
lb/hr/unit and 0.0027 lb/MMBtu without
County
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE: 19.80 Ib/hr/unit(w/and w/o DF)
Power Station 2430 MMBtu/hr/unit GT plus DF or Siemens: 11.1 Ib/hr/unit(w/and w/o DF)
4 Siemens SGT6-5000F5
2693 MMBtu/hr/unit GTplus DF
Live Oaks PowerI Sterling, GA I 03/30/2010 I Siemens SGT6-5000F - No emission limits specified.
PSD BACT for PM,o/PM25 use of pipeline quality natural qas
Victorville 2 Hybrid Victorville, CA 03/11/2010 2 GE 7FA 12.0 Ib/hr/unit without DF
154 MW per unit plus 1B.0lb/hr with DF
424.3 MMBtu/hr DF
49
Table 1-1. Summary of Recent Pa•ticulate PSD BACT Determinations for Large(>100MW)Gas Fired Combined-Cycle Generating Plants
Permit Emission Limits`
Facility Location Date Turbine' PM/PMIu/PM2,5 _
Stark PowerANolf Granbury, TX 03/03/2010 2 GE 7FA - GE: 12.0 Ib/hr/unit(w/and w/o DF)
Hollow 170 MW/unit plus Mitsubishi: 20.0 Ib/hr/unit(w/and w/o DF)
570 MMBtu/hr DF or
2 Mitsubishi M501G
254 MW/unit plus
230 MMBtu/hr DF
Panda Sherman Grayson, TX 02/03/2010 2 GE 7FA or GE: 12.0 Ib/hr/unit(without DF)
Power 2 Siemens SGT6-5000F 27.0 lb/hr with DF
with 468 MMBtu/hr/unit DF Siemens: 11.0 Ib/hr/unit without DF
15.4 lb/hr with DF
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F 7.5 Ib/hr/unit
Energy Center 2238.6 MMBtu/hr/unit plus 0.00361b/MMBtu
200 MMBtu/hr DF
Lamar Power Paris, TX 06/22/2009 4-GE 7FA with 200 MMBtu/hr DF 18.0 Ib/hr/unit without DF
Partners II LLC 20.3 lb/hr with DF
Pattillo Branch Savoy, TX 06/17/2009 4—GE 7FA, GE7FB, or 20.8 lb/hr/unit(each option)
Power LLC Siemens SGT6-5000F
With DF
Entergy Lewis The 05/19/2009 2-GE 7FA with 362 MMBtu/hr DF 27.14 Ib/hr/unit
Creek Plant Woodlands, TX
' DF refers to duct firing
2 Includes front(filterable)and back-half(condensable)PM. Limits obtained from agency permitting documents when not available in RBLC. Short-term emission
limits only are provided.
50
GE has historically guaranteed particulate emissions on constant lb/hr basis, regardless of turbine load.
Thus, as shown in Table 1-1,many of the GE turbines have PSD BACT limits expressed strictly in lb/hr.
Footprint has calculated lb/MMBtu values inclusive of minimum emission compliance load (MECL).
(Note that duct-firing will not occur at MECL, so the MECL-based limit is only for unfired conditions).
Footprint has determined that the flexibility to operate at MECL is important to the Project's mission of
providing a flexible and quick response to the future system power needs. Footprint's draft PSD permit
and Plan Approval also require PM/PM10/PM25 emission testing at MECL. MECL turbine operation
therefore results in Footprint's highest 16/MIvIBtu rate of 0.0071 lb/MMBtu. It is important to note that a
number of the lb/MMBtu emission rates in Table 1-1 correspond to(just)the full load heat input rate. For
comparative purposes, the Footprint full load Ib/MMBtu/hr PM/PM10/PM25 emission rate (without duct
firing)ranges from 0.0038 to 0.00471b/MMBtu.
Table 1-1 lists 34 projects with PSD BACT limits for PM/PMIo/PM25 approved in the last 5 years. Over
half of these projects (18) clearly have PM/PMIO/PM25 limits less stringent than the Footprint limits
discussed above. Of the remaining 16 projects,most of these are for turbine suppliers other than GE, and
generally have lower PM/PM10/PM2.5 limits expressed on a lb/MMBtu basis. The lb/MMBtu comparison
allows PM/PM10/PM25 rates for projects of different sizes to be more readily compared. The most
stringent lb/MMBtu limit identified is for the Dominion Warren County (VA) project, which is 0.0027
lb/MMBtu without duct firing. The Dominion Warren County project is based on 3 Mitsubishi 501GAC
turbines. Mitsubishi in particular has recently taken a more aggressive approach to PM/PMI0/PM2.5
guarantees, as reflected by the Warren County Project as well as the Brunswick County (VA) project
(0.0033 lb/MMBtu without duct firing and 0.0047 lb/MMBtu with duct firing),the Oregon(Ohio)project
(0.00384 lb/MMBm without duct firing and 0.00373 lb/MMBtu with duct firing) and PVEC (0.004
16/MIvIBtu without duct firing as noted in the CLF comment letter to MassDEP on the Footprint project).
With respect to the PM/PMI0/PM2.5limits achievable for the Mitsubishi 501GAC turbine, it is significant
to note that an email from George Pyres of Mitsubishi Power Systems dated October 7, 2013, which was
submitted to MassDEP in comments concerning Footprint Power, indicates that Mitsubishi has `hot yet
conducted stack PM emissions testing for our M501GAC gas turbine in combined cycle. However, we
have M501GAC units that will be commissioned next year in combined cycle that will provide such
data." (The Mitsubishi 501GAC project that is closest to commissioning is the Dominion Warren County
project.) The email from Mitsubishi actually supports Footprint's position, as provided in supplemental
material submitted to MassDEP on August 20, 2013, insofar as the fact that ultra-low particulate rates for
the 501GAC turbine are not demonstrated in practice. In the August 20, 2013 submission, Footprint
questioned whether the 0.004 lb/MMBtu emission rate for the PVEC was achievable in practice. This is
based on the fact that four Mitsubishi 501G units at Mystic Station (Everett MA), had tested PM
emissions (in 2003) ranging from 0.005 — 0.010 lb/MMBtu. While the 501GAC turbine has a newer
generation combustion system, the majority of the tested particulate matter at Mystic was condensable
particulates. It is not at all clear how a newer generation combustion system would achieve better control
of condensable particles. While careful adherence to particulate testing procedures can minimize testing
variably and artifact condensable emissions, Footprint remains convinced that the Mitsubishi's recent
501GAC limits,particularly those for the Warren County project,present undue project risk.
In addition, for Mitsubishi and Siemens projects with PM/PM1o/PM25 lb/MMBtu limits, these limits
appear to be approved as constant across the operating load range. This represents a different guarantee
philosophy than used by GE.Again, Footprint believes this is a guarantee philosophy difference and does
not reflect actual differences in the quantity of PM/PM10/PM25 emissions due to the type of turbine. As
noted in Footprint's comment letter to MassDEP dated November 1,2013, at full load unfired conditions,
Footprint's lb/MMBtu rates for PM/PM10/PM2.5 range from 0.0038 to 0.0047 lb/MMBtu. These full load
rates compare favorably to many of the lb/MMBtu rates for Siemens and Mitsubishi in Table 1-1.
51
Several Siemens "F Class" PM/PMIO/PM25 limits in Table 1-1 (Renaissance, Langley Gulch, Pondera
King) have lb/hr limits higher than the Footprint unfired value of 8.8 Ib/hr, but do not incorporate higher
duct firing limits (as is typically found to be necessary by available duct burner guarantees). Again,
Footprint believes this is a guarantee philosophy difference and does not reflect actual differences in the
quantity of PM/PMIp/PM2 5 emissions due to the type of turbine and whether duct firing is present or not.
The Russell City Energy Center Project is based on 2 Siemens 501F turbines, and was approved with
PM/PMIo/PM25 limits of 7.5 lb/hr and 0.0038 lb/MMBtu. Again, Footprint believes this is a guarantee
philosophy difference and does not reflect actual differences in the quantity of PM/PMIO/PMz s emissions.
However, one item of particular note in the Russell City Energy Center PSD Permit is that the permit
allows the facility to propose alternate measuring techniques to measure condensable PM, such as the use
of a dilution tunnel. A dilution tunnel is expected to result in lower (and more realistic) tested emissions
compared to typical stationary source impinger techniques for measuring condensable PM.Therefore,this
permit provision may explain in part the rationale for the Russell City Energy Center strategy for
accepting lower permit limits. Dilution tunnel based measurements for condensable PM are expected to
more accurately simulate the process by which condensable PM forms compared to impinger techniques,
which still present concerns with artifact emissions.
There is one other GE 7FA unit noted in Table 1-1 that has PM/PMIo/PM2.5 limits of comparative note.
This is the Green Energy (VA) project. This project is approved for either GE 7FA or Siemens turbines.
For GE 7FA, the lb/hr limits are less stringent than Footprint but the Ib/MMBtu limits are more stringent.
The Green Energy lb/MMBtu limits appear to be incorrectly calculated (too low), even based on the full
load firing rates.
In summary, the available evidence clearly indicates that PSD BACT for PM/PM10/PM2.5 emissions is to
use of state of the art combustion turbines,with good combustion practices and the use of natural gas. The
actual guarantees for PM/PMIo/PM2 5 emissions vary by manufacturer, and permit limits within the range
of recently approved projects for a given turbine supplier are justified as PSD BACT limits.
1.1.4 PSD Best Available Control Technology Assessment for Sulfuric Acid Mist KSO4)
Emissions of H2SO4 from natural gas-fired combined cycle units result from oxidation of trace quantities
of sulfur in natural gas. Normally, fuel sulfur oxidizes to SO2. A generally small portion of fuel sulfur
may initially oxidize directly to SO3 rather than SO2. Also, a portion of the fuel sulfur which initially
oxidizes to SO2 may subsequently oxidize to SO3 prior to being emitted. For purposes of emission
calculations, all SO3 is assumed to combine with water vapor in the flue gas to form H2SO4.
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of natural gas as the BACT fuel,this is the lowest sulfur content fuel available.
Key considerations in the development of a specific H2SO4 emission rate for a natural gas-fired combined
cycle unit are the sulfur content of natural gas, and the appropriate allowance for oxidation of fuel sulfur
and SO2 to SO3. For the sulfur content of natural gas,the Project has used the EPA definition of"pipeline
natural gas" in 40 CFR 72.2. This definition is that pipeline natural gas has a maximum sulfur content of
0.5 grains of sulfur per 100 standard cubic feet(scf). Based on data from GE, up to 5% of the fuel sulfur
is expected to convert directly to SO3 in the turbine combustor/duct burners. Then, up to 35% of the
(remaining) SO2 is expected to convert to SO3 in passing through the oxidation catalyst, and up to an
additional 5% of the (remaining) SO2 is expected to convert to SO3 in passing through the SCR system.
As documented in the Project supplemental data submitted to MassDEP on August 20,2013,the resulting
52
H2SO4 emission rate is 0.0010 lb/MMBtu. This corresponds to a maximum emission rate of 2.3 lb/hr of
H2SO4 per unit.
Pursuant to identifying candidate control technologies under the"top-down"procedure,the Applicant has
compiled all the PSD BACT determinations for H2SO4 in the last five years for new large (> 100 MW)
combustion turbine combined cycle projects. This compilation is based on the USEPA RBLC
(RACTBACT/LAER Clearinghouse). Several recent projects not included in RBLC have also been
included in this compilation. This review confirms that the only H2SO4 BACT technology identified for
large natural gas fired combined cycle turbines is use of clean fuel (i.e., natural gas). There are no cases
where any post combustion controls have been used to control H2SO4 emissions from large natural gas
fired combined cycle turbines. Therefore, the PSD BACT analysis for H2SO4 does not require any
evaluation of alternative control technologies.
The"top-down"procedure does require selection of BACT emission limits. Table 1-2 presents the results
of RBLC compilation for H2SO4. As for PM/PM10/PM2,5, BACT emissions for H2SO4 can be expressed
either as lb/MMBtu or lb/hr, or both. Table 1-2 lists 22 projects with PSD BACT limits for H2SO4
approved in the last 5 years More than half of these projects(13)have H2SO4 limits equal or less stringent
than the Footprint limits discussed above. Of the remaining 9 projects,the lower H2SO4 rates appear to be
due to either unrealistically low assumptions on SO2 to SO3 oxidation, low assumed natural gas sulfur
contents, or both. One of the projects listed in Table 1-2 (Panda Sherman) was approved without a CO
oxidation catalyst, which explains the low H2SO4 rate for this project. As noted above, a CO oxidation
catalyst oxidizes some of the SO2 to SO3/H2SO4. However, the other projects in Table 1-2 with lower
H2SO4 rates appear to have assumed a very stringent natural gas sulfur content and/or did not take into
account the unavoidable incremental oxidation of SO2 to SO3 from a CO catalyst. Footprint does not
believe it is prudent to ignore the SO2 to SO3 oxidation from a CO catalyst, or assume a natural gas sulfur
content lower than EPA's definition for"pipeline natural gas"(0.5 grains of S/100 scf).
In summary, the available evidence clearly indicates that PSD BACT for H2SO4 for combustion turbines
is use of clean low sulfur fuel (e.g., natural gas). The H2SO4 emission calculation needs to allow for a
reasonable variation in the sulfur content of pipeline natural gas, which is outside the control of a given
generation facility, and oxidation of SO2 to SO3 oxidation from a CO catalyst. The Applicant proposes a
H2SO4 limit for the Project (0.0010 lb/MMBtu), which'is consistent with recent PSD BACT precedents
which properly account for these variables.
53
Table 1-2. Summ^ry Of Recent H2SO4 PSD BACT Determinations for Large(>100MW)Gas Fired Comi-:ned-Cycle Generating Plants
Facility Location Permit Turbine' Emission Limits`
Date Sulfuric Acid Mist(H2SO4)
Carroll County Washington Twp., OH 11/5/2013 2 GE 7FA 0.0012 Ib/MMBtu without DF
Energy 2045 MMBtu/hr/unitplus 566 MMBtu/hr DF 0.0016 Ib/MMBtu with DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens SCC6- Mitsubishi: 0.00041 Ib/MMBtu without DF
Energy 8000H Mitsubishi. 0.00044 Ib/MMBtu with DF.
2932 MMBtu/hr/unit plus 300 MMBtu/hr DF Siemens: 0.0006 Ib/MMBtu without DF
Siemens: 0.0007 Ib/MMBtu with DF
Hickory Run New Beaver Twp., PA 04/23/2013 GE7FA, Siemens SGT6-5000F, Mitsubishi 0.92 Ib/hr/unit without DF
Energy LLC M501 G, or Siemens SGT6-8000H. 1.08 Ib/hr/unit with DF
2 combined cycle units Emissions based on Siemens SGT6-8000H
Sunbury Sunbury, PA 04/01/2013 "F Class"with DF 0.0018lb/MMBtu
Generation 2538 MMBtu/hr/unit 4.4 Ib/hr/unit without DF
4.7 Ib/hr/unit with DF
Brunswick County Freeman, VA 03/12/2013 3 Mitsubishi M501 GAC with DF 0.00058 Ib/MMBtu without DF
Power Combined GT and DF 0.00067 Ib/MMBtu with DF
3442 MMBtu/hr/unit
Moxie Patriot LLC Clinton Twp, PA 01/31/2013 Equipment type not specified 0.0005 Ib/MMBtu
2-472 or 458 MW combined cycle blocks with
DF
Garrison Energy Dover, DE 01/30/2013 I GE 7FA 6.5 Ib/hr
Center 309 MW
St. Joseph Energy New Carlisle, IN 12/03/2012 4-"F Class'(GE or Siemens) 0.75 grains S/100 scf of natural gas
Center I 1345 MW total
Hess Newark Newark, NJ 11/01/2012 I 2-GE 7FA.05 1.36 Ib/hr/unit without DF
Energy 2320 MMBtu/hr/unit plus 211 MMBtu/hr DF 1.33 Ib/hr/unit with DF
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 4.8 Ib/hr/unit
Center, LLC 180 MW plus-
425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., PA 10/10/2012 Equipment type not specified 0.0002 Ib/MMBtu
2—468 or less MW combined cycle blocks 1.4 Ib/hr for 454 MW block
GT<2890 MMBtu/hr/unit 1.5lb/hr for 468 MW block
DF<3870 MMBtu/hr/unit
Cricket Valley Dover, NY 09/27/2012 I 3-GE 0.5 grains S/100 scf of natural gas
2061 MMBtu/hr/unit pllusus 3379 MMBtu/hr DF
79
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 4.89 Ib/hr/unit
Center LLC I 180 MW plus
725 MMBtu/hr DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501GAC 0.0018 Ib/MMBtu
Energy Center 2542 MMBtu/hr/unit; no DF 3.6 Ib/hr
j1PVEC)
Thomas C. Llano,TX 09/01/2011 2-GE 7FA 13.68 Ib/hr
Ferguson Power 195 MW per unit
No DF
54
Table 1-2. Summery Of Recent H2SO4 PSS BACT Determinations for Large(>100MW)Gas Fired Comh_ned-Cycle Generating Plants
Facility Location Permit Turbine' Emission Limits`
Date Sulfuric Acid Mist(H2SO4)
Portland Gen. Morrow, OR 12/29/2010 1 -Mitsubishi M501GAC 1.5 Ib/MMcf(0.0015 Ib/MMBtu)
Electric Carty Plant 2866 MMBtu/hr
Dominion Warren Front Royal,VA 12/21/2010 3-Mitsubishi M501 GAC 0.00013 Ib/MMBtu without DF
Countv 2996 MMBtu/hr/unitt2lus 500 MMBtu/hr DF 0.00025 Ib/MMBtu with DF
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE3.37 Ib/hr/unit(w/and w/o DF)
Power Station 2430 MMBtu/hr/unit GT plus DF or Siemens: 3.77 Ib/hr/unit(w/and w/o DF)
4 Siemens SGT6-5000175
2693 MMBtu/hr/unit GTplus DF
Live Oaks Power Sterling, GA 03/30/2010 Siemens SGT6-5000F No emission limits specified.
PSD BACT for H2SO4 use of pipeline quality
natural cZas with <0.5 qrains S/100 scf
Panda Sherman Grayson,TX 02/03/2010 2 GE 7FA GE: 0.56 Ib/hr/unit(w/and w/o DF)
Power 170 MW/unit plus Mitsubishi: 0.62 Ib/hr/unit(w/and w/o DF)
570 MMBtu/hr OF or
2 Mitsubishi M501G
254 MW/unit plus
230 MMBtu/hr DF
Pattillo Branch Savoy,TX 06/17/2009 4—GE 7FA, GE7FB, or GE: 1.9 Ib/hr/unit(w/and w/o DF)
Power LLC Siemens SGT6-5000F Mitsubishi: 2.0 Ib/hr/unit(w/and w/o DF)
With OF
Entergy Lewis The Woodlands,TX 05/19/2009 2-GE 7FA with 362 MMBtu/hr DF 4.03 Ib/hr/unit
Creek Plant
' DF refers to duct firing
2 Limits obtained from agency permitting documents when not available in RBLC. Short-term emission limits only are provided.
55
1.1.5 Best Available Control Technology Assessment for Greenhouse Gases
Step 1.IdenfrfyPotentiallyFeasible GHG Control Options
In Step 1,the applicant must identify all "available"control options which have the potential for practical
application to the emission unit and regulated pollutant under evaluation, including lower-emitting
process and practices. In assessing available GHG control measures, we reviewed EPA's
RACTBACT/LAER Clearinghouse, the South Coast Air Quality Management District's BACT
determinations, and the Pioneer Valley Energy Center permit information found on the EPA Region 1
website (Pioneer Valley is a recently permitted 431 MW combined cycle turbine project in Westfield,
Massachusetts). EPA stated generally that BACT for the Pioneer Valley project is energy efficient
combustion technology and additional energy savings measures at the facility, if possible. Specifically,
BACT was cited as installation of a combined cycle turbine and GHG emission limits were developed.
For the proposed Project,potential GHG controls are:
1. Low carbon-emitting fuels;
2. Carbon capture and storage(CCS);and
3. Energy efficiency and heat rate.
Step 2. Technical Feasibility ofPotential GHG Control Options
Low Carbon-Emittine Fuels
Natural gas combustion generates significantly lower carbon dioxide emission rates per unit heat than
distillate oil (approximately 27% less) or coal (approximately 50% less). Use of biofuels would reduce
fossil-based carbon dioxide emissions, since biofuels are produced from recently harvested plant material
rather than ancient plant material that has transformed into fossil fuel. However, biofuels are in liquid
form, and the Project is not being designed for liquid fuel. In addition, combined cycle turbines have
technical issues with biofuels that have yet to be resolved. It is likely that distillate fuel would need to
have a limited percentage of biofuel added to be feasible. In this case, natural gas would still have lower
fossil-based carbon emissions compared a distillate oil/biofuel mixture. For these reasons, biofuels have
been eliminated from consideration. Therefore, natural gas represents the lowest carbon fuel available for
the Project.
Enerev Efficiencv and Heat Rate
EPA's GHG permitting guidance states,
"Evaluation of[energy efficiency options] need not include an assessment of each and
every conceivable improvement that could marginally improve the energy efficiency of
[a] new facility as a whole (e.g., installing more efficient light bulbs in the facility's
cafeteria), since the burden of this level of review would likely outweigh any gain in
emissions reductions achieved. EPA instead recommends that the BACT analyses for
units at a new facility concentrate on the energy efficiency of equipment that uses the
largest amounts of energy, since energy efficient options for such units and equipment
(e.g., induced draft fans, electric water pumps) will have a larger impact on reducing the
facility's emissions...."
EPA also recommends that permit applicants "propose options that are defined as an overall category or
suite of techniques to yield levels of energy utilization that could then be evaluated and judged by the
56
permitting authority and the public against established benchmarks...which represent a high level of
performance within an industry." With regard to electric generation from combustion sources, the
combined cycle combustion turbine is considered to be the most efficient technology available. Below is a
discussion of energy efficiency and a comparison to other common combustion-based electric generation
technologies.
GHG emissions from electricity production are primarily a function of the amount of fuel burned;
therefore, a key factor in minimizing GHG emissions is to maximize the efficiency of electricity
production.Another way to refer to maximizing efficiency is minimizing the heat rate. The heat rate of an
electric generating unit is the amount of heat needed in BTU (British Thermal Units) to generate a
kilowatt of electricity (kW), usually reported in Btu/kW-hr. The more efficient generating units have
lower heat rates than less efficient units. Older, more inefficient boilers and turbines consume more fuel
to generate the same amount of electricity than newer, more efficient boilers and turbines. This is due to
equipment wear and tear, improved design in newer models as well as the use of higher quality
metallurgy. In general, a boiler-based steam electric unit is less efficient than a combustion turbine
combined cycle unit. This is because the combustion energy from a combustion turbine is directly
imparted onto the turbine blades, and a combined cycle unit then uses the waste heat from the combustion
turbine exhaust to generate additional power, utilizing a HRSG and subsequent steam cycle.
In addition to the efficiency of the electricity generation cycle itself, there are a number of key plant
internal energy sinks (parasitic losses) that can improve a plant's net heat rate (efficiency) if reduced.
Measures to increase energy efficiency are clearly technically feasible and are addressed in more detail in
Step 4 of the BACT process.
Carbon Capture and Storaee
With regard to CCS, as identified by US EPA, CCS is composed of three main components: CO2 capture
and/or compression, transport, and storage. CCS may be eliminated from a BACT analysis in Step 2 if it
can be shown that there are significant differences pertinent to the successful operation for each of these
three main components from what has already been applied to a differing source type. For example, the
temperature, pressure, pollutant concentration, or volume of the gas stream to be controlled,may differ so
significantly from previous applications that it is uncertain the control device will work in the situation
currently undergoing review. Furthermore, CCS may be eliminated from a BACT analysis in Step 2 if the
three components working together are deemed technically infeasible for the proposed source,taking into
account the integration of the CCS components with the base facility and site-specific considerations
(e.g., space for CO2 capture equipment at an existing facility, right-of-ways to build a pipeline or access
to an existing pipeline, access to suitable geologic reservoirs for sequestration, or other storage options).
While CCS is a promising technology, EPA does not believe that at this time CCS will be a technically
feasible BACT option in certain cases.
As identified by the August 2010 Report of the Interagency Task Force on Carbon Capture and Storage
(co-chaired by US EPA and the US Department of Energy), while amine-or ammonia-based CO2 capture
technologies are commercially available, they have been implemented either in non-combustion
applications (i.e., separating CO2 from field natural gas) or on relatively small-scale combustion
applications(e.g., slip streams from power plants,with volumes on the order of what would correspond to
one megawatt). Scaling up these existing processes represents a significant technical challenge and
potential barrier to widespread commercial deployment in the near term. It is unclear how transferable the
experience with natural gas processing is to separation of power plant flue gases, given the significant
differences in the chemical make-up of the two gas streams. In addition, integration of these technologies
with the power cycle at generating plants present significant cost and operating issues that will need to be
addressed to facility widespread,cost-effective deployment of CO2 capture.Current technologies could be
57
used to capture CO2 from new and existing fossil energy power plants; however, they are not ready for
widespread implementation primarily because they have not been demonstrated at the scale necessary to
establish confidence for power plant applications.
Regarding pipeline transport for CCS, there is no nearby existing CO2 pipeline infrastructure (see
Figure 1-1); the nearest CO2 pipelines to Massachusetts are in northern Michigan and southern
Mississippi. With regard to storage for CCS, the Interagency Task Force concluded that while there is
currently estimated to be a large volume of potential storage sites, "to enable widespread, safe, and
effective CCS, CO2 storage should continue to be field-demonstrated for a variety of geologic reservoir
classes" and that "scale-up from a limited number of demonstration projects to widescale commercial
deployment may necessitate the consideration of basin-scale factors (e.g., brine displacement, overlap of
pressure fronts, spatial variation in depositional environments, etc.)".
Based on the abovementioned EPA guidance regarding technical feasibility and the conclusions of the
Interagency Task Force for the CO2 capture component alone (let alone a detailed evaluation of the
technical feasibility of right-of-ways to build a pipeline or of storage sites), CCS has been determined to
not be technically feasible.
Step J.Ranking of Tecb oicaiiy Feasible GHG Control Options by Effectiveness
Based on the results of Step 2, the only option being carried further into the analysis is the evaluation
energy efficiency and heat rate. The Project is already using the lowest carbon fuel and carbon capture
and storage is not currently feasible.
Step 4.Evaluation of EnergyEfficiency andHeatRate
Improvements to energy efficiency and "heat rate" are important GHG control measures that can be
employed to mitigate GHG emissions. Heat rate indicates how, efficiently power is generated by
combustion of a given amount of fuel. Heat rate is normally expressed in units of British thermal units
(Btu) combusted per net kilowatt-hour (kw-hr) of energy produced. A higher value of "heat rate"
indicates more fuel (i.e., Btu) is needed to produce a given amount of energy (lower or less favorable
efficiency), while a lower value of heat rate indicates less fuel (i.e., Btu) is needed to produce a given
amount of energy(higher or more favorable efficiency).
The Proposed Project is using advanced combustion turbine combined cycle technology, which is
recognized as the most efficient commercially available technology for producing electric power from
fossil fuels. Improvements to the heat rate typically will not change the amount of fuel combusted for a
given combustion turbine installation, but it will allow more power to be produced from a given amount
of fuel(i.e.,improve the heat rate)so that more GHG emissions will be displaced from existing sources.
Key factors addressed in the evaluation of energy efficiency and heat rate are the core efficiency of the
selected turbines and the significant factors affecting overall net heat rate in combined cycle operating
mode.
58
Figure 1.1. CO2 Pipelines in the United States
Select CO,Sources and C2 Pine/illec hr Company I:;,;'�,• � ��,�
Lit
'Great Athropaaonic SaurwnPbnt�'* �4
I'
lnBarpa Oaa Plant --.4_ �— ( * 'yw'� '� `-M1J ANropopenicSmrw�^ --
r �.J 'I Shag MmnlSourceeln Welle
NaouM
Bravo Dome .Antrum Ga plant
j McElmo Dome / Natural Sourm t I Atnrapoa.r1,5ourcp / - -
Nature Source
) Ammonia Plant F �
Awopapenic Source _1� jr SelocIC0r S6urces
CO2 Pipelines
ebo /�/In Sentce fT Ln Domer
Natural Source /.i Proposed
Company
IV Chaparral
a
t1 ,`T �__t_ Dea Planb
AMrapaSanlc Source�� !�/Chapparral EoerSY
rtr�I>Z 1' /V ChevninTesaco
/V Care ,LLC
1/
/ Dakots ls G.siOoaibca6on
as yb�f�,SF± Alal°" a ,/'/Denbury Resources
EuonMobil
< `il
�h� �kA•: z `� : Hess
�» /+/Kinder Morgan
Occidental Petroleum Corp.
NOxy Permian
yyya�j/�,J�{/fy� - ,l NPonn Wolf Patroloum
+: ^/Pair.Source
Tnns atco
Mrd.,, �, Nr nnyco2
r k_446 - a{}s
•+'• 4�"Lyy}'�'ii}-cfr"`a� rf+J ria , NWner
From:"Report of the Interagency Task Force on Carbon Capture and Storage,"August 2010,
Appendix B.
The design basis of the proposed project is to install approximately 630 MW of electric,generation which
is equivalent to two "F" Class turbines in combined cycle configuration. "G" class turbines are slightly
more efficient and thus have a lower heat rate; however, "G"class turbines generate approximately 380 to
400 MW per turbine(or 760 to 800 MW for two turbines). In addition, "G"class turbines generally have
a higher low operating limit (the lowest MW output at which the facility can operate in compliance with
its permits) than the proposed "Fa' class turbines. Although "G" class turbines are slightly more energy
efficient that the proposed"F" Class turbines, "G"Class turbines would alter the scope of the project due
to their size. The "F" Class design size provides the compatible size match to the existing high voltage
switchyard and electrical interconnection infrastructure associated with the exiting Salem Harbor
Generating Station site. The "F" class design also provides greater operational flexibility and therefore
lower overall emissions. The expected heat rate or efficiency differential between"F" and"Goa combined
cycles, comparably configured and equipped is less than 1 percent at ISO conditions, in unfired mode,
when both plants are comparably equipped for quick start-up. When site specific conditions are accounted
for, this apparent efficiency difference between "F" and "G" class machines is further reduced by the
higher parasitic power consumption of the fuel gas compressors for the "Goa machines, which require
higher natural gas supply pressures compared to "F" class. For these reasons, "G" class machines have
been eliminated from consideration for the Proposed Project.
59
The advanced generation of"F" class machines have upgraded performance with increased MW output
and improved heat rate compared to prior designs. These machines also represent the current state-of-the-
art for the evolving "F" class technology that is now been in operation for greater than 20 years with
thousands of machines in operation. This provides a conservative and predictable basis to formulate
financial plans and to project future reliability and costs. The steam cycle portion of the plant (HRSG,
piping, & steam turbine generator) as designed with two smaller units in the "1 on 1" configuration will
exhibit superior operational flexibility, ability to deal with rapid thermal transients and exhibit acceptable
and foreseeable long term O&M cost impacts.
With regard to energy efficiency considerations in combined cycle combustion turbine facilities, the
activity with the greatest effect on overall efficiency is the method of condenser cooling. As with all
steam-based electric generation, combined cycle plants can use either dry cooling or wet cooling for
condenser cooling. Dry cooling uses large fans to condense steam directly inside a series of piping,
similar in concept to the radiator of a car. Wet cooling can either be closed cycle evaporative cooling
(using cooling towers), or"once-through"cooling using sea water.
Total fuel heat input to the combined cycle combustion turbine (fuel burned in the combustion turbines
and in the HRSG duct burners) and thus total steam flow available to the steam turbine, is fixed. The
efficiency of conversion of the fixed steam flow to electrical output of the steam turbine generator is then
primarily a function of the backpressure at which the low pressure turbine exhausts.A wet cooling system
consisting either of a mechanical draft cooling tower with circulating water pumps and a shell and tube
condenser, or a once-through system directly circulating sea water to the condenser, are capable of
providing significantly lower condensing pressures compared to an all dry ACC system. Wet cooling
performance is superior for efficiency purposes because of the basic thermodynamics of cooling, which
allows either the cooling tower or once through system to produce colder water compared to dry cooling.
As a result, operation of a dry cooling system requires approximately 1-5% more energy than a wet
cooling system depending on ambient conditions (difference between wet and ACC systems gets smaller
with lower ambient temperatures).
However,there are significant drawbacks to either a once-through system or wet mechanical draft cooling
tower system. Once-through cooling involves use of large quantities of sea water that is returned to the
ocean at a higher temperature. The impingement and entrainment associated with intake of the necessary
large quantities of sea water, and the thermal impacts of discharges of once-through cooling, have been
recognized to have negative environmental impacts and once-through cooling has therefore been
eliminated from consideration.
Wet mechanical draft cooling towers also require a significant quantity of water,most of which is lost to
evaporation to the atmosphere. Seawater can potentially be used for makeup to a wet evaporative system,
but this is is a very challenging application. The most likely candidate source for the volumes of cooling
tower makeup water required would be the SESD sewage treatment plant. It is technically feasible to use
effluent from a public sewerage treatment facility as make-up to a wet, evaporative cooling system.
However the presence of typical chemical constituents in the effluent and the likely highly variable
concentrations of certain of these constituents would place a burden on the Project. The effluent
transferred from SESD would require further treatment to make it suitable and safe to use in the cooling
system. Even after further treatment the concentrations of certain dissolved minerals in the circulating
water would impact the design;most likely require a high degree of cooling tower blowdown to maintain
acceptable chemistry and requiring the upgrade of the metallurgy of the piping, condenser tube, pumps
and other components that would be exposed to the more corrosive action of the treated and concentrate
effluent.
60
An additional burden imposed of wet, evaporative cooling is dealing with the creation of visible fog
plume, which discharges from the cooling tower fans. With the typical New England, coastal site weather
conditions, a standard mechanical draft cooling tower would produce a very visible and persistent plume
for many hours of the year. It is possible to use a so-called "plume abated" mechanical draft tower. But
this feature can double the cost of the cooling tower and increase the total fan power consumption and
pumping head on the system. Basically the "plume abatement" feature works by using heat from the hot
condenser discharge water to preheat additional ambient air admitted above the normal cooling tower wet,
evaporative heat exchange zone. This hotter air has a lower relative humidity; such that as it mixes with
the wet, almost saturated air discharged from the evaporative cooling surface, the combined air mixture
reaches a moisture content below the saturation point. As this hotter, dryer air mixture is discharged by
the tower fans it can then mix with the cool, damp ambient air without crossing the saturation line and
producing small water droplets which form the visible plume.
The bottom line is that a wet, evaporative mechanical draft cooling tower with plume abatement features
has a doubled capital cost, higher fan power consumption and higher pumping head than a standard
cooling tower. These latter two factors greatly reduce any potential benefit from reduced parasitic load
from the wet cooling system.
stem.
Therefore, Footprint has determined that the marginal heat rate improvement that could be achieved with
a plume abated mechanical draft tower does not outweigh the drawback of the technical issue associated
with use of the SESD sewage effluent, as well as the fact that a visible plume will still be present at times
with a plume abated tower. The use of dry cooling has therefore been selected over either wet cooling
option.
The Administration Building has been designed to meet the U.S. Green Building Council's Leadership in
Energy and Environmental Design (LEED) at the Platinum level. The Administration Building, as well
as the Operations Building, among various energy conservation features, incorporate green roofs,
geothermal heat pumps for heating and cooling, building energy management systems, and a 10%
reduction in lighting power density.
Step 5.•Select BACT
The Project has proposed GHG limits as follows for the combined cycle units:
• Initial test limit of 825 lb CO2e/MWhr(net to grid),full load, ISO corrected,without duct firing
• Rolling 365-day GHG BACT limit(life of facility)of 895 lb COZe/MWhr(net to grid)
For purposes of comparison, the initial test GHG limit of 825 lb CO2e/MWhr(net to grid) corresponds to
a "heat rate" of 6,940 Btu HHV/kWhr (net). On a "gross" energy basis, these values are 795 lb
CO2e/MWhr(gross) and 6,688 Btu HHV/kWhr (gross). The rolling 365-day GHG BACT limit of 895 lb
CO2e/MWhr (net to grid) corresponds to a "heat rate" of 7,521 Btu HHV/kWhr (net). On a "gross"
energy basis,these values are 862 Ib COze/MWhr(gross)and 7,247 Btu HHV/kWhr(gross).
Note that"gross" energy is based on the full electric energy output of the generation equipment, without
consideration of internal plant loads (parasitic losses such as for pumps and fans). Net energy is based on
the amount of electric energy after internal plant demand is satisfied, and reflects the amount of energy
actually sold to the electric grid.
For purposes of comparison with other projects, Footprint's design thermal efficiency is 57.9%. This is
based on ISO full load operation, without duct firing or evaporative cooling, without any degradation
allowance,and reflects gross energy output fuel energy input based on LHV. This is the most typical way
61
that thermal efficiency is reported. This is not as meaningful for purposes of GHG BACT limits compared
to measures based on net power production, since those based on net power account for the project
internal energy consumption. Footprint considers the proposed rolling 12-month COze limit for the life of
the project as the most meaningful limit since it reflects actual long-term emissions, and actual power
delivered to the grid.
Pursuant to supporting these proposed limits consistent with the "top-down" procedure, Footprint has
compiled PSD BACT determinations for GHG in the last five years for new large (> 100 MW)
combustion turbine combined cycle projects. This compilation is based on all entries during this time
period listed in the USEPA RBLC (RACTBACT/LAER Clearinghouse). Several recent projects not
included in RBLC have also been included in this compilation. This review confirms that the only BACT
technology identified for large natural gas fired combined cycle turbines is use of low carbon fuel (i.e.,
natural gas) in high efficiency combined cycle units. There are no cases where any post combustion
controls (carbon capture and sequestration) have been used to control GHG emissions from large natural
gas fired combined cycle turbines.
Table 1-3 presents the results of RBLC compilation for GHG. GHG BACT emissions are expressed in
varying units, including mass emission (tons or pounds per unit time), lb CO2e per MWhr, and/or"heat
rate" (Btu/kWhr). The energy-based limits are expressed as either "gross" or "net". Energy units (MWhr
or kWhr) or more meaningful than mass emission limits since they relate directly to the efficiency of the
equipment, which is a key available BACT technology (in addition to low carbon fuel). The mass
emissions are specific to the fuel firing rate of a given project and the carbon content of the fuel, but do
not incorporates the project efficiency.
Table 1-3 lists 15 projects with PSD BACT limits for GHG approved in the last 5 years which have
energy based GHG limits (The mass limit projects are not considered since they are not meaningful for
GHG BACT comparison). Accounting for the different units for these limits, the Footprint Project
proposed GHG limits are clearly more stringent than most of the energy based limits in Table 1-3. For
limits where this comparison is not clear,the following clarifications are made:
• The basis for Oregon(OH)Clean Energy project limits(840 and 833 lb/MWhr gross)is not clear,
but the context of this actual permit suggests these limits are intended for ISO conditions without
duct firing which makes them less stringent than the Footprint limits.
• The Brunswick County limit of 7,500 Btu/kWhr net at full load with duct firing does not directly
correspond to either of the Footprint conditions. However, Footprint's limit of 895 Ib
CO2e/MWhr corresponds to a rolling 365-day value of 7,521 Btu/kWhr net which accounts for all
operation on an annual basis including starts, stops, and part load in addition to duct firing.
• The Palmdale project limits of 774 lb/MWhr and 7,319 Btu/kWhr (source wide net 365 day
average limits)are more stringent than the Footprint limits. However,the Palmdale project is a
62
Table 1-3. Summary Of Recent GHG PSD BACT Determinations for Large(>100MW)Gas Fired Combined-Cycle Generating Plants
Emission Limits`
Permit Greenhouse Gas (GHG)as CO2e unless otherwise
Facility Location Date Turbine noted
Carroll County Washington 11/5/2013 2 GE 7FA 859 Ib/MWhr gross at ISO conditions without duct firing
Energy Twp., OH 2045 MMBtu/hr/unit Dlus 566 MMBtu/hr DF
Renaissance Carson City, MI 11/1/2013 4 Siemens 501 FD2 units 1000 Ib/MWhr gross 12-month rolling average
Power 2147 MMBtu/hr/unit each with 660 MMBtu/hr DF
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens SCC6-8000H Mitsubishi: 840 Ib/MWhr gross
Energy 2932 MMBtu/hr/unit_21us 300 MMBtu/hr DF Siemens: 833 Ib/MWhr qross
Green Energy Leesburg,VA 04/30/2013 2 GE 7FA.05 Heat rate of 7,340 Btu HHV/kWhr gross without DF
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr DF or Heat rate of 7,780 HHV Btu/kWhr gross with DF
Stonewall 2 Siemens SGT6-5000F5
2260 MMBtu/hr/unit plus 450 MMBtu/hr DF
Hickory Run New Beaver 04/23/2013 1 GE7FA, Siemens SGT6&00F, Mitsubishi M501 G, 3,665,974 tpy both units
Energy LLC Twp., PA or Siemens SGT6-8000H. Emissions based on Siemens SGT6-8000H
2 combined cycle units
Sunbury Sunbury, PAI 04/01/2013 I T Class"with DF 281,727 Ib/hr without DF
Generation 2538 MMBtu/hr/unit 298,106 Ib/hr with DF
Brunswick CountyI Freeman,VA I 03/12/2013 Combi edsGT anld DF 3442 MMBtuu/hr/unit M501 GAC with DFHeat rata d corrrec etd to ISO conditions wthdDF at ell load
Pow( r
CenteGarrison Energy Dover, DE I 01/30/2013 GE 309 MW DF Heat rate of 7,717 Btu HHVage/kWhr net 12-month rolling
ave
St. Joseph EnergyI New Carlisle, IN I 12/03/2012 4-"F Class"1345 MW or Siemens) Heat rate of 7,646 Btu/kWhr. Further detail not specified
center
Hess Newark Newark, NJ 11/01/2012 2-GE 7FA.05 887 Ib/MWhr gross 12-month rolling average
Energy 2320 MMBtu/hr/unit plus 211 MMBtu/hr DF Heat rate of 7,522 Btu(HHV)/kWhr; net basis at full load
and corrected to ISO conditions without DF
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 920 Ib/MWhr net
Center, LLC 180 MW plus
_ 425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., 10/10/2012 Equipment type not specified 1,388,540 tpy for 454 MW block
PA 2—468 or less MW combined cycle blocks 1,480,086 tpy for 468 MW block
GT<2890 MMBtu/hr/unit
DF<3870 MMBtu/hr/unit
Heat rate of 7,605 Btu HHV/kWhr ISO without DF
Cricket Valley Dover, NY 09/27/2012 3-GE 7FA.05 57.4%design thermal efficiency
2061 MMBtu/hr/unit plus 379 MMBtu/hr DF 3,576,943 tpy all 3 units
Deer Park Energy Deer Park, TX 09/26/2012 1 -Siemens 501 F 920 Ib/MWhr net
Center LLC 180 MW plus
725 MMBtu/hr DF
63
Table 1-3. Summ-ry Of Recent GYG PSD BACT Determinations for Large(>1001VIM Gas Fired Combined-Cycle Generating Plants
Emission Limits`
Permit Greenhouse Gas(GHG)as CO2e unless otherwise
Facility Location Date Turbine' noted
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501 GAC 825 Ib/MWhr net(initial full load test corrected to ISO
Energy Center 2542 MMBtu/hr/unit; no DF conditions)
(PVEC) 895 Ib/MWhr net(rolling 365-day averaqe)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA 774 Ib/MWhr source wide net 365 day rolling average
Power - 154 MW(1736 MMBtu/hr)per unit plus (CO2)
500 MMBtu/hr DF Heat rate. 7,319 Btu/kWhr source wide net 365 day rolling
average
Thomas C. Llano, TX 09/01/2011 2-GE 7FA 908,957.6 Ib/hr 30-day rolling average
Ferguson Power 195 MW per unit
No DF
Brockton Power Brockton MA 07/20/2011 1 Siemens SGT6-PAC-5000F 870 Ib CO2e/MWhr monthly average
(MA Plan 2227 MMBtu/hr plus 641 MMBtu/hr DF 842 Ib/MWhr rolling 12-month average
Approval) 1,094,900 tpy
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F Heat rate of 7,730 Btu HHV/kWhr
Energy Center 2238.6 MMBtu/hr/unit plus 242 metric tons of CO2e/hr/both units
200 MMBtu/hr DF 5,802 metric tons of CO2e/day/both units
1,928,102 metric tons of CO2e/year/both units
119 Ib CO2e/MMBtu
DF refers t0 duct firing
2 Limits obtained from agency permitting documents when not available in RBLC
64
hybrid solar/gas turbine project, and the Palmdale GHG limits appear to account for the solar
energy production component. The Footprint Project's available land and Massachusetts climate
restrictions preclude a solar component which could achieve the Palmdale limits.
• The Brockton(MA)Project was approved for a rolling 12-month CO2 limit of 842 lb/MWhr, and
a monthly maximum of 870 16/MWhr. The basis for the 842 1b/MWhr limit in the Massachusetts
Plan Application for the Brockton Project is stated to include operation at a variety of loads,
ambient temperatures, with and without evaporative cooling, and with and without duct firing,
and including starts and stops(Brockton Power Plan Application at page 4-30). However,there is
no mention of any allowance for heat rate (efficiency) degradation over the life of the project or
between major turbine overhauls. This is a significant consideration which renders this value of
842 lb CO2/MWhr as inappropriate as a GHG BACT precedent. Footprint notes that the Brockton
Project has not been constructed, and the 842 lb/MWhr value therefore has not been demonstrated
in practice. In addition, the Footprint notes that the Brockton Project did not specifically undergo
a PSD review for GHG BACT. Footprint also notes that in the Plan Application for the Brockton
Project, it is stated that the 842 Ib/MWhr value is based on a CO2 emission factor of 117
Ib/MMBtu. Footprint notes its proposed limit of 895 lb/net MWhr is based on a CO2e emission
factor of 119 lb/MMBtu. Adjusting the Brockton value of 842 Ib/MWhr by 119/117, the
Brockton rate (based on 119 lb CO2/MIvIBtu) would be 856 lb/MWhr. In this case, the Footprint
Project value (895 Ib/M)Vhr) is only 4.6% higher than the adjusted Brockton value (856
lb/MWhr). In addition, the Brockton Project design is based on wet cooling, while the Footprint
Project will use dry cooling. Projects using dry cooling have higher heat rates (are less efficient)
than wet cooled projects, particularly during the summer months. Reasonable allowance for heat
rate (efficiency) degradation over the life of the project and between major turbine overhauls, as
well as the impact of wet vs. dry cooling, explains the proposed GHG BACT for the SHR Project
of 895 lb/net MWhr compared to the proposed Brockton limit.
CLF comments dated November 1, 2013 on the Footprint public review documents indicate that the
Newark Energy Center has a combined cycle mode heat rate limit of 6005 Btu/kWhr, corresponding to a
thermal efficiency of 58.4%. The CLF comments further note that the Russell Energy Center Project in
CA has proposed to achieve a thermal efficiency of 56.4%, and the Cricket Valley Project(NY)proposed
to achieve 57.4% efficiency. These values are taken from a letter written by Steve Riva dated April 17,
2012.
The Newark Energy Center quoted values of 6005 Btu/kWlrr and 58.4%thermal efficiency appear to be
preliminary values, since they do not match the actual New Jersey PSD Permit as discussed below. When
comparing heat rate and efficiency values, these may be quoted with varying assumptions, and it is
important to ensure an "apples to apples" comparison is made. The heat rate used to calculate thermal
efficiency is typically specified based on full load ISO operation, no duct firing, gross output, and on an
LHV basis. That is why it is commonly a lower value than "real world" rolling 12-month, net, III-IV
values. These two values (6005 Btu/kWhr and 58.4%thermal efficiency) are actually not consistent with
each other, since thermal efficiency is calculated as 3412 Btu/kW-hr/6005 Btu/kW-hr = 56.8% thermal
efficiency.In any event,the"real"numbers for the Newark Energy Center GHG BACT limits in Table 1-
3 are taken from the actual New Jersey PSD permit dated November 1, 2012, so these represent more
recent information for the Newark Energy Center Project. The actual Newark Energy Center permit has
net "heat" rate limit (without duct firing at base load corrected to ISO conditions) of 7,522 Btu/kWhr
based on the Higher Heating Value (HHV) of the fuel. As indicated above, the Footprint Project has a
nearly numerically identical rolling 365-day GHG limit which corresponds to a net heat rate of 7,521
Btu/kWhr, but that reflects all annual operation and not just base load without duct firing. The Newark
Energy Center also has a direct GHG limit of 887 Ib/MWhr, gross basis, rolling 12-month average. The
65
Footprint rolling 365-day GHG limit of 895 lb/MWhr net basis is clearly more stringent than the actual
Newark Energy Center GHG limit.
The Russell Energy Center PSD Permit has a heat rate limit of 7,730 Btu/kW-hr', with the key
assumptions for calculating compliance not specified. In any event,this limit is clearly less stringent than
Footprint's rolling 365-day GHG limit which corresponds to a net heat rate of 7,521 Btu/kWhr.
Footprint's design thermal efficiency of 57.9% is also better than the quoted Russell proposal of 56.4%
(not referenced in the Russell's actual PSD permit).
Cricket Valley's PSD permit does contain the quoted 57.4% thermal efficiency, and well as a heat rate
limit of 7,605 Btu/kW-hr. The Cricket Valley PSD permit indicates this heat rate is at ISO conditions,
HHV without duct firing. Gross or net electric output is not specified.As with Russell,this limit is clearly
less stringent than Footprint's rolling 365-day GHG limit which corresponds to a net heat rate of 7,521
Btu/kWhr. Footprint's design thermal efficiency of 57.9% is also better than the Cricket Valley value
57.4%.
CLF suggests that the GHG limits should also be expressed on a thermal efficiency basis. As stated
above, thermal efficiencies for gas turbines are normally based on the lower heating value (LHV) of the
fuel, on a gross energy basis. The only PSD Permit we identified containing a thermal efficiency value is
the Cricket Valley PSD permit. As MassDEP has done, Footprint concurs it is more appropriate to
propose GHG limits directly as COZe on a net energy basis, accounting for actual emissions of GHG and
overall project efficiency including parasitic plant loads.
In summary, the available evidence clearly indicates that PSD BACT for GHG for combustion turbines is
use of low carbon fuel (e.g., natural gas) in high efficiency combustion combined cycle turbines.
Footprint's proposed GHG limits are as or more stringent than any PSD BACT determinations, except for
a hybrid solar facility, and the Brockton Power Project, which has a rolling 12-month limit which does
not properly account for degradation over the life of the equipment. It is concluded that Footprint's
proposed GHG limits represent PSD BACT.
1.1.6 Combustion Turbine Startup and Shutdown BACT
This section supplements the PSD BACT analysis for the combustion turbine startup and shutdown
(SUSD) limits. Combustion turbine combined cycle units require warm up time to achieve proper
operation of the dry-low NOx combustors discussed above, and also to achieve system warm-up to allow
proper function of the SCR catalysts. Combustion turbine combined cycle units require higher mass
emission limits during SUSD operations for NO, CO and VOC. Since CO and VOC are not subject to
PSD review, this SUSD BACT assessment only addresses NO.. The other pollutants subject to PSD
review are PM/PMIp/PM2_5, H2SO4, and GHG, as these pollutants have lower mass emissions than for
normal operation and thus are not included in this PSD SUSD BACT evaluation. GHG also has the
rolling 12-month limit(lb/MWhr)encompassing all operation including SUSD.
This evaluation does not identify and discuss each of the five individual steps of the "top-down" BACT
process, since the only available control for SUSD are procedures to warm up the systems and begin
operation of the temperature-dependent emission control systems as quickly as practical, consistent with
all system constraints. The Project incorporates new "quick start" technology which minimizes SUSD
emissions significantly compared to prior startup procedures in widespread use. Table 1-4 presents the
proposed NOx SUSD BACT limits for the Project:
66
Table I4. Combustion Turbine NOx SUSD PSD BACT Limits
Pollutant Startup(Ib/event) Shutdown(Iblevent)
NOx 1 89 1 10
In addition to these limits, the Project has a limit for startup duration of< 45 minutes and for shutdown
duration of< 27 minutes. Also, the project is required to begin SCR operation (inject ammonia) as soon
as the systems attain the minimum temperatures as specified by the control equipment system vendors,
and other system parameters are satisfied for SCR operation.
As part of the review of these proposed NO, SUSD BACT limits under the "top-down" procedure,
Footprint has compiled all the NO, SUSD PSD BACT determinations in the last five years for new gas-
fired large (> 100 MW) combustion turbine combined cycle projects. This compilation is presented in
Table 1-5. This compilation is based on the USEPA RBLC (RACTBACT/LAER Clearinghouse).
Several recent projects not included in RBLC have also been included in this compilation. This review
confirms that the only SUSD NO,BACT technologies identified are procedures to warm up the systems
and begin operation of the SCR as quickly as practical consistent with other constraints. Table 1-5
contains 28 new large (> 100 MW) combustion turbine combined cycle projects with NO, SUSD PSD
BACT determinations. These limits are generally expressed as either lb/hr or lb/event. Some units do not
have numerical SUSD limits for NO,,,but only requirements to minimize SUSD emissions.
For purposes of comparing the Project limits to determinations only expressed in Win, Footprint's worst
case Ib/hr is calculated as 45 minutes for a cold start (at 89 pounds) plus 15 minutes at full load
(18.1 lb/hr)/4 = 93.5 lb/hr. Also, while the Project's proposed NO, SUSD limits for a start are only for a
worst-case cold start, for comparison purposes the Project's values for a warm and hot start, as provided
in the August 6,2013 Application Supplement,are 54 and 28 pounds,respectively.
All the NO, SUSD BACT limits in Table 1-5 are less stringent than the Footprint limits, except for the
warm start limits at two CA projects (Palmdale and Victorville), and startup/shutdown limits for the
Brockton MA Project. Palmdale and Victorville each have the same limit for a warm and hot start of 40
lbs/event, while the Footprint values are 54 lbs for a warm start and 28 lbs for a hot start. It is logical that
a warm start would have higher emissions than a hot start,and the average of the two Footprint values(54
lbs and 28 lbs)is 41 lbs/event,effectively identical to the Palmdale and Victorville value.
The Brockton project is based on a"quick start" Siemens SGT6-PAC-5000F combined cycle installation,
and has approved SUSD limits of 31.6 lb/hr(startup)and 29.8 lb/hr(shutdown). The startup time is stated
as 0.47 hours and the shutdown time is 0.40 hours. Thus,the lb/event values are calculated as 14.9 pounds
for a start and 11.9 pounds for a shutdown. Footprint did consider a very similar Siemens turbine
subsequent to the approval data of the Brockton permit, and this more recent data for the same basic
"quick start" Siemens machine (5000F) now has 83 lbs NO,over 45 minutes. For a combined cold start
and shutdown, Footprint now has (89 +10 = 99) lbs NO, while the Siemens data provided to Footprint
reflects(83 +20 = 103)lbs NO.. GE has lower NO,emissions for both the warm and hot start. So, based
on the latest information, there is no advantage to selecting Siemens over GE for NO, startup/shutdown
emissions based on more recent data.
67
Table 1-5. Summ:ry Of Recent NOx SUSD BACT Determinations for Large(>100MW)Gas Fi-ad Combined-Cycle Generating Plants
Emission Limits`
Permit SUSD NOx
Facility Location Date Turbine' (values are for a single unit at multiple unit facilities)
Carroll County Washington 11/5/2013 2 GE 7FA Cold Start: 476 lbs/event
Energy Twp., OH 2045 MMBtu/hr/unit plus 566 MMBtu/hr Warm Start: 290 lbs/event
DF Hot Start, 160 lbs/event
Shutdown: 77 lbs/event
Values calculated from approved Ib/hr and event durations
Renaissance Carson City, MI 11/1/2013 4 Siemens 501 FD2 units 176.9 Ib/hr SU and 147.3 lb/hr SD
Power 2147 MMBtu/hr/unit each with 660
MMBtu/hr DF
Langley Gulch Payette, ID 08/14/2013 1 -Siemens SGT6-5000F 96 ppm; 3 hr rolling average
Power 2134 MMBtu/hr/unit with 241.28 (for the amount of fuel firing during SUSD for a GE 7FA, 96
MMBtu/hr DF ppm corresponds to approximately 450 lbs over a 45 minute
quick start)
Oregon Clean Oregon, OH 06/18/2013 2 Mitsubishi M501 GAC or 2 Siemens Mitsubishi: Cold Start: 108.9 lbs/event
Energy SCC6-8000H Warm Start: 86 lbs/event
2932 MMBtu/hr/unit plus 300 MMBtu/hr Hot Start. 47.2 lbs/event
DF Shutdown: 35 lbs/event
Siemens:—Cold Start: 188 lbs/event
Warm Start: 126 lbs/event
Hot Start: 108 lbs/event
Shutdown:46 lbs/event
Values calculated from approved Ib/hr and event durations
Green Energy Leesburg,VA 04/30/2013 2 GE 7FA.05 Minimize emissions, No numeric limits
Partners/ 2230 MMBtu/hr/unit plus 650 MMBtu/hr
Stonewall DF or
2 Siemens SGT6-5000F5
2260 MMBtu/hr/unit plus 450 MMBtu/hr
DF
Brunswick County Freeman, VA 03/12/2013 3 Mitsubishi M501 GAC with DF Minimize emissions, No numeric limits
Power Combined GT and DF
3442 MMBtu/hr/unit
Garrison Energy Dover, DE 01/30/2013 GE 7FA Cold Start/: 500 lbs/event
Center 309 MW Warm/Hot Start/: 200 lbs/event
Shutdown: 23 lbs/event
St. Joseph Energy New Carlisle, IN I 12/03/2012 4-"F Class" (GE or Siemens) 443 Ib/event
Center 1345 MW total
Hess Newark Newark, NJ 11/01/2012 2-GE 7FA.05 Cold Start: 140.6 lbs/event
Energy Center 2320 MMBtu/hr/unit plus 211 MMBtu/hr Warm Start: 96.8 lbs/event
DF Hot Start 95.2 lbs/event
Shutdown: 25 lbs/event
68
Table 7-5. Summary Of Recent NOx SUSD BACT Determinations for Large(>100MW)Gas Fi-ed Combined-Cycle Generating Plants
Emission Limits`
Permit SUSD NOx
Facility Location Date Turbine (values are for a single unit at multiple unit facilities)
Channel Energy Houston, TX 10/15/2012 2-Siemens 501 F 350 Ib/hr
Center, LLC 180 MW plus
425 MMBtu/hr DF
Moxie Liberty LLC Asylum Twp., 10/10/2012 Siemens"H Class" No SUSD listed in RBLC
PA 2-468 or less MW combined cycle
blocks
GT<2890 MMBtu/hr/unit
DF<3870 MMBtu/hr/unit
Deer Park Energy Deer Park,TX 09/26/2012 1 -Siemens 501 F 350 Ib/hr
Center LLC 180 MW plus
7_2.5_MMBtu/hr DF_
ES Joslin Power Calhoun, TX 09/12/2012 3-GE 7FA 99.911/ r
_ 195 MW per unit
_ No DF
Pioneer Valley Westfield, MA 04/05/2012 1 Mitsubishi M501GAC 62 lb/hr
Energy Center 2542 MMBtu/hr/unit; no DF (310 lbs/event for cold start)
(PVEC) (124 lbs/event for warm start
(62 lbs/event for shutdown)
Palmdale Hybrid Palmdale, CA 10/18/2011 2 GE 7FA Cold Start: 96 lbs/event
Power 154 MW(1736 MMBtu/hr)per unit plus Warm/Hot Start:40 lbs/event
500 MMBtu/hr DF Shutdown: 57 lbs/event
Thomas C. Llano, TX 09/01/2011 2-GE 7FA 111.56 lb/hr
Ferguson Power 195 MW per unit
No DF
Entergy Ninnemile I Westwego, LA 08/16/2011 I Ser not unit 550MW No SUSD in RBLC
Point UnI nde
(MI Siemens SGT6-P
Start: 31.6
/2011
Brockton Power I Brockton MA I PlanOApp ovalll I 2227 MMBtu/hr o us 641MMBtuO/hr DF__ _ Shutdown: 29 8/lb/hr
Avenal Power Avenal, CA 05/27/2011 2-GE 7FA Each unit: 160lb/hr
Center 1856.3 MMBtu/hr/unit plus 562.26 Both units: 240 Ib/hr
MMBtu/hr DF
Portland Gen. Morrow, OR 12/29/2010 1 -Mitsubishi M501GAC 150 Ib/hr; 3-hr rolling average
Electric Carty Plant I I 2866 MMBtu/hr _
Dominion Warren Front Royal, VA 12/21/2010 3-Mitsubishi M501 GAC-_ Minimize emissions, No numeric limits
County . 2996 MMBtu/hr/unit plus 500 MMBtu/hr
DF
Pondera/King Houston, TX 08/05/2010 4 GE 7FA.05 GE:216 Ib/hr/unit
Power Station _ 2430 MMBtu/hr/unit GT plus DF or Siemens:220 Ib/hr/unit
4 Siemens SGT6-5000F5
- 2693 MMBtu/hr/unit GT plus DF
Live Oaks Power I Sterlinq, GA 1 03/30/20101 Siemens SGT6-5000F Minimiz-e emissions, No numeric limits
69
Table 1-5. Summ-ry Of Recent NOx SUSD BACT D^terminations for Large(>1001VItN)Gas Fled Combined-Cycle Generating Plants
Emission Limits`
4, Permit SUSD NOx
Facility Location Date Turbine (values are for a single unit at multiple unit facilities)
Victorville 2 Hybrid Victorville, CA 03/11/2010 2 GE 7FA Cold Start: 96 lbs/event
154 MW per unit plus Warm/Hot Start:40 lbs/event
424.3 MMBtu/hr DF Shutdown: 57 lbs/event
Stark Power/Wolf Granbury,TX 03/03/2010 2 GE 7FA GE: 420 Ib/hr/unit
Hollow 170 MW/unit plus Mitsubishi239 Ib/hr/unit
570 MMBtu/hr DF or
2 Mitsubishi M501G
254 MW/unit plus
230 MMBtu/hr DF
Russell City Hayward, CA 02/03/2010 2-Siemens 501 F Cold Start:480 lbs/evenUunit
Energy Center 2238.6 MMBtu/hr/unit plus Warm Start: 125 lbs/evenUunit
200 MMBtu/hr DF Hot Start: 95 lbs/evenUunit
Shutdown:40 lbs/event/unit
Panda Sherman Grayson, TX 02/03/2010 2 GE 7FA or GE: 242 Ib/hr/unit
Power 2 Siemens SGT6-5000F Mitsubishi: 148.5 lb/hr/unit
with 468 MMBtu/hr/unit DF
Lamar Power Paris, TX 06/22/2009 4-GE 7FA with 200 MMBtu/hr DF No SUSD limits in RBLC or TX permit
Partners II LLC
Pattillo Branch Savoy,TX 06/17/2009 4—GE 7FA, GE7FB, or 650 Ib/hr/unit(each option)
Power LLC Siemens SGT6-5000F
With DF
Entergy Lewis The 05/19/2009 2-GE 7FA with 362 MMBtu/hr DF 200 Ib/hr
Creek Plant Woodlands, TX
DF refers to duct firing: `Short-term Lmits only. Limits obtained from agency permitting documents when not available in RBLC.
70
PVEC does have a somewhat more stringent NO, SUSD BACT limit on an hourly basis (62.0 lbs per
hour) compared to the equivalent Footprint lb/hr value of 93.5 lbs/hr. However, PVEC has longer startup
and shutdown times, with up to 5 hours for a cold start, 2 hours for a warm start, and 1 hour for a
shutdown. On a pound per event basis, PVEC has greater SUSD emissions compared to Footprint.
Footprint will achieve the lowest practical emissions achievable for SUSD, and the proposed PSD permit
allows the MassDEP to reset the SUSD BACT limits if different values are demonstrated to be
achievable.
1.2 Auxiliary Boiler
This section supplements the PSD BACT analysis for the auxiliary boiler to address public comments
made on the draft permit documents. The Project is subject to PSD review for NO, PM/PMro/PM2.5,
H2SO4, and GHG, and thus the auxiliary boiler is subject to PSD BACT for these pollutants.
The Project includes an 80 MMBtu/hr auxiliary boiler that will have natural gas as the only fuel of use.
Table 1-6 presents the proposed BACT limits for the auxiliary boiler for pollutants subject to PSD review.
Table 1-6. Auxiliary Boiler Proposed PSD BACT Limits
Pollutant Emission Limitation Control Technology
NOx 9 ppmvd at 3%02 Ultra Low NOx Burners(9 ppm)
0.011 lbs/MMB tu Good combustion practices
PM/PM,D/PM25 0.005 lbs/MMBtu Natural gas
H2SO4 0.0009 lbs/MMBtu Natural Gas
GHG as CO2e 119.0 Ib/MMBtu I Natural Gas
(Note:the H2SO4 value is revised to reflect the inclusion of a CO oxidation catalyst)
In order to inform the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for auxiliary boilers at new large (> 100 MW) combustion turbine combined cycle
projects. This compilation is based on the USEPA RBLC (RACTBACT/LAER Clearinghouse). Several
recent projects not included in RBLC have also been included in this compilation. Table 1-7 provides this
P J p
compilation. Table 1-7 will be referred to in the individual pollutant discussion below.
1.2.1 Fuel Selection
Step 1:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2.Eliminate Infeasible Technologies
Both these technologies are technically feasible.
Step 3.Rank Control Technologies by Control Effectiveness
Natural gas boilers can achieve lower emissions compared to ULSD.
Step 4:Evaluate Controls
Footprint has chosen the lowest emitting fuel for the auxiliary boiler, natural gas. Therefore, a detailed
evaluation of alternate fuels is not required.
Step 5.•Select BACT
Natural gas is proposed as the BACT fuel for the auxiliary boiler.
71
Table 1-7. Summary Of Recent PSD BACT Determinations for Natural Gas Auxiliary Boilers at Large(>100MW)Gas Fired Combined-Cycle
Gen-rating Plants for NO., PM, H2SO4, GHG
Auxiliary Emission Limits' (Ib/MMBtL except where noted)
Permit Boiler Size
Facility Location Date MMBtu/hr NOx PM/PM101PM2.5 H2SO4 GHG
Carroll County Washington 11/5/2013 99 - 0.02 - 0.008 0.00022 26,259.76 tpy
Enerqy Twp., OH
Renaissance Carson City, 11/1/2013 (2)-40 0.035 0.005 - 11,503.7 tpy(both
Power MI units)
Oregon Clean '�i Oregon, OH 06/18/2013 99 0.02 0.008 0.00011 11,671 tpy
Energy
Green Energy Leesburg, 04/30/2013 75 9 ppmvd at 3% 02 Pipeline natural gas<0.1 - Pipeline natural
Partners/ VA (=0.011 Ib/MMBtu) gr S/100scf gas
Stonewall
Hickory Run New Beaver 04/23/2013 40 0.011 0.005 0.0005 13,696 tpy
Energy LLC '�i Twp., PA
Sunbury Sunbury, PA 04/01/2013 Not provided 0.036 0.008 -- -
Generation (repowered
unit)
Brunswick Freeman, 03/12/2013 66.7 9 ppmvd at 3%02 Pipeline natural gas<0.4 Pipeline natural gas< Pipeline natural
County Power VA (=0.011 Ib/MMBtu) qr S/100scf 0.4 qr S/100scf qas
St. Joseph New 12/03/2012 (2)-80 0.032 0.0075 - 81,996 tpy; 80%
Enerqy Center Carlisle, IN efficiency
Hess Newark Newark, NJ 11/01/2012 66.2 0.66 Ib/hr 0.33 Ib/hr 0.006 Ib/hr 7,788 Ib/hr
Energy Center (based on 0.010 (based on 0.005 (=0.0001 Ib/MMBtu at
Ib/MMBtu) Ib/MMBtu) full load)
Channel Energy Houston,TX 10/15/2012 (3)-430 21.6 Ib/hr/unit 7.8 Ib/hr/unit 1.0 Ib/hr/unit -
Center, LLC (=0.05 Ib/MMBtu at full (=0.018 Ib/MMBtu at full (=0.002 Ib/MMBtu at full
load) load) load)
Cricket Valley Dover, NY 09/27/2012 I 60 0.011 0.005 - -
Pioneer Valley Westfield, 04/05/2012 21 0.029 0.0048 0.0005 -
Energy Center MA
(PVEC)
Palmdale Hybrid Palmdale, 10/18/2011 110 9 ppmvd at 3%02 0.33 Ib/hr - Annual tuneup
Power CA (=0.011 Ib/MMBtu) (=0.003 Ib/MMBtu at full
load)
Entergy Nine- Westwego, 08/16/2011 I 338 - 7.6 Ib/MMscf - 117 Ib/MMBtu
mile Point Unit 6 LA (=0.0076 Ib/MMBtu)
Brockton Power Brockton 07/20/2011 60 0.011 0.01 - --
MA (MA Plan
Approval)
72
Table 1-7. Summary Of Recent PSD BACT Determinations for Natural Gas Auxiliary Boilers at Large(>100MW)Gas Fired Combined-Cycle
Generating Plants for NO,,, PM, i2SO4, GHG
Auxiliary Emission Limits' (Ib/MMBtt except where noted)
Permit Boiler Size
Facility Location Date MMBtu/hr NOx PM/PM10/PM2.5 H2SO4 GHG
Avenel Power Avenal, CA 05/27/2011 37.4 9 ppmvd at 3%02 0.34 grains S/100 dscf — —
Center (=0.011 Ib/MMBtu) and pipeline quality gas
Portland Gen. Morrow, OR 12/29/2010 91 50 lb/MMscf 2.5 lb/MMscf — --
Electric Carty (=0.05 Ib/MMBtu) (=0.0025 Ib/MMBtu)
Plant
Dominion Front Royal, 12/21/2010 88.1 0.011 Ib/MMBtu 0.44 lb/hr — --
Warren County VA (=0.005 Ib/MMBtu at full
load)
Pondera/King Houston,TX 08/05/2010 (2)-45 0.45 Ib/hr/unit 0.32 Ib/hr/unit — —
Power Station (=0.01 Ib/MMBtu at full (=0.007 Ib/MMBtu at full
load)- load) _
Victorville 2 I Victorville, 03/11/2010 35 9 ppmvd at 3%02 0.2 grains S/100 dscf and -- —
Hvbrid CA (=0.011 Ib/MMBtu) pipeline quality qas _
Stark Granbury, 03/03/2010 142 1.42 lb/hr/unit 1.061b/hr/unit — —
PowerMlolf TX (=0.01 Ib/MMBtu at full (=0.0075 Ib/MMBtu at full
Hollow load) load)
Panda Sherman I Grayson,TX 02/03/2010 53 0.53 Ib/hr/unit 0.53 Ib/hr/unit, —
Power (=0.01 lb/MMBtu at full (=0.01 Ib/MMBtu at full
load) load)
Pattdlo Branch Savoy,TX 06/17/2009 (4)-40 1.4 Ib/hr/unit 0.3 Ib/hr/unit — —
Power LLC (=0.01 Ib/MMBtu at full (=0.0075 Ib/MMBtu at full
load) load)
'Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC
73
1.2.2 NOx
Step 1.Identify Candidate Control Technologies
• Selective Catalytic Reduction
• Ultra-Low NOx burner
• Low NOx burner,typically with flue gas recirculation
Step 2.Eliminate Infeasible Technologies
All these technologies are technically feasible, although application of SCR is unusual for natural gas
boilers in this size range.
Step 3:Rank Control Technologies by Control Effectiveness
The ranking of these technologies is as follows:
1. SCR: Demonstrated to have achieved less than 5.0 ppmvd NO, at 3% OZ for gas fired boilers.
Can be used as supplemental control with a low NO,burner but not demonstrated with an ultra-
low-NO,burner.
2. Ultra-Low NOx burner:Demonstrated to have achieved 9 ppmvd NO,at 3%02
3. Low NOx burner, typically with flue gas recirculation: Generally recognized to achieve
30 ppmvd NO.,at 3%Oz.
Step 4.Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-8. The capital cost estimate for an SCR system
and an ultra-low NO, burner are based on information provided by Cleaver Brooks. The SCR has been
conservatively assumed to control 90% of the potential NO, emissions (to 3 ppmvdc at 3% OZ) even
though 5 ppmvdc has been approved in past projects. Control to this NO, level is likely to correspond to
an ammonia slip level of 10 ppm at 3% OZ. Table 1-8 indicates that the average and particularly the
incremental cost effectiveness of an SCR are excessive, at over $19,000 per ton for average cost of
control, and nearly $70,000 per ton on an incremental basis. The ultra-low-NO, burner is cost effective
and is the proposed BACT. There are no energy or environmental issues with ultra-low NO,burners that
would indicate selection of SCR as BACT,given the unfavorable SCR economics.
Step 5.•Select BACT
With respect to NO,the lowest limit identified for any of the power plant auxiliary boilers in Table 1-7 is
consistent with the standard guarantee for ultra-low-NOx burners, which is 9 ppmvd at 3% OZ. This
corresponds to 0.011 lb/MMBtu. There are several boilers with BACT limits for NOx in lb/hr calculated
with 0.01 rather than 0.011 lb/MMBtu, but this is considered effectively the same limit at full load and is
actually less stringent at part-load, since the limits expressed as 9 ppmvd at 3% 02/0.011 lb/NUvIBtu apply
throughout the load range. The Project auxiliary boiler meets this most stringent limit found for natural
gas-fired auxiliary boilers at new large (> 100 MW) combustion turbine combined cycle projects.
74
Table l-8. Summary of Auxiliary Boiler Top-Down BACT Analysis for NOx
FOx Emissio-is Economic Impacts _ _ Environm mtal Impacts
Emissions Installed Total Energy
Capital Annualized
Control Reduction CapIncremental Impacts Toxics Adverse
Alternative ppmvd @ Tons per Compared Cost Cost Average Cost Cost (compared Impacts Environmental
/0
3 02 year(tpy) to Baseline (differential (differential Effectiveness Effectiveness to (Yes/No) Impacts
(tpy) over over baseline) (Yes/No)
baseline) baseline)
SCR 3 _ 0.95 8.51 1 $414,750_ $162,668 _ _$19.115 $69,786 Small I Yes No
ULN 9 2.89 6_.57 _ I $134,400 $27.283 _ $4,153 — negligibleI No _No_
LN 30 9.46
(baseline)
SCR—Selective Catalytic Reduction
ULN—Ultra low-NOx burner
LN—Low NOx burner
See Appendix A, Calculation Sheets 8 and 9, for calculation of cost values.
75
1.2.3 PM/PMIOIPM2.6
For PM/PMIo/PM2.5, this evaluation does not identify and discuss each of the five individual steps of the
"top-down" BACT process, since there are no post-combustion control technologies available for
PM/PMIp/PM25. The "top-down" procedure does require selection of BACT emission limits, which is
addressed in the following paragraphs.
Table 1-7 presents the review of BACT precedents for auxiliary boilers. With respect to PM/PMIo/PM2.5,
for limits expressed in mass units (lb/MMBtu or lb/hr converted to lb/MMBtu at full load), only two of
the auxiliary boilers listed in the Table 1-7 have PM/PMio/PM25limits that are more stringent than the
Project auxiliary boiler limit of 0.005 lb/MMBtu. One of these boilers is at the Palmdale Hybrid Power
facility, with a limit of 0.33 lb/hr,which corresponds to 0.003 lb/MMBtu at full load. However,this lb/hr
limit could be met by reducing the boiler load, if the actual emissions exceed 0.003 lb/MMBtu. So at
lower loads it is actually less stringent than the Project limit of 0.005 lb/MMBtu, which applies
throughout the load range. The other boiler listed in the RBLC with a lower lb/MMBtu emission limit is
at the Portland (OR) General Electric Carty Plant. This limit of 2.5 lb/MMcf of natural gas (which
corresponds to 0.0025 lb/MMBtu) is considered unrealistically low for a guarantee for a boiler of this
type. This is because of uncertainty and variability with available PM/PMio/PM25 test methods, and the
risk of artifact emissions resulting in a tested exceedance.All new gas-fired boilers,properly operated,are
expected to have intrinsically low PM/PMIo/PM2,5 emissions. A limit of 0.005 lb/MIv1Bm is within the
range of recent PSD BACT levels and is justified as PSD BACT.
Several of the boilers listed in Table 1-7 have PM/PM10/PM25 PSD BACT limits expressed as the sulfur
content of the natural gas. These values range from 0.1 grains/100 scf to 0.4 grains/100 scf. All of these
values are lower than what USEPA defines as the maximum sulfur content of pipeline natural gas
(0.5 grains/100 set). The Applicant does not believe it is prudent to assume a natural gas sulfur content
lower than EPA's definition for pipeline natural gas. Therefore, these sulfur limits for PM/PMIo/PM2.5
PSD BACT limits are not appropriate.
1.2.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of natural gas as the BACT fuel, this is the lowest sulfur content fuel suitable for the
auxiliary boiler.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 40% molar conversion of fuel sulfur to H2SO4. This is because Footprint has incorporated a CO
oxidation catalyst to reduce CO emissions. One of the collateral impacts of this oxidation catalyst is an
increase in H2SO4 emissions. With respect to H2SO4, none of the 6 of the projects in Table 1-7 with
numeric H2SO4 limits have oxidation catalysts. Therefore,the proposed Project limit is less stringent than
5 of these 6 limits.The proposed Project limit of 0.0009 lb/MMBtu H2SO4 is justified as PSD BACT with
the addition of a CO catalyst.
1.2.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT.
76
With respect to GHG, most of the auxiliary boilers listed in Table 1-7 with GHG limits for PSD BACT
are expressed as a mass emission value, which is a project specific number reflecting the particular size
and gas throughput limits of the specific project unit. For its proposed GHG limit for the Auxiliary Boiler,
the Project has chosen a conservative value based on the USEPA Part 75 default emission factor (119
lb/MMBtu). Another unit listed in the RBLC has an 80% efficiency specified in addition to an annual
mass limit. This is the only auxiliary boiler approved with this type of limit. The Project will install an
auxiliary boiler with a nominal efficiency of 83.7%. The Applicant proposes a GHG PSD BACT limit
expressed in the units of lb/MMBtu(119 lb/MMBm) as most appropriate PSD BACT limit.
1.3 Emergency Diesel Generator
This section supplements the PSD BACT analysis for the emergency diesel generator to address public
comments made on the draft permit documents. The Project is subject to PSD review for NO.,
PM/PM o/PM25, H2SO4, and GHG, and thus the emergency diesel generator is subject to PSD BACT for
these pollutants.
The Project includes a 750 kW emergency diesel generator that will have ultra-low sulfur diesel (ULSD)
as the only fuel of use. Table 1-9 presents the proposed BACT limits for the emergency diesel generator
for pollutants subject to PSD review.
Table 1-9. Emergency Diesel Generator Proposed PSD BACT Limits
Pollutant Emission Limitation Emission Limitation
(grams/kWhr) (grams/hphr)
NOx 6.4 4.8
PM/PM10/PM25 0.20 0.15
H2SO4 0.0009 Ib/hr(0.00012 Ib/MMBtu)
GHG as CO2e 162.85 Ib/MMBtu
The proposed PSD BACT limits for NO,and PM/PMIo/PM2.5 are based on compliance with the EPA New
Source Performance Standards (NSPS), 40 CFR 60 Subpart IIII. For a 750 kW engine, Subpart 11I1
requires what is referred to as a Tier 2 engine. For H2SO4, the PSD BACT limit is based on use of ultra-
low sulfur diesel (ULSD) fuel, and conversion of 5% of the fuel sulfur on a molar basis to H2SO4. The
GHG limit is based on EPA emission factors for ULSD.
In order to inform the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for emergency generators at new large(> 100 MW)combustion turbine combined cycle
projects. This compilation is based on the USEPA RBLC (RACTBACT/LAER Clearinghouse). Several
recent projects not included in RBLC have also been included in this compilation. Table 1-10 provides
this compilation. Review of Table 1-10 indicates that only one emergency generator is fired with natural
gas, and all the others are fired with ULSD. The gas-fired engine, at Avenal Power Center in CA, does
have SCR to control NOx. All other emergency generators in Table 1-10 do not have any post
combustion controls for PSD pollutants. Table 1-10 will be referred to in the individual pollutant
discussion below.
77
Table 1-10. Summary Of Recent PSD BACT Determinations for Emergency Generators at Large(>100MW)Gas Fired Combined-Cycle
Generatinq Plants for NO., PM,H2SO4,GHG
Facility Location Permit Emergency Emission Limits'
Date Generator Size'. NOx I PM/PM10/PM2.5 H2SO4 GHG
Carroll County Washington 11/5/2013 1112 kW Subpart IIII 0.000132 833.96 tpy
Energy Two., OH qrams/kWhr
Renaissance Carson City, 11/1/2013 (2)—1000 kW
Power MI Subpart IIII -- 1731.4 tpy(both units)
Langley Gulch Payette, ID 08/14/2013 750 kW
Power Subpart IIII — —
Oregon Clean Oregon, OH 06/18/2013 2250 kW Subpart IIII 0.000132 877 tpy(87)
Energy qrams/kWhr
Green Energy Leesburg, 04/30/2013 1500 kW
Partners/ VA Subpart IIII _ Low carbon fuel and
Stonewall efficient operation
Hickory Run New Beaver 04/23/2013 750 kW 6.0 grams/kWhrI 0.25 grams/kWhr — 80.5 tpy
Energy LLC Two., PA
Brunswick Freeman, 03/12/2013 2200 kW Low carbon fuel and
County Power VA Subpart IIII ULSD
efficient operation
Moxie Patriot Clinton Twp 01/31/2013 1472 hp 4.93 grams/hp-hrI 0.02 grams/hp-hr — —
LLC PA
St.Joseph New 12/03/2012 (2)—1006 hp Subpart IIII — 1186 tpy
Energy Center Carlisle, IN
Hess Newark Newark, NJ 11/01/2012 1500 kW Subpart IIII — —
Energy Center
Moxie LibertyAsylum 10/10/2012 4.93 grams/hp-hr I 0.02 grams/hp-hr — —
LLC Twp, PA
Cricket Valley Dover, NY 09/27/12 4 Black Start Subpart IIII
EDGs 3000 kW
each
ES Joslin Power I Calhoun, TX 09/12/2012 1 (2)-EDG 14.11 Ib/hr/unit I 0.44 Ib/hr/unit — —
Pioneer Valley Westfield, 04/05/2012 2174 kW
Energy Center MA Subpart IIII -- —
(PVEC)
Palmdale HybridI Palmdale, 10/18/2011 I 110
Power CA Subpart IIII
Thomas C. Llano, TX 09/01/2011 1340 hp 16.52 lb/hr 0.55 Ib/hr — 15,314 Ib/hr 30 day
Ferguson Power (5.5 grams/hp-hr) rolling average
765.7 tpy 365 day
Enter Nine- I Westwe o, 08/16/2011 I 1250 h __ — rolling average
9Y 9 P Subpart IIII CO2e 163.6 Ib/MMBtu,
mile Point Unit 6 LA
78
Facility Location Permit Emergency Emission Limits'
Date Generator Size NOx PM/PM10/PM2.5 H2SO4 GHG
Avenal Power Avenal, CA 05/27/2011 550 kW natural SCR to 1 gram/hp- 0.34 gram/hp-hr — —
Center gas engine hr
Dominion Front Royal, 12/21/2010 2193 hp Subpart III[
Warren County VA
Pondera/King Houston,TX 08/05/2010 Size not given 26.61 Ib/hr 1.88 Ib/hr — --
Power Station
Brockton Power Brockton 07/20/2011 3-2000 kW each
MA (MA Plan 5.45 gm/hp-hr 0.032 gm/hp-hr
ADDroval)
Victorville 2 Victorville, 03/11/2010 2000 kW
Hybrid CA Subpart IIII
Stark Granbury, 03/03/2010 750 hp 23.25 Whir 1.65 Ib/hr — —
Power/Wolf TX (14 grams/hp-hr) (1.0 grams/hp-hr)
Hollow
Panda Sherman Grayson,TX 02/03/2010 Size not given 35.24 Ib/hr 0.17 Ib/hr — —
Power
Pattillo Branch Savoy, TX 06/17/2009 Size not given 18.0 Ib/hr 0.5 Ib/hr — —
PowerLLC
_ 'Generators are diesel generators except where noted.
2 Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC.
79
1.3.1 Fuel Selection
Step 1:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although use of natural gas is unusual for an emergency
engine.
Step 3:Rank Control Technologies by Control Effectiveness
Natural gas engines can achieve lower emissions compared to ULSD.
Step 4:Evaluate Controls
Normally, for an emergency generator, it is very important to have the fuel supply directly available
without the possibility of a natural gas supply interruption making it impossible to operate the emergency
generator in an emergency. The purpose of the emergency generator is to be able to safely shut the plant
down in the event of an electric power outage. So in order to maintain this important equipment
protection function, ULSD, which can be stored in a small tank adjacent to the emergency generator, is
the fuel of choice. Footprint is not aware of the specific circumstance for the emergency generator fuel
selection at Avenal, but Footprint does not believe a natural gas fired generator for the Salem Project is a
prudent choice.
Step 5.•Select BA CT
ULSD is proposed as the BACT fuel for the Project emergency generator.
1.3.2 N%
Step 1:Iden dfy Candidate Control Technologies
• Selective Catalytic Reduction
• Low NO, engine design in accordance with EPA NSPS, 40 CFR 60 Subpart IIII (Tier 2 engine
for 750 kW unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible,although application of SCR is unusual for an emergency
engine.
Step 3:Rank Control Technologies by Control Effectiveness
SCR can normally achieve 90%remove of NO,emissions, so it is more effective than the Tier 2 engine
design which is based on low-NO, engine design. However, for an emergency generator, if this unit is
used just for short period of test and facility shutdown in an actual emergency, the ability of the SCR to
80
control emissions will be significantly reduced since the engine/SCR takes time to warm up to achieve
good NO,control.
Step 4.•Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-11. The capital cost estimate for an SCR
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. The SCR has been conservatively assumed to control 90%of the potential
NO, emissions even though this is unlikely in this application. Table 1-11 indicates that the cost
effectiveness of an SCR is over $33,000 per ton of NO.. This cost is excessive, even if the emergency
generator runs the maximum allowable amount of 300 hours per year(unlikely) and 90%NO,control of
the full potential to emit is achieved.
There are no energy or environmental issues with a Tier 2 generator that would indicate selection of SCR
as BACT,given the unfavorable SCR economics.
Step S.•Select BACT
With respect to the selection of a PSD BACT for NO, for the emergency generator, Table 140 indicates
that compliance with Subpart IIII is the most common limit. Several BACT determinations contain
gram/kWhr or gram/hp-hr limits that approximate the Subpart IILI values but do not specifically reference
Subpart IIIL Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output.
Overall, with the elimination of SCR on economic grounds, the review of other RBLC precedents
supports the selection of Subpart IIII compliance as BACT.
1.3.3 PM/PM10/PM2.6
Step 1:Identify Candidate Control Technologies
• Active Diesel Particulate Filter(DPF)
• Low PM engine design in accordance with EPA NSPS,40 CFR 60 Subpart IILI(Tier 2 engine
for 750 kW unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of a DPF is unusual for an
emergency engine.
Step 3:Rank Control Technologies by Control Effectiveness
An active DPF can achieve up to 85% particulate removal (CARB Level 3), so it is more effective than
the Tier 2 engine design which is based on low-emission engine design.
Step 4:Evaluate Controls
Since a DPF is technically feasible, an economic analysis of the cost effectiveness for emission control
was conducted. This economic analysis is presented in Table 1-12. The capital cost estimate for an active
system is based on information provided by Milton Cat Power Systems. The other factors are from the
81
OAQPS Cost Control Manual. Table 1-12 indicates that the cost effectiveness of an active DPF is over
$600,000 per ton of PM/PMIO/PM2.5. This cost is excessive, even if the emergency generator runs the
maximum allowable amount of 300 hours per year(unlikely).
82
TABLE 1-11 750 KW EMERGENCY GENERATOR
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION-
Cortlio7:bybteni:l:... ....40
1�g'p}l1lt.....::::::::::::::iryx)?4s:;:::; ::: :;:: :::::::::::'::::::::::::::9pel)g6fa :Efole9WnFFeY{O:Cf3i$06gbpsltklllt(RIYL=:=::::: ;::::1;''J.4:
Eccrioititc feGtoie from jGfBe6QEl?;Torr,1i:94i1RICGI:B'A(4'1:�: :�:=:�:�:�:=:=:::�:::�:�:SCIs�CaitrEI:ElOcie ": .. . . . ..... . . . . . . . . . . . . . . .•.•. -
11�XIF:Ei : isi:;::5[:isi:Pas?::::::::asis�:�:�:�:96"fa
Equipment cost(EC) (Factor) capital Recovery $4U,btiA
a. SCR Capital Cost Estimate(Per Milian Cat) $150,000 Direct Operating Costs
b. Instrumentation(0.10A) Included a. Ammons $2,256
C. Taxes and Freight (EC'0.05) $7,500 b Operating Labor (OI.)(0.5 hr/shift)($25.6/hr) $480
c. Maintenance Labor (ML):(0.5 hr/shift)($25.6/hr) $480
Total Equipment Cost(TEC) $157,500 d Maimenance Materials=Maintenance Labm $480
Direct Installation Costs Total Direct Operating Cost $880
a. Foundation (TEC-0.08) $12,600
b. Erection and Handling (TEC-0.14) $22,050 Catalyst Replacement is not included since the emergency generator
C. Electrical (TEC-0.04) $6,300 will only operate a maximum or 300 hours in any year
d. Piping (TEC-002) $3,150
e. Insulation (TEC-0.01) $1,575
f. Painting (TEC-0.01) $1,575
Total Direct Installation Cost $47,250
Indirect Operating Costs
a. Overhead(60%or OL+ML) .$576
b. Property Tax;(TCC-0,01) $2,489
Indirect Installation Costs C. Insurance:(TCC-0.01) $2,489
a. Engineering and Supervision (TEC'0.1) $15,750 d Administration_(TCC'0.02) $4,977
b. Construction/Field Expenses (TEC'0.05) $7,875
a Construction Fee (TEC-0.1) $15.750 Total Indirect Operating Cost $10,531
d. Startup (TEC'0.02) $3,150
e. Performance Test (TEC-0.01) $1,675
Total Indirect Installation CostITotal Annual Cost $52,054
S44,f00
INOX Reduction (tons/Mr) 1.57
Total Capital Cost(TCC) $21$880
(Cost of Control($/ton-NOx) $33,230
Note 1:.Ammonls cost based on estimated we deiivered cost for 19%aqueous ammonia of$0.60 per pound of ammonia.and 12 The of NH3 Injected
per pound of NOx rammed
83
TABLE 1-12 750-KW EMERGENCY GENERATOR
ECONOMIC ANALYSIS-ACTIVE DIESEL PARTICULATE FILTER
Control:�7'�f6it5:1. .. . . .Y9ata:::::::::::::::::::::::::::::::::::::::::: ::::::::::::::::::::.
egd!IInsPN E!oidn(?ni:P6.. ?C. .. Subp!';e
- EfM10p)tq Ke4t4r?1[eln A{dis(iEP:Forinta(N¢.{U,is6/SSL7;[;[;ipipE:t;ip[;i;i;i;i;[;iopFtoritroi Efllciencyl4.W[ [. :$.
Cb�tat ::::::::::::::::::::::::: :::::::::::::::::::::::
tqurpment cast(EG) (Factor) f:epllHl Recovery $7A,336
a.
OFF Capital Cost Estimate(per Milton Cat) 590,000
b. Insmmtenlalion(0.10A) Included Direct Operating Casts
c Taxes and Freight (EC'0.05). 54.500 a Operating Labor (OL):(0.25 hr/shift)(S25.6/hr) $240
b Maintenance Labor (ML):(0.25 hr/shi0)(S25.6/hr) $240
Total Equipment Cost(TEC) 594,500 C. Maintenance Materials= Maintenance Labor $240
Direct Installation Costs Total Direct Operetlng Cost $720
a. Foundation (TEC-0.08) 57,660
b. Erection and Handling (TEC•0.14) $13.230
c. Etectricel (TEC-0.04) $3.780 DPF Replocenlentis not included since Die emergerxy generator
d. Piping (rEC•0.02) $1,890 will only operate-a maximum of 300 hours in any year
e. Insulation (TEC-0.01) $945
f. Painting (TEC-0.0 1) $945
Total Direct Installation Cost $28,380
Indirect Operating Costs
8. Overhead(60%of OL�ML) $288
- Indirect InsmOodon Co.. D. Property Tax (TCC-0.01) $1,493
a. Engineering and Supervision (TECO 1) $9,450 c insurance.(TCC0.01) $1,493
' b, ConstructionlField Expenses (TEC'0.05) $4,725 d. Administration.(TCC-0.02) $2.986
c. Canstrucgon Fee (TEC-0.1) $9.450
d. Startup (TEC-0.02) $1,890 Total Indirect operating Cost $8,260
e: performance Test (TEC-0.01) $945
ITotal Annual COSL $31,318'
Total Indirect Installation Cost =SAM -
IPM Reduction (tonSNr) -0.05
Totatcepltal Cost(TCC) $149,310
(Cost of Control($/ton-PM) $614,080
84
There are no energy or environmental issues with a Tier 2 generator that would indicate selection of a
DPF as BACT,given the unfavorable economics.
Step 5.•Select BACT
With respect to the selection of a PSD BACT for PM/PMI0/PM25 for the emergency generator,
Table 1-10 indicates that compliance with Subpart IIII is the most common limit. There are two BACT
determinations for PA projects (Moxie projects) that both have very low PM/PMIO/PM25 limits of
0.02 gram/hp-hr. Footprint suspects that this limit is a mistaken entry for the Subpart IIII value of
0.2 grams/kWhr. Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output. Brockton (MA) also has a very low PM limit, much lower than the Subpart IIII
requirements. Footprint does not consider a PM limit less than the Subpart IIII requirements to be an
appropriate BACT.
Overall, with the elimination of a DPF on economic grounds, the review of other RBLC precedents
supports the selection of Subpart IIII compliance as BACT.
1.3.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process,since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of ULSD as the BACT fuel, this is the lowest sulfur content fuel suitable for the
emergency generator.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 5%molar conversion of fuel sulfur to H2SO4.Most of the emergency generators in Table 1-10 do
not have an H2SO4 limit. The only numerical limits for H2SO4 identified for an emergency generator are
those for the two recent Ohio PSD permits (Oregon and Carroll County). The limit in each case is
0.000132 grams/kWhr. Both these project are approved with ULSD as the emergency generator fuel.
Conversion of the Footprint limit to grams/kWhr indicates that 5% molar conversion of the fuel sulfur to
H2SO4 yields 0.0005 grams/kWhr, or about 4 times the Ohio limits. Review of the Ohio approvals
indicates this factor is based on an EPA toxics emission factor which apparently allows for a much lower
molar conversion of fuel sulfur to H2SO4- While this factor may be suitable for estimating actual
emissions, Footprint believes this factor is not appropriate for setting an emission limit. Therefore, given
that most agencies do not even regulate emergency generator H2SO4, Footprint believes the PSD BACT
emission rate based on 5%molar conversion of fuel sulfur to H2SO4 is justified as BACT. This 5% molar
conversion of fuel sulfur to H2SO4 is a reasonable upper limit permit limit assumption for fuel combustion
sources that do not have an SCR or oxidation catalyst.
1.3.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT. Given that emergency generators operate so little,
agencies have not required review of generator efficiency as part of GHG BACT.
With respect to GHG, most of the emergency generators listed on the RBLC with GHG limits for PSD
BACT are expressed as a mass emission value,which is a project specific number reflecting the particular
size and gas throughput limits of the specific project unit. Therefore, these GHG equipment-specific
limits are not automatically transferrable as comparable limits for this Project. One unit listed in
Table 1-10 has a Ib/MMBtu limit based on ULSD corresponding to 163.6 lb COZe/MMBtu. For its
85
proposed GHG limit for the emergency generator, the Project has chosen a value based on the USEPA
Part 75 default emission factors (162.85 lb/MMBtu), incorporating both CO2, CH4, and N2O. The
Applicant proposes a GHG PSD BACT limit expressed in the units of lb/MMBtu(162.85 lb/MMBtu) as
most appropriate PSD BACT limit.
1.4 Emergency Fire Pump
This section supplements the PSD BACT analysis for the emergency diesel fire pump to address public
comments made on the draft permit documents. The Project is subject to PSD review for NO,
PM/PMIo/PM2,5, H2SO4, and GHG, and thus the emergency diesel fire pump is subject to PSD BACT for
these pollutants.
The Project includes a 371 hp emergency diesel fire pump that will have ultra-low sulfur diesel (ULSD)
as the only fuel of use. Table 1-13 presents the proposed BACT limits for the emergency diesel fire pump
for pollutants subject to PSD review.
Table 7-13. Emergency Diesel Fire Pump Proposed PSD BACT Limits
Pollutant Emission Limitation Emission Limitation
(grams/kWhr) (grams/hphr)
NOx 4.0 3.0
PM/PM10/PM25 0.20 015
H2SO4 0.0003 Ib/hr(0.00012 lb/MMBtu)
GHG as CO2e 162 85 lb/MMBtu
The proposed PSD BACT limits for NO,and PM/PMIo/PM2,5 are based on compliance with the EPA New
Source Performance Standards (NSPS), 40 CFR 60 Subpart IIII. For a 371 hp fire pump engine, Subpart
IIII requires what is referred to as a Tier 3 engine. For H2SO4, the PSD BACT limit is based on use of
ultra-low sulfur diesel (ULSD) fuel, and conversion of 5% of the fuel sulfur on a molar basis to H2SO4.
The GHG limit is based on EPA emission factors for ULSD.
In order to inform the PSD BACT process, Footprint has compiled all the PSD BACT determinations in
the last five years for emergency fire pumps at new large (> 100 MVI) combustion turbine combined
cycle projects. This compilation is based on the USEPA RBLC (RACTBACT/LAER Clearinghouse).
Several recent projects not included in RBLC have also been included in this compilation. Table 1-14
provides this compilation. Review of Table 1-14 indicates that all emergency fire pumps are fired with
ULSD. All emergency fire pumps in Table 1-14 do not have any post combustion controls for PSD
pollutants.Table 1-14 will be referred to in the individual pollutant discussion below.
86
Table 1-14. Summary of Recent PSD BACT Determinations for Reciprocating Fire Pump Engines at Large(>100MW)Gas Fired Combined-Cycle
Generating Plants for NO,,, PM, H2SO4,GHG
Permit Fire Pump Engine Emission Limits'
Facility Location Date Size NOx I PM/PM10/PM2.5 H2SO4 GHG
Carroll County Washington11/5/2013 400 hp Subpart IIII "" 0.000132 115.75 tpy
Energy Two., OH grams/kWhr
Oregon Clean Oregon, OH 06/18/2013 300 hp Subpart IIII 0.000132
Energy grams/kWhr
87 tpy
Green Energy Leesburg,Partners/ Low carbon fuel and
Stonewall VA 04/30/2013 330 hp Subpart IIII — efficient operation
Hickory Run New Beaver 04/23/2013 450 hp 1.9 gm/hp-hr I 0.15 grams/hp-hr 0.00012 33.8 tpy
Energy LLC Two., PA qrams/hD-hr
Brunswick Freeman, 03/12/2013 305 hp Low carbon fuel and
Subpart IIII ULSD
County Power VA I efficient operation
Moxie Patriot Clinton Twp I 460 hp 2.6 grams/hp- I 0.09 grams/hp-hr —
LLC PA 01/31/2013 hr l
St. Joseph New 12/03/2012 (2)—371 hp Subpart IIII — 172 tpy
Enerqy Center Carlisle, IN
Hess NewarkI Newark, NJ 11/01/2012 I 270 hp Subpart IIII _ _
Energy Center
M Cie Liberty I Asylum Twp 10/10/2012 I Size not given 2.6 grams/hp- 0.09 grams/hp-hr — — li
Cricket Vallev Dover, NY 09/27/2012 I 460 hD Subpart IIII _ _
ES Joslin Power Calhoun, TX 09/12/2012 _I Size notgiven 2.08 Ib/hr I 0.10 Ib/hr — —
Pioneer Valley Westfield, 270 hp
Energy Center MA 04/05/2012 Subpart IIII _
(PVEC)
Palmdale Hybrid I Palmdale, 10/18/2011 I 182 hp Subpart IIII
Power CA — —
Thomas C. Llano, TX 617 hp 3.81 Ib/hr 0.20 lb/hr — 7,027.8 Ib/hr 30 day
Ferguson Power 09/01/2011 rolling average
351.4 tpy 365 day rolling
average
Entergy Nine- I Westwego, 08/16/2011 I 350 hp — Subpart IIII — CO2e 163.6 Ib/MMBtu,
mile Point Unit 6 LA
Brockton Power Brockton 07/20/2011 100 hp _ _
MA (MA Plan 5.45 gm/hp-hr 0.032 gm/hp-hr
Approval)
87
Permit Fire Pump Engine Emission Limits'
Facility Location Date Size NOx PM/PM10/PM2.5 H2SO4 GHG
Avenal Power Avenal, CA 05/27/2011 288 hp
Center 3.4 grams/hp- ULSD —
hr
Portland Gen. Morrow, OR 12/29/2010 265 _ _
Electric Carty - Subpart IIII
Plant
Dominion Front Royal, 12/21/2010 2,3 MMBtu/hr
Warren County VA Subpart IIII --
Pondera/King Houston,TX 08/05/2010 Size not given 1.54 Ib/hrI 0.55 Ib/hr — —
Power Station
Victorville 2 Victorville, 03/11/2010 182 hp _ _
Hybrid CA Subpart IIII
Panda Sherman Grayson, TX 02/03/2010 Size not given 7.75 Ib/hr 0.55 Ib/hr — —
Power
Pattillo Branch Savoy, TX 06/17/2009 Size not given 9.3 Ib/hr 0.7 Ib/hr — —
PowerLLC
'Short term limits only for NOx, PM, and H2SO4. Limits obtained from agency permitting documents when not available in RBLC
88
e �
1.4.1 Fuel Selection
Step 1:Identify Candidate Fuels
• Natural gas
• ULSD
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although use of natural gas would be unusual for an
emergency fire pump engine.
Step 3:Rank Control Technologies by Control Effectiveness
Natural gas engines can achieve lower emissions compared to ULSD.
Step 4.•Evaluate Controls
Normally, for an emergency fire pump, it is very important to have the fuel supply directly available
without the possibility of a natural gas supply interruption making it impossible to operate the emergency
fire pump in an emergency. The purpose of the emergency fire pump is to be able to pump water in the
event of a fire. So in order to maintain this important emergency function, ULSD, which can be stored in
a small tank adjacent to the emergency fire pump, is the fuel of choice.
Step 5.•Select BA CT
ULSD is proposed as the BACT fuel for the Project emergency fire pump.
1.4.2 NO.
Step 1:Identify Candidate Control Technologies
• Selective Catalytic Reduction
• Low NOx engine design in accordance with EPA NSPS, 40 CFR 60 Subpart III1 (Tier 3
engine for 371 hp fire pump unit)
Step 2:Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of SCR is unusual for an emergency
fire pump.
Step J. Rank Control Technologies by Control Effectiveness
SCR can normally achieve 90% remove of NO. emissions, so it is more effective than the Tier 3 engine
design which is based on low-NO, engine design. However, for an emergency fire pump, if this unit is
used just for short period of test and facility shutdown in an actual emergency, the ability of the SCR to
control emissions will be significantly reduced since the engine/SCR takes time to warm up to achieve
good NOx control.
89
Step 4.Evaluate Controls
Since SCR is technically feasible, an economic analysis of the cost effectiveness for emission control was
conducted. This economic analysis is presented in Table 1-15. The capital cost estimate for an SCR
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. The SCR has been conservatively assumed to control 90%of the potential
NO, emissions even though this is unlikely in this application. Table 1-15 indicates that the cost
effectiveness of an SCR is over$90,000 per ton of NO.. This cost is excessive, even if the emergency fire
pump runs the maximum allowable amount of 300 hours per year(unlikely) and 90%NO,control of the
full potential to emit is achieved.
There are no energy or environmental issues with a Tier 3 fire pump that would indicate selection of SCR
as BACT,given the unfavorable SCR economics.
Step 5.•Select BACT
With respect to the selection of a PSD BACT for NO,for the emergency fire pump, Table 1-14 indicates
that compliance with Subpart IIII is the most common limit. Several BACT determinations contain
gram/kWhr or gram/hp-hr limits that approximate the Subpart IIII values but do not specifically reference
Subpart IIII. Several Texas projects have Ib/hr limits but do not provide the engine size to determine
limits per unit of output.
With the elimination of SCR on economic grounds, the review of other RBLC precedents supports the
selection of Subpart IIII compliance as BACT.
1.4.3 PM/PM10/PM2.e
Step 1:Identify Candidate Control Technologies
• Active Diesel Particulate Filter(DPF)
• Low PM engine design in accordance with EPA NSPS,40 CFR 60 Subpart IIII(Tier 3 engine
for 371 hp unit)
Step 2.Eliminate Infeasible Technologies
Both these technologies are technically feasible, although application of a DPF is unusual for an
emergency engine.
Step 3:Rank Control Technologies by Control Effectiveness
An active DPF can achieve up to 85% particulate removal (CARB Level 3), so it is more effective than
the Tier 3 engine design which is based on low-emission engine design.
Step 4.Evaluate Controls
Since a DPF is technically feasible, an economic analysis of the cost effectiveness for emission control
was conducted. This economic analysis is presented in Table 1-16. The capital cost estimate for an active
system is based on information provided by Milton Cat Power Systems. The other factors are from the
OAQPS Cost Control Manual. Table 1-16 indicates that the cost effectiveness of an active DPF is over
$1,000,000 per ton of PM/PM10/PM25. This cost is excessive, even if the emergency fire pump runs the
maximum allowable amount of 300 hours per year(unlikely)
90
TABLE 1-15 371 HP EMERGENCY FIRE PUMP
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION-
Ei?Aeulm Friteniia i�oin leletlsP. . .. !;e!. ..(. .. .Y. : : : :s0a:eoiilraYtto2ipiic iY�F ): �): '
lA�iist RbcbYgr�.FBcfa/•(CFiF1: O't�:
Equipment Oast(EC) (Factor) l pltsl Fecvvery =4981,
A. SCR Capital,Cos Estmate(per Milton Cat) $85,000 Direct Operating Costs
b. Instrumentation(0.10A) Included a. Ammonia $477
C. Texas and Freight (EC'0.05) $4,250 b Operating Labor (OL):(0.5 hr/shin)($25.6mr) $480
G Mainlimance Labor (ML):(O.6 hr/shin)($25.6/hr) $480
Total Equipment Cost(TEC) $89,250 d Maintenance Materials= Maintenance Labor $480
Direct Installation Costs Total Direct Operating Cost $1,440
a. Foundation (TEC-0.08) $7,140
b. Erection act Handling (TEC•0.14) $12.495
C. Electrical (TEC'0.04) $3,570 Catalyst Replacement is not included since the emergency fire pump
'd. Piping (TEC•0.02) $1,785 Will only operate a maximum of 300 hours in any year
e, Insulation (rEC•0.01) $893
L Painting (TEC'0.01) $893
Total Direct Installation Cost $26,776
Indirect Operating Costs
a. ve
Omead(60%of OL-ML) 5576
Indirect Installation Coss b. Property-Tax.(TCC-0.01) $1,410
a Engineering and Supervision (TEC-0.1) $8,925.00 c. Insurance:(TCC•0.01) $1,410
b. ConsructionfField Expenses (l-Evcim) $4,463 d. Administration:(rCC'0.02) $2,820
C. Construction Fee (TEC'0.1) $8,925
d S=w (TEC0.02) $1,765 Total lndlrxt Operating Cost $6,216
e. Performance Test (TEC'0.01) $893
Total Indirect Installauon cost $24.990 ITotal Annual Cost $30,641
INOX Reduction(tons/yr) 0.33
' Tdtel Ceplrel Coat(TCC) $141,016
ICost of Control($/ton-NOx) $92,502
Note 1: Ammonia coat based on estimated as.dellveved cost for 19%aqueous ammonia of$0.60 par pound of ammonia,and 1.2 The of NH3 Inletted
per pound of NOx removed
91
TABLE 1-16 371 HP EMERGENCYDIESEL FIRE PUMP
ECONOMIC ANALYSIS-ACTIVE DIESEL PARTICULATE FILTER
. . P........ . . . . . . . ....rf.:: : : : � ::'R?4,.,.
?iapro ibFet,6roSom:ansa:pl;anon::te?/iiraifik?n.... ... rEinaai;�yiY•.f:..
f:aEllubl Recaveh>'actor(oRia:::::::0:19a:�:�:�:�::::::::::::::::::::::::::::::::::::::;:;:;:;:;:::::::�::::::::�:::.:.:::::::::::::::::::�:�:
Equipment cost(tc). (Factor) Capitol Recovery $12,159
DPF Capital Cost Estmate 545,000 Direct Operating Costs
b. Imrumentation(0.1 OA) Included
C. Taxes and Freight (EC•0.05) $2,250 a Operating Labor (OL):(0.25 hr/shift)($25 0/bq $240
b Maintenance Labor (ML):(0.25 hf/shin)($25.8/hr) $240
Total Equipment Cost(TEC) $47,250 a MaintenonceMaterials= Maintenance tabor $240
Direct Installation Costs Total Direct OpsrMing Cost $720
-Foundation (rEC'0.08) $3,780
b. Erection and Handlirp (rEC'0.14) $6,015
C. Oeclrrcal (TEC'0.04) $1.890 DPF Replacement is not included since the emergency fire pump
d. Piping CrEC'0.02) $945 - wt1 only operate a maxlmuns 01300 bourn in any year
e. Insulation (TEC'0.01) $473
f. Painting (TEC'0,01) $473
Total Direct Installatlon,Cost $14,175
Indirect Operating Costs
a. Overhead(60%of OL+ML) $288
Indirect Installation Costs b. Property Tax:(TCC-0.01) $747
n. Engineering and Supervision (TEC'0.1) $4,725.00 c. Insurance:(TCC'0.01) $747
b. Construction Field Expenses (TEC'0.05) $2,363 d. Administration:(TCC'6.02) $1,493
c. Construction Fee (TEC'0.1) $4,725
d. Stan up (TEC'0.02) 5045 Total Indirect Operating Cost $9275
e. Performance Test (TEC-O.M.) $473
Total Indirect Installation Cost $13=0 (Total An nual Coat $16,161
Total Capital Cost(TCC) $74,8515 IPM Reduction(ton9/yr) 0.02
(Coat of Control($tton-PM) $1,033,319
92
There are no energy or environmental issues with a Tier 3 fire pump that would indicate selection of a
DPF as BACT,given the unfavorable economics.
Step 5.•Select BACT
With respect to the selection of a PSD BACT for PM/PMIp/PM25 for the emergency fire pump,
Table 1-14 indicates that compliance with Subpart III1 is the most common limit. There are two BACT
determinations for PA project (Moxie projects) that both have very low PM/PMio/PM2.5 limits of
0.02 gram/hp-hr. Footprint suspects that this limit is a mistaken entry for the Subpart IIII value of
0.2 grams/kWhr. Several Texas projects have lb/hr limits but do not provide the engine size to determine
limits per unit of output. Brockton(MA) also has a very low PM limit, much lower than the Subpart IIII
requirements. Footprint does not consider a PM limit less than the Subpart 1I11 requirements to be an
appropriate BACT.
With the elimination of a DPF on economic grounds, the review of other RBLC precedents supports the
selection of Subpart 11I1 compliance as BACT.
1.4.4 H2SO4
For H2SO4, this evaluation does not identify and discuss each of the five individual steps of the "top-
down"BACT process, since the only available control for H2SO4 is limiting the fuel sulfur content. Based
on the selection of ULSD as the BACT fuel, this is the lowest sulfur content fuel suitable for the
emergency fire pump.
The BACT process for H2SO4 proceeds directly to the selection of BACT. Footprint has based the H2SO4
limit on 5%molar conversion of fuel sulfur to H2SO4. Most of the emergency fire pumps in Table 1-14 do
not have an H2SO4limit. The only numerical limits for H2SO4 identified for an emergency fire pump are
those for the two recent Ohio PSD permits (Oregon and Carroll County), and the Hickory Run (PA)
project. The limit for the Ohio cases is 0.000132 grams/kWhr, and for Hickory Run is 0.00012 grams/hp-
hr (0.00016 grams/kW-hr). All these projects are approved with ULSD as the emergency fire pump fuel.
Conversion of the Footprint limit to grams/kWhr indicates that 5% molar conversion of the fuel sulfur to
H2SO4 yields 0.0005 grams/kWhr, or about 4 times the Ohio limits and three times the Hickory Run limit.
Review of the Ohio approvals indicates this factor is based on an EPA toxics emission factor which
apparently allows for a much lower molar conversion of fuel sulfur to H2SO4. While this factor may be
suitable for actual emissions,Footprint believes this factor is not appropriate for setting an emission limit.
Therefore, given that most agencies do not even regulate emergency fire pump H2SO4,Footprint believes
the PSD BACT emission rate based on 5%molar conversion of fuel sulfur to H2SO4 is justified as BACT.
As noted above for the emergency diesel generator,this 5%molar conversion of fuel sulfur to H2SO4 is a
reasonable upper limit permit limit assumption for fuel combustion sources that do not have an SCR or
oxidation catalyst.
1.4.5 GHG
For GHG,this evaluation does not identify and discuss each of the five individual steps of the"top-down"
BACT process, since there are no post-combustion controls suitable for GHG. The BACT process for
GHG proceeds directly to the selection of BACT. Given that emergency fire pumps operate so little,
agencies have not required review of fire pump efficiency as part of GHG BACT.
With respect to GHG, most of the emergency pumps listed on the RBLC with GHG limits for PSD BACT
are expressed as a mass emission value, which is a project specific number reflecting the particular size
and gas throughput limits of the specific project unit. Therefore,these GHG equipment-specific limits are
93
not automatically transferrable as comparable limits for this Project. One unit listed in
Table 1-14 has a lb/MMBtu limit based on ULSD corresponding to 163.6 lb CO2e/MMBtu. For its
proposed GHG limit for the emergency pumps, the Project has chosen a value based on the USEPA Part
75 default emission factors (162.85 lb/MMBtu), incorporating both CO2, CIIq, and N2O. The Applicant
proposes a GHG PSD BACT limit expressed in the units of lb/MMBtu (162.85 lb/NIMBtu) as most
appropriate PSD BACT limit.
1.5 Auxiliary Cooling Tower
This section provides a PSD BACT analysis for the auxiliary mechanical draft cooling tower. The
primary function for the auxiliary cooling tower is to provide necessary equipment cooling for the gas
turbine itself, which is not possible to provide using the Air Cooled Condenser (ACC) used to condense
steam discharged from steam turbines. The auxiliary mechanical draft cooling tower planned for use is a
3-cell commercial scale tower, with a total circulating water flow (all 3 cells) of 13,000 gallons per
minute (gpm).
In general, mechanical draft cooling towers provide cooling of the circulating water by spraying (warm)
circulating water over sheets of plastic material known as fill. This exposes the circulating water to
ambient air being drawn in through the sides of the tower towards a fan generally located above the fill.A
fraction of the circulating water evaporates into this air, warming it and causing it to become saturated
with moisture. A small portion of the circulating water may be entrained into this air flow. These droplets
of circulating water contain dissolved solids. Specially designed drift eliminators are typically located
above the water sprays to remove most of these droplets and return them to the fill.But a small fraction of
these droplets can escape into the fan discharge into the atmosphere. These droplets then evaporate, and
the particulates in these droplets are a source of particulate (PNVPMIo/PM2,5) emissions. PM/PMJo/PM2.5
are the only PSD pollutants emitted from the auxiliary cooling tower.
The Footprint auxiliary cooling tower is being designed to limit the drift rate to 0.001%of the circulating
water flow (0.13 gpm). The design dissolved solids concentration for the circulating water is 1,500
milligrams per liter (mg/1) As documented in Appendix B of the December 2012 PSD Application,
Calculation Sheet 6, the potential PM/PM o emissions from the auxiliary cooling tower are 0.43 tpy, and
the potential PM2.5 emissions are 0.17 tpy.
Step 1:Identify Candidate Technologies
Particulate control technologies identified for cooling towers at new large > 100 MW combined cycle
turbines are as follows:
• Air-Cooled Condensers(ACCs): This eliminates the use of circulating water for cooling and thus
eliminates drift for large towers used for steam turbine condenser cooling
• High efficiency cooling tower drift eliminators.
• Reduction in the dissolved solids concentration in circulating water.
Step 2:Eliminate Infeasible Technologies
ACCs are technically feasible for steam turbine condenser cooling large combined cycle units. However,
use of an ACC is not technically feasible for the auxiliary equipment cooling required for a GE Frame
7FA.05 combustion turbines since ACCs cannot achieve the degree of cooling performance required.
High efficiency cooling tower drift eliminators are also technically feasible for mechanical draft cooling
towers. The total dissolved solids concentration (TDS) in circulating water is a function of the makeup
94
water TDS, which depends on the makeup water source, and the TDS at which the tower is operated.
Removing TDS from the makeup water is considered technically infeasible for a small auxiliary
mechanical draft cooling tower. However, the TDS in the circulating water can be decreased by
increasing the amount of"blowdown"from the tower. Blowdown is a stream of wastewater continuously
discharged from the tower to remove TDS from the circulating water. Increasing blowdown reduces the
TDS and is technically feasible.
Step J.Rank Control Technologies by Control Effectiveness
The ranking of the technically feasible technologies is as follows:
1. High efficiency cooling tower drift eliminators: Generally recognized to be capable of
achieving a drift rate of 0.0005% of circulating water flow for large cooling tower used for
power plant steam turbine condenser cooling. However, for small commercial mechanical
draft cooling towers being used in this application,the standard design is for 0.001%drift.
2. Reduce the TDS in circulating water: Mechanical draft cooling towers are operated with
circulating water TDS as low as 1000 milligrams/liter(mg/1).
Step 4.Evaluate Controls
Footprint has compiled all the PSD BACT determinations in the last five years for mechanical draft
cooling towers at new large (> 100 MW) combustion turbine combined cycle projects. This compilation
is based on the USEPA RBLC(RACTBACT/LAER Clearinghouse). Several recent projects not included
in RBLC have also been included in this compilation. Table 1-17 provides this compilation.
Review of Table 1-17 indicates that the available cooling tower BACT determinations are almost
exclusively for large towers used for steam turbine condenser cooling. These towers are commonly
specified for 0.0005% drift. Texas project determinations typically do not have the size of the tower
indicated, and only have lb/hr emissions indicated which does not provide a meaningful comparison.
The smallest tower identified with a PM PSD BACT determination is the 12,000 gpm chiller tower at the
Entergy Ninemile Point project in Louisiana. This tower in fact has drift specified at 0.001%, which
agrees with our finding that small towers are designed for 0.001% drift. Therefore, it is concluded that
0.001%drift is justified as BACT for the small auxiliary mechanical draft cooling tower for Footprint.All
towers identified with drift limits of 0.0005%are significantly larger than the Footprint auxiliary tower.
With respect to the circulating water total dissolved solids (TDS) concentration, for projects where this
value is identified, these values range from 1000 to 6200 mg/1. Only two projects have design values <
Footprint's 1500 mg/l.A collateral environmental impact of increasing the blowdown to decrease TDS is
increasing consumption of water. Footprint has selected 1500 mg/1 as a reasonable TDS value balance to
drift emissions and water conservation.
Step 5.•Select BACT
The Footprint Project will meet 0.001% drift and limit the potential PM/PM10 emissions from the
auxiliary cooling tower to 0.43 tpy, and the potential PM2.5 emissions to 0.17 tpy. These values are
justified as BACT.
95
Table 1-17. Summary of Recent Cooling Tower Particulate BACT Determinations for Large(>100MW)Gas Fir-d Combined-Cycle Generating Plants
Cooling Tower Description (total BACT'
Permit circulating water flow rate in gallons pM/PM,o/PMzs
Facility Location Date per minute unless otherwise specified) -
Renaissance Power Carson City, MI 11/1/2013 10 cell tower 0.0005%drift
Langley Gulch Power Payette, ID 08/14/2013 76,151 gpm Drift Eliminators(not limit specified); 5000 mg/I
Oregon Clean Energy Oregon, OH 06/18/2013 322,000 qpm 0.0005%drift;2030.5 mq/1
Green Energy Partners/ Leesburg,VA 04/30/2013 187,400 gpm 0.0005%drift; 5000 mg/I
Stonewall
Brunswick County Power Freeman, VA 03/12/2013 46,000 gpm (towers for turbine inlet air 0.0005%drift; 1000 mg/I
chillers)
St. Joseph Energy Center New Carlisle, IN 12/03/2012 2 towers at 170,000 qpm each 0.0005%drift
Hess Newark Energy Newark, NJ 11/01/2012 220,870 qpm 0.0005%drift;4150 mq/I
Channel Energy Center, Houston, TX 10/15/2012 Size not specified 1.33 Ib/hr PM10
LLC
Pioneer Valley Energy Westfield, MA 04/05/2012 Full wet cooling for 431 MW combined 0.0005%drift
Center(PVEC) cycle facility—circulating flow not given
Deer Park Energy Center Deer Park, TX 09/26/2012 Cooling tower size not specified PM—3.13 Ib/hr
LLC PM10/PM25 1.75lb/hr
Entergy Ninemile Point Westwego, LA 08/16/2011 Chiller cooling tower 12,000 gpm Chiller cooling tower 0.001%drift
Unit 6 Unit 6 cooling tower 115,847 qpm Unit 6 coolinq tower 0.0005%drift
Brockton Power Brockton MA 7/20/2011 92,500 qpm 0.0005%drift, 3235 mg/I
Portland Gen. Electric Morrow, OR 12/29/2010 Cooling tower circulating water flow rate 0.0005%drift, 1200 mg/I
Carty Plant 85,000 qpm
Pondera/King Power Houston, TX 08/05/2010 2 towers-size not specified 1.28 Ib/hr/tower
Station
Victorville 2 Hybrid Victorville, CA 03/11/2010 130,000 qpm 0.0005%drift; 5000 mq/1
Stark Power/Wolf Hollow Granbury, TX 03/03/2010 Cooling tower size not specified 0.0005%drift
Russell Energy Center Hayward, CA 02/03/2010 141,352 qpm 0.0005%drift, 6200 mq/I
Panda Sherman Power Grayson,TX 02/03/2010 Cooling tower sizes not specified Main tower 4.68 Ib/hr PM, inlet air chiller tower
0.27 Ib/hr PM
Both 0.0005%drift
Lamar Power Partners II Paris, TX 06/22/2009 Cooling tower size not specified 2.4 Ib/hr PM10
LLC
Pattillo Branch Power LLC Savoy, TX 06/17/2009 4 towers-size not specified 1.0 Ib/hr/tower PM
0.3 Ib/hr/tower PM,o
'Mass emissions (Ib/hr)are only specified if comparable units across projects(%drift, total dissolved solids)are not provided.
96
Appendix A
Updates to Footprint Air Emissions Calculations
Updated GE performance data is provided as Attachment A-1 (3 sheets). These sheets
update the performance data previously provided.
Items that have changed subsequent to the public review drafts issued by MassDEP are
highlighted in yellow on all the sheets that are updates of prior sheets.
Calculation Sheet 1 presents the potential to emit (PTE) calculations for one turbine.
Two operating cases are used to calculate potential emissions (PTE) are 100% load at
50 OF for baseload operation (8,040 hours/year) and 100% load at 90 OF with the duct
burners and evaporative coolers on (720 hours per year). GE Case 7 is 100% load at 50
OF, with a heat input of 2,130 MMBtu/hr. GE Case 12 is 100% load at 90 OF with the
duct burners and evaporative coolers on with a heat input of 2,449 MMBtu/hr. The PTE
values are based on the direct calculation with the exact Ib/MMBtu values shown on
Calculation Sheet 1.
For CO, Calculation Sheet 1 shows the PTE based on 8,760 hours of operation, but the
worst case PTE is based on separate calculations using startup and shutdown (SUSD)
emissions and an assumed operating scenario. These calculations are provided on
Calculation Sheet 2 for GE and reflect a higher PTE for CO compared to those in
Calculation Sheet 1. Therefore, the maximum SUSD scenario value for CO PTE is
used. Calculation Sheet 1 shows the revised emissions for CO for both the turbine
(based on a maximum rate of 8.0 Ib/hr/turbine) and the auxiliary boiler with the CO
catalyst. The auxiliary boiler CO emission rate with the oxidation catalyst is 10% of the
prior rate (0.035 Ib/MMBtu)(0.10) = 0.0035 Ib/MMBtu.
Calculation Sheet 3 in the December 21, 2012 application had been for Siemens SUSD
and is now dropped. Calculation Sheets 4, 5, and 6 presented emission calculations for
the emergency generator, emergency diesel fire pump, and auxiliary cooling tower
respectively. These have not changed and are not repeated here.
Calculation Sheet 7 presents the updated overall summary of potential-to-emit (PTE) for
the facility.
Calculation Sheets 8 and 9 are new, and are the NOx BACT cost spreadsheets for the
auxiliary boiler, supporting the values in Table 1-8.
97
Attachment A-1(Sheet 1 of 3)
GE Energy 107F Series 5 Rapid Response Combined Cycle Plant-Emissions Data-Natural Gas'
GE Energy Performance Data-Site Conditions
IOperabng Point1 2 3 4 5 6 7 8 9 10 11 12 13
Unfired ( Unfired 'Unfired Unfired I Unfired Unfired Unfired Unfired Unfired Unfired 50%DO 100%Do
Unfired
Case Description firing firing
IAmblent Temperature 'F 0 I 0 0 20 , 20 20 50 50 50 I 90 90 90 90
IAmbient Pressure psia 14.7 14.7 14.7 14.7 1 14.7 14.7 14.7 14.7 14.7 1 14.7 14.7 14.7 14.7
IAmbient Relative Humidity % 60 I 60 60 60 60 60 60 60 60 60 60 60 60
GE Energy Performance Data-Plant Status
HRSG Duct Burner(On/Off) Unfired Unfired ( Unfired UnfiredUnfired Unfired Unfired Unfired Unfired Unfired Fired Fired Unfired
Evaporative Cooler state(On/Off) Off Off Off Off Off Off Off Off Oft On On On 'Off
IGas Turbine Load % .BASE 75% 50% BASE 75% 46% BASE 75% 46% BASE PEAK On
BASE
Gas Turbines Operating - 1 1 1 1 1 1 1 1 1- 1 1 1 1
GE Energy Performance Data-Fuel Data
IGT Heat Consumption MMBtu/hr 2300 1850 1460 2250 1790 1360 2130 1700 I+1 13111 { 2040 2082 2082 1980
Duct
t.lhr
ITotale(GT+rDB)at Consumption MMBtuJhr 2300 1850 1460 2 50 1790 I 1 60 200
3700 I 1310 I 2040 I 2265 2449 1980
GE Energy Performance Data-HRSG Exit Exhaust Gas Emissions
ICO I, Pdo Pm 2 2 1 2 2 2 2 2 2 2 2 2 2
� O
NH3 ppmvdc I 2 2 I 2 ( 2 2 2 2 2 2 I 2 2 2 2
IND% Ib/MMBtu 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 O.007d 0.0074 0.0074 0.0074 0.0074 0.0074
ICO Ib/MMBtu 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045
IVDC Ib/MM3tu' 0.0013 I 0.0033 0.0013 0.0013 0.0013 0.0013 0.0013 0.0013 0.0013 0.0013 0.0022 0.0022 0.0013
1NH3 Ib/MMBtu 0.0027 I 0.0027 0.0027 0.0027 0.0027 . 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027 0.0027
ICondenlates Fnicerabl Sulfates Ib/MMBtu 0.0038 I 0.0048 0.0060 0.0039 0.0049 0.0065 0.0041 0.0052 0.0067 0.0043 0.0057 0.0053 0.0044
INOx Ib/hr 17.0 13.7 10.8 16.7 13.2 10.1 15.8 12.6 9.7 15.1 16.8 18.1 14.7 I
CO Ib/hr 8.0 8.0 6.6 8.0 8.0 6.1 8.0 7.7 5.9' 8.0 8.0 8.0 8.0
VOC Ib/hr 3.0 2.4 1.9 2.9 2.3 1.8 2.8 2.2 1.7 2.7 5.0 5.4 2.6
INH3 Ib/hr 6.2 5.0 3.9 6.1 4.8 3.7 5.8 4.6 35 5.5 6.1 6.6 5.3
Particulates-Filterable+
Condensible,Including Sulfates Ib/hr 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 8.8 13.0 13.0 8.8
ppmvdc N parts per minion by volume,dry bags,.,rxted to 15%02
MMOtu is on a Higher Heating Value(HHV)basis
ya '
Attachment A-1(Sheet 2 of 3)
GE'Energy 107F Series 5 Rapid Response Combined Cycle Plant- Emission Data-Natural Gas
GE Energy Performance Data-Site Conditions
Operating Point 1 14 15 16 17 18 19 20 21 22 23 24 25
50%DB 10W.DB Unfired Unfired Unfired 50%D8 100%DB Unfired 50%DB 100%D8 Unfired Unfired
Case Description firing firing firing firing firing Bring
(Ambient Temperature °F 1 90 90 90 90 105 105 105 I 105 105 105 105 105 1
(Ambient Pressure psia 1 14.7 14.7 14.7 14.7 14.7 14.7 14.7 I 14.7 14.7 14.7 14.7 14.7 {
(Ambient Relative Humidity % 1 60 60 60 60 50 50 50 I 50 50 50 50 50
GE Energy Performance Data-Plant Status
iHRSGDuct Burner(On/Off) t Fired Fired Unfired Unfired Unfired Fired Fired Unfired Fired Fired Unfired Unfired {
I Evaporative Cooler state(On/Off) Off Off Off Off I On On On Off Off I Off Off Off {
(Gas Turbine Load I % PEAK PEAK 75% 1 47% BASE PEAK PEAK BASE PEAK PEAK l 75% 49% 1
(Gas Turbines Operating 11 1 1 { 1 1 1 1 1 1 1 I 1 1 I
GE Energy Performance Data-Fuel Data
GT Heat ConsumptionMMBtu/hr 1 2017 2017 1590 11260 1990 I 2005 2005 1 1880 1928 1928 1520 ' 1240 {
IDuct Burner Heat Consump tion MMBtu hr 1 183 377 D 0 0 183 377 I 0 183 377 0 I 0
ITotal Heat Consumption(GT+D MMBtu/hr I 2201 2394 1590 1260 1990 2188 2382 1 1880 2112 2305 1520 I 1240
GE Energy Performance Data-HRSG Exit Exhaust Gas Emissions
INOxppmvdc 2 2 2 2 2 ( 2 2 2 2 2 1 2 2
ICO ppmvdc 2 2 2 2 2 2 2 2 2 2 1 2 2
INH3 ppmvdc IVOC127 2 7 2 2 2 2 2 2 2 2
7 17 7 I 17 I 2 2
1
INOx Ib/MMBtu , 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 0.0074 10.0074 0.0074 0.0074 0.0074 0.0074
ICO Ib/MMBtu 1 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045 0.0045
IVOC Ib/MMBtu 1 0.0022 0.0022 0.0013 0.0013 0.0013 a0022 0.0022 0.0013 0.0022 0.0022 0.0013 1 0.0013
INH3 Ib/MMBtu 1 0.0027 0.0027 0.0027 0.0027, 0.0027 0.0027 0.0027 0.0027 0.0027 -0.0027 0.0027 0.0027
Particulates-Filterable+
Condensible,Including Sulfates Ib/MMBtu 0,0059 0.0054 0.0055 0.0070 0.0044 0.0059 0.0055 10,0047 0.0062 0.0056 0.0058 0.0071
(NOx Ib/hr 16.3 17.7 11.8 9.3 14.7 .16.2 17.6 13.9 I 15.6 171 11.2 9.2
ICO Ib/hr 8.0 8.0 7.2 5.7 8.0 8.0 8.0 8.0 8.0 8.0 6:8 5.6
1VOC Ib/hr 4.8 5.3 2.1 1.6 2.6 4.8 5.2 2.4 I 4.6 5.1 2.0 1.6
INH3 Ib/hr 5.9 6.5 4.3 3.4 5.4 5.9 6,4 5.1 1 5.7 6.2 4.1 3.3
Particulates-Filterable+
Condensible,including Sulfates Ib/hr 13.0 13.0 8.8 8.8 8.8 13.0 13.0 8.8 I 13.0 13.0 8.8 8.8
ppmvdc n parts per million by volume,dry bass,corrected to 15%02
MMatu Is on a Maher Heating Valve IHHV)basis
Attachment A-1(Sheet 3 of 3)
GE Energy 107FA.05 Rapid Response Combined Cycle Plant
Manufacturer's Emissions Data-Natural Gas-Startup and Shutdown Conditions-Single Unit Basis
NOx(Ib) CO 0b) VOC(lb) PM30 Ilbl Duration Imin)
Cold Start(GT Fire to HRSG Stack Emissions Compliance with Base Load Hold) 89 285 23 7.3 45
Warm Start(GT Fire to HRSG Stack,Emissions Compliance with Base Load Hold) 54 129 '13 5.0 32
Hot Start(GT Fire to HRSG Stack,Emissions Compliance with Base Load Hold) 28 121 12 2.6 18
Shutdown(HRSG Stack EC to GT Flame Off) 10 151 29 5.8 27
100
Calculation Sheet 1
Annual Potential Emissions for Combustion Turbines and Auxiliary Boiler
1
One CombUstien Turbine at 100% Auxiliary Boiler
Load 1
I 50 degF 90 degF Annual Gas Annual 1
I No DF DF,EC toy IblMMBtu tpy I
I Hours per year 8040 720 . 6570(FLE) 6570(FLE) I
I MMBtu/hr 2130 2449 80 I
� � I
I NOx(lb/MMBtu) 0.0074 00074 I 69.9 0011 2.9 1
I I I
I CO 80lb/hr 1 35.0 0.0035 09 I
I I I
I VOC(INMMBtu) 0.0013 00022 I 131 0.005 1.3
I 1 1
I S02(ib/MMBtu) 00015 0,0015 1 14.2 0.0015 0.4 I
I PM/PM-10/PM-2.5 881b/hr 1301b1hr 40.1 1 0005 13 1
I i 6 I
NH3(IblMMStu) 00027 0,0027 I 255 1 - -- 1
I I f I
I H2SO4(IbIMMBtu) I 0001 0.001 1 9.4 1 0,0009 1 0.24 1
I Lead(lb/MMBtu) I- - - I - 4.90E-07 I 0.00013 I
Formaldehyde(Ib/MMBtuj 10.00035 0.00035 3.3 17,40E-05 1 0.019 I
I I I I I I
Total HAP(lb/MMBtu) 100006671 0000667 1 6.3 1 1.90E-03 1 05 1
I CO2(IWMMStu) I 118.9 1 118.9 11,122,9201 1189 1 31,247 1
1 CO2e (tb/MMBta) 1 1190 1 1190 11,124.0031 119.0 1 31,277 1
1Notes: 1 1
11. DF=Duct Firing 1
2. EC=Evaporative Coolers
3. FLE=Full Load Equivalent
4. Annual potential emissions per turbine for all pollutants except CO and PM are based on
[(2130 MMBtulhr)(IbIMMBtu no DF)(8040 hrs)+(2449 MMBtulhr)(Ib/MMBtu DF)(720 hrs))/2000 lbtton
S. Annual potential emissions shown here per turbine for CO are based on 8 Ib/hr for 8760 hours.
However,the worst case PTE for CO includes the startup/shutdown scenario as shown in
Calculation Sheet 2.
6. Annual potential emissions per turbine for PMIPM-10/PM-2.5 are based on
[(8.8 ib/hr)(8040 firs)+113.0 Ib/hrp720 hrs)]/2000 Ib/ton
7. H2SO4 emissions for the aux boiler are based on 40%molar conversion of fuel sulfur to H2SO4
Correcting for molecular welght,the H2SO4 emission rate Is:
(0.0015 lb S02IMMBtu)(0.4)(98 lb/mole H2SO4)1(64 ltdmole S02)=0.00091b/MM8tu
8. Annual potential emissions for the aux boiler are based on:
(80 MMBtu/hr)(Ib/MMBtu)(6570 hours FLE)/(200016/ton)
101
Calculation Sheet 2
GE Emissions for CO and VOC Including Startup Shutdown Scenario
I Emissions for Normal Load Uses
I MMBW/hr CO(lb/hr) VOC(Ib/hr)'
Spring/Fall Normal bad Use 7(50 deg) 21308.0 2,8
Summaer Use 13 except for 720 hours 1980 8.0 2.6
Summer Use 12 for 720 hours(90 de ) 2449 8.0 5.4
Winter Use 4(20 deg) 2250 8.0 2.9
I ASSUMED OPERATING SCENARIOS GE STARTUP/SHUTDOWN EMISSIONS
Assumed Operating Pronle I starts/wk starts/yr
Normal Loads CO VOC
days/ hrs/ hrs/ Weeks/ Normal Load Cases
week day week yr hrs/w Emlsslonsfor Eads Season
cold warm hot cold warm hot cold warm hot cold warm has
Combined startup/shutdown pounds of em ssions persingle,event 436 280 .272 52 42 41 I
Annual SUSD emissions for each category and season fibs).-
Spring/Fall I 5 12 60 20 1200 _0.25_4.75, 0 0 L2180_266001 0 , 260_3990_t 0
Case 7 9600 3323
Summer 7 24 168 2 336 0- 2 0 0 4 0 0 1120 0 0 168 0
5 16 80 8 '640 0 5 0 0 40 0 0 11200 0 0 1680 0
5 12 60 2 120 0 5 0 0 30 0 0 2800 0 0 420 0
1096 Case 13 3008 968
Case 12 5760 3879
Winter 5 16 808 8 640 025 4]5 0 2 38 0 872 10640 0 104 1596 0
976 Case 7M8 2855
TOTAL RUN HRS 42 3272
Planned outage 7 24 168 4 672 6 2616 0 0 312 0 0
Net Dispatched(Includes time In SUSD) '4457
Unplanned FO 4,1% 3s9 4 1088 164
ANNUALHRS 97M
Total Tons in Each Utcgory 1 29.8 4.4 13.1 1 5.5
CO VOC
Total Emissions per unity 42.9 9.9 (
Note: The startup/shutdown cycling scenario is no longer controlling for annual VOC emissions.
Z
Calculation Sheet 7
Summary of Facility Potential to Emit(PTE)in tons per year(tpy)
Annual emissions,tons/year
CTUnit 1(GT+ Cr Unit 2(GT+ Aux Boller Emerge Fire Pump Aux Cooling Fadlity Totals
Pollutant OB) DB) Generator Tower
NO, 69.9 69.9 2.91.7 0.4 0 144.8
CO 42.9 42.9 0.9 1.0 0.3 0 88.0
VOC 13.1 13.1 1.3 0.35 0.12 0 28.0
SOz '14.2 14.2 0.4 0.0017 0.0006 0 28.8
PM" 40.1 40.1 1.3 0.1 0.0 0.4 82.0
PM'.' 40.1 40.1 1.3 0:1 0.0 0.2 81.8
NH, 25.5 25.5 0 0 0 0 51.0
H,504 mist 9.4 9.4- 0.24 1.33E=04 4.84E-05 0 19.0
Lead 0 0 0.00013 8.54E,07 3.10E-07 0 0.00013
Formaldehyde 3.3 3.3 0.019 8.76E-05 4.76E-04 0 6.6
Total HAP 6.3 6.3 0.5 1.76E-03 1.57E-03 0 13.1
CO2 1,122,920 1,122,920 31247 180 66 0 2;277,333
COze 1,124,003 1,124,003 31277 181 66 0 2,279,530
103
Calculation Sheet 8
80 MMBtu/hr Auxiliary Boiler
ECONOMIC ANALYSIS-SELECTIVE CATALYTIC REDUCTION
.
BACT:ASS4ssfn ..
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
IiaerPsx�le: . . . . . ::;:1Q•'Q01s::: . . . . . . . Btisr?tlpb>;mlaidv*in::3Qgpi,'*ja�md 1ti3960'rG(�Y) . . . . . 5.d6;
@icnoiata feeooie t}ojtiiNriesDE2;6bijtiEipliesleiie a. CPinyil....cia3je;99c
(RricbySrj%Fecrar�(CR[T::::::p,'L63. . . . . ::. . . . . . . . . . . .
Equipment cost(EC) (Factor) Capital Recovery $67,514
a. SCR Capital Cost Estimate(Cleaver Brooks) $250,000 Direct Operating Coate
b Taxes and Freight (EC'0.05) $12,500 a. Ammonia $12,261
b Operating labor (OL):(P.5 hr/shift)($25.6/hr) $10,512
Total Equipment Cost(TEC) 5262,500 c Maintenance Labor (ML):(0.5 hr/shift)($25.6/hr) $10,512
d Maintenance Material=Maintenance Labor $10,512
Direct Installation Costs
Total Direct Operating Cost $43;797
. a. Foundation (TEC-0.08) $21,000
b. Erection and Handling (TEC-0.14) $36,750 Catalyst Replacement
C. Electrical (TEC-0.04) $10,500
d. Piping (TEC'0.02) $5,250 e. 33%of TEC required at year 3.33 and year 6.67,plus
a Insulation (TEC-0.01) $2,625 erection and indirect costs(0.25 or replacement)
L Painting (TEC-0.01) $2,625 b. 10-year annualized cost for-catalyst replacement $22,062
Total Direct Installation Cost $78,750 Indirect Operating Coats
Indirect Installation Coats a. Overhead(60%or OL-ML) $12,614
b. Property 7ruc(TCC'0.01) $4,148
a. Engineering and Supervision (TEC-0.1) $26,250 C. Insumnce:(TCC'0.01) $4,148
b Construction/Field Expenses (TEC-0.05) $13,125 d. Administration:(TCC-0.02) $8,295
_
C. Construction Fee (TEC-0.1) $26,250
d. Startup (TEC-0.02) $5,250 Total Indirect Operating Cost '$29,205
e. Pedonmance Test (TEC-0.01) $2.62$
Total Indirect Installation Cost $73,500 'Total Annual Cost $162,668
INOx Reduction(tons/yr) 8.51
Total Capital Cost(TCC) $414,760 '
(Cost of.Control($Ron-NOx) $19,115
Note 1: Ammonia cost based on estimated as delivered coat for 19%aqueous ammonia of$0.50 per pound of ammonia,and 1.2 Me of NH3 Injected
par pound of NOx removed
Calculation Sheet 9
80 MMBtu/hr Auxiliary Boller
ECONOMICANALYSIS-ULTRA LOW NOx(ULN)BURNER COMPARED TO STANDARD LOW NOx BURNER
SACT`Assessment:l:::::::::::::::::-::::::::::::::::.:.:.:.:.:<::.:.:1:.::::::::}:::::::i:::i:i:::;:i::::::p:::}:1:::.;
Cpldfgl$ys(ep[).1(0 90 y9gtg
:;:;:::;:9pge1)AeEiolsit best 3Q DP?ivC4loir6chott4o�9804:
2doncrploFmlorp frnin MeaeDE?,F.uirn BVtD=Aft=SACT:::::::::: . . . .O'.. . .intiefu9p)iinvde:doriaclti1 ( . .:.
Osipltil:FffiCdvetY FaL•lOKtCRPF. . .:[G)6{:�:�:�:�:�:�:=:�:�:=:::::�::: . . . .. ... . . . . . . . . .... . .. ..... . . . . . . . . .
Equipment Cost(EC) (Factor) Capital Recovery $21,907
a. Capital Con Estimate(Differential Cost of ULN
compared to standard low NOx burner) $100,000
(par Cleaver Brooks) Direct Operating Costs
In Taxes and Freight (EC•0.05) $5,000
Direct Operating Costs are assumed to be the
Total Equipment Cost(TEC) $105,000 Sarna for ULN co
mpared to standeM law-NOz burner
Direct Installation Costs
Direct Installation Costs are assumed to be Ne
same for ULN compared to standard low-NOx burner indirect Operating Costs(based on differential coat)
Indirect Instellallon Costa(based on differential cost) a. Overhead(60%of OL+My $0
b. Property Tax:(TCC•0.01) $1.944
a. Fsgineering and Supervision (rEC•0.1) $10,500 c Insurance:(TCC•0.01) $1,344
b Construction/Field Expenses (TEC-0.05) $5,250 d. Administration(rCC`0.02) $2,688
C. Construction Fee (TEC'0.1) $10,500
d. Startup (TEC-0.02) $2,100 Total Indirect Operating Cost $5.576
e. Perrormanre Test (TEC-0.01) $1,050
Total Indirect Installation Cost $29.400
Total Capitol Coat Differential for ULN $134,400
Compared to Standard Low NOx Burner ITotel Annual Cost $27,283
'NOx Reduction(tonsNr) 6.57
(Cost of Control($/ton-NOXI $4,153
105
24 Fort Avenue, Salem, IiA 01970
Public Repository � ®
Salem Public Library
370 Essex Street OGS 0,2,? �®
Salem, MA 01970 p ' LCF 013
�Iqv�FN��EM
Re: Salem Harbor Station ��rN
Monthly Dust Complaint Log
To Whom It May Concern:
There was one coal dust complaint in August 2013. On August 13`h a complaint was fielded by
our Community Relations Office and an adjuster was dispatched to obtain a sample for analysis
according to Station protocol. The results of the analysis determined that the substance was not
plant related.
If you have any questions please feel free to call me at 978-740-8402.
Sincerely,
// zx-
Robert
DeRosier ?/2 7 /� 3
EHS Manager Date
Footprint Power Salem Harbor Operations LLC
cc: N. Malia Griffin
City of Salem BOH
FootproMtPower"
24 Fort Avenue, Salem, MA 01970
Public Repository
Salem Public Library
370 Essex Street
Salem, MA 01970 m0
Re: Salem Harbor Station
Monthly Dust Complaint Log
F9��y
To Whom It May Concern: ,y
There were no dust complaints in the month of October, 2013.
If you have any questions please feel free to call me at 978-740-8402.
Sincerely,
Scott G. Silverstein
COO Date
Footprint Power Salem Harbor Operations LLC
cc: N. Malia Griffin
City of Salem BOH
Dominion Energy New England,Inc. Dominion°
24 Fort Avenue,Salem,MA 01970
Web Address:w .dronxom
-NED
` ED
October 9,2009 ®� 4 2009
&0
,.�.+ gar HE�ALTI-1
Public Repository
Salem Public Library
370 Essex Street
Salem,MA 01970
Subject: Salem Harbor Station
Monthly Dust Complaint Log-September 2009
To Whom It May Concern:
Salem Harbor Station logged Icall in September of 2009. The caller requested a power wash of her condo
building. We returned the call to set up a site visit but our call was not returned. This conmplaint will be
carried into October's report,details are on the attached sheet. If you have any questions,please feel free
to call Rob DeRosier,Station Environmental Coordinator,at(978)740-8402.
Very truly yours, {�
Michael A Fitzgerald
Station Director
Salem Harbor Station
cc: R DeRosier
N. Malia Griffin
City Salem BOH
�5
J
•eu.u.u..•..a...u.....•v..................vu.ue.e......................a.........r.u..•.....a......us.....r.•...weu.o--.................
Coal Dust Report
-M........._....................................._...... .............s.................. ..................._..........._.............._.._.._.._....._.._.....
Complaint Type: Coal Dust
_.._.._.._.._.._.._.._.._.._.._.._.._I._.._.._.._.._.._.._.._.._y_.._.._.._.._.._.._.._.._.._.._.._.._.._. _.._.._.._.._.._.._.._.._.._.._.._.._.._.._.._.._.._..
Address Essex St Cit Salem Incident Location: House Incident Date
Alt.Address:
1st Contact Date: 9/28/2009 Inspect'd ❑ Site Visit Date: Analysis Taken? ❑ Analysis Result Date
Comments: Security recv'd this call. Caller stated she was Claim? ❑ Unfounded ❑ Closed Date
told she could call power plant to have her condo
bldg power washed due to coal dust. I returned
call and left a voicemail requesting call back.
Final Resolution:
Friday, October 09, 2009 Page 1 of 1
Footprint Power®
r�
24 Fort Avenue, Salem, MAO 1
Public Repository
Salem Public Library
370 Essex Street
Salem, MA 01970
Re: Salem Harbor Station
Monthly Dust Complaint Log
To Whom It May Concern:
There were no coal dust complaints in June 2013.
If you have any questions please feel free to call Robert DeRosier, Station EHS Manager, at 978-
740-8402.
Sincerely,
i
ott SilvWen ;7— r
President and COO Date
Footprint Power Salem Harbor Operations LLC
cc: R. DeRosier
N. Malia Griffin
City of Salem BOH
l I,
/r Commonwealth of Massachusetts
Executive Office of Energy 6 Environmental Affairs
Department of Environmental Protection
Northeast Regional Office• 2058 Lowell Street, Wilmington MA 01887.97&6943200
DE JAL L PATRICK RICHARD K SULLIVAN JR
Governor Secretary
SEP0 9 2013 KENNETH! KIMMELL
Coir,inia;goner
Mr. Scott G. Silverstein RE: SALEM
Footprint Power Salem Harbor Transmittal No.: X254064
Development LP Application No.: NE-12-022
1140 Route 22 East, Suite 303 Class: OP 119
Bridgewater,NJ 08807 IMF No.:
PROPOSED AIR QUALITY PLAN
APPROVAL
310 CMR 7.02
�C� 1, 310 CMR 7.00: Appendix A
V�O Including Section 61 Findings
,Flo 772
�
fjoci I y0/3 DRAFT PREVENTION OF
SIGNIFICANT DETERIORATION
�GTy PERMIT
40 CFR 52.21
PROPOSED NEW GAS-FIRED POWER PLANT in SALEM, MA
Public Comment Drafts
Dear Mr. Silverstein:
Footprint Power Salem Harbor Development LP (Footprint) has proposed the construction and
operation of a 630 megawatt (MW) nominal (692 MW with duct firing) combined cycle electric
generating facility(the proposed Facility) at 24 Fort Avenue in Salem, Massachusetts, the
location of your existing power generating facility(Salem Harbor Station).
The Massachusetts Department of Environmental Protection (MassDEP), Bureau of Waste
Prevention, has reviewed your Application identified as Transmittal No. X254064, Application
No. NE-12-022 and determined that the Application is administratively and technically complete.
MassDEP hereby proposes to approve the construction and operation of the proposed Facility,
subject to the conditions set forth in the attached documents. Final action by MassDEP is subject
to the public review process.
This information is available in alternate format Call Michelle Waters-Ekanem,Diversity Director,at 617-292-5751.TDD#1-866.539-7622 or 1-617-574-6868
MassDEP Website w mass govldep
Printed on Recycled Paper
MassDEP letter re: Footprint Power Salem Harbor Development LP
Proposed Plan Approval and
Draft Prevention of Significant Deterioration Permit
Transmittal No.X254064,Application No.NE-12-022
September 2013
Page 2 of 3
Enclosed please find the:
(1) Proposed Plan Approval;
(2) Draft Prevention of Significant Deterioration (PSD) Permit;
(3) Draft PSD Permit Fact Sheet; and
(4)Notice of Public Hearing and Public Comment Period (Public Notice).
To facilitate public participation, a copy of the foregoing documents will be posted on
MassDEP's internet page httu://www.mass.Qov/eea/a2encies/massden/.
As you are aware, Footprint is responsible for ensuring that the Public Notice is published in the
newspaper(s) of general circulation in the municipality where the Facility is proposed. Footprint
has represented to MassDEP that it has arranged for the Public N6tice to be published in The
Boston Globe and The Salem News on Tuesday, September 10, 2013.
The Public Notice will also appear in this week's Environmental Monitor. MassDEP plans to
send copies of the Public Notice to a number of individuals and organizations as a notice method
reasonably calculated to give actual notice of the proposed permits to persons potentially affected
by the proposed project and to elicit public participation.
The required Public Comment period will commence with the date of publication of the Public
Notice. Footprint should promptly publish and forward proof of publication to the attention of
James E. Belsky, Regional Permit Chief, Bureau of Waste Prevention, at 205B Lowell Street,
Wilmington, Massachusetts 01887.
As you are aware, the Public Hearing has been scheduled for Thursday, October 10, 2013 at
7:00 PM at the Bentley Elementary School, 25 Memorial Drive, Salem, Massachusetts. The
Public Comment period is scheduled to close at 5:00 PM on Friday, October 11, 2013.
After the Public Hearing and the close of the Public Comment period, MassDEP will commence
a public comment review. As you are aware, MassDEP will not issue a final plan approval or
PSD permit until EFSB has issued the approval required by Massachusetts General Laws,
M.G.L. c. 164, Section 69J1/4.
Should you have any questions concerning this matter, please contact Cosmo Buttaro by
telephone at (978) 694-3281, or in writing at the letterhead address.
l
�1 MassDEP letter re: Footprint Power Salem Harbor Development LP
Proposed Plan Approval and
Draft Prevention of Significant Deterioration Permit
Transmittal No. X254064,Application No.NE-12-022
September 2013
Page 3 of 3
Sincerely,
_
Cosmo Buttaro
Environmental Engineer
E k
Environmental Engineer
k
s E. Bels
onal PermP
au of Wa
Enclosures
cc: George Lipka, Tetra Tech, 160 Federal Street, 3`d Floor, Boston,MA 02110
Lauren A.Liss, Rubin& Rudman LLP, 50 Rowes Wharf,Boston,MA 02110
80arz-oLiieanar 120 Washington Street,4"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
Atm: Air Permits Program Manager
EPA: Donald Dahl(e-copy)
MassDEPBoston: 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)
Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
LlDepartment of Environmental Protection
Northeast Regional Office•205B Lowell Street, Wilmington MA 01887.978.694.3200
DEVAL L PATRICK RICHARD K SULLIVAN JR,
Governor Secretary
SEP 0 9 2013 KENNETH KIMiMELL
Commiccloner
Mr. Scott G. Silverstein RE: SALEM
Footprint Power Salem Harbor Transmittal No.: X254064
Development LP Application No.: NE-12-022
1140 Route 22 East, Suite 303 Class: OP119
Bridgewater, NJ 08807 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 21 C, 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
This Information is available in alternate format.Call Michelle Waters-Ekanem,Diversity Director,at 617-292-5751.TDD#1-866-539-7622 or 1-617-574-6868
MassDEP Website.w .mass gov/dep
Printed on Recycled Paper
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). 11
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
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Transmittal No.X254064
Application No.NE-12-022
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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. EUl 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). EUI and EU2 each will have a
nominal generating capacity of approximately 315 MW (346 MW with duct firing). EUI 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. EUI 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, EUl 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 (NO,) 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
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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 NO,. 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 EUI and EU2
to sample, analyze and record NO., CO, and NH3 concentration levels, and the percentage of
oxygen (02), 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 EUI, 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
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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 NO, 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 NO, and VOC emissions,
respectively. Therefore, the proposed Facility is a new major source of NO, emissions and is
subject to Appendix A for its NO, emissions. The proposed Facility is required to meet LAER
for NO, emissions and the Permittee must obtain NO, 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 NO, emission limit for EUI and EU2 of 2.0 parts per
million by volume, dry basis, corrected to 15 percent Oxygen (ppmvd @ 15% Oz), one hour
block average. The Permittee provided a LAER analysis in the Application that included the
sources of data reviewed in support of this NO, LAER determination. These sources were EPA's
RACTBACT/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 NO, emission limit of less than 2.0 ppmvd @ 15% 02 has been
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approved and subsequently demonstrated in practice. In addition, the two most recent NO,
LAER determinations for similar Massachusetts projects such as Brockton Power Company LLC
(Application No. 41308015, 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% 02, 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 NO,emission limit constitutes NO, 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 NO, 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 NO, 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 NO, ERCs were created and banked from the
shutdown of Natick Paperboard, 90 North Main Street, Natick and twenty two (22) tons per year
of NO, 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 NO, 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 NO, Emission Reduction
Credits (ERCs), dated April 2005, NO, 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
NO,ERCs. Since 183 tons per year of NO,emission offsets will be used to offset NOx emissions
from the Facility, 183 tons per year of NO, ERCs in the Rate ERC Bank must be retired at the
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Transmittal No.X254064
Application No.NE-12-022
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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,
NO., 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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Application No.NE-12-022
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• 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.
i -
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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 Pennittee'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.
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Application No.NE-12-022
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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 relyon 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 NO., and 888 tons (8%) of S02. "
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 (CO2,) 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.
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Application No.NE-12-022
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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 NO, 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:
I. "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 OUALITY 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 (03), 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 03 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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Application No.NE-12-022
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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.
.r5` aTr Rr� •*R„ vq'"'K'i>`3:-:y:}?'11,1::.. ".£'.rv.:;,,y,i".a.ti ,. .n..l .Y::"� . .fl,9 R._. ..n
,ka'^k. . .,.. .<:H..,at:.r: i,.--.-'-,..na.. ., ..,.�» ::ti•}1•.:;-:.e�. ble .r
::Gi iteria;` `' Avera'in u Pnma" Secoii Ia „Si`" i cant: 'I`; Mai iffiii
PolliitagY;. ' :Period.:.a _� s.-p N:4AQS:. .'' NAAQS=. j. 1"m ac)`.Levei''�Predicf�d Facility:
- - ..:cs".:>, iia a.•rt,
act,::M•s:..".a�:..: ::+
NO2 Annual l'1 100 Same 1 0.4
1-Hour(2) 188 None 7.5 41.8
SO2 Annual 11'31 80 None 1 0.03
24-Hour(3,4) 365 None 5 0.7
3-Hour(4) None 1,300 25 1.1
1-Hour(5,6) 196 None 7.8 1.0
PM2.5 Annual "1 12 Same 0.3 0.12
24-Hour(8) 35 Same 1.2 3.2
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q.
2
-T'
Primary.; eepn f
IWO
3
T" '0iW TV
PM10 24-Hour (9) 150 Same 5 4.3
co 8-Hour(4) 10,000 None 500 112.4
1-Hour(4) 40,000 None 2,000 313.6
03 8-Hour(IU) -147 Same NA NA
Pb 3-Month 0.15 Same NA <0.00016
Table I Notes:
1. Not to be exceeded.
2. Compliance based on 3 year average of the 980' percentile of the daily maximum I 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 99h percentile of the daily maximum I hour average at each
monitor within an area.
6. The I hour SO2 standard was effective as of August 23,2010.,
1 1
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 98" 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 I Kev:
NAAQS=National Ambient Air Quality Standards
EPA=United States Environmental Protection Agency
NO2=Nitrogen Dioxide
SO2=Sulfur Dioxide
PM23=Particulate Matter less than or equal to 2.5 microns in diameter
PM,0=Particulate Matter less than or equal to 10 microns in diameter
CO=Carbon Monoxide
03=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.
;:.Tablei2 —
Criferia' Averaging l : umulative Impact s; Bacl{gioun Total Impact Plns rPiiinarytri,;w
Polliitanti: ;Periodu'. r r°;:;.h- :.
Faci P1usEXistin u s _trl`, obnd, ' -
t ' . . g g/m ), 4; 'Backgra NAAQS
. t y:
= - �•d: ...p�;;i.tSOUCCPS�t )- -:,�... .i:': x�vi�:.�-�•':.�; .��.. - 3.•�•�xsd°s° -
�`
a
:;'.: -<"` ,�4�'"::, �Ug/U1��`-.>_...
NO2 1-Hour 83.7 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 98"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 1"highest values occurring in each year for the 24-How PM2 5 concentration, and
the 5 year average of the 8`s 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 NO,emissions to NO2 in the ambient air.
Table 2 Kev:
NAAQS=National Ambient Au Quality Standards
NO2=Nitrogen Dioxide
PM2.5=Particulate Matter less than or equal to 2.5 microns in diameter
ug/m'=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.
. :
m;':: :4 '.:Y. •_Mu:a.A.x..'.s,e' �1r°'.',`taaa•.
._.:
u.
°Pollutant" :t-4!..Ayer'.agin Period. -AALJTE-` n m' # '1VIaximum Pr"edicte l:Ttscili
Acetaldehyde 24-Hour(TEL) 2 0.053708
Annual (AAL) 0.5 0.000775
Ammonia 24-Hour(TEL) 100 1.093673
Annual (AAL) 100 0.034497
Benzene 24-Hour(TEL) 1.74 0.080104
Annual (AAL) 0.12 0.000591
1,3-Butadiene 24-Hour(TEL) 1.20 0.002035
Annual (AAL) 0.003 0.000019
o-Dichlorobenzene 24-Hour(TEL) 81.74 0.000047
Annual (AAL). 81.74 0.000006
p-Dichlorobenzene 24-Hour(TEL) 122.61 0.000047
Annual (AAL) 0.18 0.000006
Ethylbenzene 24-Hour(TEL) 300 0.012962
Annual (AAL) 300 0.000409
Formaldehyde 24-Hour(TEL) 2.0 0.203990
Annual (AAL) 0.8 0.005265
Naphthalene 24-Hour(TEL) 14.25 0.009739
Annual (AAL) 14.25 0.000067
Propylene Oxide 24-Hour(TEL) 6 0.334015
Annual (AAL) 0.3 0.002126
Sulfuric Acid 24-Hour (TEL) 2.72 0.053184
Annual (AAL) 2.72 0.001841
Toluene 24-Hour(TEL) 80 0.083392
Annual (AAL) 20 0.001857
Xylenes 24-Hour(TEL) 11.80 0.047138
Annual (AAL) 11.80 0.000942
Arsenic 24-Hour(TEL) 0.003 0.000012
Annual (AAL) 0.0003 0.000001
Beryllium 24-Hour (TEL) 0.001 0.000000
Annual (AAL) 0.0004 0.0000001
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...... TOWI`
Maximuin`Predicteil Fadi
Cadmium 24-Hour(TEL) 0.003 0.000044
Annual (AAL) 0.001 0.000006
Chromium (total) 24-Hour(TEL) 1.36 0.001137
Annual (AAL) 0.68 0.000013
Chromium (hexavalent) 24-Hour(TEL) 0.003 0.000205
Annual (AAL) 0.0001 0.000002
Copper 24-Hour (TEL) 0.54 0.00003
Annual (AAL) 0.54 0.00000
Lead 24-Hour (TEL) 0.14 0.00009
Annual (AAL) 0.07 0.000003
Mercury (elemental) 24-Hour (TEL) 0.14 0.00001
Annual (AAL) 0.07 0.000001
Nickel 24-Hour(TEL) 0.27 0.00021
Annual (AAL) 0.18 0.00001
Selenium 24-Hour(TEL) 0.54 0.00002
Annual (AAL) 0.54 0.0000002
Vanadium 24-Hour(TEL) 0.27 0.00009
Annual (AAL) 0.27 0.00001
Table 3 Notes:
1. Most air toxics do not have a NAAQS,with the exception of lead.
Table 3 Kev:
AAL=Allowable Ambient Limit
TEL=Threshold Effects Exposure Limit
ug/m'=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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.7
3
d','*ility.
.....P611kiat-,471,
3
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 Kev:
SMC=Significant Monitoring Concentration
ug/m'=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 PM25 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 representativ6 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
C
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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 PMZ 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/m3 vs. 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 PMZ S Significant Impact
Levels and Significant Monitoring Concentration—Questions and Answers",March 4,2013.
hfo://www.eDa.aov/nsr/documents/20130304ca.ndf
4. ACCIDENTAL RELEASE MODELING OF AOUEOUS AMMONIA (NH3)
Aqueous NH3 will be used as the reducing agent in the proposed Facility's SCR system
to control NO, 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 I (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 I hour maximum concentrations of NH3:
'h,'-Ao6tfi6h, Misti&i6b'm 4
9AP6
F
(M
or
"ii"M;"f1OUr1Y
S:
Power Plant North 230 25 150 20.2
PCAP
Power Plant West 340 25 150 13.1
PCAP
Power Plant East 450 25 150 4.4
PCAP
Nearest Residence 570 25 150 6.7
(Fort Avenue)
Salem Essex 750 25 150 6.8
Sewerage District
(SESD)
Table 5 Key:
PCAP=Projected Controlled Access Perimeter
ERPG-1 =Emergency Response Planning Guideline Level I
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:
:.::^�i :\ �e,.:tvfr:',fY._..�;aW ti.:ry:?V:'a j,;.j n., .c-.�.,i^✓E.fTv'b. :a•;c:;:=•.'&,:r-•.._[t: � .,�,,.:.Y.S'_.. v."i•.:r^`p
cTable:6 : ,..:a
EU#; Design Capacity° 'Pollution-,Cgntrol' ;
%r Cr..a.•;i".'y,, r4%�r� .S;4 n:s Rte.� _`��S°'� .i . .+.I.:<-.. _n-•i..
+--� .d.'_. + W:, ..
EUI General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD I)
Including Duct Burner input) Selective Catalytic
Reduction (PCD2)
346 MW (electric CO Oxidation Catalyst
power output) (PCD3)
EU2 General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NOx
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD4)
Including Duct Burner input) Selective Catalytic
Reduction (PCD5)
346 MW (electric CO Oxidation Catalyst
power output) (PCD6)
EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or 80 MMBtu/hr, Ultra Low NOx Burners
equivalent HHV (energy (PCD7)
Auxiliary Boiler input)
EU4 Cummins Model No. DQFAA or equivalent 7.4 MMBtu/hr, None
Emergency Engine/Generator HHV (energy
input)
1102 bhp (engine
mechanical power
output)
750 KW
(generator electric
power output)
EU5 Cummins Model No. CFP9E-F50 or equivalent 2.7 MMBtu/hr, None
Fire Pump Engine HHV (energy
input)
371 bhp (engine
mechanical power
output)
Table 6 Key:
EU#=Emission Unit Number
No.=Number
MMBtuihr=fuel heat input,million British thermal units per hour
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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
NO,=Oxides of Nitrogen
CO=Carbon Monoxide
5. APPLICABLE REO UIREMENTS
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:
, AOtil/Poeis'Bron L
unit';
EUI, EU2 Operation at>MECL, 1' / NO, (no duct firing) < 18.1 lb/hr
excluding start-ups and <0.0074 lb/MMBtu tD
shutdowns <2,0 ppmvd @ 15% 02 11)
< 0.051 lb/MW-hr
Fuel Heat Input Rate of
each EU: < 15.0 ppmvd @ 15% 02
<2,449 MMBtu per hour, or
HHV < 0.43 lb/MW-hr 113)
NO, (duct firing) < 18.1 lb/hr 11'"
Natural Gas shall be the <0.00741b/MMBtu (1)
only fuel of use. <2.0 ppmvd @ 15% 02 11)
< 0.0551b/MW-hr
Fuel Heat Input of each EU:
< 18,888,480 MMBtu, < 15.0 ppmvd @ 15% 02
HHV per 12-month rolling or
period 191 < 0.43 lb/MW-hr�13>
CO (no duct firing) < 11.0 lb/hr"")
< 0.0045 lb/MMBtu(1)
<2.0 ppmvd @ 15% 02 (1)
<0.031 lb/MW-hr 11,2, 10, 141
CO (duct firing) < 11.0 lb/hr 1"21
<0.0045 lb/MM13tu 111
< 2.0 ppmvd @ 15% 02(1)
<0.033 lb/MW-hr(1.2,1 s)
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...........
Air_`-C6DtdiUiKMif "w!:PEm
isslow"Um"I
EUI, EU2 Operation at> MECL,-T7 VOC (no duct firing), < 3.0 lb/lir
excluding start-ups and as Methane (CH4) < 0.0013 lb/MMBtu
shutdowns < 1.0 ppmvd @ 15% 02
< 0.009 lb/MW-hr(1,2,10, 14)
Fuel Heat Input Rate of VOC (duct firing), < 5.4 lb/hr(1,21
each EU: as Methane(CI14) < 0.0022 lb/MMBtu
:S 2,449 MMBtu per hour, < 1.7 ppmvd @ 15% 02 (1)
HHV < 0.016 lb/MW-hr (1,2,15)
S in Fuel <0.5 grains/100 scf
Natural Gas shall be the SO2 (no duct firing) <3.7 lb/hr(',21
only fuel of use. < 0.0015 lb/MMBtu
< 0.3 ppmvd @ 15% 02
Fuel Heat Input of each EU: < 0.010 lb/MW-hr(1,2,10,141
< 18,888,480 MMBtu, S02 (duct firing) < 3.7 lb/hr 1''21
HHV per 12-month rolling < 0.0015 lb/MMBtu
period(9) < 0.3 ppmvd @ 15% 02 (1)
<0.011 lb/MW-hr 11,2,15)
H2SO4 (no duct firing) < 2.3 lb/hr(',21
< 0.0010 lb/MMBtu (1)
< 0.1 ppmvd @ 15% 02
< 0. 007 lb/MW-hr 11,2,10,141
H2SO4 (duct firing) <2.3 lb/hr I''21
<0.0010 lb/MMBtu (1)
< 0.1 ppmvd @ 15% 02
< 0.008 lb/MW-hr(1,2,151
PM/PMIO/PM2.5 (no duct < 15.5 lb/hr(',',')
firing) < 0.0088 lb/MMBtu (1,8)
<0.044 lb/MW-hr 11,2,8, 10, 14)
PM/PMio/PM2.5 (duct firing) < 15.5 lb/hr
<0.0067 lb/MMBtu (1,8)
< 0.049 lb/MW-hr(1,2,8,15)
NH3 (no duct firing) < 6.6 lb/hr(',21
< 0.0027 lb/MMBtu (1)
<2.0 ppmvd @ 15% 02
<0.019 lb/MW-hr(1,2,10, 14)
NH3 (duct firing) < 6.6 lb/hr",21
<0.0027 lb/MMBtu
2.0 ppmvd @ 15% 02
<0.020 lb/MW-hr 11,2,151
Greenhouse Gases, COU < 825 lb/MW-hr
< 8951b/MW-hr 1161 l
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Air Co
EUI, EU2 Operation at>MECL, Opacity <5%, except 5%to < 10%for
excluding start-ups and <2 minutes during any one hour
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)
Operation at<MECL NOX < 89 lb per event'4,121
during start-ups (3,12) CO <285 lb per event(4,12)
VOC, <23 lb per event(4'121
Start-up duration: as Methane(CH4)
<45 minutes (3,12) S in Fuel <0.5 grains/100 scf
SO2 <2.0 lb per event 14, 12)
Natural Gas shall be the i H2SO4 < 1.3 lb per event 14,'2)
only fuel of use. PM/PMIO/PM2.5 <7.3 lb per event(4'8' 12)
NH3 NA
Opacity < 10% 1'' 'L)
Operation at< MECL N% < 10 lb per event
during shutdowns (3,12) CO < 151 lb per event 1121
VOC, <29 lb per event
Shutdown duration: as Methane (CH4)
< 27 minutes (3,12) Sin Fuel <0.5 grains/100 self
SO2 < 0.3 lb per event
Natural Gas shall be the I H2SO4 < 0.2 lb per event
only fuel of use. PMIMO/PM2.5 < 5.8 lb per event 1a' 1n
NH3 NA
Opacity < 10%
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a
-E-fifission- mnit��o-z -
EU3 Operation at> MECL lixl NOx < 0.88 lb/hr
< 0.011 lb/MMBtu(1)
Fuel Heat Input Rate: < 9.0 ppmvd P 3% 02
< 80 MMBtu per hour, CO <2.8 lb/hr")
HHV < 0.035 Ib/MMBtu(1)
<47 ppmvd (& 3% 02
Natural Gas shall be the VOC, < 0.4 lb/hr
only fuel of use. as Methane(C144) < 0.005 lb/MMBtu (1)
I < 11.8 ppmvd A 3%02
Total Fuel Heat Input: S in Fuel <0.5 grains/100 scf
525,600 MMBtu HHV SO2 < 0.12 lb/hr
per 12-month 9)rollin;period < 0.0-015 lb/MMBtu (1)
(
<0.9 ppmvd P, 3% 02
H2SO4 <0.009 lb/hr('),
< 0.0001 lb/MMBtu (1)
< 0.05 ppmvd P, 3% 02
PM/PM10/PM25 <0.4 lb/hr
< 0.005 lb/MMBtu (1,8)
Greenhouse Gases, CO2, < 119.0 lb/MMBtu
Opacity <5%, except 5%to < 10% for
<2 minutes during any one hour
(5)
EU4 < 300 hours of operation NOx and VOC (NMHC as < 11.60 lb/hr 16)
per 12-month rolling period CH1.8), <4.8 gm/bhp-hr(6)
Combined Total < 6.4 gm/r
W_br(6)
Ultra Low Sulfur Diesel CO < 6.34 lb/hr (6)
Fuel Oil shall be the only <2.6 gm/bhp-hr 16)
fuel of use. < 3.5 gm/KW-hr 16>
S in Fuel <0.0615% by weight
SO2 < 0.011 lb/hr(6)
H2SO4 < 0.0009 lb/hr
PM/PMIO/PM2.5 <0.36 lb/hr(')
<0.15 gm/bhp-hr 161
< 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 ho
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Tablv7c-k�'
EUk,`::;' '0 -Tiodiiifioii E'
pera,ior4>.na mission Limit
T
4Y
EU5 < 300 hours of operation NO, and VOC (NMHC as <2.44 lb/hr (6)
per 12-month rolling period CHI.8), < 3.0 gm/bhp-hr
Combined Total <4.0 gm/KW-hr
Ultra Low Sulfur Diesel CO < 2.14 lb/hr")
Fuel Oil shall be the only <2.6 gm/bhp-hr(6)
fuel of use. _< 3.5 gm/KW-hr(6)
S in Fuel < 0.0015%by weight
< 300 hours of operation SO2 < 0.004 lb/hr(6)
per 12-month rolling period) H2SO4 < 0.0003 lb/hr
PM/PMIO/PM2.5 < 0.12 lb/hr(0'
Ultra Low Sulfur Diesel <0.15 gm/bhp-hr(6)
Fuel Oil shall be the only < 0.2 gm/KW-hr(')
fuel of use. Greenhouse Gases, CO2, < 162.85 lb/NMBtu
Opacity <5%, except 5%to < 10%for
<2 minutes during any one hour,
EUI, EU2, NA Smoke 310 CMR 7.06 (1)(a)
EU3, EU4,
EU5
Facility-Wide NA NO, < 144.8 TPY
CO < 106.4 TPY ul
VOC <28.0 TPY(7)
S02 <28.8 TPY"I I
PM/PMIO,/PM25 < 109.4 TPY(7,1)
NH3 <51.0 TPY
H2SO4 < 18.8 TPY
Pb <0.00013 TPY cel
IFormaldehyde or Single HAP <6.6 TPY"I
Total HAPs < 13.1 TPY(71
CO2 <2,277,333 TPY til
Greenhouse Gases, CO2, <2,279,530 TPY
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 MAMtu/hr, HHV, at 90 'F 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 start-
up 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
CHI s),which corresponds to a gas density of 0.5746 kg/m'.
7. Facility emissions include the two CTG/HRSG pairs with duct burners (EUI 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 EUI and EU2 are based on 8,040 hours of natural gas firing per 12
month rolling period at 100% load and 50°F 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 90°F 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 EUI 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 NO,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 NO, 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/PM25 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 50°F 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 90°F 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°F, 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°F, 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/COMB data generated from the first year of commercial operation.
13. NO,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 118.91b/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 EUI 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 Kev:
EU#=Emission Unit Number
No.=Number
NO,=Nitrogen Oxides
CO=Carbon Monoxide
VOC=Volatile Organic Compounds
NMHC=Non-Methane Hydrocarbons
S= Sulfur
SO2=Sulfur Dioxide
PM=Total Particulate Matter
PMIO=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
Ib/hr=pounds per hour
MMBtu=million British thermal units,higher heating value(FIHV)basis
lb/MMBtu=pounds per million British thermal units
ppmvd @ 15%02=parts per million by volume,dry basis, corrected to 15 percent oxygen
ppmvd @ 3%02=parts per million by volume,dry basis,corrected to 3 percent oxygen
scf=standard cubic feet
kg/m'=kilograms per cubic meter
%=percent
gm/KW-hr=grams per Kilowatt-hour
Ib/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
°F=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 (EUI 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% 02. 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 NO, emission
standard for EUI and EU2 is 15 ppmvd @ 15% 02 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-NO, combustion technology in conjunction with SCR add-on NO, control technology to
control NO,emissions to 2.0 ppmvd @ 15% Oz and 0.051 lb/MW-hr during natural gas firing, well
below the NSPS limits.
The NSPS for S02 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 S02 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 S02 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 S02/IvMtu) heat input. The Permittee will meet the NSPS for S02 by burning
natural gas with sulfur content not exceeding 0.5 grains sulfur per 100 standard cubic feet of gas
fired(0.0015 lb S02/MNIBtu),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 EU 1 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.
Emereencv Eneine/Generator and Fire Pumn Eneine (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 (EUI 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 homers. Therefore, the duct bumers 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 Pumn 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 IIIL 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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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 NO,(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, NO., 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.
;Tattle
Pollutant ";<;=aerogram . `Applicable``€:Snbject.Faci1ity Emission
:.Regulatiun ,. _ : I7nifs :
7S02 ~Acid Rain 40 CFR Parts EUI, EU2
Program (ARP) 72, 73, and 75
NO, NO, Ozone 310 CMR 7.32 EUI, EU2
Season Clean Air
Interstate Rule
(CAIR)
CO2 Regional 310 CMR 7.70 EUI, EU2
Greenhouse Gas
Initiative (RGGI)
CO2 Budget
Trading Program
(State Only
Requirement)
Table 8 Kev:
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
NO,=Nitrogen Oxides
CO2=Carbon Dioxide
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No. NE-12-022
Page 34 of 54
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.
F,', 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 1 I below:
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EUI, 1. The Permittee shall ensure that the proposed Facility is constructed to accommodateth
EU2,EU3 emissions (compliance) testing requirements as stipulated in 40 CFR Part 60 Appendix A. Th
two outlet sampling ports (90 degrees apart from each other) for each emission unit must b
located at a minimum of one duct diameter upstream and two duct diameters downstream oil
any flow disturbance. In addition,the Permittee shall.facilitate access to the sampling ports an
testing equipment by constructing platforms,ladders,or other necessary equipment.
2. The Permittee shall ensure that compliance testing of the proposed Facility is complete
within 180 days after initial firing of each EU to demonstrate compliance with the emissio
limits specified in Table 7 of this Proposed Plan Approval. All emissions testing shall b
conducted in accordance with MassDEP's "Guidelines for Source Emissions Testing" and i
accordance with EPA reference test methods as specified in 40 CFR Part 60, Appendix A, 4
CFR Part 60 Subpart KKKK, 40 CFR Parts 72 and 75, or by another method which has bee
approved in writing by MassDEP. The Permittee shall schedule the compliance testing such tha
MassDEP personnel can witness it.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 35 of 59
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EUI, 3. The Permittee shall conduct initial compliance tests of the proposed Facility to document
EU2,EU3 actual emissions of EUI, 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 EUI and EU2 as specified below shall be conducted at four (4)
load conditions that cover the entire normal operating range: the minimum emissions
i compliance load (MECL); 75 percent load; 100 percent (base) load without duct firing; and
peak(approximately 102 percent load) with 100 percent duct firing.
NO,, CO,VOC, SO2,PM, PM,o, PM2.5,NH3, CO2,H2SO4, Opacity
Testing for these pollutants for EU3 as specified below shall be conducted at four (4) loal
conditions that cover the entire normal operating range: the MECL(to be determined during th�
compliance test); 50 percent load; 75 percent load; and 100 percent load.
NO,, 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 EUI and EU2; parametric monitoring testing for P?vl.
PM10, and PM2.5 emissions for EUI and EU2; and NO./CO emissions optimization testing!
for EU3.
5. The Permittee shall conduct NO./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 EUI and EU2 to measure and record
following emissions:
a) 02; b)NO,; 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 EUI, 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 36 of 59
7,
EU 1, 19. The Permittee shall operate each CEMS and/or COMS serving EUI, EU2 and EU3 at all
,EU2, EU3lines except for periods of CEMS and COMS calibration checks, zero and span adjustments,
�reventative maintenance, and periods of unavoidable malfunction.
10. The Permittee shall obtain and record emissions data from each CEMS and/or COMS
serving EUI, 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
i. 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
-.xceedance of emission limits in Table 7 due to an emergency or malfunction shall not be
Seemed a federally permitted release as that term is used in 42 U.S.C. Section 9601(l0).
12. The Permittee shall use and maintain its CEMS and/or COMS serving EUI, EU2 and
EU3 as "direct-compliance" monitors to measure NO,, CO, NH3, 02, and/or opacity.
"Direct-compliance" monitors generate data that legally documents the compliance status of
�i 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 EUI, 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
Ul, 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
�nput (MMBtu) for EUI, 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.
EUI, 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 EUI and EU2. These.compliance tests shall represent periods of
�:)peration below the MECL for EUI 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 b
considered enforceable. 1
18. Whenever either combustion turbine is operating below the MECL for start-up an
shutdown, the VOC emissions shall be considered as occurring at the rate determined in thl
ost recent compliance test for start-up/shutdown conditions.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No. X254064
Application No.NE-12-022
Page 37 of 59
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EUI, 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:
VOC,,t,al = VOCJi,,t X (COaw,1/CO1i,it), 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.
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l. The Permittee shall monitor the natural gas consumption of EUI and EU2 in accordaric
40 CFR Part 60 Subpart KKKK utilizing a continuous monitoring system accurate to
percent, and as approved by MassDEP. I
P2. The Permittee shall monitor the sulfur content of the natural gas combusted by EUI anj
rU2 in accordance with 40 CFR Part 60 Subpart KKKK, or pursuant to any alternative fuell
onitoring schedule issued in accordance with 40 CFR Part 60 Subpart KKKK.
23. The Permittee shall install and operate continuous monitors fitted with alarms,to monito
continuously the temperatures at the inlets to the SCR and CO catalysts serving EUI am
EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambienil
temperatures for EUI and EU2.
�4. The Permittee shall install and operate high and low level audible alarm monitors on thei
H3 storage tank and shall ensure that they are properly maintained.
5. The Permittee shall monitor the load, start-up and shutdown duration, and mass
emissions (lb/event) during start-up and shutdown periods of EU 1 and EU2.
r6. The Permittee shall monitor the operation of EUI and EU2, in accordance with the:
1surrogate methodology or parametric monitoring developed during the most recent
compliance test concerning PM,PMIO,and PM2,5 emission limits.
7. The Permittee shall monitor the SO2 and CO2 emissions in accordance with 40 CFR Part
�5.
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.
Facility- 32. The Permittee shall monitor all operations to ensure sufficient information is available to
Wide 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No. X254064
Application No.NE-12-022
Page 38 of 59
Table 9 Kev:
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
Oz=Oxygen
NOx=Nitrogen Oxides
CO=Carbon Monoxide
NH3=Ammonia
PM=Particulate Matter
PMio=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
Ib/hr=pounds per hour
Ib/MMBtu=pounds per million British thermal units
ppmvd=parts per million by volume,dry basis
Ib/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
_
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EU 1, 1. The Permittee shall maintain records of each emission unit's hourly fuel heat input rate
EU2, EU3 (MMBtu/hr, HHV), total fuel heat input (MMBtu), and natural gas consumption (scf) per
onth and twelve month rolling period basis.
The Permittee shall maintain records of each date and daily hours of operation and total
ours 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!
onitors (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 wit
the subject emission control systems, DAHS, CEMS, and/or COMS serving EUI, EU2, and
EU3, and the NH3 handling system serving EUI and EU2. JJ
EUI, EU2 5. The Permittee shall continuously estimate and record VOC emissions on the DAHS using thl
CONOC correlation curve developed from the most recent compliance test.
6. The Permittee shall continuously estimate and record PM, PMto, and PM2.5 emissions on th
AHS using the surrogate methodology or parametric monitoring derived from the most recen�
compliance test.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 39 of 59
bI
77 -
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EU 1, 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 EUI 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, of
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 EUI and EU2 in accordance
with 40 CFR Part 75.
11. The Permittee shall record the Greenhouse Gas emission rate of EUI 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 EUI 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.
Facility- 18. A record keeping system for the Facility shall be established and maintained up-to-date
Wide 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No. X254064
Application No.NE-12-022
Page 40 of 59
77
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Facility- 119. The Permittee shall maintain all records required by 310 CMR 7.32, 310 CMR 7.70, 310
Wide CMR 7.71 (Reporting of Greenhouse Gas Emissions), and 40 CFR Part 98 (Mandatory
lGreenhouse Gas Emissions Reporting) at the Facility. 1
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,i
include actual emissions for the month as well as for the previous 11 months. (The MassDEP
approved format can be downloaded
at,
httD://www.mass.aov/eea/a2encies/massdeD/air/aDDrovals/limited-emissions-record-keet)ini2-.1
land-rei)orting.html#WorkbookforReDortin2On-S1teRecordKeei)ing in Microsoft Excel:'l
♦forrnat.)
Pl. The Permittee shall maintain a copy of this Plan Approval, underlying Application, andi
re most up-to-date Standard SOMP for each emission unit and PCD approved herein on-
site.
site.
22. The Permittee shall maintain a complaint log concerning emissions, odor, andnoisefrom
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
sball take all reasonable actions to respond to said complaints in a timely manner.
�3. The Permittee shall maintain records for the annual preparation of a Source egistration/Emission Statement Form in accordance with 310 CMR 7.12.
4 The Permittee shall maintain records of monitoring and testing as required by Table 9.
11 records required by this Plan Approval shall be kept on site for five (5) years and made
available
vailable for inspection by MassDEP or EPA upon request.
Table 10 Kev:
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 0.00 1 5weight percent sulfur
lb=pounds
scf=standard cubic feet
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 41 of 59
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
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EUI, 1. The Permittee must obtain written MassDEP approval of an emissions test protocol prior
EU2, EU3 to initial compliance emissions testing of EUI, 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 EUI and EU2; b) a parametric monitoring strategy to ensure continuous,[
monitoring of PM, PMio, and PM25 emission from EU1 and EU2; and c) procedures for thel
required NO, and CO optimization for EU3. The protocol must be submitted to MassDEP at
least 30 days prior to commencement of testing. j
atThe Permittee shall submit a final emissions test results report to MassDEP within 45 days)
iter completion of the initial compliance emissions testing program.
3. A QA/QC program plan for the CEMS and/or COMS serving EUI, EU2 and EU3 must be
submitted, in writing, at least 30 days prior to commencement of commercial operation o
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 t
MassDEP for MassDEP approval prior to their implementation.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 42 of 59
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EU 1, 4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the
EU2, EU3 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, anq
the amount of excess emissions. Periods of excess emissions shall include periods of start-
up, 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 pool I
maintenance, careless operation, or any other preventable upset condition or preventable!
equipment breakdown shall not be considered malfunctions. "Emergency" means an
i
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 lo
restore normal operation, and that causes the source to exceed a technology based limitatiorV
under the Plan Approval, due to unavoidable increases in emissions attributable to the
i-mergency. 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.)
1-,) A tabulation of periods of operation (including dispatch) of each emission unit and total!
1 iours of operation of each emission unit during the calendar quarter.
EUI, EU15. 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 EUI 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
,MR 7.02(5)(c), plans and specifications for the main exhaust stack, CTGs, the SCR control
:;3ySteM (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 detennined,
but in any case not later than 30 days prior to commencement of construction/installation of
each component of EUI
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 43 of 59
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EU4, EU5 8. The Permittee shall submit to MassDEP a certification for each engine in accordance with
310 CMR 7.26 (42)(e)l 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.
Facility- 10. The Permittee shall submit to MassDEP a plan for monitoring and abating air and noise
Wide 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
I
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 7.32,11
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.aira,massmail.state.ma.usI as soon as possible, but in any case no later than
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(a�,massmail.state.ma.usI 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No. X254064
Application No.NE-12-022
Page 44 of 59
006 ngj e
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Facility- 18. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 30 of
Wide each year to demonstrate the Facility's compliance status regarding the Facility-Wide emission
limits (TPI) specified in Table 7. Reports shall include actual emissions for the previous 12
months., (The MassDEP approved format can be downloaded at
httD://www.mass.izov/eea/agencies/massdeD/air/ai)Drovals/limited-emissions-record-keeDin2-
and-reDortine.html#Workbookf6rReDortinQOn-SiteRecordKeeDing 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 th
SOMP prior to the SOMP becoming effective. The updated SOMP shall supersede priol
I versions of the SOMP.
120. 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(amassmail.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 Kev:
EU#=Emission Unit Number
EPA=United States Environmental Protection Agency
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 45 of 59
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
NO,=Oxides of Nitrogen
CO=Carbon Monoxide
NH3=Ammonia
PM=Particulate Matter
PM,o=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 REOUIREMENTS
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:
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....._:.,.:tv '. t:.r ' K.:L.-c`:.rK4..is .y. •'.:... .ic._rw,r1�
r
y� .. .. _. 2Tabe.1Nx
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pecial�.,T'•erms=an,
d'Conditions
EUI, 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 EUI 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,l
portable NH3 detectors for use during an NH3 spill, or other emergency situation involvin
NH3, at the Facility.
EUI, EU2, 4. The Permittee shall develop as part of the Standard Operating Procedures for EUI, EU2,
EU3 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 46 of 59
4ALTO'o
06: rlls and
on i ons
EU 1, EU2, 5. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the on-1
EU3 line availability and data capture requirements for the CEMS and COMS equipment serving],
the Facility. i
Facility- 6. The Permittee shall properly train all personnel to operate the Facility and the control anj
Wide monitoring equipment serving the Facility in accordance with vendor specifications. A I
persons responsible for the operation of the Facility shall sign a statement affirming tha
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.
18. The Permittee shall comply with all provisions of 40 CFR Parts 72 and 75, 40 CFRPart
160, 40 CFR Part 63, 40 CFR Part 64, 40 CFR Part 68, 40 CFR Part 98, and 310 CMR 6.00
lthrough 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 Kev:
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:
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empera re, nge,,-�_
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000
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EUI, EU2 230 20 39.2 to 61.9 175 to 215
(1) (Each Flue) (Each Flue) (Each Flue) (Each Flue)
EU3 230 3 < 70.2 < 530
EU4 86 1 < 113.3 <620
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No. X254064
Application No.NE-12-022
Page 47 of 59
vu
EV#
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a&A-a I�ge-�,,
b:*�.. .... Y' h Rlioig V,,jjitMP6ntU
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F_EU5_ 1 22 M67 <80.6 I
< 820
Table 13 Notes:
1. EUI,EU2,and EU3 shall emit through one stack,containing three(3)flues.
Table 13 Kev:
EU#=Emission Unit Number
'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 (STI through ST12 in Table 14). Two additional
monitoring locations (RI 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, L5o, Ljo, L,m, 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 (Lgo) levels (in dBA) at locations STI 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 STI, ST2, STS, ST6,and STB.
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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 48 of 59
The allowable sound levels generated from base load (100% load) operation of the
proposed Facility by the Permittee are summarized in Table 14 below:
y -
_ , ,...."., .> ;:-s:. 'P,,: .:;.? `:Tablea4r'..,:':r-:;'� ``,:;' :�.:,:,:.,.�,:;•,,�.'=r;;;: . r,; :,,:: ; .::..,
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r dBA'M,I.`
-Facifi
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t r
909
STI —Located to the 47 44 49 2
North/Residences near
39 Fort Avenue
ST2 - Existing Property 42 44 46
4
Line to the West/Block
House
Square/Residences near
Fort Avenue and Derby
Street Intersection
ST3 —Located to the 39 41 43 4
Northeast/25 Memorial
Drive/Bentley
Elementary School
ST4—Existing Property 1 39 43 44 5
Line to the
Southwest/Residences
near Intersection of
Webb Street and Derby
Street/23 Derby Street
ST5 —Existing Property 39 44 45 6
Line to the Southwest/59
Derby Street
ST6—Located to the 36 34 38 2
East across Salem
Harbor/76 Naugus
Avenue (Marblehead)
ST7—Located to the 39 39 I 42 3
East/Winter Island Park
(Harbormaster Office)
ST8—Located to the 38 33 39 1
Northeast/Intersection of
Fort Avenue and Winter
Island Road/Winter
Island Road
ST9—Existing Property 39 42 44 5
Line to the South/Blaney
Street Pier on Salem
Wharf
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 49 of 59
"—W --v , ,.:x:..-
, I .
y
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er
bi6if-itidp"� 'Ific'ici`ase(s,
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W
901
141
w
ST 10— Southwest 36 41 42 6
Comer of the Existing
Property/Mackey
Building/Art Gallery
ST 11 —Near House of 39 37 41 2
Seven Gables across
from 41 Turner Street
ST12—Pickering Wharf 41 32 42 1
near Victoria's Station
approximately 100 feet
behind Sail Schooner
"Fame" Kiosk
RI —Plummer House 40 33 41 1
R2—Winter Island Road 34 33 38 4
Residences
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 1-90 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 Kev:
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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 50 of 59
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: rhain 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 EUI 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 EUl,EU2, and EU3 designed to meet
a total sound power attenuation of 22 1 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 (L,,,) of 83 dBA for CTG step-up transformers and 90 dBA for STG step up
transformers on EUI 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.
I) 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 51 of 59
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 REOUIREMENTS
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 1/4 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.
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 52 of 59
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 non-
road engine standard limitations per 40 CFR 89.112.
C) All contractors shall utilize the best available technology for reducing the
emission of PM and NO, 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 andg a rocedures for obtaining special variance during times when certain construction
P P
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
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 53 of 59
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
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 54 of 59
results report shall be submitted within 45 days after emission testing.
K. Pursuant to 310 CMR 7.01(3) and 7.02(3)(0, 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 (EDEA #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-
Footprint Power Salem Harbor Development LP
Proposed Plan Approval
Transmittal No.X254064
Application No.NE-12-022
Page 55 of 59
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 diesel-
fueled 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 (NO.), 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 NO, turbine combustors in combination with SCR will reduce
NO,emissions;
• 183 tons per year of NO, 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 noise-
producing 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 noise-
producing 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, § 69J'/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 69J'/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 69J'/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
Edm6ard J. Braczyk
Environmental Engineer
es E. Belsky
gonal Permit hief
eau of Waste revention
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,4d'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)
MassDEPBoston:Karen Re.-as(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)
Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
LlDepartment of Environmental Protection
Northeast Regional Office•205B Lowell Street, Wilmington MA 01887 .978-694-3200
DEVAL L PATRICK - RICHARD K SULLIVAN JR
Governor Secretary
KENNETH L KIMMELL
Commissioner
Draft
Prevention of Significant Deterioration Permit
Application No.NE-12-022
Transmittal No.X254064
Footprint Power Salem Harbor Development LP
Salem Harbor Station
24 Fort Avenue
Salem, MA 01970
692 MW Combustion Turbine Combined Cycle
Electric Generating Facility
Pursuant to the provisions of the Clean Air Act (CAA) Chapter I, Part C (42 U.S.C. Section
7470, et. seg), the regulations found at the Code of Federal Regulations Title 40, Section 52.21, and
the Agreement for Delegation of the Federal Prevention of Significant Deterioration Program, dated
April 2011, by the United States Environmental Protection Agency, Region I (EPA) to the
Massachusetts Department of Environmental Protection (MassDEP), MassDEP is issuing a
Prevention of Significant Deterioration (PSD) Permit to Footprint Power Salem Harbor Development
LP (the Permittee) concerning its proposed, new 692 Megawatt, combined cycle electric generating
facility to be located at 24 Fort Avenue in Salem, MA (proposed Facility). This is the site of the
present Salem Harbor Station electric generating facility.
The operation of the Facility shall be subject to the attached permit conditions and permit
limitations. This PSD Permit is valid only for the equipment described herein and as submitted to
MassDEP in the December 21, 2012 application for a PSD Permit under 40 CFR 52.21 and
subsequent application submittal addenda. This PSD Permit shall be effective 30 days after the date
of signature or, if no comments requesting a change in the Draft Permit are received, shall be
effective immediately upon signature and shall remain in effect until it is surrendered to MassDEP.
This Permit becomes invalid if the Permittee does not commence construction within 18 months after
the date of signature. MassDEP may extend the 18 month period upon a satisfactory showing that an
extension is justified. The Fi �S1D Permit does not relieve the Permittee from the obligation to
cRmply with cable e and federal air pollution control rules and regulations.
,1
SEP 0 9 2013
Mines E. Belsky Date Issued
' Yermit Chief
Bureau of Waste P vention
This information is available in alternate forrnat.Call Michelle Waters-Ekanern,Diversity Director,at 677-292-5751.TDD#7-866-539-7622 or 1.617-574-6868
MassDEP Website w .mass govldep
Pnnted on Recycled Paper
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 2 of 25
TABLE OF CONTENTS
I. PROJECT DESCRIPTION (For Informational Purposes) 3
II. EMISSION UNIT (EU) IDENTIFICATION 4
III. OPERATIONAL, PRODUCTION and EMISSION LIMITS 5
IV. MONITORING AND TESTING REQUIREMENTS 12
V. RECORD KEEPING REQUIREMENTS 16
VI. REPORTING REQUIREMENTS 19
VII. SPECIAL TERMS AND CONDITIONS 23
VIIL RIGHT OF ENTRY 25
IX. TRANSFER OF OWNERSHIP 25
X. SEVERABILITY 25
XI. CREDIBLE EVIDENCE 25
XII. OTHER APPLICABLE REGULATIONS 25
XIII. AGENCY ADDRESSES 25
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 3 of 25
I. PROJECT DESCRIPTION (For Informational Puraoses)
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, the proposed Facility will be capable of
generating an additional 62 MW, for a total of 692 MW. The existing Salem Harbor Station
Boiler Units 1 and 2 were removed from service on or prior to December 31, 2011. Boiler Unit 3
and Boiler Unit 4 are required to cease operation, permanently shutdown, and be rendered
inoperable no later than June 1, 2014.
The proposed Facility components include two combustion turbine generators with
integrated duct burners, Heat Recovery Steam Generators, and Steam Turbine Generators, as
well as an auxiliary boiler, an emergency engine/generator set, a fire pump, an aqueous NH3
storage tank, an auxiliary cooling tower, and generator step-up (GSU)transformers.
Effective April 11, 2011, EPA and MassDEP entered into an "Agreement for Delegation
of the Federal Prevention of Significant Deterioration (PSD) Program by the United States
Environmental Protection Agency, Region I to the Massachusetts Department of Environmental
Protection" (Delegation Agreement). Pursuant to the Delegation Agreement and to 40 CFR
52.21(u), EPA delegated full responsibility for implementing and enforcing the federal PSD
regulations for sources located in the Commonwealth of Massachusetts to MassDEP.
Therefore, MassDEP is authorized to issue this Draft PSD Permit concurrently with a
separate Proposed Plan Approval in accordance with 310 CMR 7.02, for the above described
proposed Facility.
The Fact Sheet for the Draft PSD Permit is attached to this Draft PSD Permit and the
Proposed Plan Approval. This Fact Sheet explains MassDEP's evaluation and determination of
Best Available Control Technology (BACT) and air quality impacts. The PSD Permit and the
310 CMR 7.02 Comprehensive Plan Approval processes have the same review considerations for
these items for this proposed Facility.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 4 of 25
II. EMISSION UNIT (EU) IDENTIFICATION
Each Emission Unit (EU) identified in Table 1 is subject to and regulated by this PSD
Permit:
Design`Ca acrty._ : .Polliifion':Control:
JA
EUl General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD I)
Including Duct Burner input) Selective Catalytic
Reduction (PCD2)
346 MW (electric CO Oxidation Catalyst
power output) (PCD3)
EU2 General Electric Model No. 107F Series 5 2,449 MMBtu/hr, Dry Low NO,
Combustion Turbine/Heat Recovery Steam Generator HHV (energy Combustors (PCD4)
Including Duct Burner input) Selective Catalytic
Reduction(PCD5)
346 MW (electric CO Oxidation Catalyst
power output) (PCD6)
:EU3 Cleaver Brooks Model No. CBND-80E-300D-65 or 80 MMBtu/hr, Ultra Low NO, Burners
equivalent HHV (energy (PCD7)
Auxiliary Boiler input)
EU4 Cummins Model No. DQFAA or equivalent 7.4 MMBtu/hr, None
Emergency Engine/Generator HHV (energy
input)
1102 bhp (engine
mechanical power
output)
750 KW
(generator electric
power output)
EU5 Cummins Model No. CFP9E-F50 or equivalent 2.7 MMBtu/hr, None
Fire Pump Engine HHV (energy
input)
371 bhp (engine
mechanical power
output)
Table 1 Kev:
EU#=Emission Unit Number
No.=Number
MAOtu/hr=fuel heat input,million British thermal units per hour
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 5 of 25
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
III. OPERATIONAL, PRODUCTION and EMISSION LIMITS
The Facility is subject to, and the Permittee shall ensure that the Facility shall not exceed
the Operational, Production, and Emission Limits as contained in Table 2 below, including
footnotes:
r
6perafi6ual:LProducti0ii" Air.Contaminant; .Emission^Limit"'*;-`[e".
EU1, EU2 Operation at> MECL, NO, (no duct firing) < 18.1 lb/hr
excluding start-ups and < 0.0074 lb/MMBtu 111
shutdowns <2.0 ppmvd @ 15% Oz 111
<0.051 lb/MW-hr 11,z, 1o,1a1
Fuel Heat Input Rate of
each EU: < 15.0 ppmvd @ 15% Oz
<2,449 MMBtu per hour, or
HHV < 0.43 lb/MW-hr 1131
NO,(duct firing) < 18.1 lb/hr 11'2)
Natural Gas shall be the < 0.0074 lb/MMBtu 111
only fuel of use. <2.0 ppmvd @ 15% Oz 11)
<0.055 lb/MW-hr 11,2,151
Fuel Heat Input of each EU:
< 18,888,480 MMBtu, < 15.0 ppmvd @ 15% Oz
HHV per 12-month rolling or
period 191 <0.43 lb/MW-hr 1131
CO (no duct firing) < 11.0 lb/hr 1'•2)
< 0.0045 lb/MMBtu 111
<2.0 ppmvd @ 15% 02111
< 0.031 lb/MW-hr 11.2, 10,141
CO (duct firing) < 11.0 lb/hr u,21
<0.0045 lb/MMBtu 111
<2.0 ppmvd @ 15% 0211)
< 0.0331b/MW-hr 11,z,ts1
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 6 of 25
-Tabli 2
EUI, EU2 Operation at>MECL, VOC (no duct firing), < 3.0 lb/hr
excluding start-ups and as Methane (CH4) <0.0013 lb/MMBtu
shutdowns < 1.0 ppmvd @ 15% 02
< 0.009 lb/MW-hr ll,2,10,14)
Fuel Heat Input Rate of VOC (duct firing), < 5.4 lb/hr 11,2)
each EU: as Methane (CI14) < 0.0022 lb/MMBtu.(1)
<2,449 MMBtu per hour, < 1.7 ppmvd @ 15% 02
HHV < 0.016 lb/MW-hr 11,2, 15)
S in Fuel <0.5 grains/100 scf
Natural Gas shall be the SO2 (no duct firing) < 3.71b/hr"")
only fuel of use. < 0.0015 lb/MMBtu (1)
< 0.3 ppmvd @ 15% 02
Fuel Heat Input of each EU: < 0.010 lb/MW-hr(1,2,10,14)
< 18,888,480 MMBtu, SO2 (duct firing) < 3.7 lb/hr(1,2)
HHV per 12-month rolling <0.0015 lb/MMBtu(1)
period (9) < 0.3 ppmvd @ 15% 02(1)
<0.011 lb/MW-hr
H2SO4 (no duct firing) < 2.3 lb/hr I"')
<0.0010 lb/MMBtu
:S 0.1 ppmvd @ 15% 02
< 0. 007 lb/MW-hr(1,2, 10,14)
H2SO4 (duct firing) < 2.3 lb/hr
<0.0010 lb/MMBtu (1)
:S 0.1 ppmvd @ 15% 02
< 0.008 lb/MW-hr(1,2, 15)
PM/PM1 O/PM2 5 (no duct < 15.5 lb/hr(""')
firing) <0.0088 lb/MMBtu (") 11
< 0.044 lb/MW-hr(1,2,8,10,14)
PMJPM1 O/PM2 5 (duct firing) < 15.5 lb/hr
< 0.0067 lb/MMBtu 8)
< 0.049 lb/MW-hr(1,2,8,
15)
NH3 (no duct firing) < 6.6 lb/hr(1,2)
<0.0027 lb/MMBtu
:<2.0 ppmvd @ 15% 02
< 0.0191b/MW-hr(1,2,10,14)
NH3 (duct firing) < 6.6 lb/hr 11,21
<0.0027 lb/MMBtu (1)
:S 2.0 ppmvd @ 15% 02
<0.020 lb/MW-hr(1,2,15)
Greenhouse Gases, CO2, < 825 lb/MW-hr
< 8951b/MW-hr 116)
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 7 of 25
nussion't An if
EUI, EU2 Operation at> MECL, Opacity . < 5%, except 5%to< 10%for
excluding start-ups and <2 minutes during any one hour
shutdowns (5)
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 (')
Operation at<MECL NO, < 89 lb per event(4,12)
during start-ups (3,12) CO <285 lb per event(4,12)
VOC, <23 lb per event la,lz1
Start-up duration: as Methane (CH4)
<45 minutes (3,12)
Sin Fuel < 0.5 grains/100 sef
SO2 < 2.0 lb per event 14,'21
Natural Gas shall be the H2SO4 < 1.3 lb per event (4.121
only fuel of use. I PM/PM101TM2.5 < 7.3 lb per event(4,8,12)
NH3 NA
Opacity < 10% (5, 12)
Operation at <MECL NO, < 10 lb per event(12)
during shutdowns (3,12) CO < 151 lb per event(12)
VOC, <29 lb per event 1121
Shutdown duration: as Methane (CH4)
<27 minutes(3,12) S in Fuel <0.5 grains/100 scf
S02 _< 0.3 lb per event
Natural Gas shall be the
H2SO4 < 0.2 lb per event 1121
only fuel of use. x,lel PM/PMIO/PM2.5 < 5.81b per event
NH3 NA
Opacity < 10%0, 12)
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 8 of 25
W
W:' pera iona —Pf6dficfi& k.CofitainfiWit ;ioh 1WAt.'4'�,
41
EU3 Operation at>MECL NO, < 0.88 lb/hr
< 0.011 lb/MMBtu (1)
Fuel Heat Input Rate: < 9.0 ppmvd P 3% 02
< 80 MMBtu per hour, CO < 2.8 lb/hr(')
HHV < 0.035 lb/MMBtu (1)
<47 ppmvd A 3% 02
Natural Gas shall be the VOC, <0.4 lb/hr(')
only fuel of use. as Methane (CH4) <0.005 lb/MMBtu (1)
< 11.8 ppmvd(d,) 3% 02
Total Fuel Heat Input: S in Fuel < 0.5 grains/100 sef
< 525,600 MMBtu, HHV SO2 < 0.12 lb/hr(I)
per 12-month 9)rolling period < 0.0015 lb/MMBtu (1)
(
:<0.9 ppmvd (&, 3% 02 Ill
H2SO4 < 0.009 lb/hr(')
< 0.0001 lb/MMBtu
< 0.05 ppmvd(&, 3% 02
PM/PMIO/PM2.5 < 0.4 lb/hr t'°s)
<0.005 lb/MMBtu(1,8)
-Greenhouse Gases, CO2, < 119.0 lb/MMBtu
Opacity <5%,except 5%to < 10% for
<2 minutes during any one hour,
EU4 <300 hours of operation NO, and VOC (NMHC as < 11.60 lb/hr(6)
per 12-month rolling period CHI 8), <4.8 gm/bhp-hr(')
Combined Total < 6.4 gm/KW-hr(6)
Ultra Low Sulfur Diesel Co < 6.34 lb/hr I')
Fuel Oil shall be the only <2.6 gm/bhp-hr
fuel o < 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/PMIO/PM2.5 <0.36 lb/hr(6)
*0.15 gm/bhp-hr(6)
* 0.2 gm/KW-hr(6)
Greenhouse Gases, CO21 < 162.85 lb/MMBtu
Opacity <5%,except 5%to < 10%for
<2 minutes during any one hour
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 9 of 25
4EU#,, '-"' _0p&ki6iiAf/Pro;dxictW t nant '' - jnission: ir
4M
EU5 < 300 hours of operation NO, and VOC (NMHC as <2.44 lb/hr(b)
per 12-month rolling period CHI.8), _<3.0 gm/bhp-hr 161
Combined Total <4.0 gm/KW-hr 161
Ultra Low Sulfur Diesel CO <2.14 lb/hr(b)
Fuel Oil shall be the only I <2.6 gm/bhp-hr 161
fuel of use. < 3.5 gm/KW-hr 16)
S in Fuel <0.0015%by weight
< 300 hours of operation SO2 <0.004 lb/hr
per 12-month rolling period) H2SO4 < 0.0003 lb/hr 161
PM/PMIO/PM2.5 < 0.12 lb/hr'6'
Ultra Low Sulfur Diesel < 0.15 gm/bhp-hr 161
Fuel Oil shall be the only <0.2 gm/KW-hr 161
fuel of use. Greenhouse Gases, CO2e < 162.85 lb/MMBtu
Opacity < 5%,except 5%to < 10%for
<2 minutes during any one hour
EU 1, EU2, NA Smoke 310 CMR 7.06 (1)(a)
EU3, EU4,
EU5
Facility-Wide NA NO, < 144.8 TPY
CO < 106.4 TPY
VOC <28.0 TPY
SO2 <28.8 TPY
PMfPMIO/PM2 5 < 109.4 TPY
NH3 <51.0 TPY
H2SO4 < 18.8 TPY
Pb <0.00013 TPY
Formaldehyde or Single HAP < 6.6 TPY
Total HAPS < 13.1 TPY
CO2 <2,277,333 TPY
Greenhouse Gases, CO2e <2,279,530 TPY 17)
Table 2 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 NINStu/hr, HHV, at 90 'F 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(NIECL) 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
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 10 of 25
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 start-
up 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
CHrs),which corresponds to a gas density of 0.5746 kg/m'.
7. Facility emissions include the two CTG/HRSG pairs with duct burners (EUI 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 EUI and EU2 are based on 8,040 hours of natural gas firing per 12
month rolling period at 100% load and 50°F 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 90°F 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 EUI 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 MMBm/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 NO,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 NO, 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/PMIa/PM25 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 50°F 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 907 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
MMBm/br,HHV).
10. Emission limit is based on full(base) load(100%load)ISO corrected(59 OF, 14.7 psis,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/COMB data generated from the first year of commercial operation.
13. NO,emission limits are from 40 CFR Part 60 Subpart KKKK. Compliance with the more stringent LAER
NOx emission limits of this PSD Permit shall be deemed compliance with the NOx limits from 40 CFR Part 60
Footprint Power Salem Harbor Development LP
' Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 11 of 25
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 CO,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 EUI 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 2 Kev:
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
PM,o=Particulate Matter less than or equal to 10 microns in diameter
PM,.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
Hexafiuoride) 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
1bMIIvIBtu=pounds per million British thermal units
ppmvd @ 15%02=parts per million by volume,dry basis,corrected to 15 percent oxygen
ppmvd @ 3%02=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
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 12 of 25
TPY=tons per 12-month rolling period
°F=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
IV. MONITORING AND TESTING REOUIREMENTS
S
.'s
ii
orQ1Bud.Teshng,Regnlrements,``
EUI, 1. The Permittee shall ensure that the proposed Facility is constructed toaccommodatethel
EU2,EU3 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 2 of this PSD Permit. 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.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 13 of 25
""M
onitd
g and'Testiug'Requirements, :,-.,
EU 1, 3. The Permittee shall conduct initial compliance tests of the proposed Facility to document
EU2, EU3 actual emissions of EUI, EU2, and EU3 so as to determine their compliance status versus the
emission limits (in lb/hr, Ib/MA4Btu, ppmvd, and lb/MW-hr, as applicable) in Table 2 for the
pollutants listed below.
Testing for these pollutants for EUI 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.
NO,, 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 EUI and EU2; parametric monitoring testing for PM1
PM10, and PM2.5 emissions for EUI and EU2; and NO./CO emissions optimization testing
for EU3.
�5. The Permittee shall conduct NOX/CO optimization on., and tune, EU3 according to
1procedures contained in EPA 340/1-83-023 "Combustion Efficiency Optimization
for Operators of Oil and Gas Fired Boilers" with the goal of reducing air pollutant ------------
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.
15. The Permittee shall install, calibrate, test, and operate a Data Acquisition and Handling
System(s) (DAHS), CEMS, and COMS serving EUI and EU2 to measure and record the
following emissions:
1a) 02; b)NO.; 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 EUI, 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, and 310 CMR 7.32, 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 2 of this PSD Permit.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 14 of 25
'dT tim
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Y men
g�an,_, es , g,R&nik.e fj�-:
EUI, II9. The Permittee shall operate each CEMS and/or COMS serving EUI, EU2 and EU3 at all
:EU2, EU3 mes except for periods of CEMS and COMS calibration checks, zero and span adjustments,
�reventative maintenance, and periods of unavoidable malfunction.
10. The Permittee shall obtain and record emissions data from each CEMS and/or COMS
serving EUI, 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 2 of this PSD Permit. ("Excess Emissions" are
defined as emissions which are in excess of the emission limits as stated in Table 2). An
.-xceedance of emission limits in Table 2 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 EUI, EU2 and
EU3 as "direct-compliance" monitors to measure NO., CO, NH3, 02, 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 EUI, 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, and 310 CMR 7.32.
�14. The Permittee shall install, operate, and maintain a fuel metering device and recorder r
U I, 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
�nput(MMBtu) for EUI, EU2, and EU3.
!16. The Permittee shall monitor each date and daily hours of operation and total hours of
operation for EUI, EU2, and EU3 per month and twelve month rolling period.
EUI, 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 EUI and EU2. These compliance tests shall represent periods of
�operation below the MECL for EUI 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 2 (lb per event) and
opacity limits, for these periods of time. MassDEP will incorporate these emission limits into
a Final PSD Permit for the as-built Facility upon issuance and such limits shall be considered
enforceable.
118. Whenever either combustion turbine is operating below the MECL for start-up and
tshutdown, the VOC emissions shall be considered,as occurring at the rate determined in the
t recent compliance test for start-up/shutdown conditions.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 15 of 25
Monit d T
EUI, 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 PSD
Permit, 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:
VOC,,tal = VOCH,n X (CO,,tua1/CO1i,i,), 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. I
r1. The Permittee shall comply with all applicable monitoring requirements of 40 CFR Part
60 Subpart KKKK.
P2. The Permittee shall monitor the natural gas consumption of EU1 and EU2 in accordance
rith 40 CFR Part 60 Subpart KKKK utilizing a continuous monitoring system accurate to +
percent, and as approved by MassDEP.
P3. The Permittee shall monitor the sulfur content of the natural gas combusted by EU1 and
U2 in accordance with 40 CFR Part 60 Subpart KKKK, or pursuant to any alternative fuel
onitoring schedule issued in accordance with 40 CFR Part 60 Subpart KKKK.
24. 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 EUI and
EU2. In addition, the Permittee shall monitor the combustion turbine inlet and ambient
temperatures for EUI and EU2.
5. The Permittee shall install and operate high and low level audible alarm monitors on the
storage tank and shall ensure that they are properly maintained.
r6 The Permittee shall monitor the load, start-up and shutdown duration, and mass
emissions (lb/event) during start-up and shutdown periods of EUI and EU2.
�7. The Permittee shall monitor the operation of EUI and EU2, in accordance with the'
isurrogate methodology or parametric monitoring developed during the most recent
Icompliance test concerning PM, PMIO, and PM2.5 emission limits.
8. The Permittee shall monitor the SO2 and CO2 emissions in accordance with 40 CFR Part
75.
9. The Permittee shall monitor the Greenhouse Gas emission rate utilizing the calculation)
rocedures in 40 CFR Part 98 Subpart A, Table A-1.
30. The Permittee shall continuously monitor the net electrical output to the grid of the
proposed Facility.
FU3 31. The Permittee shall comply with all applicable monitoring requirements of 40 CFR Part
60 Subpart Dc.
EU4,EU5 32. The Permittee shall comply with all applicable emissions standards, operating
restrictions, and monitoring requirements of 40 CFR Part 60 Subpart IIII.
33. 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.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 16 of 25
IV#
EU4, EU5 34. The Permittee shall monitor the quantity and sulfur content of ULSD fuel oil burned in
EU4 and EU5.
Facility- 35. If and when MassDEP requires it, the Permittee shall conduct compliance testing in
Wide accordance with EPA Reference Test Methods and 310 CMR 7.13.
Table 3 Kev:
EU4=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
02=Oxygen
NO,=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
Ib=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
MNMtu=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 0.00 1 5weight percent sulfur
V. RECORD KEEPING REOUIREMENTS
I'4abk"-4'�"; ylj�i
2�
-------------
:RecordKee piii jkjbi4uiremen,s.,�7
EUI, I1. The Permittee shall maintain records of each emission unit's hourly fuel heat input ratl
EU2, EU3 (MMBtu/hr, HHV), total fuel heat input (MMBtu), and natural, gas consumption (scf) pe
month and twelve month rolling period basis. I
� The Permittee shall maintain records of each date and daily hours of operation and total)
-ours of operation of each EU per month and twelve month rolling period.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 17 of 25
:ik
EU1, 13. The Permittee shall maintain on-site permanent records of output from all continuous
EU2, EU3�noniitors (including CEMS and COMS) for flue gas emissions and natural gas consumption
I(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 EUI, EU2, and
EU3;and the NH3 handling system serving EU1 and EU2.
EUI, EU2 5. The Permittee shall continuously estimate and record VOC emissions on the DAHS using the
CONOC correlation curve developed from the most recent compliance test.
16. The Permittee shall continuously estimate and record PM, PMIo, and PM2 5 emissions on the
S using the surrogate methodology or parametric monitoring derived from the most recent,
compliance test.
7. The Permittee shall maintain records of the load, start-up and shutdown duration, and
ass emissions (lb/event) during start-up and shutdown periods of EUI and EU2.
1 8. The Permittee shall maintain records of net electrical output to the grid from the Facility
on a daily basis.
� The Permittee shall comply with all applicable record keeping requirements of 40 CFR
art 60 Subpart KKKK.
10. The Permittee shall maintain records of the sulfur content of the natural gas combusted by
EUI and EU2 at the frequency required pursuant to 40 CFR Part 60 Subpart KKKK, of
pursuant to any alternative fuel monitoring schedule issued in accordance with 40 CFR Part
60 Subpart KKKK.
�11 The Permittee shall record SO2 and CO2 emissions from EU1 and EU2 in accordance
Iith 40 CFR Part 75.
�2. The Permittee shall record the Greenhouse Gas emission rate of EUI and EU2 on a daily
asis utilizing the calculation procedures in 40 CFR Part 98 Subpart A, Table A-1.
(13. The Permittee shall maintain continuous records of SCR and CO control system inlet
raperatures, combustion turbine inlet temperatures and ambient temperatures.
14. 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 15. The Permittee shall comply with all applicable record keeping requirements of 40 CFR
Part 60 Subpart Dc.
16. 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 17. The Permittee shall comply with all applicable record keeping requirements of 40 CFR Part
60 Subpart IIII.
t18The Permittee shall maintain a record of the quantity of ULSD fuel oil combusted in, and
. total hours of operation of, EU4 and EU5 per month and per 12-month rolling period.
119.
The Permittee shall maintain a record of the sulfur content of each ULSD fuel oil delivery at e Facility.
lr0. The Applicant shall maintain records concerning engine certifications as described in 310
N4:R 7.26 (42)(e)1. at the Facility.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 18 of 25
Nibl' 4
4
e
EU# ecoi eepin g: eq turehi ts
_en_ P,�
Facility- 21. A record keeping system for the Facility shall be established and maintained up-to-date
Wide 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 PSD Permit. 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.
22. The Permittee shall maintain all records required by 310 CMR 7.32 and 40 CFR Part 98
(Mandatory Greenhouse Gas Emissions Reporting) at the Facility.
23. The Permittee shall maintain monthly records to demonstrate the Facility's compliance
status regarding the Facility-Wide emission limits (TPY) specified in Table 2. Records shall
include actual emissions for the month as well as for the previous 11 months. (The MassDEP
approved format can be downloaded at
httD://www.mass.Qov/eea/agencies/massdeD/air/aD'provals/limited-emissions-record-keeDini2-
and-reDorting.html#WorkbookforReDortingOn-Site'RecordKeet)ing in Microsoft Excel
format.)
24. The Permittee shall maintain a copy of this PSD Permit, underlying Application, and the
most up-to-date Standard SOMP for each emission unit and PCD approved herein on-site.
25. The Permittee shall maintain records of monitoring and testing as required by Table 3.
All records required by this PSD Permit shall be kept on site for five (5) years and made
available for inspection by MassDEP or EPA upon request.
Table 4 Kev:
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
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 19 of 25
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
Ib=pounds
scf=standard cubic feet
MMBtu/lu=million British thermal units per hour
MMBtu=million British thermal units
HHV=higher heating value basis
TPY=tons per 12-month rolling period
VI. REPORTING REOUIREMENTS
ReportingRequireymerit
EUI, 1. The Permittee must obtain written MassDEP approval of an emissions test protocol prior
EU2, EU3 to initial compliance emissions testing of EUI, 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 EUI and EU2; b) a parametric monitoring strategy to ensure continuous
monitoring of PM, PM10, and PM2.5 emission from EUI and EU2; and c) procedures for the
required NO, 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 EUI, 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.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 20 of 25
�
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Rie"06"Alow, equweme :�.__
Requirements
EU 1, 4. The Permittee shall submit a quarterly Excess Emissions Report to MassDEP by the
EU2, EU3 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 start-
up, 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
i'-o 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
Linder the PSD Permit, due to unavoidable increases in emissions attributable to the
i-mergency. An emergency shall not include noncompliance to the extent caused by improperly
iiesigned equipment, lack of preventative maintenance, careless or improper operations,
operator error or decision to keep operating despite knowledge of these things.)
�-) A tabulation of periods of operation (including dispatch) of each emission unit and total
tours of operation of each emission unit during the calendar quarter.
EUI, EU2.5. After completion of the initial compliance emissions testing program, the Permittee shall
!3ubmit information for MassDEP review that documents the actual emissions impacts
venerated by EUI and EU2 during start-up and shutdown periods versus any applicable
and d SILs or the AALs and TELs for air toxics. This information shall be submitted
o 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, CTLs, 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.
7. The Permittee shall comply with all applicable 'reporting requirements of 40 CFR Part 61
Subpart KKKK.
tThe Permittee shall submit to MassDEP a Phase 11 Acid Rain Permit Application at least 241
onths prior to commencement of commercial operation of any subject emission unit.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 21 of 25
Y.,
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E U#
Re "R�!u
poitl Big ii
EUI, EU2 9. The Permittee shall submit to MassDEP a Clean Air Interstate Rule (CAIR) Permi
Application in accordance with 310 CMR 7.32 at least 18 months prior to commencement o�
commercial operation of any subject emission unit.
EU3 10. 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. I
11. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 60
Subpart Dc. I
EU4, EU5 12. 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.
13. 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.
14. The Permittee shall comply with all applicable reporting requirements of 40 CFR Part 60
�Subpart IIII.
Facility- 15. The Permittee shall submit, in writing, the following notifications to MassDEP within
Wide fourteen (14) days after each occurrence:
a) date of commencement of construction of each,subject emission unit at the Facility;
!o) date when construction has been completed of each subject emission unit at the Facility;
i.) 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.
16. 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.
17. 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.
18. The Permittee shall report to EPA in accordance with 40 CFR Part 75.
19. The Permittee shall comply with all applicable reporting requirements of 310 CMR 7.32
and 40 CFR Part 98 (Mandatory Greenhouse Gas Emissions Reporting).
20. The Permittee must notify MassDEP by telephone or fax or e-mail
[nero.air(o)massmail.state.ma.usI 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.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 22 of 25
V
Facility-. 21. The Permittee shall notify MassDEP immediately by telephone or fax or e-mail
Wide rnero.air(a 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.
22. The Permittee shall submit a semi-annual report to MassDEP by July 30 and January 30 of
each year to demonstrate the Fakility's compliance status regarding the Facility-Wide emission
limits (TPI) specified in Table 2. Reports shall include actual emissions for the previous 12
months. (The MassDEP approved format can be downloaded at
httt)://www.mass.Qov/eca/aizencies/massdeD/air/ai)Drovals/limited-emissions-record-keel)ing-
land-renorting.html#WorkbookforReDortin2On-SiteRecordKeei)iniz in Microsoft Excel
format)
23. 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.
�4, The Permittee shall submit to MassDEP all information required by this PSD Permit over
he signature of a "Responsible Official" as defined in 310 CMR 7.00 and shall include the
lCertification statement as provided in 310 CMR 7.01(2)(c).
25. All notifications and reporting to MassDEP required by this PSD Permit 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.airamassmail.state.ma.us
6. The Permittee shall provide a copy to MassDEP of any record required to be maintained
y this PSD Permit within thirty (30) days from MassDEP's request.
�7. 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 3,
Monitoring and Testing Requirements.
P8. The Permittee shall submit to MassDEP a final stack emission test results report, within
Iforty five (45) days after emission testing, for emission testing as defined in Table 3
Monitoring and Testing Requirements.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 23 of 25
Table 5 Kev:
EU#=Emission Unit Number
EPA=United States Environmental Protection Agency
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
N%=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
VII. SPECIAL TERMS AND CONDITIONS
e iie�•:. :.43�:�
%�' hy``i: .e„ 1J' - .. , iV, ...m,:: -fid.•t.::,:':
....,.., .,.....>._, .:..0{:.,.. �. . ,: pecral.Terms and:.Condihons ,."
EUI, EU2 11. The Permittee shall not allow the combustion turbines at the Facility to operate below the
ECL, except for start-ups and shutdowns. Emissions during start-ups and shutdowns shall
e included in the TPY limits specified in Table 2.
2. The Permittee shall ensure that the SCR control equipment serving EUI 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.
13. The Permittee shall maintain in the Facility control room, properly maintained, operable,
ortable NH3 detectors for use during an NH3 spill, or other emergency situation involving
113, at the Facility.
4. The Permittee shall comply with all applicable portions of Section 112(r) of the Clean Aii
Act and associated regulations at 40 CFR Part 68.
EU 1, EU2, 5. The Permittee shall develop as part of the Standard Operating Procedures for EU 1, EU2,
EU3 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.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No. X254064
Application No.NE-12-022
Page 24 of 25
;�.SpecialTerms`and-Coadifions;'s• s'
EU1, EU2, 6. The Permittee shall maintain an adequate supply of spare parts on-site to maintain the on-
EU3 line availability and data capture requirements for the CEMS and COMS equipment serving
the Facility.
Facility- 7. The Permittee shall properly train all personnel to operate the Facility and the control and
Wide 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 thel
Permittee to Facility personnel at least once annually.
18. 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 ir
excessive dust emissions. Jl
19. The Permittee shall comply with all provisions of 40 CFR Parts 72 and 75, 40 CFR Pard
160, 40 CFR Part 63, 40 CFR Part 64, 40 CFR Part.68, 40 CFR Part 98, and 310 CMR 6.01
Khrough 8.00 that are applicable to this Facility.
Table 6 Kev:
EU4=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
VIII. RIGHT OF ENTRY
The Permittee shall allow all authorized representatives of MassDEP and/or EPA, upon
presentation of credentials, to enter upon or through the Facility where records required under
this PSD Permit are kept. The Permittee shall allow such authorized representatives, at
reasonable times:
1. To access and copy any records that must be kept under this PSD Permit;
2. To inspect any facilities, equipment (including monitoring and air pollution control
equipment), practices, or operations regulated or required under this PSD Permit; and
3. To monitor substances or parameters for purposes of assuring compliance with this
PSD Permit.
Footprint Power Salem Harbor Development LP
Draft PSD Permit
Transmittal No.X254064
Application No.NE-12-022
Page 25 of 25
IX. TRANSFER OF OWNERSHIP
In the event of any changes in control or ownership of the Facility, this PSD Permit shall
be binding on all subsequent owners and operators. The Permittee shall notify the succeeding
owner and operator of the existence of this PSD Permit and its conditions before such change, if
possible, but in no case later than 14 days after such change. Notification shall be sent by letter
with a copy forwarded within 5 days to MassDEP and EPA.
X. SEVERABILITY
The provisions of this PSD Permit are severable, and if any provision of the PSD Permit
is held invalid, the remainder of this PSD Permit will not be affected thereby.
XI. CREDIBLE EVIDENCE
For the purpose of submitting compliance certifications or establishing whether or not the
Permittee has violated or is in violation of any provision of this PSD Permit, the methods used in
this PSD Permit shall be used, as applicable. However, nothing in this PSD Permit shall preclude
the use, including the exclusive use, of any credible evidence or information, relevant to whether
the Permittee would have been in compliance with applicable requirements if the appropriate
performance or compliance test procedures or methods had been performed.
XII. OTHER APPLICABLE REGULATIONS
The Permittee shall operate all equipment regulated herein in compliance with all other
applicable provisions of federal and state air regulations.
XIII. AGENCY ADDRESSES
Subject to change, all correspondence required by this PSD Permit shall be forwarded to:
Permit Chief, Bureau of Waste Prevention
The Department of Environmental Protection (MassDEP)
Northeast Regional Office
205B Lowell Street
Wilmington, Massachusetts 01887
i
l . ' Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
Department of Environmental Protection
Northeast Regional Office•2058 Lowell Street, Wilmington MA 01887.978-6943200
DEVAL L PATRICK RICHARD K,SULUVAN JR.
GDvcrnor
Secretary
KENNETH L.KIMMELL
Coinmuchner
Draft
Prevention of Significant Deterioration Permit
Fact Sheet
Salem Harbor Redevelopment Project
24 Fort Avenue
Salem, MA
Transmittal No. X254064
Application No. NE-12-022
This information is available in alternate format.Call Michelle Waters-Ekanem,Diversity Director.at 617-292-5751.TDD#1-866-539-7622 or 1-617-574-6868
MassDEP Website'v mass.gov/dep
Printed on Recycled Paper
I. General Information
Name of Source: Salem Harbor Redevelopment (SHR) Project
Location: Salem, Massachusetts
Applicant's Name and Address: Footprint Power Salem Harbor Development LP
1140 Route 24 East, Suite 303
Bridgewater, NJ 08807
Application Prepared By: Tetra Tech
160 Federal Street
Boston, MA 02110
Prevention of Significant Deterioration/
Comprehensive Plan Application
Transmittal Number: X254064
Application Number: NE-12-022
Massachusetts Department of
Environmental Protection(MassDEP)
MassDEP Contact: Cosmo Buttaro
MassDEP Northeast Regional Office
205B Lowell Street
Wilmington, MA 01887
(978) 694-3281
Cosmo.Buttaronn,State.MA.US
On December 21, 2012, Footprint Power Salem Harbor Development LP (Footprint) submitted
an initial Application to MassDEP requesting a Prevention of Significant Deterioration (PSD) Permit
and a 310 Code of Massachusetts Regulations (CMR) 7.02 Major Comprehensive Plan Application
Approval (Plan Approval) for a new 630 MW (692 MW with duct firing) natural gas fired quick start
combined cycle electric generating facility to be located at the site of the existing Salem Harbor Station.
The existing Salem Harbor Station is being shut down. Footprint submitted additional information on
April 12, 2013, June 10, 2013, June 18, 2013, August 6, 2013, August 20, 2013, September 4, 2013, and
September 6, 2013. MassDEP considers the Application for this Draft PSD Permit to be
administratively and technically complete. On September 9, 2013, MassDEP issued a Draft PSD Permit
for a 30 day public comment period.
On April 11, 2011, MassDEP and the U.S. Environmental Protection Agency Region 1 (EPA)
executed an "Agreement for Delegation of the Federal PSD program by EPA to MassDEP" (PSD
Delegation Agreement). This PSD Delegation Agreement directs that all Permits issued by MassDEP
under the Agreement follow the applicable procedures in 40 CFR 52.21 and 40 CFR part 124 regarding
permit issuance, modification and appeals.
The SHR Project is also subject to the MassDEP Plan Approval and Emission Limitations
requirements under the MassDEP regulations at 310 CMR 7.02 and 310 CMR 7.00: Appendix A
(Appendix A). MassDEP is concurrently issuing the Proposed Plan Approval and the Draft PSD Permit.
2
The Proposed Plan Approval regulates all pollutants affected by the proposed project, including the
pollutants regulated under the PSD Permit, and also implements MassDEP's nonattainment New Source
Review(NSR) program regulations at Appendix A. Footprint must ensure that its SHR Project complies
with both the federal PSD Permit and MassDEP's PlanApproval, as well as other applicable federal and
state requirements.
After reviewing the December 21, 2012 Application and additional information, MassDEP
prepared this Fact Sheet and Draft PSD Permit for the proposed SHR Project as required by the PSD
Delegation Agreement and 40 CFR Part 124 - Procedures for Decision Making.
MassDEP's permit decisions are based on the information and analysis provided by the
Applicant (Footprint) and MassDEP's own technical expertise. This Fact Sheet documents the
information and analysis MassDEP used to support the PSD Permit decisions. It includes a description
of the proposed SHR Project, the applicable PSD regulations, and an analysis demonstrating how
Footprint complied with all applicable requirements.
Based on all submittals, MassDEP has concluded that Footprint's Application is complete and
provides the necessary information showing the SHR Project meets federal PSD regulations. MassDEP
is making Footprint's submitted information part of the official record for this Fact Sheet and PSD
Permit.
II. Project Location
The proposed plant site is located in Salem, Massachusetts within the existing +/- 65 acre Salem
Harbor Station property which is bounded by Fort Avenue and the South Essex Sewerage District
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.
III. Proposed Project
Footprint proposes to construct a nominal 630 megawatt (MW) (692 MW with duct firing)
quick-start, combined-cycle natural gas-fired power plant at the proposed plant site. The SHR Project
will be configured as two operating units. Each unit will be able to operate independently to respond to
dispatch requirements. Most of the SHR Project's equipment will be housed in a building structure that
will be approximately 115,000 square feet (sf) in area. The SHR Project will include a variety of power
plant equipment including: two gas turbine generators (GTGs); two steam turbine generators (STGs);
two heat recovery steam generators (HRSGs) with selective catalytic reduction (SCR) and oxidation
catalyst pollution control equipment; generator step-up transformers; two air cooled condensers; an
ammonia storage tank; and water tanks. In addition, the SHR Project will include areas within other
buildings for administrative and operating staff; warehousing of parts and consumables; and
maintenance shops and equipment servicing.
3
Each unit of the proposed SHR Project will be a combined-cycle power plant. The first stage in
the generation process will be the operation of a GTG set. Thermal energy will be produced in the
GTGs through the combustion of natural gas, which will be converted into mechanical energy required
to drive the turbine compressor section as well as the generator. Each gas turbine will have the
capability to generate in excess of 200 MW under all environmental conditions using solely natural gas.
The GTG exhaust gas still contains considerable recoverable heat energy. This heat energy will be
recovered in a three pressure level HRSG to produce steam. This steam will be directed to a STG where
this heat energy will be converted to electrical energy representing approximately 40 percent (%) of the
total energy generated by each unit. Efficiency is enhanced in the cycle by using reheat systems as well
as using waste steam to heat feedwater in the HRSG, thereby further improving the overall efficiency of
the SHR Project. Once the steam leaves the steam turbine, it is condensed back to water using an air
cooled condenser (ACC). This water is then returned to the HRSGs through a system of pumps and
control mechanisms. Additional steam may be generated when required by the use of special burners
within the HRSGs (duct firing) to increase the electricity produced by the STGs.
Footprint will be using the GE Energy 7F Series 5 Rapid Response Combined Cycle Plant for
each main power block. Each GE power block can produce approximately 150 MW (300 MW total for
the plant) of output within 10 minutes of startup using both operating units together.
Continuous emissions monitoring systems (CEMS) will sample, analyze and record fuel firing
rates and nitrogen oxides (NO,) and carbon monoxide (CO) (and ammonia (NH3)) concentration levels,
and the percentage of diluent (either oxygen or carbon dioxide) in the exhaust gas from each of the two
HRSG exhaust flues. Exhaust gases will be discharged through a single 230 foot tall chimney enclosing
two flues (one for each turbine/HRSG), each with a diameter of 20 feet.
Ancillary equipment at the proposed SHR Project will include three additional fuel combustion
emission units:
• An 80 million British thermal units per hour (MMBtu/hr) natural gas fired auxiliary
boiler equipped with ultra low-NOx burners (Cleaver Brooks "Nebraska" D-type boiler Model No.
CBND 80E-300D-65 or equivalent),
• A 750 Kilowatt (KW) (standby rating) emergency generator firing ultra-low sulfur
distillate oil containing no more than 0.0015 weight percent sulfur (ULSD) (Cummins Model No.
DQFAA Diesel Emergency Generator or equivalent), and
• A 371 brake horsepower (BHP) fire pump engine firing ULSD oil (Cummins Model No.
CFP9E-F50 or equivalent).
Footprint has requested the combined cycle turbines be permitted for year-round operation on
natural gas and for the equivalent of 720 hours of operation of natural gas duct firing per rolling 12-
month period. The auxiliary boiler will be limited to the equivalent of 6,570 hours of natural gas firing
at full (100 percent) load per rolling 12-month period. The emergency diesel engine/generator and the
fire pump will each be limited to no more than 300 hours of operation per rolling 12-month period.
4'
IV. PSD Program Applicability and Review
MassDEP administers both the nonattainment New Source Review (NSR) program and the
attainment NSR PSD program under delegation from EPA. As stated previously, the PSD program
delegation is in accordance with the provisions of the April 11, 2011 PSD Delegation Agreement
between MassDEP and EPA which states that MassDEP agrees to implement and enforce the federal
PSD regulations as found in 40 CFR 52.21.1
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 this Fact Sheet. Therefore, MassDEP's evaluation of Emission Offsets and Nonattainment
Review for the construction of the proposed SHR Project, as required by Appendix A, is provided in the
Proposed Plan Approval.
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 NO, or VOC emissions. With respect to NO, 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 PSD regulations at 52.21 require that a major new stationary source of an attainment
pollutant, or major modification to an existing major stationary source of an attainment pollutant,
undergo a PSD review and that a PSD Permit be granted before commencement of construction.
40 CFR 52.21(b)(1) of the federal PSD regulations defines a "major stationary source" as either
(a) any of 28 designated stationary source categories with potential emissions of 100 tons per year (tpy)
or more of any regulated attainment pollutant, or(b) any other stationary source with potential emissions
of 250 tpy or more of any regulated attainment pollutant. Combined cycle generating facilities like the
SHR Project are one of the 28 designated stationary source categories for which 100 tpy of potential
emissions qualifies the source as "major."z
In addition, once a new stationary source has been determined to be a "major" source, it is
subject to PSD review for each regulated attainment pollutant that the source would have the potential to
Section III. Scope of Delegation, Section A., states, "Pursuant to 40 CFR 52.21(u), EPA hereby delegates to MassDEP full
responsibility for implementing and enforcing the federal PSD regulations for all sources located in the Commonwealth of
Massachusetts,subject to the terms and conditions of this Delegation Agreement."
' "Determining Prevention of Significant Deterioration (PSD) Applicability Thresholds for Gas Turbine Based Facilities,"
memorandum from Edward J. Lillis,Chief,Permits Branch,EPA,dated February 2, 1993.
5
emit in "significant" amounts, which in some cases is lower than the "major" thresholds. 40 CFR
52.21(b)(50)(iv) includes pollutants "subject to regulation" as defined in 40 CFR 52.21(b)(49) as
regulated pollutants. For this project, Greenhouse Gas (GHG) emissions become a regulated pollutant if
the project's total GHG emissions on a CO2,basis equal or exceed 75,000 tpy.
If MassDEP determines a new stationary source or new modification is subject to the PSD
program, the source must apply for and obtain 'a PSD Permit that meets regulatory requirements
including:
• Best Available Control Technology (BACT) requiring sources to minimize emissions to
the greatest extent practical;
• An ambient air. ualit analysis to ensure all the emission increases do n
q Y Y of cause or
contribute to a violation of any applicable PSD increments or NAAQS;
• An additional impact analysis to determine direct and indirect effects of the proposed
source on industrial growth in the area, soil, vegetation and visibility; and
• Public comment including an opportunity for a public hearing.
V. PSD Applicability
The SHR Project is considered a major source of air pollution as defined by EPA's PSD
program. Potential emissions from the proposed facility are significant for seven different PSD
pollutants: NO., CO, PM, PM10, PM2,5, sulfuric acid (H2SO4) mist, and GHG. Table 1 shows potential
emissions from the proposed new equipment at the site and Table 2 lists total facility potential to emit
relative to the PSD major source thresholds and significance level thresholds for PSD regulated
pollutants.
Table 1. Facility-Wide Annual Potential Emissions
Pollutant CT Unit 1 CT Unit 2 Auxiliary Emergency Fire Pump Auxiliary Facility
(tpy) (tpy) Boiler(tpy)2 Generator (tpy)' Cooling Total(tpy)
(toy)3 Tower
(toy)4
NO, 69.9 69.9 2.9 1.7 0.4 0 144.8
CO 48.0 48.0 9.2 1.0 0.3 0 106.4 J
VOC 13.1 13.1 1.3 0.35 0.12 0 28.0 J
SO2 14.2 14.2 0.4 0.0017 0.0006 0 28.8
PM 53.8 53.8 1.3 0.06 0.02 0.43 109.4
PM10 53.8 53.8 •1.3 0.06 0.02 0.43 109.4
PM2.5 53.8 53.8 1.3 0.06 0.02 0.17 109.2
NH3 25.5 25.5 0 0 0 0 51.0 J
H2SO4 Mist 9.4 9.4 0.03 0.00013 0.00005 0 18.8 J
Pb 0 0 0.00013 0.000001 0.0000003 0 0.00013 J
Formaldehyde 3.3 3.3 0.019 0.00009 0.0005 0 6.6
Total HAP 6.3 6.3 0.5 0.0018 0.0016 0 13.1
CO2 1,122,920 1,122,920 31,247 180 66 0 2,277,333 f
GHG, CO2, 1,124,003 1,124,003 31,277 181 66 0 2,279,530 J
6
Table 2. Preve ttion of Significant Deterioration Regu atory Threshold Evaluation
Pollutant Project Annual PSD Major PSD Significant PSD Review
Emissions (tons) Source Emission Rate Applies
Threshold (tons) (tons)
CO 106.4 100 100 Yes j
NOx 144.8 100 40 Yes 1
SO2 28.8 100 40 No
PM 109.4 100 25 Yes j
PM10 109.4 100 15 Yes
PM2 5 109.2 100 10 Yes 1
VOC 28.0 100 40 No 1
(Ozone precursor) 1
Pb 0.00013 100 0.6 No
Fluorides Negligible. 100 3 No 1
H2SO4 Mist 18.8 100 7 Yes 1
1-12S none expected 100 10 No
Total Reduced Sulfur none expected 100 10 No 1
(including 1-12S)
Reduced Sulfur none expected 100 10 No
Compounds
(including H2S)
GHG (as CO20 2,279,530 100,000 75,000 Yes 1
Table 1 and 2 Notes:
1. Emissions, except CO emissions, for each CT are based on 8,040 hours of natural gas firing per 12 month rolling
period at full (base) load(100% load) and 50°F 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 90°F ambient temperature with 100% duct burner firing (2,449 MMBtu/hr, HHV CT and duct burner combined) and
evaporative cooling, and include start-up and shutdown emissions. Worst case CO emissions for each CT are based on a typical
annual operating scenario of 3,272 hours at different seasonal emission rates depending on heat input rates (loads), ambient
temperatures, and duct burner/evaporative cooling status, and 36, 166, and 4 cold, warm, and hot start-up/shutdown cycles,
respectively.
2. Auxiliary boiler emissions are based on 6,570 hours of natural gas firing per 12 month rolling period at 100% load
(80 MMBtu/hr,HHV).
3. The emergency diesel generator (FDG) and fire pump (FP) emissions are each 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.
4. The auxiliary cooling tower contributes to particulate emissions only based on 8,760 hours of operation per 12 month
rolling period.
Table I and 2 Kev:
CT=Combustion Turbine
tpy=tons per year
NO,=Nitrogen Oxides
7
CO=Carbon Monoxide
VOC=Volatile Organic Compounds
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 Au Pollutants
CO2=Carbon Dioxide
GHG=Greenhouse Gases
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.
142S=Hydrogen Sulfide
ULSD=Ultra Low Sulfur Diesel Fuel Oil containing a maximum of 0.0015 weight percent sulfur
°F=degrees Fahrenheit
%=percent
MMBtu=million British thermal units
MMBm/hr=million British thermal units per hour
HHV=higher heating value basis
VI. BACT Analysis
As required by the federal PSD program at 40 CF R 52.210)(2) and (3), the SHR Project is
required to comply with BACT for the NO,, CO, PM, PM10, PMz 5, H2SO4, and GHG emissions from
the new turbines and other emission units.
BACT is defined as, "an emissions limitation ... based on the maxim tan degree of reduction for
each pollutant subject to regulation under [the Clean Air] Act which would be emitted from any
proposed major stationary source or major modification which the Administrator, on a case-by-case
basis, taking into account energy, environmental, and economic impacts and other costs, determines is
achievable for such source or modification through application of production processes or available
methods, systems and techniques ...for control of such pollutant. " 40 CFR 52.21(b)(12); C1eanAir Act
(CAA) 169(3).
BACT determinations involve an evaluation process known as the "top-down" process. In
brief, the "top-down" process involves a ranking of all available control technologies in descending
order of control effectiveness. Applicants are required to first examine the most stringent ("top-case")
alternative. MassDEP will presume this emission limit represents BACT unless the Applicant can
demonstrate that it is not feasible for technical, energy, environmental or economic reasons. If the most
stringent control alternative is eliminated, then the Applicant must consider the second best, and so on.
This procedure is modeled after the EPA December 1987 Top Down BACT Policy. It was further
described in the June 1991 NESCAUM BACT Guideline and October 1990 Draft EPA New Source
Review Workshop Manual.
8
MassDEP has also developed "top-down" BACT guidance (June 2011) for various source
categories including combustion turbine combined cycle units, boilers, and internal combustion
engines. Footprint has used this guidance, in part, to propose BACT for the SHR Project.
The results of the BACT analyses for the proposed SHR Project are presented below for NO.,
CO, PM, PM10,PM2.5, H2SO4 mist, and GHG emissions.
Combined Cycle Combustion Turbines
O
Clean Fuels
For the combined cycle combustion turbines, a major element of the BACT analysis is the use of
clean fuels. Footprint has proposed to burn solely natural gas in the combustion turbines. MassDEP
agrees that natural gas is the cleanest-buming fossil fuel available, and therefore represents the most
stringent"top" BACT with respect to the selection of turbine fuels.
NOx
In addition to the requirement to apply PSD BACT for NO., the SHR Project is also subject to
the determination of Lowest Achievable Emission Rate (LAER) because potential NO, emissions from
the SHR Project exceed the 310 CMR 7.00: Appendix A major source threshold of 50 tpy. Since
determinations of LAER and BACT are similar, and LAER is more stringent than BACT, the control
technology evaluation for NO,reflects the requirements of both BACT and LAER.
LAER is defined in 310 CMR 7.00 as:
"the more stringent rate of emissions based on the following:
(a) The most stringent emissions limitation which is contained in any state 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. This limitation, when applied to a modification, means the lowest
achievable emissions rate for the new or modified emissions units within a stationary source.
In no event shall LAER allow a proposed new or modified stationary source to emit any pollutant
in excess of the amount allowable pursuant to applicable new source standards of performance. " (3 10
CMR 7.00: Appendix A(2) Definitions).
In order to identify the "most stringent emissions limitation which is achieved in practice" by an
"F" Class combined cycle combustion turbine facility, Footprint evaluated numerous sources of
information. These sources included both state and federal resources of publicly available air permitting
information. California, New York, New Jersey, Connecticut, and Massachusetts were the focus for
state specific determinations and guidance. Footprint evaluated the following sources of information to
determine BACT (and LAER) for NO.:
9
• EPA's RACT,BACT,LAER Clearinghouse(RBLC);
• MassDEP's BACT Guidance of June 2011 including Top Case BACT Guidelines for
Combustion Sources;
• EPA Region IV's National Combustion Turbine List;
The California Air Resources Board(CAIU30) BACT Clearinghouse;
• The California South Coast Air Quality Management District's (SCAQMD) BACT
guidelines;
• State environmental program websites;
• New Jersey's State Of The Art(SOTA)Manual for Stationary Combustion Turbines; and
• The California Energy Commission Energy Facilities Siting Board.
In addition to these sources of information, additional publicly available information, such as
permits for individual projects not listed in the RBLC or other sources, was also included in the analysis.
Footprint presented the following conclusions:
• A search of EPA's RBLC for the lowest NOx emission rate for projects approved in the
last 10 years for the EPA characterized "Process Type 15.210" (large gas-fired combined cycle
combustion turbines) showed that the lowest approved NOx rate in RBLC is 2.0 ppmvdc (parts per
million by volume, dry basis, corrected to 15% 02).
• The EPA Region IV National Combustion Turbine Spreadsheet, was examined to
identify if any NO. emission limits more stringent than 2.0 ppmvdc are reported. The only project
identified with a NOX emission limit less than 2.0 ppmvdc is the Sunlaw (CA) Cogeneration Project,
which shows "1-2 ppm" for NOX. However, the RBLC entry for Sunlaw (RBLC ID # CA-0863)
confirms the emission level demonstrated in practice for this facility is 2.0 ppm.
The CARB BACT Clearinghouse had nine records for combined cycle gas turbines
greater than 50 MW;the only one more stringent than 2.0 ppmvdc NOx was the IDC Bellingham Project
(in MA), which is shown as having a NO,; limit of 1.5 ppmvdc. This entry contains a note indicating
that the limit(s) "are as stringent or more stringent than prior existing SCAQMD BACT for this source
category. These limits have not been verified by performance data. These limits were negotiated with
the Applicant and are presumably based on vendor guarantees." The IDC Bellingham Project was never
built, so the approved N% level of 1.5 ppm was never demonstrated in practice. Therefore, IDC
Bellingham is not a precedent for NOX BACT (or LAER).
• The SCAQMD BACT Clearinghouse has three gas turbine combined-cycle units listed,
with two approved at 2.0 ppmvdc and one approved at 2.5 ppmvdc.
10
• New Jersey's SOTA Manual for combustion turbines specifies a NO, limit of 2.5 ppmvdc
for combustion turbine combined cycle units greater than 150 MMBtu/hr heat input.
• The June 2011 MassDEP BACT guidance for combustion sources identifies 2.0 ppmvdc
of NO,as the"top case" BACT for large gas-fired combined cycle units.
• The two most recent NO, LAER precedents for similar Massachusetts projects are also
2.0 ppmvdc for gas firing. These are for the Brockton Power Company LLC (Plan Approval No.
4B08015, July 20, 2011) and Pioneer Valley Energy Center (EPA Final PSD Permit No. 052-042-
MA15), April 2012).
In summary, Footprint did not identify any BACT (or LAER) precedents for large gas-fired
combined cycle turbines where a NO, emission limit of less than 2.0 ppmvdc has been approved and
subsequently demonstrated in practice. Based on this review, MassDEP has determined that 2.0 ppmvdc
represents the "top case" BACT for NO, (as well as LAER) for the SHR Project's proposed combustion
turbines.
Footprint has proposed to achieve the NO, emission limit of 2.0 ppmvdc by using state of the art
dry low-NO, (DLN) combustors in combination with selective catalytic reduction (SCR). DLN
combustors are designed to minimize the creation of NO, in the turbine's combustion chamber. SCR
reduces NO,to nitrogen(NZ) and water(HZO) in the presence of a catalyst and ammonia.
SCR is placed in the exhaust flue of the combustion turbine. An SCR system is composed of an
ammonia storage tank, ammonia (NH3) forwarding pumps and controls, an injection grid (a system of
nozzles that spray NH3 into the exhaust gas ductwork), a catalyst reactor, and instrumentation and
controls. The injection grid disperses NH3 in the flue gas upstream of the catalyst, and NH3 and NOx are
reduced to Nz and H2O in the catalyst reactor.
Several different types of catalysts can be used to 'accommodate a wide range of flue gas
temperatures. Base metal catalysts, typically containing vanadium and/or titanium oxides, are typically
used for flue gas exhausts ranging between 450°F and 800°F. Combined cycle combustion turbine
projects employ a HRSG to produce steam from the hot exhaust gases exiting the turbine in order to
generate additional electricity in a steam turbine. As a result, combined cycle projects proponents can
design the HRSG such that a base metal SCR catalyst can be placed within the HRSG under its optimum
temperature window to maximize NOx reduction.
Because Footprint is proposing the "top case" NO, emission rate, it was not required to conduct
a "top-down" BACT analysis identifying other potential control technologies. Based on the results of
Footprint's NO, BACT (and LAER) evaluation research, MassDEP accepts Footprint's conclusion that
only SCR has been successfully demonstrated in practice to achieve the low NO, emission rate that
currently represents BACT (and LAER) for large combustion turbines (100 MW or greater), and that
SCR(in combination with DLN combusters) therefore will deliver BACT for NOx for the SHR Project.
11
CO
Carbon monoxide (CO) is emitted from combustion turbines as a result of incomplete oxidation
of the fuel. CO emissions can be minimized by the use of proper combustor design and good
combustion practices. Footprint is proposing to include catalytic oxidation systems for the SHR Project,
which Footprint has stated is the most stringent available CO control technology. A catalytic oxidation
system can provide 90% nominal reduction in CO emissions. The oxidation catalyst is a passive reactor
that consists of a honeycomb grid of metal panels coated with a platinum catalyst. The catalyst grid is
placed in the HRSG in the turbine exhaust gas. Footprint proposes that the SHR Project will achieve
CO emissions of 2.0 ppmvdc, which matches the top level of control for CO emissions as specified in
the June 2011 MassDEP Top Case BACT Guidelines for combustion turbine combined cycle units firing
natural gas.
The two most recent CO BACT precedents for similar Massachusetts projects are also 2.0
ppmvdc for natural gas firing. These are for the Brockton Power Company LLC (Plan Approval No.
4B08015, July 20, 2011) and Pioneer Valley Energy Center (EPA Final PSD Permit No. 052-042-
MA 15, April 2012).
Therefore, MassDEP concludes that Footprint has proposed the "top-case" BACT for CO for the
combustion turbine combined cycle units, which is 2.0 ppmvdc.
PM/PMto1PM?.5
Emissions of particulate matter result from trace quantities of ash (non-combustibles) in the fuel
as well as products of incomplete combustion. Footprint has proposed to minimize particulate emissions
from the proposed SHR Project by utilizing state of the art combustion turbines firing solely natural gas,
since natural gas is the lowest ash-content fuel available. Footprint conservatively presumes that all
particulate matter (PM) emissions from combustion turbines firing natural gas are less than 2.5 microns
in diameter (PM2.5), and therefore is proposing to achieve emissions of PM, PMIO, and PMZ 5, of 0.0067
pounds per million British thermal units (lb/MMBtu) at 100% combustion turbine (CT) load, 0.0071
lb/MMBtu at 75% CT load, and 0.0088 lb/MMBtu at the minimum emissions compliant CT load. These
proposed rates are lower than the June 2011 MassDEP Top Case BACT level of 0.011 lb/MMBtu.
The two most recent PM/PMIo/PMZ 5 BACT precedents for similar Massachusetts projects have
also been evaluated. The Brockton Power Company LLC (Plan Approval No. 4B08015, July 20, 2011)
was approved for 0.007 lb/MMBtu for loads down to 6No load. MassDEP concludes that the PM
BACT for Brockton and the SHR Project are comparable for SHR CT loads at 75% and greater.
Footprint has indicated that the turbine vendor performance levels at minimum emissions compliant CT
load require a slightly higher lb/MMBm PM limit. MassDEP has evaluated this request and concludes
that the operating flexibility afforded by operating at the minimum load levels warrants the approval of a
PM rate of 0.0088 lb/MMBtu at the minimum load conditions.
Pioneer Valley Energy Center (PVEC) (EPA Final PSD Permit No. 052-042-MA 15, April 2012)
was approved for a PM/PMio/PM2.5 emission rate of 0.004 lb/MMBtu for natural gas firing. Footprint
contends that this rate does not represent BACT since it was not demonstrated in practice since the
PVEC Project has not yet been constructed, and that it is not consistent with recent test data for the same
12
model turbine. Footprint contends that the MassDEP "top case" BACT precedent identified in the June
2011 BACT Guidance is for the Mystic Station Plan Approval which was approved for 0.011
lb/MMBtu, and that the four Mystic Station MHI 501G units had tested PM emissions ranging from
0.005 to 0.010 lb/MMBtu. Footprint contends that the majority of the tested particulate matter was
condensable particulates at Mystic.
Footprint further contends that the PVEC is also based on the MHI 501G turbine, and since the
majority of the tested particulate matter was condensable particulates for Mystic, it is not reasonable to
expect that the MHI 501 G unit at PVEC could reliably achieve 0.004 lb/MMBtu in practice.
MassDEP has determined that the Footprint position regarding the PVEC emission limit of 0.004
lb/MMBtu has merit and concludes that the PM emission rate of 0.0088 lb/MMBtu represents BACT for
PM/PMio/PM2.5 for the SHR Project's combined cycle turbines.
Sulfuric Acid Mist (H,SO4)
Emissions of sulfuric acid mist (H2SO4) are generated by the oxidation of sulfur in the fuel. The
only means for controlling sulfuric acid mist emissions from the SHR Project is to limit the sulfur
content of the fuel. Thus, by using solely natural gas which has a very low fuel sulfur content, H2SO4
emissions are minimized. The SHR Project is proposing an H2SO4 emission limit of 0.0010 lb/MMBtu,
which is lower than the Top Case BACT rate of 0.0016 lb/MMBtu in the June 2011 MassDEP BACT
guidance.
The most recent H2SO4 BACT precedent for a similar Massachusetts project has also been
evaluated. The Pioneer Valley Energy Center (EPA Final PSD Permit No. 052-042-MA15, April 2012)
was approved with an H2SO4 BACT limit for natural gas firing of 0.0019 lb/MMBtu. The Brockton
Power Company LLC Project (Plan Approval No. 4B08015, July 20, 2011) did not include an H2SO4
BACT limit.
MassDEP therefore concludes that Footprint's proposed H2SO4 emission limit of 0.0010
lb/MMBtu is BACT for H2SO4 for the SHR Project's combined cycle turbines.
Greenhouse Gas Emissions(GHG)
Greenhouse gas emissions for PSD permitting from combustion sources are the aggregate of
three pollutants: carbon dioxide, methane, and nitrous oxide. Since each pollutant has a different
effect on global warming, PSD applicability is based on a carbon dioxide equivalent (CO2,), determined
by multiplying each pollutant by its global warming potential. Like other combustion sources, the main
constituent of GHG for a combined cycle turbine is carbon dioxide. For Footprint's proposed combined
cycle turbines,their carbon dioxide emissions constitute 99.9% of their GHG emissions on a CO2,basis.
Nitrous oxide and methane make up the other 0.1% of the GHG emissions from these combined cycle
turbines on a CO2,basis.
The most stringent control technology for control of GHG from a combustion turbine combined
cycle unit is by means of carbon capture and storage (CCS). Footprint evaluated the feasibility of CCS
based on material published by EPA. CCS is composed of three main components. The first component
13
is the capture or removal of carbon (i.e., CO2) from the exhaust gas. The second component is transport
of the captured CO2 to a suitable disposal site, and the third component is the actual disposal of CO2,
normally deep underground in geological formations. Current technologies could be used to capture
CO2 from new and existing fossil energy power plants; however, they are not ready for widespread
implementation primarily because they have not been demonstrated at the scale necessary to establish
confidence for power plant applications.
Footprint indicated for pipeline transport for captured carbon, there are no nearby existing CO2
pipelines. The nearest CO2 pipelines to Massachusetts are in northern Michigan and southern
Mississippi. With regard to storage for CCS, EPA, in an Interagency Task Force Report ("Report of the
Interagency Task Force on Carbon Capture and Storage," August 2010), concludes that while there is
currently estimated to be a large volume of potential storage sites, "to enable widespread, safe, and
effective CCS, CO2 storage should continue to be field-demonstrated for a variety of geologic reservoir
classes" and that "scale-up from a limited number of demonstration projects to widescale commercial
deployment may necessitate the consideration of basin-scale factors (e.g., brine displacement, overlap of
pressure fronts, spatial variation in depositional environments, etc.)".
Based on conclusions of the Interagency Task Force for the CO2 capture component alone
(setting aside a detailed evaluation of the technical and economic feasibility of right-of-ways to build a
pipeline or of storage sites), Footprint contends that CCS has been determined to not currently be
technically feasible for projects of the size of the SHR Project. MassDEP concurs with this conclusion.
Since Footprint has demonstrated that it will be using the lowest carbon emitting fuel for a fossil
fuel project, Footprint further states that GHG BACT is then met by efficient generation of power by
means of combustion turbine combined cycle technology. Footprint's proposed GHG BACT is an
initial design limit of 825 pounds CO2, per net Megawatt hour of power delivered to the grid (lb
CO2,/MWhrg,;d). Footprint proposes to demonstrate compliance with this value by means of an initial
performance test, to be conducted within 180 days of facility startup. This test will be done at CT full
(base) 100% load,without duct firing, with the test results corrected to turbine ISO conditions.
Footprint also proposes to meet a 365-day rolling average GHG limit of 895 lb CO2,/MWhrgid,
for the life of the facility.
Footprint has proposed these limits which are identical to the approved GHG BACT limits for
the Pioneer Valley Energy Center (PVEC, EPA Final PSD Permit No. 052-042-MA15, April 2012).
This 365 day rolling average limit accounts for operation at varying loads, startup and shutdown,
.varying temperatures, and in particular unavoidable performance degradation between major overhauls
and over the life of the facility.
Footprint also notes that the PVEC Project used a CO2, emission factor of 116 lb/MMBtu. The
SHR Project CO2, emission factor is 119 lb/MMBtu, of which CO2 emissions comprise 118.9
lb/MMBtu and the other GHG comprise 0.1 lb/MMBtu. Footprint claims this makes its proposal to
meet the same limits as PVEC actually 2.6% more stringent than PVEC's approved limits.
In addition to the PVEC Project, the other recent GHG BACT precedent for a similar project in
Massachusetts is the Brockton Power Company LLC Project (Plan Approval No. 41108015, July 20,
14
2011). The Brockton Project was approved for a rolling 12-month CO2 limit of 842 lb/MWhr. The
basis for the 842 lb/MWhr CO2 limit in the Plan Application for the Brockton Project is stated "to
include operation at a variety of loads, ambient temperatures, with and without evaporative cooling, and
with and without duct firing, and including starts and stops" (Brockton Power Plan Application at page
4-30). However, there is no mention of any allowance for heat rate (efficiency) degradation over the life
of the project or between major turbine overhauls. Footprint contends that this is a significant
consideration which renders this value of 842 lb CO2/1vlWhr as inappropriate as a GHG BACT
precedent. Footprint notes that the Brockton Project has not yet been constructed, and the 842 lb
CO2fMWhr value therefore has not been demonstrated in practice. In addition, Footprint notes that the
Brockton Project did not specifically undergo a PSD review for GHG BACT.
Footprint also notes that in the Plan Application for the Brockton Project, it is stated that the 842
lb CO2/MWhr value is based on a CO2 emission factor of 117 lb/MMBtu. Footprint notes its proposed
limit of 895 lb CO2,/MWhrg;d is based on a CO2, emission factor of 119 lb/MMBtu. Adjusting the
Brockton value of 842 lb CO2/MW`hr by 118.9/117, the Brockton rate based on 118.9 lb CO2/MMBtu
would be 856 lb CO2/MWhr. In this case, the SHR Project value (895 lb CO2,/MWhrg;d) is only 4.6%
higher than the adjusted Brockton value (856 lb CO2/MWhr). In addition,the Brockton Project design is
based on wet cooling, while the SHR Project will use dry cooling. Projects using dry cooling have
higher heat rates (are less efficient) than wet cooled projects, particularly during the summer months.
Reasonable allowance for heat rate (efficiency) degradation over the life of the project and between
major turbine overhauls, as well as the impact of wet vs. dry cooling, explains the proposed GHG BACT
for the SHR Project of 895 lb CO2,/MWhrg;d compared to the proposed Brockton limit.
MassDEP concludes that the 365 day rolling average GHG emissions of 895 lb CO2,/MWhrgr;d,
which includes a reasonable allowance for the various factors affecting long-term GHG emissions,
including performance degradation, represents BACT for GHG emissions. Therefore the SHR Project
proposed GHG BACT limits of 825 lb CO2,/MWhrg,;d (initial design limit) and the 895 lb
CO2e/MWhrgfid (365 day rolling average) are approved as BACT for GHG.
Startup and Shutdown Emissions
Combustion turbines experience increased NO, 2SO4 and PM emissions during startup
P CO,,,, g p
and shutdown due to the non-steady state operations. In addition, low operating temperatures during
these conditions preclude the use of the SCR to reduce NO.. Footprint has proposed to comply with
BACT for startup and shutdown by 'employing good operating practices (by following the
manufacturer's recommendations during startup), and by limiting startup time. The combustion turbines
will be operated in accordance with manufacturer specifications during startups and shutdowns in order
to ensure that emissions are minimized during these short time periods. Additionally, ammonia injection
will be initiated as soon as the SCR catalyst reaches its vendor-specified minimum operating
temperature and all system parameters are met to minimize NO, emissions during these periods. The
proposed startup and shutdown emission limits are presented in Table 3.
MassDEP agrees that these emission rates represent BACT during startup and shutdown periods.
The emission limits for pollutants other than NO., CO, H2SO4, and PM will apply at all times, including
during startup and shutdown.
15
"Table 3: Startup and Shutdown Emission Limits Ohs per event) .. : l
Pollutant Startup (durati6n'45 minutes) Shutdown"(duratiow27 minutes). j
NO, 89 10 1
CO 285 151 1
PM/PM1O/PM2 5 23 29 1
H2SO4 1.3 0.2
Auxiliary Boiler
The proposed SHR Project will include the installation of an 80 MMBtu/hr heat input, natural
gas-fired auxiliary boiler. Annual operation of the auxiliary boiler will be limited to the full load
equivalent of 6,570 hours per year. The unit will be equipped with ultra-low NO, burners for NO,
control. Emissions will be controlled through the exclusive use of natural gas as fuel, good combustion
practices and a limit on the annual operations. In addition, the auxiliary boiler will meet the emission
limits determined by MassDEP to be the Top Case BACT for natural gas-fired boilers between 40
MMBtu and 100 MMBtuthr in size (June 2011) with the exception of PM/PMI0/PM2.5 emissions. The
top BACT case listed in the June 2011 MassDEP Guidance for natural gas-fired boilers of this size is
0.002 lb/MMBtu which Footprint contends- is not feasible as BACT for this Application. For
PM/PMIo/PM2.5 emissions, Footprint is proposing a BACT limit of 0.005 Ib/MMBm. Footprint
contends this BACT limit is more stringent than other recent BACT limits for natural gas-fired boilers in
Massachusetts. PM BACT limits, established relatively recently, were 0.007 lb/MMBtu for auxiliary
boilers at Mystic Station and Veolia MATEP, and 0.01 lb/MMBtu for Brockton Power. The PM BACT
limit for the auxiliary boiler at Pioneer Valley Energy Center is comparable at 0.0048 lb/MMBtu.
MassDEP concurs with Footprint's assessment of auxiliary boiler PM BACT. MassDEP also
finds that the auxiliary boiler NOx limit of 0.011 lb/MMBtu represents BACT for NO..
The approved BACT emission limits for the auxiliary boiler are shown in Table 4.
Table 4.4' BACT.Emissibn Limits,for the Auxiliary Boiler
Pollutant Emission BACT Determination Control Technology
NOx 0.011 Ib1MMBtu MassDEP Top Case BACT -Ultra Low NOx Burners
PM/PMIo1PM2.5 ` 0.0051b/MMBtu I Guidelines for Natural Gas (9 ppm)
CO 0.035 lb/MMBm Boilers (40-100 MMBtu/hr - Good combustion practices
heat input} (June 2011} -Natural gas 1
H2SO4` 0.00101b/MMBtu Natural Gas
1. PM BACT for natural gas-fired boilers between 40 and 100 MMBtulhr in the MassDEP guidance (June 2011) is
0.002 Ib/MMBtu. Footprint is proposing a PM/PM,WPM2.5 emission limit of 0.005 lb/MMBtu which is comparable or less
than MassDEP values recently approved for new gas-feed boilers.
2. Mystic Station auxiliary boiler SO2 emission limit is 0.0023 Ib/MMBtu. Based on the natural gas sulfur content
restriction of 0.5 grains per 100 H;, the proposed S02 emission limit is 0.0015 lb/M.MBta. H2SO4 emissions assumed to be
equivalent to approximately 2/3 of SO2 emissions based on vendor data. No H2SO4 emission limit cited in Mystic Station
Plan Approval.
16
�I
Emergency Generator and Fire Pump Engines
The SHR Project will include an emergency diesel generator (EDG) engine and a diesel fire
pump (FP). Both engines will operate on ULSD fuel. The proposed EDG will be a Cummins
750DQFAA ULSD-fired engine (or equivalent) with a standby generating capacity of 750 kW. The FP
engine will be a 371 BHP, 2.7 MMBtu/hr ULSD-fired engine. Both engines will be used in emergency
situations only (with the exception of periodic maintenance/testing events) and will be limited to a
maximum of 300 hours per rolling 12-month period of operation. There are no post-combustion
controls that have been demonstrated in practice for small, emergency internal combustion engines. In
order to satisfy BACT requirements, Footprint has proposed that the EDG will meet the EPA Tier 2
standards and that the FP will meet EPA Tier 3 standards for off-road diesel engines. These both meet
requirements specified under 40 CFR Part 89 as is specified in MassDEP's Air Pollution Control
Regulation at 310 CMR 7.26(42)(b) and represent the Top Case under MassDEP's June 2011 BACT
Guidelines. Emissions will be controlled through the use of ULSD, good combustion practices and
limited annual operation. With the exception of emergency situations, the units will typically operate no
more than one hour per week, for testing and maintenance purposes. The specific EDG and FP BACT
emission limits are shown in Tables 5 and 6.
Table 5. EDG BACT Emission Limits
Pollutant EPA Tier 2 Standard 1 Emissions Obs/hr) ,. Emissions (tpy)
NO,' 6.4 g/kWh 11.60 1.7
CO 3.5 g/kWh 6.34 1.0 1
PM/PM10/PM2 5 0.2 g/kWh 0.421 0.06 ` 1
H2SO4' 0.0009 0.00013
1. EPA Tier 2 standard for NO,and VOC is 6.4 g/kWh, combined. For worst case potential emissions,NO,emissions
assumed equal to this level and VOC emissions assumed equal to the older EPA Tier 1 limit of 1.3 g/kWh.
2. Emission limit reflects the addition of approximately 0.032 g/kWh for condensable particulate to the EPA Tier 2
standard based on AP-42 ratios.
3. There is no Tier 2 limit for SO2 emissions. SO2 emissions are limited based upon ULSD fuel sulfur content of
0.0015 weight percent. H2SO4emissions assumed equal to 8 weight percent of SO2 emissions.
Table 5 Kev:
g/kWh=grams per Kilowatt-hour
lb/hr=pounds per hour
tpy=tons per year
Table 6. FP BACT Emission Limits
Pollutant EPA Tier 3 Standard "Emissions (lbs/hr) Emissions (tpy)
NOx' 4.0 g/kWh 2.44 0.4
CO 3.5 g/kWh 2.14 0.3
PM/PMta/PM2.5 0.2 g/kWh 0.14 ` 0.02 `
H2SO4' 0.0003 0.00005 1
17
1. EPA Tier 3 standard for NO,and VOC is 4.0 g/KWh,combined. For worst case potential emissions,NO,emissions
assumed equal to this level and VOC emissions assumed equal to the older EPA Tier 1 limit of 1.3 g/kWh.
2. Emission limit reflects the addition of approximately 0.032 g/kWh for condensable particulate to the EPA Tier 3
standard based on AP-42 ratios.
3. There is no Tier 3 limit for SO2 emissions. SO2 emissions are limited based upon ULSD fuel sulfur content of
0.0015 weight percent. H2SO1 emissions assumed equal to 8 weight percent of SO2 emissions.
Table 6 Kev:
g/kWh=grams per Kilowatt-hour
lb/hr=pounds per hour
tpy=tons per year
VII. Monitoring and Testing
Footprint will install, calibrate, and operate dedicated continuous emission monitoring systems
for measuring NO, and CO emissions, in addition to the diluent oxygen (02), in the flue gas from the
combined cycle turbines. Each system will consist of a probe, analyzer, and data acquisition and
handling system. The NO, monitoring system shall meet the specifications and quality assurance
procedures of 40 CFR Part 75. The CO and 02 monitoring systems shall meet the specifications and
quality assurance procedures of 40 CFR Part 60 Appendix B, Performance Specifications 4 and 4A (for
CO) and Performance Specification 3 for 02. Emission data for CO and NO, will be measured by the
analyzer in ppmvd (parts per million by volume, dry basis). This ppmvd data can be directly compared
to the permit emission limits to determine compliance.
Pursuant to 40 CFR 75.13, Footprint will also monitor CO2 emissions in accordance with 40
CFR Part 75, Appendix G. To obtain NOx and CO mass emissions on an hourly basis, Footprint will use
EPA methods contained in 40 CFR Part 75 for NOx and 40 CFR Part 60, Appendix A, Method 19 for
CO. Footprint will need to measure heat input on an hourly basis and moisture content to convert the
measured ppmvd data to pounds per hour(lbs/hr). 1,
Footprint is required to monitor and keep records of the amount of sulfur in the natural gas that is
combusted in the combined cycle turbines.
Footprint is also required to conduct stack tests for CO,NO, PM, PM10, PM2.5, CO2, and H2SO4
emissions within 180 days after initial firing of the combined cycle turbines.
VIII. Impact Analysis Based on Modeling
As part of its Application, Footprint submitted a dispersion modeling analysis that met the
requirements of 40 CFR Part 51, Appendix W.
Footprint's consultant (Tetra Tech) conducted a refined dispersion modeling analysis to
determine impact concentrations at receptors located along the SHR Project fence line and beyond. The
refined analysis was based on proposed, worst case facility emission rates, and 5 years (2006-2010) of
18
meteorological conditions. The meteorological data was collected at the Boston Logan Airport National
Weather Service (NWS) station, which is the nearest NWS station to the project and is representative of
the project site area since it is exposed to similar coastal environmental conditions.
The dispersion modeling results for the proposed SHR Project are provided in Table 7 and show
that the SHR Project's impact concentrations are below the corresponding Significant Impact Levels
(SILs) established by EPA for all pollutants except NO2 (1-hour) and PM2.5 (24-hour). Compliance with
the NAAQS and PSD Increments is therefore, according to EPA guidance, demonstrated for all
pollutants and averaging periods for which impacts are below the SILs. Cumulative modeling with
other regional sources was conducted for NO2 and PM2,5.
Table 7. Project Maximum Predicted Impact Concentrations Compared to Significant Impact I
Levels (micrograms/cubic meter)
Pollutant Averaging Maximum Predicted Salem Harbor SIL
Period Redevelopment Project Impact 4
PMro ' 24-Hour 4.3 { 5
PM2,5 24-Hour 3.2 I 1.2
Annual 0.12 I 0.3
NO2 1-Hour i 41.8 7.5
Annual 0.4 1
SO2 1-Hour ( 1.0 7.8
3-Hour 1.1 25
24-Hour 0.7 I 5
Annual 0.03 1
CO 1-Hour 313.6 2000
8-Hour 112.4 500
Backaround Concentrations and Nearbv Sources
Tetra Tech determined ambient background concentrations through the use of existing ambient
monitoring data representative of the SHR Project site area. Ambient background concentrations are
based on the measurements made at the MassDEP monitoring site (ID# 025-009-2006) located in Lynn,
MA. The Lynn monitoring site is located approximately 5.9 miles to the southwest of the project site.
This monitoring site is representative of the SHR Project site since it is located relatively close to the
site. Furthermore, use of data from the Lynn monitoring site is also conservative because Lynn is a
more industrialized and densely populated area than the proposed SHR Project site area, particularly
without the influence of the coal and residual oil fired existing Salem Harbor Station, as will be the
situation when the SHR Project begins operations. The SHR Project site is located adjacent to Salem
Harbor, a significantly large water body where potential emission sources are more limited. The Lynn
monitoring site is also located closer to the metropolitan Boston area than the project site area. Any
potentially elevated ambient background pollutant concentrations from mobile and stationary emission
sources located in and around the Boston metro area that may be transported to the Salem project area
(via predominant south-southwesterly winds, i.e. winds blowing towards the north-northeast), must pass
the Lynn monitoring site, and are therefore represented in the measurement data collected at the Lynn
monitoring site.
19
The GE Aircraft Engine facility in Lynn and the Wheelabrator Saugus waste-to-energy facility,
two major industrial emission sources modeled cumulatively with the proposed SHR Project, are located
slightly less than 2 miles from the monitoring site but are located about 7 miles from the SHR Project
site. Therefore, the cumulative modeling compliance demonstration, which includes both the
background ambient concentrations and impacts from the interactive existing major sources potentially
double counts the contribution of these sources and therefore, potentially overestimates cumulative
impact concentrations. This is particularly significant because 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 south-southwesterly winds (winds blowing towards the north northeast) which
is one of the predominant wind directions in the area.
Nearby sources that must be considered in cumulative modeling are described in 40 CFR Part 51,
Appendix W as follows:
"Nearby Sources: All sources expected to cause a significant concentrations gradient in the
vicinity of the source or sources under consideration for emission limit(s) should be explicitly
modeled. The number of expected sources is expected to be small except in unusual situations.
Owing to both the uniqueness of each modeling situation and the large number of variables
involved in identifying nearby sources, no attempt here is made to define the term. Rather,
identification of nearby sources calls for the exercise of professional judgment by the appropriate
reviewing authority (paragraph 3.0(b)). This guidance is not intended to alter the exercise of the
judgment or to comprehensively define which sources are nearby sources."
The term "sources" in EPA's modeling guidance refers to stationary point sources of air
emissions. Air emissions from mobile sources are addressed through the use of ambient background
concentrations as measured by representative monitors. M3ssDEP reviewed recent emissions source
inventory data for point sources of NO, and PM2.5 surrounding the project. In accordance with
MassDEP's June 2011 "Modeling Guidance for Significant Stationary Sources of Air Pollution", nearby
sources within 10 kilometers that emit significant emission rates for NO, and PM2.5 (40 tons per year
and 10 tons per year actual emissions, respectively) may significantly interact with a new or modified
facility.
The sources that were identified for inclusion in the source interaction cumulative modeling
analysis include the General Electric (GE) Lynn, MA and Wheelabrator Saugus, MA facilities for both
NO. and PM2.5 emissions, as well as the Rousselot (formerly Eastman Gelatin Corp.), Peabody
Municipal Light (PML), and Marblehead Municipal Light (MML) facilities, for N% emissions only.
The GE and Wheelabrator facilities are located approximately 7.5 and 7.2 miles, respectively, to the
southwest of the project site. Based on the 2008 MassDEP emission source inventory data, actual GE
emission levels for NO, and PM2.5 are 248.3 and 11.8 tons per year, respectively. Wheelabrator
emission levels for NO, and PM2.5 are 721.8 and 6.2 tons per year, respectively. The Rousselot, PML,
and MML facilities are located approximately 3.1 miles to the east, 2.8 miles to the northeast, and 1.3
miles to the southeast of the project site, respectively. The actual 2008 NO, emission levels for these
facilities are 15.0 tons per year (Rousselot), 6.4 tons per year (PML), and 0.34 tons per year (MML).
The actual NO, emissions from these three sources are below.the PSD significance level of 40 tons per
year of NO., but were included in the analysis because of their proximity to the proposed SHR Project.
20
The results of the cumulative impact assessment, presented in Table 8, demonstrate that the
proposed SHR Project's worst case emissions will result in compliance with the National Ambient Air
Quality Standards (NAAQS). Note that while impacts related to secondary PM2.5 emissions have not
been explicitly quantified, sufficient margin is available between the predicted impact concentrations
from direct PM2.5 emissions and the NAAQS, that the NAAQS would not be threatened by additional
PM2 5 emissions. This conclusion is further supported by the fact that the maximum PM2.5 impacts are
predicted very close to the facility fence line, where secondary PM2 5 emissions would not have
sufficient time to develop, and therefore, could only be additive to predicted project impacts where
impacts of direct PM2.5 emissions are less than what has been reported for the compliance
demonstration.
Table 8. Salem Harbor Station Redevelopment Project NAAQS Compliance Assessment
(micrograms/cubic meter)
Pollutant Averaging Cumulative Impact, Background ` Total Impact Primary
Period SHR Project Plus Plus NAAQS
Existing Sources 2 Background
PM2.5 24-Hour 3.5 18.9 22.4 35
NO2 1-Hour 83.7 3 82.3 166.0 188
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 981h 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 I'highest values occurring in each year for the 24-Hour PM2 5 concentration,and the 5 year average
of the 8b highest daily maximum concentrations occurring in each year for the I-Hour NO2 concentration.
3. The modeled cumulative impacts represent an EPA-approved Tier 2 approach reflecting an 80 percent conversion of
NO,emissions to NO2 in the ambient air.
In addition to demonstrating compliance with the NAAQS, Footprint is required to demonstrate
that its emission impacts will not exceed available PSD increments. No increment exists for 1-hour
NO2. On October 20, 2010, EPA published an increment standard for PM2.5, averaged over both annual
and 24-hour basis. In this rulemaking, EPA established the major source baseline date of October 20,
2010 and a requirement that all PSD PM2.5 sources will not consume more than the available increment.
For PM2,5, increment is tracked on a county wide basis in Massachusetts. The SHR Project will be the
first major source permitted in Essex County after this date, and therefore the entire increments of 9
µg/m3 (24-Hour PM2.5) and 4 µg/m3 (Annual PM2.5) are available. As shown in Table 9, the SHR 24-
hour PM2.5 and Annual PM2,5 impacts are 35.5% and 3% of their respective PSD increments.
Table 9. Salem Harbor Station Redevelopment Project PSD Increment Compliance Assessment
(micrograms/cubic meter)
Pollutant Averaging Period SHR Project Maximum Allowable PSD
Increment Increment
Consumption)
PM2.5 24-Hour 3.2 9
21
Table 9. Salem Harbor Station Redevelopment Project PSD Increment Compliance Assessment
(micrograms/cubic meter)
Pollutant Averaging Period SHR Project Maximum Allowable PSD
Increment Increment
Consumptions
PM2.5 Annual 0.12 4
1. Consistent with EPA modeling guidance for PSD increment compliance assessments, impact concentrations are
based on the 5-year average of the 1st highest values occurring in each year for 24-hour and annual PM2.5 concentrations.
Impairment to Visibilitv. Soils, and Veeetation
40 CFR 52.21(0) requires the Applicant to conduct an analysis of the air quality impact and
impairment to visibility, soils, and vegetation that would occur as a result of the SHR project and
general commercial, residential, industrial, and other growth associated with the project. The
VISCREEN model was used by Tetra Tech to assess potential visibility impacts at the closest Class I
Area, the Presidential Range/Dry River National Wilderness Area (185 km away). The SHR Project's
maximum potential emissions were used in the analysis. MassDEP reviewed the analysis and has
determined that the visibility impairment related to the SHR Project's plume will not exceed threshold
criteria.
The EPA guidance document for soils and vegetation, "A Screening Procedure for the Impacts of
Air Pollution Sources on Plants, Soils, and Animals" (EPA Screening Procedure) (EPA 450/2-81-078)
established a screening methodology for comparing air quality modeling impacts to "vegetation
sensitivity thresholds." As an indication of whether emissions from the SHR Project will significantly
impact the surrounding vegetation (i.e., cause acute or chronic exposure to each evaluated pollutant), the
modeled emission concentrations have been compared against both a range of injury thresholds found in
the guidance, as well as those established by the NAAQS secondary standards. Since the NAAQS
secondary standards were set to protect public welfare, including protection against damage to crops and
vegetation, comparing modeled emissions to these standards provides some indication of whether
potential impacts are likely to be significant. Table 10 lists the project impact concentrations and
compares them to the vegetation sensitivity thresholds and NAAQS secondary standards. All pollutant
impact concentrations are below the vegetation sensitivity thresholds.
Table 10. Vegetation Impact Screening Thresholds
Pollutants Averaging Maximum Secondary NAAQS EPA's 1980 Screening
Period' Project (lig/in ) Concentrations (µg/M3)
Impacts
(µglen)
SO2 1-hour 1.1 NA 917
3-hour 1.2 1300 786
Annual 0.03 NA 18
NO2 4-hour 41.81 NA 3760
1 month 41.8 ' NA 561
Annual 0.4 100 94
CO Week 112.4 ' NA 1,800,000 (weekly)
22
Table 10. Vegetation Im )act Screening Thresholds
Pollutants Averaging Maximum Secondary NAAQS EPA's 1980 Screenin
Period Project (pg/m3) Concentrations (pg/mi)
Impacts
(pg/m3)
PMJO 24-hour 4.3 150 None
PM2.5 24-hour 3.2 35 None
Annual 0.12 15
1. Conservatively based on shorter term average predicted concentration.
The EPA Screening Procedure also provides a method for assessing impacts to soils. This
assessment evaluates trace elements contamination of soils. Since plant and animal communities can be
affected before noticeable accumulations occur in the soils, the approach used here evaluates the way
soil acts as an intermediary in the transfer of a deposited trace element to the plants. For trace elements,
the concentration deposited in the soil is calculated from the maximum predicted annual ground level
concentrations conservatively assuming that all deposited material is soluble and available for uptake by
plants. The amount of trace element potentially taken up by plants was calculated using average plant to
soil concentration ratios. The calculated soil and plant concentrations were then compared to screening
concentrations designed to assess potential adverse effects to soils and plants. Table 11 presents the
results of the potential soil and plant concentrations based on Tetra Tech's analysis and compares them
to the corresponding screening concentration criteria. A calculated concentration in excess of either of
the screening concentration criteria is an indication that a more detailed evaluation may be required.
MassDEP reviewed the analysis and has determined that concentrations as a result of operation of the
proposed SHR Project are all well below the screening criteria.
Table 11. Soils Impact Screening Assessment
Pollutant Deposited Soil Soil Percent of Plant Tissue Plant Percent
Concentration Screening Soil Concentration Screening of Plant
(ppmw) Criteria Screening (ppmw) Criteria Screening
(ppmw) Criteria (ppmw) Criteria
Arsenic 3.02E-04 3 0.0 4.23E-05 0.25 0.0
Cadmium 1.63E-03 2.5 0.1 1.74E-02 3 0.6
Chromium 3.78E-03 8.4 0.0 7.56E-05 1 0.0
Copper 1.23E-03 40 0.0 5.76E-04 0.73 0.1
Lead 8.30E-04 1000 0.0 3.73E-04 126 0.0
Mercury 3.71E-04 455 0.0 1.85E-04 NA NA
Nickel 3.31E-03 500 0.0 1.49E-04 60 0.0
Selenium 7.08E-05 13 0.0 7.08E-05 100 0.0
Vanadium 3.40E-03 2.5 0.1 3.40E-05 NA NA
Note: Based in screening procedures described in Chapter 5 of the EPA,guidance document for soils and vegetation, "A
Screening Procedure for the Impacts of Air Pollution Sources on Plants,Soils,and Animals."
23
IX. Mass Based Emission Limits
To ensure the NAAQS and increment are not violated, a PSD Permit must contain enforceable
permit terms and conditions which ensure the mass flow rates for each modeled pollutant are not
exceeded. This is accomplished by establishing mass-based emission limits for each modeled pollutant
with or without the use of CEMS. When a CEMS is used, the PSD Permit must establish the averaging
time for each mass-based emission limit that ensures compliance with the NAAQS. Without a CEMS,
the applicable stack test method establishes the averaging time by default. Footprint is required to
install CEMS for both CO and NO,, therefore averaging times for these pollutants are specified in the
Permit.
The Draft PSD Permit contains the mass-based emission limits Footprint used in demonstrating
compliance with the NAAQS and increment, and are therefore enforceable emission limits in the PSD
Permit.
X. Environmental Justice
The PSD Delegation Agreement specifies that MassDEP identify and address, as appropriate,
"disproportionality high and adverse human health or environmental effects of federal programs,
policies, 'and activities on minority and low-income populations," in accordance with Executive Order
12898 (February 11, 1994). Footprint considered draft federal guidance as well as the Massachusetts
Executive Office of Energy and Environmental Affairs (EOEEA) Massachusetts-specific Environmental
Justice (EJ) Policy in preparing an EJ assessment for the ,SHR Project. MassDEP reviewed the EJ
assessment and agrees that the analysis satisfies both state and federal requirements.
The EPA defines EJ as "the fair treatment and meaningful involvement of all people regardless
of race, color, national origin or income with respect to the development, implementation, and
enforcement of environmental laws, regulations and policies; Fair treatment means that no group of
people, including a racial, ethnic, or socioeconomic group, should bear a disproportionate share of the
negative environmental consequences resulting from industrial, municipal, and commercial operations
or the execution of federal, state, local, and tribal programs and policies."4
As demonstrated in Footprint's Application, Supplements, and as further set forth below, no such
group of people will bear a disproportionate share of negative health or environmental consequences
from the issuance of a PSD Permit to Footprint as (1) the SHR Project will not be located in or abutting
an EJ area; (2) nearby EJ communities have been provided with several opportunities to participate in
the permitting process; and (3) the SHR Project meets all applicable air emissions standards and would
not cause or contribute to a violation of the health-based National Ambient Air Quality Standards.
Moreover,the resulting regional emission reductions will benefit all communities, including EJ areas.
3 US EPA,"Draft Technical Guidance for Assessing Environmental Justice in Regulatory Analysis",May 1,2013 Post-
internal Agency Review Draft.
4 US EPA,Basic Information:Environmental Justice. httD://www.eDa.eov/enviromnentaliustice/basics/index.htTnl
24
Identification of Environmental Justice Areas
The Commonwealth of Massachusetts Executive Office of Energy and Environmental Affairs
(EOEEA) Geographic Information System (GIS) includes EJ areas divided by block groups based on the
2010 US Census data.5 The block groups are based on the number of people generally ranging from 500
to 2500 people as opposed to physical boundaries such as streets or rivers. There are three main EJ
classifications in the EOEEA EJ Policy (which is more expansive than the EPA policy) - Minority, Low
Income, and English Isolation (referred to as "Lacking English Language Proficiency" in the EOEEA
Policy):
• "Minorities" under the EOEEA Policy are individuals who refer to themselves on federal census
forms as "non-white" or as "Hispanic," which is broader than the EPA EJ definition. Any block
group with 25 percent or more minority population is considered to be an EJ area.
• Income of approximately 65% of the median annual household income is considered low
income. In Massachusetts median income is based on the state median household income of
$62,133 per year. Thus, any block group'with a median annual household income of$40,673 or
less is considered to be an EJ area.
• English Isolation is any household in which members 14 years old and older speak a non-English
language and also speak English less than "very well" (i.e., are not proficient in English). Any
block group with 25% or more of households as English Isolated is considered to be an EJ area.
Based on EJ mapping completed by EOEEA, the SHR Project does not abut any EJ areas and is
not located within 1 kilometer of any EJ areas. However, the site is within approximately 10 kilometers
of a number of EJ communities in Salem, Lynn, Peabody, Danvers and Beverly. The closest EJ areas
are classified as Minority/Low Income and Minority/Low Income/English Isolation and are located
approximately 1.2 kilometers (;/4 of a mile) to the southwest of the SHR Project property boundary. A
portion of this area is known as the "Point Neighborhood."
The Point was originally surrounded by water on three sides and was known as Long Point or
Stage Point. There were fish shacks and mill buildings in this area originally. In the mid 1880's the
Naumkeag Steam Cotton Company built its first mill along the South.River in the area of current day
Shetland Park. Immigrants, mainly French Canadians, settled in this area and provided the labor force
for the textile mills. The area was filled in to provide housing and more mill buildings. The Great
Salem Fire of 1914 destroyed this area but it was quickly rebuilt. The area thrived until the 1950's when
the textile industry moved to the south. Over the past few decades, many Spanish-speaking immigrants
have settled in this area.
There are several additional areas in Salem located further than 10 km from the SHR Project
property and these are classified as containing low income and minority populations.
5 2010 census data is the latest demographic data available. httn://www.mass.aov/meis/ei boston metro.odf
25
Public Particination
Footprint has conducted informational meetings; answered questions, and translated
presentations in non-English languages, in response to public interest and to encourage public
participation. The following is a summary of the public outreach, including outreach to EJ communities,
conducted over the past year.
• Notification of Filine an Environmental Notification Form (ENF) under the Massachusetts
Environmental Policy Act (MEPA)—AuQust, 2012
A legal,notice of the availability of the ENF was published in the Salem News in English,
Spanish and Portuguese on August 8, 2012. It was also published in the Marblehead Reporter in English
on August 9, 2012. Additional publication of the Legal Notice of Environmental Review was published
in English, Spanish and Portuguese in the Boston Globe on August, 18, 2012, the Lynn Daily Item on
August 21, 2012 and in the Danvers Herald, the Beverly Citizen and the Peabody-Lynnfield Weekly
News on August 23, 2012.
• Enerey Facilities Siting Board (EFSB) Public Hearing, Salem MA—Sentember 19, 2012
The following actions were taken by Footprint for the EFSB Hearing:
- Placed Notification advertisements in both English and Spanish in the Boston Globe, Salem
News, and Spanish Paper El Mundo.
- Placed English and Spanish Legal Notice of the of EFSB Petition, stating Footprint's
Development plans and the date/location of upcoming EFSB hearings, in the following
locations: Salem Public Library, City Clerk's Office, North Shore Community Development
Coalition, Salem Housing Authority, and ABE/ESOL Training Resources of America(Salem
Office). English copies of the EFSB Petition were also placed in these locations.
Notification of the placement of these EFSB documents in both English and Spanish was
placed in the EFSB advertisements in all three papers.
- Mailed EFSB Notice io abutters of existing Salem Harbor Station.
- Retained services of Spanish translator for EFSB hearings, to both translate information as it
was presented, and to translate questions presented from the public in Spanish.
- Offered to meet with interested members of the public along with Spanish translator.
• Presentation to Historic Derby Street Neighborhood Association,November 12, 2012
In addition to the presentation, Footprint offered to Linda Haley, Chairperson, that its
representatives would meet with individual residents to answer questions if requested.
26
i
• Draft Environmental Impact Reoort, December 2012
Notice of the public scoping meeting and site visit was sent to Beverly, Lynn, Salem, Peabody,
Marblehead, and Danvers. Notification of the availability of the Draft Environmental Impact Report
was published in the Boston Globe, the Salem News, the Marblehead Reporter, the Beverly Citizen, the
Danvers Herald, the Lynn Daily Item and the Peabody-Lynnfield Weekly News in English, Spanish and
Portuguese. These notices appeared on December 19 and December 20, 2012 with the exception of the
Marblehead Reporter notice which appeared on December 27, 2012.
• Presentation to the Salem Harbor Power Plant Stakeholders Group. January 22. 2013
Members have been appointed by Salem Mayor Kim Driscoll. .The Stakeholders are those
individuals who represent abutters to the plant, city officials whose position speaks for abutters (e.g.,
City Councilors, state elected officials, etc.). Footprint has made a pledge to respond to all requests for
information(English or Spanilsh), and to openly discuss Community needs and requests.
• Presentation to The Point Neighborhood Association. February 25. 2013
Lucy Curchado, Chairperson. Footprint provided a Spanish Translator. The presentation was
translated to Spanish sentence for sentence by the translator. Much of the Point leadership attended the
meeting and many questions were asked. The translator obtained questions from the Point membership,
translated those questions into English so they could be answered by Footprint representatives, and then
translated back into Spanish in response to the questioner. Footprint offered to either meet with any
members and provide a Spanish interpreter, or to respond in writing (Spanish)to questions if submitted.
• Public Presentation at the Bentlev F,lementary School. February 26. 2013
At Mayor Driscoll's request, Footprint made a presentation to the general public. The public
was invited to ask questions and/or request additional information.
• Final Environmental Imnact Report, April 4, 2013
Notification of the availability of the Draft Environmental Impact Report was published in the
Boston Globe, the Salem News, the Marblehead Reporter, the Beverly Citizen, the Danvers Herald, the
Lynn Daily Item and the Peabody-Lynnfield Weekly News in English, Spanish and Portuguese on April
4, 2013.
• Salem Planning Board Meetings, Mav 2,2013, Mav 6, 2013, and June 6, 2013
These meetings were continued to June 20, 2013 and were held at Bentley Elementary School.
They were open to the public.
�7
• Oneoing coordination with Luev Curchado. Chairoerson of the Point Neiehborhood Association
Footprint is in the process of translating its most recent/complete power point presentation into
Spanish for distribution to the membership. Footprint has offered to translate, provide information,
and/or respond to any other issues, questions or concerns of the Neighborhood Association.
Impact Analvsis
Prior to 1949 the site was used for commercial purposes related to the handling of coal and oil.
The fust power plant built on the site was a coal-fired unit that commenced operation in 1951. A second
coal-fired generation unit commenced operation in 1952, and a third coal-fired unit was added in 1958.
In 1978 a fourth, oil-fired, unit was added. The existing facility has operated as a grandfathered facility
(that did not have to meet emissions standards applied to new power plants) for many years and may not
have been able to be built under today's environmental regulations. However, the existing facility did
provide a significant economic value to the residents of Salem in tax payments. The proposed SHR
Project will result in significant decreases of air pollutant emissions, not just as compared with the
existing facility, but also regionally, while providing a tax benefit to the City of Salem and its residents.
Once operational, the SHR Project will be among the most efficient fossil-fueled fired electric
generators in the Northeast Massachusetts (NEMA) zone and is expected to provide 5.1 million MWh of
electricity annually. This additional supply will reduce the need for generation from other power plants
with lower efficiency and higher operating costs, primarily fueled by natural gas, oil, and coal. Charles
River Associates, a consultant to Footprint, has conducted an analysis projecting the operation of the
New England bulk power system over the period 2016-2025, for scenarios with and without the SHR
Project in service, and quantified the expected changes in air emissions by the project directly and the
associated reductions of emissions at competing plants elsewhere in New England and, in particular,
Massachusetts. MassDEP has reviewed the CRA study and agrees that because the SHR Project would
displace other, less efficient generation on the New England grid, operation of the SHR Project would
reduce regional air emissions by 457,626 tons, (1.3%) of CO2, 984 tons (10%) of NO, and 888 tons
(8%) of S02 annually.
Health Risk Assessment
Footprint commissioned a health risk assessment (HRA) to assess the potential for human health
risk associated with the SHR Project 6 Gradient Corporation prepared the human health risk assessment
evaluating the likelihood of both acute non-cancer health risks and chronic non-cancer and cancer health
risks that may result from people's inhalation of airborne pollutants for SHR Project stack air emissions.
Gradient also collected relevant background health information for Salem and surrounding communities
to determine if any types of disease (e.g., cancer and asthma) were higher than expected compared to
Massachusetts as a whole.
Footprint states that the HRA indicates that maximum predicted air levels of specific substances
associated with SHR Project air emissions would not be expected to contribute to adverse health effects
among potentially affected populations. Footprint states that several separate lines of evidence from the
6 Gradient Corporation,"Health Risk Assessment(HRA)for the Salem Harbor Redevelopment(SHR)Project",January 4,
2013.
28
HRA support the conclusion that the potential air emissions from the SHR Project are not expected to
have an adverse effect on public health in the Salem area. Footprint states that these include the
following:
- The maximum cumulative air concentrations (project impact plus existing background) of the
criteria pollutants of concern, which include SO2, CO, NO2, and PM, are well below the
health-protective NAAQS. NAAQS are set to protect human health with a wide margin of
safety even for sensitive populations. Stack emissions of criteria air pollutants are thus not
expected to lead to impacts on human health (e.g., asthma, cardiovascular and respiratory
diseases) in nearby communities, even in sensitive populations.
- For possible non-cancer effects, all hazard quotients (HQs), calculated for an off-site resident
exposed to maximum modeled incremental SHR Project stack impacts, were well below
unity (HQ = 1), with none being higher than HQ = 0.01. The overall summed HI for SHR
Project stack emissions is also well below 1.0, i.e., HI = 0.08. These results help assure that
non-cancer, adverse health effects are not to be expected from the non-criteria air-pollutant
emissions.
- Conservatively projected cancer risks for maximum modeled SHR Project stack impacts of
possible carcinogenic chemicals were well below the 1 in 10,000 to I in 1,000,000 lifetime
risk range, which is considered to be aceeptably'low by EPA. The overall summed cancer
risk from the SHR Project was about 1 in 10,000,000 over a lifetime, which is well below the
EPA de minimis risk level. The individual pollutant cancer risks were each even lower than
the de minimis level, between about I in 10,000,000,000 and about 4 in 100,000,000. These
results support de minimis cancer risk from worst-case chronic exposures to maximum
modeled SHR Project stack impacts.
- Based on the air-modeling results, short-term SHR Project air emissions impacts are not
expected to give rise to acute health effects. SHR Project-related maximum short-term
concentrations of SO2 and NO2 were compared to short-term exposure guidelines and
standards, including the short-term NAAQS for SO2 and NO2 which were specifically
designed to protect against asthma exacerbation and respiratory irritation. The comparisons
show that the cumulative impacts (maximum 1-hour plus ambient background) for NO2 and
SO2 are well below the I hour health-protective NAAQS as well as other short-term exposure
guideline levels.
- Gradient stated that review of community health data for Salem and nearby communities
confirms that the Salem area has overall similar rates of asthma, cardiovascular conditions,
and cancer compared with the state as a whole. In combination with the results of the HRA,
Gradient concluded that air emissions from operation of the proposed SHR Project are not
expected to significantly alter any of these baseline.health statistics.
Additional Analysis of Surroundine Areas
The maximum criteria air pollutant impacts from the SHR Project were also compared to the
EPA- and MassDEP-adopted significant impact levels (SILs). SILs are impact levels set at only a few
29
percent of the ambient air quality standards and below which the regulatory agencies consider impacts to
be insignificant.7 Impacts above the SILs are not considered significant, per se, but rather additional
modeling is required to demonstrate that the proposed project will not exceed the NAAQS. A
significant impact area (SIA) is the area of a circle having the radius of the maximum distance from a
source to the point at which concentrations drop below the SIL. The SIA is used as a basis for analysis
not because of any concern that emissions impacts inside the SIA are adverse - since they are below the
NAAQS, they are by definition not adverse - but rather ,because impacts outside the SIA are so
insignificant as to be de minimis. In EJ analyses, the SIA is often presented on a direction specific basis
and represents all receptors with projected impacts above the SIL.
The dispersion modeling completed for the SHR Project and described elsewhere in this Fact
Sheet, demonstrates that the predicted maximum impacts from the SHR Project for the majority of
criteria air pollutants are below the SILs at all locations and therefore, represent no adverse human
health or environmental effects to Salem and outlying communities. The predicted impacts of the SHR
Project result in slight to moderate execedances of SILs for only PM2.5 (24-hour average
concentrations), and NO2 (1-hour concentrations). Since the SILs are set considerably lower than the
NAAQS, the modeled emissions do not necessarily mean a project's impacts would be unhealthy or
would have an adverse effect on any population. Footprint evaluated these as a way to determine if an
EJ area would be disproportionately subject to higher air impacts than other segments of the community
at large.
The following sections describe the maximum modeled impacts for the only two pollutants with
maximum impacts exceeding their respective SIL with specific reference to the SIAs in reference to
nearby EJ areas versus other nearby areas.
NO? Analysis
The 1-hour NO2 SIL is 7.5 µg/m3. The 1-hour NO2 isopleths (i.e., maximum pollutant impact
concentration contours associated with emissions from the SHR Project) were prepared for the Salem
region and these isopleths show the following:
• There are two small areas of isolated peak NO2 one-hour concentrations (in the range of 36 to 42
µg/m3 and well below the NAAQS of 188 µg/m). These are located very close to the SHR
Project site to the northeast and southwest of the power plant stack. These areas are not close to
any EJ areas.
• Maximum concentrations beyond approximately 1 kilometer from the SHR Project's main stack
are less than approximately 16 pg/m and thus are all less than 10% of the health based NAAQS.
However, the SIA of 7.5 µg/m3 extends as far as 14 kilometers beyond the Footprint property
line extending into Salem, Beverly, Marblehead, Middleton, Wenham, Danvers, Peabody, Lynn,
and Swampscott. While this encompasses all of the EJ areas in Salem as well as some in
Beverly, Danvers, Middleton and Lynn, the population associated with the EJ areas within the
SIA is a small percentage of the total population within the SIA.
7 For example,the 1-hour NO2SIL is 7.5 microgram per cubic meter versus the health based standard of 188 micrograms per
cubic meter and the 24 hour PMz 5 SIL is 1.2 microgram per cubic meter versus the health based standard of 35 micrograms
per cubic meter. These SIL concentrations are only 3 to 4 percent of the NAAQS.
30
The results of this assessment demonstrate that the SHR Project's NO2 impact concentrations
will not have disproportionately high human health or environmental effects on EJ areas.
PM?s Analysis
Isopleths of maximum 24-hour average predicted concentrations from the SHR Project were also
prepared. These isopleths show the following:
• The highest 24-hour PM2.5 concentrations are only a small fraction of the health based NAAQS
(3 to 4 µg/m3 compared to the 35 µg/m3 NAAQS). These areas of highest impact are localized
and generally occur either on plant property, in areas immediately adjacent to the site, or in
Salem Harbor adjacent to the Salem shoreline.
• The 24-hour PM2.5 SIL is 1.2 µ2/m3 and this SIA encompasses a two city block area of a low
income EJ area just south of the South River. However, the vast majority of the SIA is within
Salem Harbor or consists of residences and businesses in the Salem downtown area along Derby
Street. It also encompasses Winter Island and a portion of the Salem Willows Park. The EJ area
represents a very small percentage of the total population within the SIA.
The results of this assessment demonstrate that the SHR Project's PM2,5 emissions will not have
disproportionately high human health or environmental effects on EJ areas.
CO? Benefits
The EPA's May 1, 2013 Draft EJ Guidance states, "The U.S. Climate Change Science Program
stated as one of its conclusions: The United States is certainly capable of adapting to the collective
impacts of climate change. However, there will still be certain individuals and locations where the
adaptive capacity is less and these individuals and their communities will be disproportionally impacted
by climate change. Therefore, these specific population groups may receive benefits from reductions in
greenhouse gas (GHG) emissions." Operation of the SHR Project is actually projected to reduce (on a
net basis) annual regional GHG emissions by approximately 457,626 tons of CO2,even after taking into
account the SHR Project's own CO2 emissions. This is based on the study done by Charles River
Associates provided as Appendix C of the DEIR prepared for the SHR Project. The CO2 reduction
represents approximately 1.3% of the regional CO2 emissions from power plants.
Conclusion
The proposed SHR Project is not located in or adjacent to an EJ area, and MassDEP hereby finds
that there will be no disproportional adverse health or environmental impact to any such community.
Indeed, the proposed SHR Project will be an improvement over emissions from the existing facility, and
will reduce regional emissions of NO., SO2 and CO2 to the benefit of all area residents. Footprint has
demonstrated that emissions from the proposed SHR Project itself will be well within the NAAQS,
which are designed to be health-protective of the most sensitive populations.
31
The above-discussed analyses and actions fulfill MassDEP's obligations under the Delegation
Agreement and fulfill all obligations under Executive Order 12898 and EPA Environmental Justice
Policy.
XI. National Historic Preservation Act, Endangered Species Act, Tribal Consultation
Section IV. of the PSD Delegation Agreement contains the requirements for Applicants (e.g.,
Footprint), MassDEP, and EPA with regards to the PSD Program. Under the PSD Delegation
Agreement, EPA must engage in consultation as required by federal law before MassDEP issues PSD
Permits.
Section IV.14.3. states that "If EPA requires more time to consult with an Indian tribe before
issuance of a Draft PSD Permit, refrain from issuing the Draft PSD Permit until EPA informs MassDEP
that it may do so." In addition, Section IV.H.4. states that "In all cases, MassDEP will refrain from
issuing any Final PSD Permit until EPA has notified MassDEP that EPA has satisfied its NHPA, ESA,
and Tribal consultation responsibilities with respect to that Permit."
In an April 18, 2013 letter from Tetra Tech to EPA Region 1, Tetra Tech asked EPA to notify
MassDEP that EPA has satisfied its consultation responsibilities for the proposed SHR Project's PSD
Permit. The letter included several attachments sent to various State, Federal and Tribal agencies
responsible for their respective National Historic Preservation Act (NHPA), Endangered Species Act
(ESA), and Tribal programs. EPA Region 1 reviewed Tetra Tech's .letter and attachments and
concluded in its September 5; 2013 letter to MassDEP that it had satisfied its NHPA, ESA, and Tribal
consultation responsibilities with respect to Footprint's PSD Permit.
The following sections outline how the NHPA, ESA, and Tribal consultation requirements
identified under the PSD Delegation Agreement have been met.
National Historic Preservation Act
On August 18, 2013, Tetra Tech submitted a letter to the Massachusetts Historic Commission
(MHC) notifying the MHC of Footprint's submittal of a PSD Permit Application for the proposed SHR
Project. The letter explained that Tetra Tech reviewed the National and State Register files and the
Inventory of Historic and Archaeological Assets of the Commonwealth at the MHC. The file search did
not identify any previously identified historic or archaeological resources within the proposed SHR
Project site.
The proposed SHR Project was also subject to a full:Massachusetts Environmental Policy Act
(MEPA) review. As part of the MEPA review, 'a MEPA Environmental Notification Form (ENF) was
distributed to the MHC in August 2012. The MHC did not submit comments on the ENF to the MEPA
office. Accordingly, EPA found that NHPA consultation requirements for the proposed SHR Project
have been satisfied.
32
Endangered Species Act
Section 7 of the Endangered Species Act (ESA) requires that certain federal actions such as
federal PSD Permits address the protection of endangered species in accordance with the ESA.
On April 18, 2013, Tetra Tech submitted a letter to Thomas R. Chapman, Supervisor, New
England Fish and Wildlife Service (FWS) field office notifying the FWS office of Footprint's submittal
of the PSD Permit Application for the proposed SHR Project. The letter stated that Footprint is aware of
and understands current ESA consultation procedures outlined on the FWS website. The website
provides an endangered species consultation process in which the Applicant conducts the initial
consultation. Tetra Tech reviewed the data for Essex County and identified two endangered species, the
small whorled Pogonia plant and the piping plover. Tetra Tech determined the presence of the two
species is limited to either the woodlands or the coastal beaches and are not present in the City of Salem
where the proposed SHR Project will be located. Tetra Tech concluded that the proposed SHR Project
does not pose a threat to any currently identified or proposed endangered species or their habitats in the
area subject to FWS jurisdiction and as a result, no further ESA impact analysis is required. In a
November 28, 2012 letter from Thomas R. Chapman, FWS, to Lisa Carrozza, Tetra Tech, FWS
confirmed that no federally listed, proposed, threatened or endangered species or critical habitat are
known to occur in the proposed SHR Project area and that no further ESA coordination is necessary.
In addition, on April 18, 2013, Tetra Tech submitted a letter to John Bullard, Regional
Administrator, National Oceanic and Atmospheric Administration (NOAA) National Marine Fisheries
Service (NMFS), Northeast Regional Office, which notified (NMFS) of the PSD Permit Application
submittal. The letter described the proposed SHR Project and its location at the existing Salem Harbor
Station and concluded that the changes will reduce net regional emissions of air pollutants due to
displacement of other, less efficient electrical generation on the New England electric grid.
Based on the letters to FWS and NMFS, EPA found that ESA consultation requirements for the
proposed SHR Project had been satisfied.
Tribal Consultation
On April 18, 2013, Footprint submitted separate letters to the Tribal Environmental Directors
and the Tribal Historic Preservation Officers for the Wampanoag Tribe of Gay Head (Aquinnah) and
Mashpee Wampanoag Tribe. The letters notified the Tribes of the proposed SHR Project's PSD Permit
Application and described how the proposed SHR Project willreduce net regional emissions of air
pollutants due to displacement of other, less efficient electrical generation on the New England electric
grid. In addition, EPA notified the tribes about Footprint's proposed SHR Project in a follow-up E-mail
message. As of this date, neither Tetra Tech nor EPA has received any comments from the Tribes.
XII. Comment Period, Hearings and Procedures for Final Decisions
All persons, including Applicants, who believe any condition of the Draft Permit is inappropriate
must raise all issues and submit all available arguments and all supporting material for their arguments
33
in full by the close of the public comment period, to Cosmo Buttaro of MassDEP at the address listed in
Section XIII of this Fact Sheet.
A public hearing will be held during the public comment period. See the public notice for
details. MassDEP will consider requests for extending the public comment period for good cause. In
reaching a final decision on the PSD Permit, MassDEP will respond to all significant comments and will
issue a Response to Comments document.
Following the close of the public comment period, and after the public hearing,MassDEP will
issue a Final Permit decision and forward a copy of the final decision to the Applicant and each person
who has submitted written comments or requested notice. Within 30 days following the notice of the
permit decision, any interested parties may submit a petition for review of the Permit to MassDEP's
Wilmington Office, which is consistent with appeal requirements specified in 40 CFR 124.19.
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 69J'/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 69.11/4.
XIII. MassDEP Contacts
Additional information concerning the Draft PSD Permit may be obtained between the hours of
9:00 a.m. and 5:00 p.m., Monday through Friday, excluding holidays from:
Cosmo Buttaro
MassDEP Northeast Regional Office
205B Lowell Street
Wilmington, MA 01887
(978) 694-3281
Cosmo.Buttaro i State.MA.US
34
.4
Commonwealth of Massachusetts
Executive Office of Energy &Environmental Affairs
LlDepartment of Environmental Protection
One Winter Street Boston, MA 02108.617-292-5500
DNAL L PATRICK RICHARD K.SULLIVAN JR
Governor secrel.sry
KENNETH L <MWELL
comrmac'oner
The Commonwealth of Massachusetts
Department of Environmental Protection
Bureau of Waste Prevention
Metropolitan Boston/Northeast Regional Office
2058 Lowell Street,Wilmington, MA 01887
TEL (978) 694-3200
ENSf4f::GieFea4n
` -and.Publc=Commeat.Rer4od on Proposed Air Quality Plan Approval
lg
and Prevention of Significant Deterioration Permit
& Notice of Section 61 Findings
Notice is hereby given that the Department of Environmental Protection (MassDEP or the
Department), acting in accordance with the provisions of Massachusetts General Laws
Chapter 30A, Chapter 111, Sections 142A through 1420, and 310 CMR 7.00:Appendix A(9)(b)
and the Code Federal Regulations(CFR),Title 40, Part 51.161, will hold a public hearing on, and
offer for public comment:
(1) the PROPOSED PLAN APPROVAL; and
(2) the DRAFT PREVENTION OF SIGNIFICANT DETERIORATION (PSD) PERMIT.
In addition, this is a:
(3) Notice of Section 61 Findings (incorporated into the proposed Plan Approval).
The Proposed Plan Approval and Draft PSD permit concern Footprint Power Salem Harbor
P PP P
Development LP's proposed construction and operation of a nominal 630 megawatt(MW)
combined cycle electric generating facility to be located at 24 Fort Avenue, Salem, MA. With
duct firing under summer conditions, the facility will be capable of generating an additional
62 MW, for a total of 692 MW. The purpose of the Proposed Plan Approval and Draft PSD
Permit is to allow for commencement of construction of the facility and its operation, and
provide information on the project description, best available control technology (BACT), lowest
achievable emission rate (LAER) and emission offsets, emission control systems,facility limits,
continuous emission monitors, record keeping, reporting and testing requirements, in
accordance with 310 CMR 7.00:Appendix A, 310 CMR 7.02 and 40 CFR 52.21.
This information is available in alternate format Call Michelle Waters-Ekanem,Diversity Director,at 617-292-5751.TDD#1-866-539-7622 or 1.617-5743868
MassDEP Website v mass gov/dep
Printed on Recycled Paper
An air quality impact analysis showed that the facility's air emissions will not cause a significant
impact on the air quality of contiguous states, nor violate federal and state Air Quality
Standards,federal emission standards for Hazardous Air Pollutants, any State Air Quality
guidelines, nor exceed PSD increments.
MassDEP hereby proposes to approve the application and hereby issues the Proposed Plan
Approval and Draft PSD Permit to:
Applicant: Mr.Scott G. Silverstein
Footprint Power Salem Harbor Development LP
1140 Route 22 East, Suite 303
Bridgewater, NJ 08807
Facility Name/Address: Salem Harbor Station Redevelopment Project
24 Fort Avenue
Salem, MA 01970
Transmittal No.: , X254064
Application No.: NE-12-022 q
Notice is also hereby given that MassDEP intends to hold a public hearing on the actions noted
above for the purpose of receiving public comments on the Proposed Plan Approval and Draft
PSD Permit before issuing the Plan Approval and PSD Permit. The public hearing will be held as
set forth below:
Date: Thursday, October 10, 2013
Time: 7:00 p.m.
Location: Bentley Elementary School
25 Memorial Drive
Salem MA 01970
The public hearing site is wheelchair accessible. For special accommodations for this event, please
contact Cosmo Buttaro at(978) 694-3281 as soon as possible. This information is available in
alternative format by calling MassDEP's ADA Coordinator at(617) 556-1057.
Copies of the Proposed Plan Approval and Draft PSD Permit and the application file can be
reviewed at MassDEP's Northeast Regional Office located at 205B Lowell Street, Wilmington, MA
commencing on the date of this Notice during normal business hours of 8:45 AM to 5:00 PM by
calling Cosmo Buttaro at(978) 694-3281. Copies of the Proposed Plan Approval and Draft PSD
Permit are also available for review at the Board of Health in the community where the facility is
located.
Comments on the actions noted above will be accepted until 5:00 PM on October 11, 2013,and
must be sent in writing to James E. Belsky, BWP Permit Chief at MassDEP's Northeast Regional
Office located at 205B Lowell Street, Wilmington, MA 01887. The public hearing will be conducted
under the provisions of Massachusetts General Laws, Chapter 30A. Testimony may be presented
orally or in writing at the public hearing on October 10, 2013. Written comments will be accepted
until 5:00 PM on October 11,2013. Persons are requested to submit three (3) written copies of
their testimony and/or comments to the Department.
By Order of MassDEP
Kenneth L. Kimmell
Commissioner
t
Footprint Powero
P
4
24 Fort Avenue, Salem, MA 01970
RECEIVED
Public Repository Nov 0 2013
Salem Puke Library ,,, .
370 Essex Street d0A"D_6F H' My
Salem, MA 01970
Re: Salem Harbor Station
Monthly Dust Complaint Log
To Whom It May Concern:
There was one dust complaint in the month of September. It was fielded on September 9a' and
was determined to be not-plant related based on analysis.
If you have any questions please feel free to call me at 978-740-8402.
Sincerely, ',
fIx
j 1 /4
ScottG.`Silverstein J14 s
COO Date
Footprint Power Salem Harbor Operations LLC
cc: N. Malia Grim
City of Salem BOH
Footprint Power® .
24 Fort Avenue, Salem, MA 01970
Public Repository
Salem Public Library
370 Essex Street
f�ZD
Salem,MA 01970 FEB 2 .1 H i.j
Old OFc
Re: Salem Harbor Station BGARO OF HEALTH
Monthly Dust Complaint Log
To Whom It May Concern:
There were no coal dust complaints in January 2013.
If you have any questions please feel free to call Robert DeRosier, Station Environmental
Manager, at 978-740-8402.
Sincerely
Scott' . Silverstein
President and COO Date
Footprint Power Salem Harbor Operations LLC
cc: R.DeRosier
N.Malia Griffm
City of Salem BOH
Wannalancit Mills
Suffolk Street, Suite 200
Lowell, MA 01854
978.970. PHONE
978.453.19951995 rnx c„q
www.TRCsolutions.com
TRC Reference Number: 165377 ��
�Fg 7 0
c
February 6, 2009 `� „
iu 2ppg
hc,glT
Ms. Janet Mancini h
Health Agent
Salem Board of Health
120 Washington Street (4th Floor)
Salem, Massachusetts 01970
Re: Notice of Availability: Response Action Outcome (RAO) Statement and
Submittal of Release Notification Form (BWSC Form 103)
No 2 Fuel Oil Release,
Salem Harbor Station, Salem, Massachusetts
MassDEP RTN: 3-28203
Dear Ms. Mancini:
TRC Environmental Corporation (TRC), on behalf of our client, Dominion Energy
New England Inc of Salem, Massachusetts (Dominion), is notifying your office of a
Class A-1 Response Action Outcome (RAO) Statement prepared for Salem Harbor
Station located at 24 Fort Avenue in Salem, Massachusetts (the "Site"). This
notification is being made in fulfillment of the public notice requirements of the
Massachusetts Contingency Plan (MCP), 310 CMR 40.1403(3)(f). A Class A-1
RAO Statement indicates that response actions were taken, a Permanent solution
has been achieved, and the level of oil and hazardous material in the environment
has been reduced to background. The Massachusetts Department of
Environmental Protection (MassDEP) assigned Release Tracking Number (RTN)
3-28203 to the release. The Release Notification Form (BWSC Form 103) for this
release is attached to this letter, as required by 310 CMR 40.1403(h).
On December 11, 2008, a release of less than 50 gallons of No. 2 fuel oil occurred
from an oil return line adjacent to Salem Harbor. Soil and groundwater were not
affected by the release. The oil sheens on the surface water were contained and
remediated to background levels.
A copy of the RAO Statement can be viewed at the Massachusetts Department of
Environmental Protection's Northeast Regional Service Center at 205 Lowell
Street in Wilmington, Massachusetts Tuesdays through Thursdays from 9:0o a.m.
to 12:00 P.M. (except state holidays). Please contact the Department of
Environmental Protection at 978-694-3320 for an appointment.
i Public Notification Letter February 6, 2009
Salem Harbor Station RTN 3-28203
If you have any questions about this letter, please contact our office at (978) 970-
5600.
Sincerely,
TRC'_ENVIRONMENTAL CORPORATION
Dorothy A. McGlincy, PG, LSP
Senior Program Manager
cc: Mr. Robert DeRosier, Dominion Energy New England, Salem Harbor Station
MassDEP, Bureau of Waste Site Cleanup,Northeast Region
1
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41 �
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1
AECOM
AECOM
300 Baker Avenue,Suite 290,Concord, Massachusetts 01742
T 978.371.4000 F 978.371.2468 w .aecom.com
March 4, 2009
Ms. Janet Mancini
Acting Health Agent
Salem Board of Health
120 Washington Street(4th Floor)
Salem, Massachusetts 01970
Subject: Board of Health Notice under the Massachusetts Contingency Plan
Phase IV Final Inspection Report&Completion Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Ms. Mancini:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Phase IV Final Inspection
Report (FIR)and Completion Statement for the above referenced site. The Site is a portion of the above
property at which soil and groundwater have been impacted by the release of petroleum hydrocarbons. Phase
IV activities involved pilot testing, operation of a full-scale Dual Phase Extraction system during the period from
February 8, 2007 through December 7, 2007, and post-remediation environmental sampling. These activities
will support a Class A-2 Response Action Outcome for the Site. No further MCP response actions are required.
The Phase IV FIR and Completion Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at(978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech (978) 371-4246.'
Sincerely,
AECOM
q�- ra RECEIVE®
Elissa J. Brown, CPG, LSP, LEP
Program Director APR 0 8 2009
/
C: V Mayor Kimberley Driscoll, City of Salem GOAHD Or HEALTH
LTH
Meredith Simas, Dominion
DEP BWSC NERO
AECOM
AECOM
300 Baker Avenue,Suite 290,Concord, Massachusetts 01742
T 978 371.4000 F 978 371.2468 www aecom.com
March 4, 2009
Ms. Janet Mancini
Acting Health Agent
Salem Board of Health
120 Washington Street(4'h Floor)
Salem, Massachusetts 01970
Subject: Board of Health Notice under the Massachusetts Contingency Plan
Response Action Outcome Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Ms. Mancini:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Response Action Outcome
(RAO)Statement for the above referenced site. The Site is a portion of the above property at which soil and
groundwater have been impacted by the release of petroleum hydrocarbons. Remedial action and assessment
activities have demonstrated that the residual concentrations of petroleum in soil and groundwater do not
present a threat to human health, safety, welfare or the environment. This Class A-2 RAO will support a
Permanent Solution for the Site. No further MCP response actions are required.
The Response Action Outcome Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at (978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech (978)371-4246.
Sincerely,
AECOM
Elissa J. Brown, CPG, LSP, LEP
Program/ Director
y/
C: Mayor Kimberley Driscoll, City of Salem
Meredith Simas, Dominion
DEP BWSC NERO
AECOM
AECOM
300 Baker Avenue,Suite 290,Concord,Massachusetts 01742
T 978.371.4000 F 978.371.2468 w .aecom.com
REGI EL
March 4, 2009
MAR 12 2009
Ms. Janet Mancini BOARD OF ' 'L�""i'
Acting Health Agent
Salem Board of Health
120 Washington Street(4`n Floor)
Salem, Massachusetts 01970
Subject: Board of Health Notice under the Massachusetts Contingency Plan
Phase IV Final Inspection Report & Completion Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Ms. Mancini:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Phase IV Final Inspection
Report(FIR) and Completion Statement for the above referenced site. The Site is a portion of the above
property at which soil and groundwater have been impacted by the release of petroleum hydrocarbons. Phase
IV activities involved pilot testing, operation of a full-scale Dual Phase Extraction system during the period from
February 8, 2007 through December 7, 2007, and post-remediation environmental sampling. These activities
will support a Class A-2 Response Action Outcome for the Site. No further MCP response actions are required.
The Phase IV FIR and Completion Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at(978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech(978) 371-4246.'
Sincerely,
AECOM J /
Elissa J. Brown, CPG, LSP, LEP
Program Director
C: Mayor Kimberley Driscoll, City of Salem
Meredith Simas, Dominion
DEP BWSC NERO
ry I AECOM
AECOM
300 Baker Avenue,Suite 290,Concord,Massachusetts 01742
T 978.371 4000 F 978 371.2468 w .aecom.com
March 4, 2009
Mayor Kimberley Driscoll
Salem City Hall
93 Washington Street
Salem, Massachusetts 01970
Subject: Chief Municipal Officer Notice under the Massachusetts Contingency Plan
Phase IV Final Inspection Report& Completion Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Mayor Driscoll:
Theur ose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
P P YY . P 9
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Phase IV Final Inspection
Report (FIR) and Completion Statement for the above referenced site. The Site is a portion of the above
property at which soil and groundwater have been impacted by the release of petroleum hydrocarbons. Phase
IV activities involved pilot testing, operation of a full-scale Dual Phase Extraction system during the period from
February 8, 2007 through December 7, 2007, and post-remediation environmental sampling. These activities
will support a Class A-2 Response Action Outcome for the Site. No further MCP response actions are required.
The Phase IV FIR and Completion Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at(978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech (978) 371-4246.
Sincerely,
AECOM
Elissa J. Brown, CPG, LSP, LEP
Program Director
C: %/Ms. Janet Mancini, Acting Health Agent, Salem Board of Health
Meredith Simas, Dominion
DEP BWSC NERO
" I AECOM
AECOM
300 Baker Avenue,Suite 290,Concord,Massachusetts 01742
T 978 371.4000 F 978.371.2468 w .aeconn.conn
March 4, 2009a�� 1VED
Ms. Janet Mancini MAR 122009
Acting Health Agent Gr,
t n� :
Salem Board of Health 6/AL- 1OF
120 Washington Street(4th Floor) HEAL1-H
Salem, Massachusetts 01970
Subject: Board of Health Notice under the Massachusetts Contingency Plan
Response Action Outcome Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Ms. Mancini:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Response Action Outcome
(RAO)Statement for the above referenced site. The Site is a portion of the above property at which soil and
groundwater have been impacted by the release of petroleum hydrocarbons. Remedial action and assessment
activities have demonstrated that the residual concentrations of petroleum in soil and groundwater do not
present a threat to human health, safety, welfare or the environment. This Class A-2 RAO will support a
Permanent Solution for the Site. No further MCP response actions are required.
The Response Action Outcome Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at(978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech (978) 371-4246.
Sincerely,
AECOM
Elissa J. Brown, CPG, LSP, LEP
Program Director
C: Mayor Kimberley Driscoll, City of Salem
Meredith Simas, Dominion
DEP BWSC NERO
+ I AECOM
AECOM
300 Baker Avenue,Suite 290,Concord,Massachusetts 01742
T 978 371.4000 F 978 371 2468 w .aecorn corn
March 4, 2009
Mayor Kimberley Driscoll
Salem City Hall
93 Washington Street
Salem, Massachusetts 01970
Subject: Chief Municipal Officer Notice under the Massachusetts Contingency Plan
Response Action Outcome Statement
Former Northeast Petroleum site, Salem Harbor Station, 24 Fort Avenue
MassDEP Release Tracking Number: 3-20421
Dear Mayor Driscoll:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCP-310 CMR
40.0000), that Dominion Energy Salem Harbor LLC (Dominion) has prepared a Response Action Outcome
(RAO)Statement for the above referenced site. The Site is a portion of the above property at which soil and
groundwater have been impacted by the release of petroleum hydrocarbons. Remedial action and assessment
activities have demonstrated that the residual concentrations of petroleum in soil and groundwater do not
present a threat to human health, safety, welfare or the environment. This Class A-2 RAO will support a
Permanent Solution for the Site. No further MCP response actions are required.
The Response Action Outcome Statement is available for review at the Massachusetts Department of
Environmental Protection's Northeast Regional Office in Wilmington. Should have any questions regarding this
notice, please contact Mr. Rob DeRosier of Dominion at(978) 740-8402 or Ms. Elissa Brown, LSP at Earth
Tech (978)371-4246.
Sincerely,
AECOM
Elissa J. Brown, CPG, LSP, LEP
ProgramDirector
/
C: v Ms. Janet Mancini, Acting Health Agent, Salem Board of Health
Meredith Simas, Dominion
DEP BWSC NERO
r
A COMMONWEALTH OF MASSACHUSETTS
EXECUTIVE OFFICE OF ENERGY & ENVIRONMENTAL AFFAIRS
DEPARTMENT OF ENVIRONMENTAL PROTECTION
NORTHEAST REGIONAL OFFICE
205B Lowell Street,Wilmington,MA 01887 • (978) 694-3200
DEVAL L.PATRICK ,/v IAN A.BOWLES
Governor p e '� IVY Secretary
TIMOTHY P.MURRAYy� ,� 9 2009 F E 613 2009 '
E® LAURIE BURT
Lieutenant Governor f Commissioner
Mr. Michael Fitzga d RE: SALEM
Dominion Energy Salem Harbor, LLC Metropolitan Boston/Northeast Region
Salem Harbor Station 310 CMR 7.13: Stack Testing
24 Fort Avenue Modified Final Approval
Salem, MA 01970
Dear Mr. Fitzgerald:
The Metropolitan Boston/Northeast Regional Office of the Department of Environmental
Protection, Bureau of Waste Prevention (MassDEP), has reviewed your letter dated October 28,
2008 concerning your request to modify the Stack Testing schedule as stipulated in the Stack
Testing Approval_ letter issued to you by MassDEP on August 14, 2001. This Stack Testing
Approval letter required Particulate Matter(PM) emissions,testing to be completed by November
1 of each year for Boiler Units 1, 2, 3, and 4 at your facility, Salem Harbor Station(SHS), located
at 24 Fort Avenue in Salem, MA. A description of the affected Boiler Units and the applicable
PM emissions standards are contained in Table 1 below:
FW�
Peseri tion of Facili nd 13oiler,P1VI'Emissions,Standards ,
Q tS-
Boifer", Maa_>Imnm-Heat Energy"{ Prrmary Fuels ? PM Em2ss►ons �• Applicable,.
` t" Input Rating, ; ;Combus'ed (1) t`4 �1Standard"tf, .: Regulat,on and/or;?
+,fUnit s
i `.v _ tw W n•, ' ., R " ;� Y'
_ i"ApprovalNumlierk;
# i(MMBtu/h"our 1 4_'. �, r, lb/MiVIBtu) (2)_u
1 954 Coal 0.12 310 CMR 7.02(8)(d)
2 966 0.12
3 1,696 0.12
4 4,800 No. 6 Fuel Oil 0.04 MBR-9I-COM-016
MBR-9I-COM-029
Table 1 Notes:
(1) No. 6 Fuel Oil shall have a maximum sulfur content of 2.2 percent by weight.
(2) Based on the average of three(3)one-hour test runs.
Table 1 Kev:
MMBtu/hr=million British thermal units per hour
lb/MMBtu=pounds per million British thermal units
This information is available in alternate formal.Call Donald M.Gomes,ADA Coordinator at 617-556-1057.TDD4 866-539-7622 or 617-574-6868.
http://v .mms.gov/dep a Fax(978)694-3499
0 Printed on Recycled Paper
Dominion Energy Salem Harbor,LLC—Salem Harbor Station
Modified Final PM Test Approval
Page 2 of 4
Currently, Boiler Unit 4 operates as a peaking unit and operates at, and is forecast to operate at, a
relatively low annual capacity utilization (ACU) factor, averaging approximately nine (9)percent
(%). Since peaking units are typically dispatched without advance notice it is difficult to schedule
PM emissions testing while Boiler Unit 4 is required to operate and coordinate said testing with
the stack testing vendor and MassDEP. Furthermore, since Boiler Unit 4 operates as a peaking
unit, compliance testing under the current schedule is likely to result in air emissions that would
not otherwise occur if Boiler Unit 4 is operated solely for the purpose of PM emissions testing.
Therefore, due to the ongoing low ACU of Boiler Unit 4, the facility has requested that the PM
emissions testing frequency for said unit be changed to once every five (5) years. The facility
conducted the most recent PM emissions testing of Boiler Unit 4 on December 2, 2008.
MassDEP has determined that your request is in conformance with current air pollution control
engineering practices, and hereby grants Modified Final Approval for said request, as
submitted, subject to the conditions listed below.
Please review the entire Approval carefully, as it stipulates the particular conditions with which
the facility owner/operator must comply in order for the facility to be operated in compliance
with the Regulations. Failure to comply with this Approval will constitute a violation of the
Regulations and can result in the revocation of the Approval.
Special Conditions
1. This Approval letter supersedes, in its entirety, the Stack Testing Approval letter issued
by MassDEP to you on August 14, 2001.
2. The December 2, 2008 PM emissions testing of Boiler Unit 4 shall be credited towards
calendar year 2008. Hereafter, SHS shall complete additional PM emissions testing of Boiler
Unit 4 every five (5) calendar years by November I" of each year, presuming Boiler Unit 4 has
not exceeded an ACU of twenty (20) % in any given year. Under this schedule, the next PM
emissions testing of Boiler Unit 4 shall be completed by November 1, 2013. Should the ACU for
Boiler Unit 4 be greater than twenty (20) % in any given calendar year, then SHS shall complete
additional PM emissions testing by November I" of the following calendar year. In order to
notify MassDEP of the need to test, SHS shall report the occurrence of greater than 20%ACU of
Boiler Unit 4 as part of its Annual Compliance Report, as required by 310 CMR 7.00: Appendix
C. PM emissions testing of Boiler Units 1, 2, and 3 shall continue to be conducted annually prior
to November Pt.
3. The PM emissions testing of Boiler Units 1, 2, 3, and 4 shall be conducted in accordance
with 310 CMR 7.13. The emissions testing program shall include two types of PM: a) PM as
measured by EPA Method 5, designated as "front-half' PM; and, b) PM as measured by EPA
Method 202, designated as "back-half' PM. The "front-half' PM as summarized in the above
Table 1 for Boiler Units 1, 2, 3, and 4 will continue to be used as the compliance measure, while
the "back-half' PM will be used for informational purposes only. This testing shall be conducted
in the presence of a MassDEP representative(s), when such is deemed necessary, on a mutually
r
Dominion Energy Salem Harbor,LLC—Salem Harbor Station
` Modified Final PM Test Approval
Page 3 of 4
agreed upon date(s). At least thirty (30) days prior to the emissions testing program, SHS shall
submit a written test protocol that outlines the test methodology to be employed during the
required testing to this Office for MassDEP review and approval.
4. Within sixty (60) days of the completion of each required PM emissions test, SHS shall
submit the test results to this Office for review.
This Approval does not negate the responsibility of the facility to comply with this or any other
applicable federal, state, or local regulations now or in the future. Nor does this Approval imply
compliance with this or any other applicable federal, state, or local regulations now or in the
future.
This Approval may be suspended, modified, or revoked by MassDEP if, at any time, MassDEP
determines that the facility is violating any condition or part of this Approval.
Failure to comply with any of the above stated conditions will constitute a violation of the
"Regulations", and can result in the revocation of the Approval granted herein and/or other
appropriate enforcement action as provided by law.
Anneal Process
This Approval is an action of MassDEP. If you are aggrieved by this action, you may request an
adjudicatory hearing. A request for a hearing must be made in writing and postmarked within
twenty-one (21) days of the date you received this Approval.
Under 310 CMR 1.01(6)(b), the request must state clearly and concisely the facts, which are the
grounds for the request, and the relief sought. Additionally, the request must state why the
Approval is not consistent with applicable laws and regulations.
The hearing request along with a valid check payable to the Commonwealth of Massachusetts in
the amount of one hundred dollars ($100.00) must be mailed to:
Commonwealth of Massachusetts
Department of Environmental Protection (MassDEP)
P.O. Box 4062
Boston, MA 02211
This request will be dismi's'sed if the filing fee is not paid, unless the appellant is exempt or
granted a waiver as described below. The filing fee is not required if the appellant is a city or
town (or municipal agency), county, or district of the Commonwealth of Massachusetts, or a
municipal housing authority.
MassDEP may waive the adjudicatory hearing-filing fee for a person who shows that paying the
fee will create an undue financial hardship. A person seeking a waiver must file, together with
Dominion Energy Salem Harbor,LLC—Salem Harbor Station
Modified Final PM Test Approval
Page 4 of 4
the hearing request as provided above, an affidavit setting forth the facts believed to support the
claim of undue financial hardship.
Should you have any questions concerning this Approval, please contact Cosmo Buttaro by
telephone at(978) 694-3281, or in writing at the letterhead address.
Sincerely,
Cosmo Buttaro fureau
s E. Belsky
Environmental Engineer it Chief
of Waste P evention
cc: Board of Health, 120 Washington Street,4t'Floor, Salem, MA 01970
Fire Headquarters, 48 Lafayette Street, Salem, MA 01970
MassDEPBoston- Yi Tian (E-Copy)
MassDEP/Wilmington—Marc Altobelli (E-Copy&Hard Copy),Joseph Su(E-Copy&
Hard Copy), Mary Persky, Cosmo Buttaro
r ,per
�\ COMMONWEALTH OF MASSACHUSETTS
EXECUTIVE OFFICE OF ENERGY & ENVIRONMENTAL AFFAIRS
DEPARTMENT OF ENVIRONMENTAL PROTECTION
NORTHEAST REGIONAL OFFICE
205B Lowell Street, Wilmington, MA 01887 • (978) 694-3200
DEVAL L.PATRICK IAN A.BOWLES
Governor
Secretary
TIMOTHY P.MURRAY IF16 E C E I VE"D LAURIE BURT
Lieutenant Governor Commissioner
DEC 10 2007
December 6, 2007 C11 v of SALEM
BOARD OF HEALTH
Diane G. Leopold
Vice President, Fossil & Hydro
Dominion Generation
Innsbrook Technical Center
5000 Dominion Boulevard
Glen Allen, VA 23060
Re: Termination of Administrative Consent Order, ACO-BO-00-2002
Bra ;nt Station, RTN-No.4 13169
SemHarbor Station, RTN No. 3-212b3�
Dear Ms. Leopold:. �.
By letter dated November 21, 2007, Dominion ("Dominion") certified to MassDEP that all
measures required by the Administrative Consent Order,ACO-BO-00-2002 (the "ACO"or
"Consent Order"), have been completed in full satisfaction of the ACO's requirements.
MassDEP has reviewed its files and agrees that the requirements of the Consent Order have been
fully satisfied. Accordingly, the ACO is terminated as of the date of this letter.
Dominion's letter further requested that MassDEP terminate the groundwater monitoring
program for Brayton Point and Salem Harbor Stations required under Section III.E.3 of the
ACO. Section III.E.3 had provided that, "USGen [Dominion's predecessor] shall continue to
monitor the ground water at the Stations according to current sampling and analysis plans until
modified by the Department."
With respect to Salem Harbor Station,the groundwater monitoring program required under
Section III.E.3 of the ACO is hereby terminated. In addition, Dominion is no longer required to
submit groundwater monitoring reports for Salem Harbor Station pursuant to 314 CMR 5.00, the
Groundwater Discharge Permit Program regulations.
With respect to Bravton Point Station, while the groundwater monitoring program required under
Section III.E.3 of the ACO is hereby terminated, other groundwater monitoring requirements
continue to apply. Specifically, groundwater monitoring for Basin No. 3 as required by the
This information is available in alternate format.Call Donald Dl.Gomes,ADA Coordinator at 617-556-1057.TDD service-1-800-298-2207.
http.//w .mass gov/dep•Fax(978)694-3499
Printed on Recycled Paper
Letter to Diane G. Leopold,VP,Dominion Page 2 of 2
Termination of Administrative Consent Order,ACO-BO-00-2002
--Lagoon Closures at Salem Harbor Station and Brayton Point Station
December 6,2007
Department's July 14, 1999 Basin No. 3 Groundwater Monitoring Plan is hereby terminated.
Please be advised, however, that monitoring wells MW 301 and BP-01 (which are noted in the
Basin No. 3 Groundwater Monitoring Plan) are still required to be monitored pursuant to
condition number 13, Groundwater Monitoring Network for Oil Ash Cells 1, 2, 3, 4. 5, 6, 7, 8, 9.,
10 and 10A, of the Provisional Approval with Conditions for the BWP SW23 Comprehensive
Site Assessment issued by the Southeast Regional Office on October 26, 2007.
This letter shall not be construed as, nor operate as, relieving Dominion of the necessity of
complying with all applicable federal, state, and local laws, regulations and approvals.
Should you have any questions or comments concerning this letter and Salem Harbor Station,
please contact Jeff Chorman of my staff at(617) 292-5888. Should you have any questions that
relate to Brayton Point Station,please contact Robert Greene of MassDEP's Southeast Regional
Office at (508) 946-2826.
Sincerely,
,�,,
Jamqs C. dolman
Assi tart Commissioner
Bureau of Waste Prevention
cc: Lou Arak, Dominion
Meredith Simas, Dominion
Jeffrey Chormann, MassDEPBWPBoston
Edward Pawlowski, (Acting)Deputy Regional Director, MassDEP/BWP/NERO
Muhammad Ahsan, MassDEPBWP/NERO
Robert Greene, MassDEP/SERO
Geri Lambert, MassDEP/OE
Susan Reid, CLF
Lisa Evans, HealthLink
Cindy Keegan, HealthLink
City of Salem Board of Health g �.
Somerset Board of Health RECEIV
DEC 10 2007
CITY OF:SALEM
BOARD OF11�TH
LETTER OF TRANSMITTAL
DATE: I October 16, 2007
TO: PIP Notitication Mailing List (attached)
cc: Chief Municipal Officer, Town of Salem
Board of Health, Town of Salem
Dominion Energy Salem Harbor, LLC
SUBJECT. a Fern Harbor Statio
ega o ice—Public Meeting to Present Draft Response Action Outcome Statement
FROM: I Anthony J. Wespiser
X For Your Information For Your Review
For Your Use For Your Comment
Per Your Request
Enclosed please find one copy of the Legal Notice for the Public Meeting being held by Dominion Energy
Salem Harbor, LLC to present the draft Response Action Outcome Statement for the Former Unlined
Wastewater Treatment Basin Site at Salem Harbor Station.
The Legal Notice was published in the Salem Evening News on Friday, October 5, 2007, and the Beverly
Citizen on Thursday, October 11, 2007.
If you have any questions, please feel free to call Meredith Simas of Dominion, at phone 508-646-5338.
A 1i
Anthony J. Wespiser, P.E.
EarthTech
A Tyco Intunationa]Ltd Company
300 Baker Avenue, Suite 290
Concord, MA 01742
(978)-371-4000
FAX: (978)-371-2468
Notification Mailing List
(Final Public Involvement Plan(PIP), June 2003)
Unlined Treatment Basin Site, Salem Harbor Station
Salem, Massachusetts
RTN 3-21283
Ms.Karen Kahn Mr. Keith E. Glidden Mayor of Salem
17 Sutton Avenue 21 Turner Street,#2 Salem City Hall
Salem, MA 01970 Salem,MA 01970 93 Washington Street
Salem,MA 01970
Ms. Lisa Brooke Ms. Cindy Keegan
136 Bay View Avenue 12 Williams Street Health Agent
Salem, MA 01970 Beverly,MA 01915 Salem Board of Health
120 Washington Street, 4th Fir
Ms. Patricia J. Ould Ms.Maggie Haley Salem,MA 01970
5 Intervale Road 21 Turner Street,#2
Salem, MA 01970 Salem,MA 01970 Dept. of Environ Protection
Northeast Regional Office
Ms. Sharon Shea Ms. Lynn Nadeau 205B Lowell Street
23 Briggs Street 10 Surf Street Wimington,MA 01887
Salem, MA 01970 Marblehead,MA 01945
Meredith Simas
Ms. Julie Whitlow Ms.Rebecca Kenneally Dominion Electric Environmental
5 Columbus Sq. #3 18 English Street Services-New England
Salem, MA 01970 Salem, MA 01970 Brayton Point Station
Brayton Point Road
Ms. Caroline Nye Ms. Anita Poss Somerset, MA 0272
5 Shore Avenue 10 Harvard Street
Salem,MA 01970 Marblehead,MA 01945 Lou Arak
Dominion Electric Environmental
Ms Rebekah Lashman Mr.Douglas H. Haley Services-New England
128 Bay View Avenue 43 Turner Street 24 Fort Avenue
Salem, MA 01970 Salem,MA 01970 Salem, MA 01970
Mr.David Heisler Ms. Jennifer S. Soud Anthonv Wheelock
7 Essex Street 55 Riverdale Road Dominion Energy New England
Salem, MA 01970 Bradford,MA 01835 24 Fort Avenue
Salem, MA 01970
Ms. Dolores Jordan Jeanne Oliphant
97 Derby Street 229 Green St Elissa J. Brown,CPG, CHMM, LSP
Salem, MA 01970 Marblehead,MA 01945 Earth Tech,Inc.
300 Baker Avenue, Suite 290
Ms. Elizabeth P Coughlan Linda Haley Concord,MA 01742
7 Essex Street 43 Turner St
Salem,MA 01970 Salem,MA 01970 Anthony J. Wespiser, P.E.
Earth Tech, Inc.
Ms Shelley Alpern Nancy Zachor 300 Baker Avenue, Suite 290
48 Essex, #2 58 Derby St. Concord, MA 01742
Salem, MA 01970 Salem, MA 01970
Mr. Lee Mondale Pat Gozemba
9 Guernsey Street 17 Sutton St
Marblehead, MA 01945 Salem,MA 01970
Ms. Lori Ehrlich Lisa Evans
46 Gerald Road 21 Ocean Ave
Marblehead, MA 01945 Marblehead,MA 01945
NOTICE OF PUBLIC INVOLVEMENT PLAN MEETING
FORMER UNLINED WASTEWATER TREATMENT BASINS
24 FORT AVENUE, SALEM, MASSACHUSETTS
RELEASE TRACKING NUMBER 3-21283
A release of oil and/or hazardous materials has occurred at this location, which is
a disposal site as defined by M.G.L. c. 21 E, § 2 and the Massachusetts
Contingency Plan, 310 CMR 40.0000. On March 3, 2003, Dominion Energy
Salem Harbor, LLC received a petition from residents in Salem and surrounding
communities requesting that this disposal site be designated a Public
Involvement Plan site, in accordance with M.G.L. c. 21E § 14(a) and 310 CMR
40.1404. As a result, a public meeting will be held at Hawthorne Hotel, 18
Washington Square West, Salem, Massachusetts, 01970 on Thursday, October
25, 2007 at 6:00 PM to present the draft Response Action Outcome Statement,
to solicit public comment on the draft Response Action Outcome Statement, and
to provide information about disposal site conditions. Copies of the draft
Response Action Outcome Statement will be made available at the meeting.
Any questions regarding this meeting or the draft Response Action Outcome
Statement should be directed to Meredith Simas, Environmental Specialist,
Dominion, 1 Brayton Point Road, Somerset, MA 02725, at phone 508-646-5338
(Email: meredith.simas@dom.com).
The disposal site file can be reviewed at the Massachusetts Department of
Environmental Protection, Northeast Region Office, 2058 Lowell Street,
Wilmington, Massachusetts 01887, Main Phone: 978-694-3200.
f
Ear `II ech 300 Baker Avenue P978371.4000
Suite 290 F 978.371.2468
A tgCO International Ltd Company Concord, MA 01742 mw.earthtech.com
- - _-RECEIVED
October 30, 2007
'oCT 3 12007
Notification Mailing List(attached) CITY OF SALEM
BOARD OF HEALTH
Subject: Notification of Availability—
Draft FIR,RAO & AIJL_.._----
r Unimea Yreatinent Basin Site,Salent Harbor Statio
Salem,lviassacnusects
RTN 3-21283
Dear Recipient:
This letter is written on behalf of Dominion Energy Salem Harbor, LLC pursuant to the provisions of the
June 2003 Public Involvement Plan to notify interested parties that the Draft Phase IV Final Inspection
Report (FIR), Draft Response Action Outcome Statement (RAO), and Draft Activity and Use Limitation
(AUL) are available for viewing at the public repositories(listed below).
Salem Public Library Salem Planning Department
370 Essex Street 120 Washington Street
Salem,MA 01970 Salem,MA 01970
Beverly Public Library HealthLink
32 Essex Street 4 Sewall Street
Beverly, MA 01915 Marblehead, MA 01945
Marblehead Public Library Conservation Law Foundation
235 Pleasant Street c/o Ms. Anita Poss
Marblehead,MA 01945 10 Harvard Street
Marblehead,MA 01945
Swampscott Public Library
61 Burrill Street
Swampscott, MA 01907
If you have any questions,please feel free to call Meredith Sums, Environmental Specialist, at Dununiun.
at 508-646-5338.
Sincerely,
Eart Tech!
Anthony . Wespiser, P.E.
Project Manager
Attachment: Notification Mailing List
f �
:a
Notification Mailing List
(f=inal Public Involvement Plan(I'll?), June 2003)
Unlined Treatment Basin Site, Salem Harbor Station
Salmi,Massachusetts
RTN 3-21283
Ms.Karen Kahn Mr. Keith E. Glidden Mayo) of Salem
17 Sutton Avenue 21 Turner Street,#2 Salem City Hall
Salem,MA 01970 Salem, MA 01970 93 Washington Street
Salem,MA 01970
Ms. Lisa Brooke Ms. Cindy Keegan
136 Bay View Avenue 12 Williams Street Health Agent
Salem,MA 01970 Beverly, MA 01915 Salem Board of Health
120 Washington Street, 4th Fir
Ms. Patricia J. Ould Ms. Maggie Haley Salem,MA 01970
5 Intervale Road 21 Turner Street,#2
Salmi,MA 01970 Salcm,MA 01970 Dept, of Environ.Protection
Northeast Regional Office
Ms. Sharon Shea Ms.Lynn Nadeau 205B Lowell Street
23 Briggs Street 10 Surf Street Wimington,MA 01887
Salem,MA 01970 Marblehead,MA 01945
Meredith Simas
Ms.Julie Whitlow Ms. Rebecca Kenneally Dominion Electi is Environmenial
5 Columbus Sq. #3 18 English Sheet Services-New England
Salem,MA 01970 Salem,MA 01970 Brayton Point Station
Brayton Point Road
Ms Caroline Nye Ms. Anita Poss 5ometset, MA 0272
5 Shore Avenue 10 Harvard Street
Salem,MA 01970 'Marblehead,MA 01945 Lou Atak
Dominion Electric Environmental
Nis.Rebekah Lashman 'Ir. Douglas IL Haley Services- New England
128 Bay View Avenue 43 Turner Sheet 24 Fort Avenue
Salem,MA 01970 Salcm MA 01970 Salem,MA 01970
Mr. David Heisler Ms. Jennifer S. Send Anthony Wheelock
7 Essex Street 55 Riverdale Road Dominion Energy New England
Salem,MA 01970 Bradford,MA 01835 24 Fort Avcnue
Salem,MA 01970
Ms.Dolores Jordan Jeanne Oliphant
97 Derby Sheet 229 Green St Elissa J.Brown,CPG,CHMM, LSP
Salem,MA 01970 Marblehead,MA 01945 Earth Tech,Inc.
300 Baker Avenue, Suite 290
Ms. Elizabeth 11.Coughlan Linda Haley Concord,MA 01742
7 Essex Street 43 Turner St
Salem,MA 01970 Salem,MA 01970 Anthony J. Wespiser,P.E.
Earth Tech, Inc.
Ms. Shelley Alpern Nancy Zachor 300 Baker Avenue,Suite 290
48 Essex, 42 58 Derby St Concord, MA 01742
Salem,MA 01970 Salem,MA 01970
Mr. Lee Mondale Pat Gozemba
9 Guernsey Sweet 17 Sutton St
Marblehead.MA 01945 Salem, MA 0t970
Ms. Lori Ehrlich Lisa Evans
46 Gerald Road 21 Ocean Ave
Marblehead,MA 01945 Marblehead,MA 01945
UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
Ja�SED STgT�s REGION I
ONE CONGRESS STREET SUITE 1100
Q BOSTON, MASSACHUSETTS 02114-2023
FNlq( PROtEG� `
y
October 29, 2007
Re: NPD it No 4Q26
or Northeast Gateway Energy Bridge Deepwater Port
Dear Interested Party:
The above referenced final National Pollutant Discharge Elimination System (NPDES) permit
has been issued pursuant to the Clean Water Act(the "Federal Act'), as amended. The
Environmental Permit Regulations, at 40 C.F.R. §124.15, 48 Fed. Reg. 14271 (April 1, 1983),
require this permit to become effective on the date specified in the permit. The permit has
been posted on the EPA Region 1 website and can be viewed at
httD://www.eDa.eov/reeionl/nodes/permits listine ma.html .
Posted at the same website is the EPA's response to the comments received on the draft
permit. Part II General Conditions and information relative to appeals and stays of NPDES
permits can be found at httD://www.eDa.2ov/reeionl/nDdes/et)a attach.html .
Should you have any questions concerning the permit, feel free to contact Ellen Weitzler at
617-918-1582.
inc rel
Y�
David Webster, Chief RECEIVED
ED
Industrial Permits Unit Zdp�
Office of Ecosystem Protection OCT 31
CITY OF SALEM
BOARD OF HEALTH
I�
Airport Professional Park
2300 Post Road
Warwick Rhode Island 02866
Telephone: 401-7363440
Fax: 401-736-3423
EA Engineering, Science,and Technology, Inc. (\- www.eaest.com
30 October 2007
Ms.Christina Harrington,Chairperson
Town of Salem Board of Health
120 Washington Street—4"Floor
Salem MA 01970
RE: Notice of RAO Submittal_and Availability of Report
Li (j Light Station-Bakers Islam
Salem,Massachusetts
MADEP RTN 3-26363; EA Project No. 61710.25
Ms.Harrington:
EA Engineering,Science,and Technology,hic. (EA)has prepared a Class B-1 Response Action Outcome
(RAO) Submittal on behalf of the United States Coast Guard(USCG)for the referenced site. The RAO
Submittal was submitted to the Massachusetts Department of Environmental Protection's(MADEP's)
Bureau of Waste Site Cleanup in Wilmington,MA on 30 October 2007.
A copy of the RAO Submittal can be reviewed at the MADEP Offices in Wilmington,MA by calling
(978) 694-3320. A copy of the submittal can also be requested by contacting Peter Grivers of EA at(401)
736-3440,Ext. 216,or Ms.Rachel Marino of the USCG at(401)736-1736.
Sincerely,
EA ENGINEERING, SCIENCE,AND
TECHNOLOGY,INC.
loMMIZ)
Peter M. Grivers,P.E.,LSP
Project Manager
cc: MADEP—BWSC—Northeast Region
R.Marino,USCG-CEU
St RECEIVED
Stambler,USCG-CEU
EA Project File 61710.25
NOV 01200y
CITY OF SALEM
BOARD OF HEALTH
EarthTeeh 300 Baker Avenue r 978371.4000
Suite 290 F 978.371.2468
A tgCO International Ltd Company Concord, MA 01742 www.earthtech.com
November 20, 2007 NOV 2 72007
Joanne Scott, Agent G/ L.H HEALTH
Salem Board of Health
120 Washington Street (4th floor)
Salem, Massachusetts 01970
Subject: Chief Municipal Officer Notice under the Massachusetts Contingency Plan
FIR,RAO & AUL
Former Unlined Treatment Basins
Salem Harbor5tat4on__ .
24 Fort Avenue
Salem, assac msetts
MADEP Release Tracking Number: 3-21283
Dear Ms Scott:
The purpose of this letter is to notify you, pursuant to the Massachusetts Contingency Plan (MCT 310
CMR 40.0000), that-Dominion Energy Salem Harbor, LLC has prepared a Phase IV Final Inspection
Report (PIR), a Response•Action;Outcome Statement (RAO), and an Activity and Use Lmrtahon (AUL)
for the above referenced site. ;The FIR, RAO, and AUL are available for review at the Massachusetts
Department of Environmental Protection's Northeast Regional Office in Wilmington.
Should have any questions regarding this notice, please contact Meredith Simas at 508-646-5338 of
myself at 978-371-4383.
Sincerely,
Earth Tech, Inc.
*AnhonyInager
spiser, P.E.
Project '
cc: The Honorable Kimberley,Driscoll .
• •Meredith Simas;Dominion,.,:;,
,.DEP,BWSC,NER6,. ;F:
;.., . C,
F
EarthTech
300 Baker Avenue v 978.371.4000
Suite 290 r 978.371.2468
A tgG17 International Ltd Company Concord, MA 01742 www earthtech.com
November 28, 2007
Notification Mailing List(attached)
Subject: Notification of Availability—
FIR& RAO (Final Versions) --
Unlined Treatment Basin Sit Salem Harbor S ateon
Salem, Massachusetts
RTN 3-21283
Dear Recipient:
This letter is written on behalf of Dominion Energy Salem Harbor, LLC pursuant to the provisions of the
June 2003 Public Involvement Plan to notify interested parties that the final versions of the Phase IV
Final Inspection Report (FIR) and Response Action Outcome Statement (RAO) are available for viewing
at the public repositories (listed below).
Salem Public Library Salem Planning Department
370 Essex Street 120 Washington Street
Salem, MA 01970 Salem, MA 01970
Beverly Public Library HealthLmlc
32 Essex Street Ground floor of Church of the Holy Name
Beverly, MA 01915 60 Monument Ave
Swampscott, MA 01907
Marblehead Public Library
235 Pleasant Street Conservation Law Foundation
Marblehead, MA 01945 c/o Ms. Anita Poss
10 Harvard Street
Swampscott Public Library Marblehead, MA 01945
61 Burrill Street
Swampscott, MA 01907
If you have any questions, please feel free to call Meredith Simas, Environmental Specialist, at Dominion,
at 508-646-5338.
Sincerely,
,arth Tech, I
Anthon J. Wespiser, P.E.
Project Manager
Attachment: Notification Mailing List
Notification Mailing List
(Final Public Involvement Plan (PIP), June 2003)
Unlined Treatment Basin Site, Salem Harbor Station
Salem, Massachusetts
RTN 3-21283
Ms.Karen Kahn Mr. Keith E Glidden Mayor of Salem
17 Sutton Avenue 21 Turner Street, 42 Salem City Hall
Salem,MA 01970 Salem, MA 01970 93 Washington Street
Salem, MA 01970
Ms. Lisa Brooke Ms Cindy Keegan
136 Bay View Avenue 12 Williams Street Health Agent
Salem,MA 01970 Beverly, MA 01915 Salem Board of Health
120 Washington Street,4th Fir
Ms. Patricia J. Ould Ms.Maggie Haley Salem, MA 01970
5 Intervale Road 21 Turner Street.#2
Salem,MA 01970 Salem,MA 01970 Dept. of Envnon Protection
Northeast Regional Office
Ms. Sharon Shea Ms. Lynn Nadeau 205B Lowell Street
23 Briggs Street 10 Surf Street Wennington, MA 01887
Salem,MA 01970 Marblehead,NIA 01945
Meredith Simas
Ms Julie Whitlow Ms.Rebecca Kenneally Dominion Electric Environmental
5 Columbus Sq. #3 18 English Street Services-New England
Salem, MA 01970 Salem,MA 01970 Brayton Point Station
Brayton Point Road
Ms Caroline Nye Ms.Anita Poss Somerset,MA 02725
5 Shore Avenue 10 Harvard Street
Salem, MA 01970 Marblehead, MA 01945 Anthony Wheelock
Dominion Energy New England
Ms. Rebekah Lashman Mi.Douglas H Haley 24 Toil Avenue
128 Bay View Avenue 43 Turner Street Salem, MA 01970
Salem, MA 01970 Salem,MA 01970
Elissa J Brown, CPG, CHMM, LSP
Mr. David Heisler Ms. Jennifer S. Soud Earth Tech, Inc
7 Essex Street 55 Riverdale Road 300 Baker Avenue, Suite 290
Salem, MA 01970 Bradford, MA 01835 Concord, MA 01742
Ms. Dolores Jordan Jeanne Oliphant Anthony J Wespisei, P E.
97 Derby Street 229 Green St Earth Tech, Inc.
Salem, MA 01970 Marblehead,MA 01945 300 Baker Avenue. Suite 290
Concord,MA 01742
Ms Elizabeth P. Coughlan Linda Haley
7 Essex Street 43 Turner St
Salem, MA 01970 Salem,MA 01970
Ms. Shelley Alpern Nancy Zachor
48 Essex,#2 58 Derby St
Salem,MA 01970 Salem,MA 01970
Mr. Lee Mondale Pat Gozemba
9 Guernsey Street 17 Sutton St
Marblehead,MA 01945 Salem,MA 01970
Ms. Lon Ehrlich Lisa Evans
46 Gerald Road 21 Ocean Ave
Marblehead, MA 01945 Marblehead,MA 01945
e `
LETTER OF TRANSMITTAL
DATE: I November 15, 2004
TO: PIP Mailing List(attached) 1
cc: Chief Municipal Officer,Town of Salem
Board of Health, Town of Salem
USGen New England, Inc.
SUBJECT.t1 Salem Harbor Station':
—06—gal Notice Public Meeting to Present MCP Phase II and Phase III Documents
FROM: I Anthony J. Wespiser
X For Your Information For Your Review 1
For Your Use For Your Comment
Per Your Request
Enclosed please find one copy of the Legal Notice for the Public Meeting being held by USGen NE to
present the Phase II Comprehensive Site Assessment Report and Phase III Remedial Action Plan for the
Former Unlined Wastewater Treatment Basin Site at Salem Harbor Station.
The Legal Notice is scheduled to be published in the Salem Evening News on Monday, November 15, 2004,
and the Beverly Citizen on Thursday, November 18, 2004.
If you have any questions, please feel free to call Ray Kenison of USGen New England, Inc., at
(978) 740-8402.
Anthon},J h
Wser, P.E.
E A R T H `J T E C H
b �( ,• R j/ A tyCO ,,„
INTERNATIONAL
LTD COMPANY
196 Baker Avenue
NOV 16 O Concord, MA 01742
2004 (978)-3714000
CITY OFFAX: (978)-371-2468
BOARD OF HEALTH
Mailing List
Final Public Involvement Plan(PIP), June 2003
Unlined Treatment Basin Site, Salem Harbor Station
Salem, Massachusetts
RTN 3-21283
Ms. Karen Kahn Ms. Lori Ehrlich Pat Gozemba
17 Sutton Avenue 46 Gerald Road 17 Sutton St
Salem,MA 01970 Marblehead, MA 01945 Salem,MA 01970
Ms. Lisa Brooke Mr.Keith E. Glidden Lisa Evans
136 Bay View Avenue 21 Turner Street,#2 21 Ocean Ave
Salem,MA 01970 Salem,MA 01970 Marblehead,MA 01945
Ms. Patricia J.Ould Ms.Cindy Keegan Mayor of Salem
5 Intervale Road 12 Williams Street Salem City Hall
Salem,MA 01970 Beverly,MA 01915 93 Washington Street
Salem,MA 01970
Ms. Sharon Shea Ms. Maggie Haley
23 Briggs Street 21 Turner Street,#2 Health Agent
Salem, MA 01970 Salem,MA 01970 Salem Board of Health
120 Washington Street,4th Flr
Ms.Julie Whitlow Ms. Lynn Nadeau Salem, MAO 1970
5 Columbus Sq. #3 10 Surf Street
Salem, MA 01970 Marblehead, MA 01945 Dept. of Environ. Protection
One Winter Street,9th Floor
Ms.Caroline Nye Ms. Rebecca Kenneally Boston, MA 02108
5 Shore Avenue 18 English Street
Salem, MA 01970 Salem,MA 01970 A. Rayner Kenison
National Energy&Gas Transmission
Ms. Rebekah Lashman Ms.Anita Pass 24 Fort Avenue
128 Bay View Avenue 10 Harvard Street Salem,MA 01970
Salem, MA 01970 Marblehead, MA 01945
Lou Arak
Ms. Linda Hally Mr. Douglas H. Haley National Energy&Gas Transmission
43 Turner Street 43 Turner Street 24 Fort Avenue
Salem,MA 01970 Salem,MA 01970 Salem,MA 01970
Mr. David Heisler Ms.Jennifer S. Soud Susan Flash
7 Essex Street 55 Riverdale Road National Energy&Gas Transmission
Salem,MA 01970 Bradford,MA 01835 200 Foxboro Blvd., Suite 100
Foxboro,MA 02035
Ms. Dolores Jordan Dave Payne
97 Derby Street 100 Ocean Ave. Seth Jaffe
Salem,MA 01970 Marblehead, MA. 01945 Foley Hoag LLP
155 Seaport Boulevard
Ms. Elizabeth P. Coughlan Jeanne Oliphant Boston, MA 02210-2600
7 Essex Street 229 Green St
Salem,MA 01970 Marblehead, MAO 1945 Joseph P. Vitale, P.E., LSP
Earth Tech, Inc.
Ms. Shelley Alpern Linda Haley 196 Baker Avenue
48 Essex,#2 43 Turner St Concord, MA 01742
Salem,MA 01970 Salem,MA 01970
Anthony J. Wespiser,P.E.
Mr. Lee Mondale Nancy Zachor Earth Tech, Inc.
9 Guernsey Street 58 Derby St. 196 Baker Avenue
Marblehead, MA 01945 Salem,MA 01970 Concord,MA 01742
NOTICE OF PUBLIC MEETING
USGen New England, Inc., Salem Harbor Station
24 Fort Avenue, Salem, Massachusetts
Massachusetts Contingency Plan(MCP)
PHASE II COMPREHENSIVE SITE ASSEMENT REPORT and
PHASE III REMEDIAL ACTION PLAN
(Site of Former Unlined Waste Water Treatment Basins)
Pursuant to the provisions of the June 2003 Final Public Involvement Plan for
the Former Unlined Wastewater Treatment Basins at Salem Harbor Station,
USGen New England, Inc., (USGen NE) will hold a public meeting to present the
Phase II Comprehensive Site Assessment Report and Phase III Remedial Action
Plan filed with the Massachusetts Department of Environmental Protection on
November 5, 2004.
The public meeting will be held at 7:00 PM on Monday, November 29, 2004.
at Hawthorne Hotel, l8 Washington Square West, Salem, Massachusetts, 01970.
A 20-day public comment period will immediately follow the public meeting (i.e.,
commence on November 29, 2004).
To obtain more information on the meeting, please contact Ray Kenison,
Environmental Engineer, National Energy & Gas Transmission, Inc, Salem
Harbor Station, 24 Fort Avenue. Salem, Massachusetts 01970 at 978-740-8402
(Email: ray.kenison@negt.com).
r
i
196 Baker Avenue, Concord, Massachusetts 01742
November 19,2004 . Q,�vt I' �i.t✓� �.
Notification Mailing List(attached)
DB cipy Gi- s A
Subject: Notification of Availability— ARD OF LEIVI
e 1T CSA Report&Phase III Remedial Action Plan HEAL Ty
Unlined Treatment Basin Site,Salem Har or Station
Salem,Massa u
RTN 3-21283
Dear Recipient:
This letter is written on behalf of USGen New England,Inc. pursuant to the provisions of the
June 2003 Public Involvement Plan to notify interested parties that the Phase II Telephone
Comprehensive Site Assessment Report and Phase III Remedial Action Plan are available for
viewing at the public repositories(listed below). 9 7 8 3 7= 4 000
Salem Public Library Swampscott Public Library Facsimile
370 Essex Street 61 Burrill Street
Salem,MA 01970 Swampscott,MA 01907 9 7 8 3 7=.2 4 6 8
Beverly Public Library Salem Planning Department
32 Essex Street 120 Washington Street
Beverly,MA 01915 Salem,MA 01970
Marblehead Public Library HealthLink
235 Pleasant Street 4 Sewall Street
Marblehead,MA 01945 Marblehead,MA 01945
If you have any questions,please feel free to call Ray Kenison,Environmental Engineer,at
(978)740-8402.
Sincerely,
AT
ech,lanager. Wespiser,P.E.
Project
Attachment: Notification Mailing List
E A R T H S T E C H
Infrastructure Tyco Infrastrutuvre S/ervices Company
d
Notification Mailing List
(Final Public Involvement Plan(PIP),June 2003)
Unlined Treatment Basin Site, Salem Harbor Station
Salem,Massachusetts
RTN 3-21283
Ms.Karen Icahn Mr.Keith E. Glidden Mayor of Salem
17 Sutton Avenue 21 Turner Street,#2 Salem City Hall
Salem,MA 01970 Salem,MA 01970 93 Washington Street
Salem,MA 01970
Ms.Lisa Brooke Ms. Cindy Keegan
136 Bay View Avenue 12 Williams Street Health Agent
Salem,MA 01970 Beverly,MA 01915 Salem Board of Health
120 Washington Street,4th Flr
Ms.Patricia J. Ould Ms.Maggie Haley Salem,MA 01970
5 Intervale Road 21 Turner Street,#2
Salem,MA 01970 Salem,MA 01970 Dept. of Environ.Protection
MOne Winter Street,9th Floor
Ms. Sharon Shea
Ms.Lynn Nadeau Boston,MA 02108
23 Briggs Street 10 Surf Street
Salem,MA 01970 Marblehead,MA 01945 A.Rayner Kenison
National Energy&Gas Transmission
Ms.Julie Whitlow Ms.Rebecca Kenneally 24 Fort Avenue
5 Columbus Sq.#3 18 English Street Salem,MA 01970
Salem,MA 01970 Salem,MA 01970
Lou Arak
Ms.Caroline Nye Ms.Anita Pass National Energy&Gas Transmission
5 Shore Avenue 10 Harvard Street 24 Fort Avenue
Salem,MA 01970 Marblehead,MA 01945 Salem,MA 01970
Ms.Rebekah Lashman Mr.Douglas H.Haley Susan Flash
128 Ba View Avenue
Y 43 Turner Street National Energy&Gas Transmission
Salem,MA 01970 Salem,MA 01970 200 Foxboro Blvd., Suite 100
Foxboro,MA 02035
Mr.David Heisler Ms.Jennifer S. Saud
7 Essex Street 55 Riverdale Road Seth Jaffe
Salem,MA 01970 Bradford,MA 01835 Foley Hoag LLP
155 Seaport Boulevard
Ms.Dolores Jordan
Jeanne Oliphant Boston,MA 02210-2600
97 Derby Street 229 Green St
Salem,MA 01970 Marblehead,MA 01945 Joseph P.Vitale,P.E.,LSP
Earth Tech,Inc.
Ms.Elizabeth P.Coughlan Linda Haley 196 Baker Avenue
7 Essex Street 43 Turner St Concord,MA 01742
Salem,MA 01970 Salem,MA 01970
Anthony J.Wespiser,P.E.
Ms. Shelley Alpem Nancy Zachor Earth Tech,Inc.
48 Essex,#2 58 Derby St. 196 Baker Avenue
Salem,MA 01970 Salem,MA 01970 Concord,MA 01742
Mr.Lee Mondale Pat Gozemba
9 Guernsey Street 17 Sutton St
Marblehead,MA 01945 Salem,MA 01970
Ms.Lori Ehrlich Lisa Evans
46 Gerald Road 21 Ocean Ave
Marblehead,MA 01945 Marblehead,MA 01945
RANSOM
Environmental o
1 n
Consu to ts,Inc. MAY 21 2004
May 20, 2004 CITY OF SALEM Project 031177
BOARD OF HEALTH
Ms. Joanne Scott
Agent, Salem Board of Health
93 Washington Street
Salem,Massachusetts 01970
RE: Immediate Response Action (IRA)Completion Report and
Response Action Outcome(RAO) Statement
Unidentified Oil Release
OutfalLPip East of Congress Street
alem Harbor
Sa em, assachusetts
MA DEP Release Tracking No. 3-23136
Dear Ms. Scott:
In accordance with the Massachusetts Contingency Plan(MCP)and on behalf of the Massachusetts
Electric Company(MECo), Ransom Environmental Consultants, Inc. (Ransom)has prepared this letter
regarding the implementation of an Immediate Response Action(IRA) at the above-referenced site. The
MCP requires that the local chief municipal officer and board of health be notified of the completion of a
Response Action Outcome(RAO) Statement for the Site.
On August 30, 2003, the Massachusetts Department of Environmental Protection(MA DEP)informed
MECo of the discovery of a release of an unidentified oil into Salem Harbor from a concrete outfall pipe
located within the intertidal zone of a granite seawall located east of Congress Street. The concrete outfall
pipe from which oily water was observed to discharge is located approximately 500 feet to the south-
southeast of the Derby Street and Hawthorne Boulevard intersection. The release to Salem Harbor was
subsequently assigned Release Tracking Number(RTN) 3-23136 by the MA DEP. The MA DEP
dee-mined that MECO was a Potentially Responsible Party(PPP)for this release, indicating MA DEP's
preliminary determination that the oil release to Salem Harbor was associated With the release of mineral
oil dielectric fluid(MODF) from an underground, oil-filled cable located beneath the Derby Street and
Hawthorne Boulevard(RTN 3-23029)intersection.
While not acknowledging responsibility for the release of oil into Salem Harbor,MECo performed IRA
and assessment activities. IRA activities took place between August 30 and November 11, 2003. While
the source of the unidentified oil release into Salem Harbor cannot be categorically attributed to any one
source,based on the results of petroleum hydrocarbon fingerprinting of the oil samples collected from the
harbor, the Derby Street and Hawthorne Boulevard intersection excavation, and the released MODF,it is
Ransom's opinion that the oil discharged to the Salem Harbor was not MODF. .
■ Brown's Wharf,Newburyport,Massachusetts 01950,Tel(978)465.1822,Fax(978)465-2986
200 High Street. Portland,Maine 04101,Tel(207( 772-2891
195 Commerce Way,Suite D, Portsmouth,New Hampshire 03801,Tel(603)436-1490
2127 Hamilton Avenue,Hamilton,New Jersey 08619,Tel (609) 584-0090
1445 Wampanoag Trail,Suite I08A,East Providence,Rhode Island 02915,Tel (401)433-2160
www.ransomenv.com
,l
Ms. Joanne Scott
Salem Board of Health
Based on the cleanup activities and Ransom's observations, the release of unidentified oil from the outfall
pipe was adequately addressed through the placement of oil-absorbent booms and pads in the vicinity of
the outfall pipe and, since it was first observed in August 2003, evidence of subsequent releases of oil from
the outfall pipe have not been observed. Therefore,based on the information presented in this letter, it is
Ransom's opinion that background conditions have been achieved with respect to this release. Based on
the information presented in this report,the requirements of a Class A-1 RAO have been met.
A copy of the RAO Statement is available for public view at the MA DEP Northeast Regional Office
located at 35 Congress Street in Salem,Massachusetts. MA DEP files are open for public view by
appointment only,Monday through Friday, 9:00 a.m. to noon. You may contact the MA DEP Northeast
Regional Office at(978) 740-0809 for more information on reviewing MA DEP files.
Please contact me at(978)465-1822 if you have any questions regarding the IRA activities or RAO
Statement.
Sincerely,
RANSOM ENVIRONMENTAL CONSULTANTS, INC.
Ti thy J. Sn ���
icensed Site Professional/
HED/TJS:sh
cc: Massachusetts Department of Environmental Protection,Northeast Regional Office
Joe Callanan,MECo
Ransom Project 031177 Page 2
P:\2003\031177\Harbor Release\bohnot.doc May 20, 2004
rohraLc
Environmental Services a.,: > }
December 29, 2003 n� v 3 9nPi3
Honorable Stanley Usovicz - ^r a
Mayor, City of Salem X11 ,, = LSM
93 Washington Street BOA'D C" �EA�j�
Salem, Massachusetts 01970
Ms. Joanne Scott
Health Agent, City of Salem
9 North Street
Salem, Massachusetts 01970
Re: Availability of Immediate Response Action Plan
Amerada Hess Station #21303
38 Enon Street
Beverly, Massachusetts 01915
MADEP Release Tracking Number 3-23334
Mr. Mayor and Ms. Scott
In accordance with the Massachusetts Contingency Plan (MCP) 310 CMR 40.1403(3), notification
is hereby made that an Immediate Response Action Plan has been completed for the above-
referenced location (the site). Notification is being provided to the city of Salem due to the subject
site being located within 350 feet of Wenham Lake, a public water supply for Beverly and Salem.
The IRA Plan was prepared as a result of the detection of elevated levels of petroleum vapors in
indoor air to an adjacent building. Proposed response actions include the operation of a soil vapor
extraction system, indoor air and soil gas monitoring, extraction of perched groundwater from the
underground storage tank (UST) field and the operation of an air sparge system under applicable
MCP guidelines and regulations.
Copies of the Immediate Response Action Plan can be reviewed or obtained at the Massachusetts
Department of Environmental Protection's Northeast Regional Office, located at One Winter
Street, Boston, Massachusetts. If you have any questions or would like additional information
about the site, you may contact the undersigned at (781)769-5005.
Sincerely,
EnviroTrac Ltd.
Donald M ggioli, P.E., LSP.
Vice President—New England
cc: MADEP Northeast Regional Office
Donald Bull, Amerada Hess Corporation
1400 Providence Highway, Suite 2100, Norwood, MA 02062 (781) 769-5005 Fax: (781) 769-9345