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\ UNITED STATES ENVIRONMENTAL PROTECTION AGENCY
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BOSTON, MA 02109-3912
FACT SHEET
Outer Continental Shelf Preconstruction Air Permit
Revolution Wind Farm Project
Revolution Wind, LLC
Offshore Renewable Wind Energy Development
Renewable Energy Lease Area OCS-A 0486
EPA Draft Permit Number: OCS-R1-05
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Acronyms and Abbreviation List
APPS
Air to Prevent Pollution from Ships
PM10
Particulate Matter with an
Aerodynamic Diameter <= 10 Microns
BACT
Best Available Control Technology
PM2.5
Particulate Matter with an
BOEM
Bureau of Ocean Energy Management
Aerodynamic Diameter <=2.5 Microns
CAA
Clean Air Act
PSD
Prevention of Significant Deterioration
CA SIP
California State Implementation Plan
PTE
Potential to Emit
CERC
Continuous Emission Reduction Credit
RW
Revolution Wind LLC
C.F.R
Code of Federal Regulations
SER
Significant Emission Rate
CH4
Methane
SFW
South Fork Wind LLC
CO
Carbon Monoxide
SIL
Significant Impact Levels
COA
Corresponding Onshore Area
SO2
Sulfur Dioxide
CO2
Carbon Dioxide
TPY
Tons Per Year
C02e
Carbon dioxide equivalent
u.s.c.
United States Code
CZMA
Coastal Zone Management Act
voc
Volatile Organic Compounds
DEIS
Draft Environmental Impact Statement
WDA
Wind Development Area
WTG
Wind Turbine Generator
DERC
Discrete Emission Reduction Credit
EAB
Environmental Appeals Board
EGRID
Environmental Protection Agency's
Emissions and Generation Resource
Integrated Database
EPA
United States Environmental Protection
Agency
EJ
Environmental Justice
ERC
Emission Reduction Credit
ESA
Endangered Species Act
EUG
Emission Unit Group
FWS
U.S. Fish and Wildlife Service
g/kW-hr
Grams per kilowatt-hour
H2SO4
Sulfuric acid
HAP
Hazardous Air Pollutant
ISO NE
ISO New England
KV
Kilovolt
KW
Kilowatt
LAER
Lowest Achievable Emission Rate
MassDEP
Massachusetts Department of
Environmental Protection
MW
Megawatt
NHPA
National Historical Preservation Act
NMFS
National Marine Fisheries Service
NMHC
Non-methane hydrocarbons
NNSR
Nonattainment New Source Review
NSR
New Source Review
N2O
Nitrous oxide
NO2
Nitrogen dioxide
NOx
Nitrogen oxides
OCS
Outer Continental Shelf
OECLA
Offshore Export Cable Laying
Activities
OSS
Offshore Substation
Pb
Lead
PM
Particulate Matter
2
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Table of Contents
I. General Information 8
II. Project Description 9
A. Project Location 9
B. Offshore Construction Activities 10
C. Offshore Operation & Maintenance Activities 11
D. Stationary Source Combined Emission Total(s) 12
III. Applicability of 40 C.F.R. Part 55 - OCS Air Regulations 12
A. OCS Statutory and Regulatory Authority 12
B. Procedural Requirements for OCS Permitting 13
C. Scope of the "OCS Source" 16
D. Scope of the Stationary Source 17
IV. Emission Units Subject to Part 55 22
A. Wind Turbine Generators and Offshore Substation(s) 24
B. Vessels 25
1. Jack-up vessels or jack-up barges 28
2. Cable-laying vessels 29
3. Support and other vessels 29
4. Crew transfer vessels 30
V. Prevention of Significant Deterioration 31
A. Project Aggregation 32
B. Major Modification Applicability 32
1. Emission Increase Calculation (Project Emission Increase) 33
2. Emission Netting (Contemporaneous Netting) 35
3. Summary 35
C. Best Available Control Technology (BACT) 35
1. Methodology 36
2. BACT Analysis for the Revolution Wind Project 37
D. Ambient Air Impact Analysis 65
1. Construction Phase 66
2. Operational Phase 72
3. Consultation with Federal Land Managers 82
VI. Nonattainment New Source Review (NNSR) 83
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A. Major Modification Applicability 84
1. Emission Increase Calculation (Project Emission Increase) 84
2. Emission Netting (Contemporaneous Netting) 85
3. Summary 85
B. Lowest Achievable Emission Rate (LAER) 86
1. Methodology 86
2. LAER Analysis for the Revolution Wind Project 87
C. Offset Requirements 110
1. Compliance Demonstration 112
D. Alternative Site Analysis 113
E. Nonattainment NSR Compliance Certification 113
VII. Other COA Emission Control Requirements 114
A. 310 CMR 7.02: Plan Approval and Emission Limitations 115
1. SO: State BACT 116
B. 310 CMR 7.05: Fuels All Districts 116
C. 310 CMR 7.06: Visible Emissions 116
D. 310 CMR 7.11: Transportation Media 117
E. 310 CMR 7.12: Source Registration 117
F. 310 CMR 7.18: Volatile and Halogenated Organic Compounds 118
G. 310 CMR 7.72: SF6 118
VIII. Other Federal Requirements 119
A. New Source Performance Standards (NSPS) 119
B. National Emission Standards for Hazardous Air Pollutants 121
C. MARPOL Annex VI, the Act to Prevent Pollution from Ships, and 40 C.F.R. Part 1043 ... 122
IX. Monitoring, Reporting, Recordkeeping and Testing Requirements 123
X. Consultations 124
A. Endangered Species Act, Magnuson-Stevens Fishery Conservation and Management Act,
and National Historic Preservation Act 125
B. Coastal Zone Management Act (CZMA") 126
C. Clean Air Act General Conformity 126
XI. Environmental Justice 126
A. Air Quality Review 128
B. Environmental Impacts to Potentially Overburdened Communities 128
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C. Tribal Consultation 131
D. Public Participation 131
XII. Comment Period, Hearings and Procedures for Final Decisions 132
XIII. EPA Contacts 132
Figure 1 Location of Revolution Wind Offshore Wind Farm Project 9
Table 1 Estimated Construction OCS Emissions (tons per year (tpy)) for the Revolution Wind Project 10
Table 2 Estimated Operations and Maintenance Emissions (tpy) 11
Table 3 Combined Construction Emissions for Revolution Wind and South Fork Wind Projects (tpy) 12
Table 4 Combined O&M Emissions for Revolution Wind and South Fork Wind Projects (tpy) 12
Figure 2 Map of Massachusetts/Rhode Island OCS Lease Area 21
Table 5 Description of Vessels and Equipment for WTG and OSS Installation Activities included in the
Potential to Emit 26
Table 6 Emission Increase from the Revolution Wind Project 34
Table 7 Worst Case Annual Emission Estimate Compared with PSD Significant Emissions Rate (SER)
Thresholds 34
Table 8 Emission Unit Group (EUG) 1 - Offshore Generators on WTGs and OSS(s) 38
Table 9 EUG 2 - Marine Engines on Vessels Operating as Potential OCS Source(s) 39
Table 10 EUG 3 - Medium , and High Voltage GIS on the WTG, OSS, and/or ESP 41
Table 11 Options of Control Technologies or Techniques for EUG 1 43
Table 12 Options of Control Technologies or Techniques for EUG 2 44
Table 13 - Summary of Technical Feasible Options for EUG 2 BACT 49
Table 14 Annex VI NOx Emission Standards (g/kW-hr) 40 C.F.R. 1043.60 61
Table 16 NAAQS, PSD Increments, and Significant Impacts Level 66
Figure 3 Distances Between the Revolution Wind Area and Closest Class I Areas 68
Table 17 Assessment of Construction Period Ambient Air Impact for the Source 71
Table 18 Comparison of Construction Period Impacts to Class I PSD Increments 72
Table 19 Comparison of the OCS Source Operational Period Impacts Against Class II SILs 75
Table 20 NAAQs Assessment Results 77
Figure 4 PM2.5 SIA Comparison Analysis (24-hr) 79
Table 21 Class II PSD Increment Assessment Results 80
Table 22 Class I PSD Significance Assessment 80
Table 23 NNSR SER Thresholds under 310 CMR 7.00, Appendix A 83
Table 24 Emission Increase from the Revolution Wind Project (NNSR) 85
Table 25 Worst Case Annual Emission Estimate Compared with NNSR SER Thresholds 85
Table 26 EUG 1 - Offshore Generators on OSS(s) and WTG(s) 87
Table 27 EUG 2 - Marine Engines on Vessels Operating as Potential OCS Source(s) 88
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Table 28 Control Technologies or Techniques for OCS Offshore Generators on the OSS(s) and WTG(s) 91
Table 29 Control Technologies or Techniques for Marine Engines on Vessels when operating as OCS
Source(s) 92
Table 30 - Summary of Technical Feasible Options for EUG 2 LAER 96
Table 31 Annex VI NOx Emission Standards (g/kW-hr) 40 C.F.R. 1043.60 106
Table 33 Maximum NOx Offsets Needed for Operational Phase of Project (assuming a 1.26:1 offset ratio) 111
Table 34 Maximum VOC Offsets Needed for Operational Phase of Project (assuming a 1.26:1 offset ratio)lll
Figure 5 - Calculate the annual SF6 emissions using the mass-balance approach 119
Table 35 Table 2d to Subpart ZZZZ of Part 63 - Requirements for Existing Stationary RICE Located at
Area Sources of HAP Emissions 121
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I. General Information
Applicant's name and address:
Revolution Wind Farm Project
56 Exchange Terrace, Suite 300
Providence, Rhode Island 02903
Location of regulated activities:
Outer Continental Shelf (OCS) Lease Area OCS-A 0486 is
in federal waters, approximately 7.5 nautical miles (nm)
south of Nomans Land Island, Massachusetts. See Section
II. A for more information.
Draft OCS permit number:
EPA contact:
OCS-R1-05
Morgan M. McGrath, P.E.
On May 1, 2022, Revolution Wind, LLC (RW or the applicant) submitted to EPA Region 1
(EPA) an initial application requesting a Clean Air Act (CAA or the Act) permit under Section
328 of the CAA for the construction and operation of an offshore wind farm, including export
cables, on the OCS (the wind farm). Once operational, the project has an estimated maximum
production capacity between 704 and 880 megawatts (MW) of renewable energy. On August 12,
2022, RW submitted a revised application which EPA determined was complete on October 7,
2022, based on all submitted information from RW, including information provided by RW's
consultants. The EPA is proposing a draft permit that will contain the applicable requirements
under 40 C.F.R. Part 55. Since the decommissioning phase of the wind farm will occur well into
the future, the EPA is unable to determine best available control technology (BACT) and lowest
achievable emissions rate (LAER) for the decommissioning phase and will not be permitting this
phase at this time.
After reviewing the application and additional information, the EPA prepared this Fact Sheet and
draft OCS preconstruction air permit as required by 40 C.F.R. Part 55, and 40 C.F.R. Part 124 -
Procedures for Decision Making. All CAA permitting requirements applicable to the wind farm
are contained within EPA permit number OCS-R1-05.
The EPA's draft permit is based on the information and analysis provided by the applicant and
the EPA's own technical expertise. This Fact Sheet documents the information and analysis the
EPA used to support the OCS draft permit decisions. It includes a description of the proposed
wind farm, the applicable regulations, and an analysis demonstrating how the applicant will
comply with the requirements contained in the permit.
The EPA has made available to the public RW's application materials and any supplemental
information provided by RW as part of the official record for this Fact Sheet and the draft CAA
permit. The application and supplemental information for this permit is available online at the
EPA Region 1 Web Site: https://www.epa.gov/caa-permitting/caa-permitting-epas-new-england-
region.
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II. Project Description
A. Project Location
The Revolution Wind project includes up to 100 wind turbine generators (WTGs) with a capacity
of 8 to 12 MW per turbine, submarine cables between the WTGs (inter-array cables), and up to
two Offshore Substations (OSSs), all of which will be located wi thin federal waters on the OCS,
specifically in the Bureau of Ocean Energy Management (BOEM) Renewable Energy Lease
Area OCS-A 0486. The lease area itself is approximately 98 square rnn, 13 nm wide and 19 nm
long at its furthest points. The Wind Development Area (WDA) for the project will be located
approximately 7.5 nm southwest of Nomans Land Island, Massachusetts. An electric export
cable (alternating current) will make landfall at Quonset Point in North Kingstown, Rhode
Island, and connect the wind farm to the existing electric transmission system via the Davisville
Substation. See Figure 1.
Application
Figure 2-1
OCS Pai Til I Am
Leg^e- d
g2E-nrn OCS Perrrtt Area
RWF Lease Area
¦ rwec comaor
OSSs
WTGS
OSS Link
-IAC
Posntiai Ports
0 33 5
rt at*
I 1 li H lo
0">ted EVERS^URCE
Figure 1 Location of Revolution Wind Offshore Wind Farm Project
Construction of the project is scheduled to begin in 2023 with installation of the onshore
components and initiation of seabed preparation activities (e.g., clearing of debris and
obstructions). Offshore construction activities subject to the OCS air permit are anticipated to
begin in 2024 and to be commissioned and operational by the second quarter of 2025. RW's air
permit application and associated air dispersion modeling scenarios assume a worst-case
emission scenario of one year of construction, though construction could occur over two years.
RW will be responsible for the construction and the operation and maintenance (O&M) of the
windfarm.
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B. Offshore Construction Activities
Offshore construction of the wind farm involves the installation of the foundations to the sea
floor and preparation of the structures for the WTGs and the OSS(s). Work vessels then supply
all the WTG components and install them on the foundations. RW plans to install a monopile
foundation for each WTG. Monopile foundations will be driven to target embedment depths
using impact pile driving and/or vibratory pile driving.
According to RW's application, offshore construction for the wind farm is anticipated to be
completed in the following general sequence:1
1. Mobilization of vessels
2. Export cable and inter-array cable route clearance
3. Transportation of the foundations
4. Installation of the OSS foundation(s)
5. Installation of the WTG foundations
6. Installation of the WTGs
7. Installation of the export cable, inter-array cable, and oss-link cable
8. Topside OSS installation(s)
WTG commissioning will begin when the first WTG is installed offshore.2 For purposes of
EPA's CAA OCS permit, construction emissions from the wind farm are estimated to begin once
any equipment or any activity that by itself meets the definition of an OCS source is located
within the WDA. At that point, the EPA considers the facility to meet the definition of an OCS
source for the purposes of calculating potential emissions, and emissions from vessels servicing
or associated with any part of the facility are included in the OCS source's potential emissions
while traveling to and from any part of the OCS source when within 25 nautical miles of it.
The following table contains the project's potential emissions during the construction phase
(annualized), as contained in RW's revised emission estimates provided to the EPA on February
28, 2023. Note that the estimates during the construction period represent the annualized worst-
case potential to emit (PTE).
Table 1 Estimated Construct km OCS Emissions (tons per year (tpy)) for the Revolution Wind Project
NiO
COie
CO
NOx
PMio
PM2.5
SO2
Lead
VOC
13.5
302,957
1,039.3
3,978
137.1
133.1
15
0.02
83.6
(1) N20 emissions were not provided in the February 28 update. Calculations for N20 were completed based on
previous N20 to NOx ratio (.36%).
1 More detailed information on the construction process can be found in RW's OCS permit application, which is
accessible in the permit docket for this action.
2 The definition of 'commissioning' is not standardized, but generally covers all activities after all components of
the wind turbine are installed. Commissioning tests will usually involve standard electrical tests for the electrical
infrastructure as well as the turbine, and inspection of routine civil engineering quality records. See
https://www.wind-energv-the-facts.org/comniission.ing-operation-and-maintenance.html
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C. Offshore Operation & Maintenance Activities
The O&M phase of the wind farm will begin when commissioning of the WTGs is completed,
and the facility begins operating. The O&M phase will require frequent crew transport vessel
(CTV) and service operation vessel (SOV) use for routine daily O&M activities. Infrequently,
survey vessels will be used to perform routine surveys of foundations and cables that will be
carried out in years one and two, and every three years thereafter, or after a major storm event
(one in 50-years storm). Non-routine repairs may require the use of jack-up vessels, cable burial
vessels, cranes, and cherry pickers.
During the O&M phase, the OCS source components will primarily be powered by the wind
farm. During periods when the wind is not sufficient for the WTGs to operate normally, or if the
WTGs are not operating for any other reason, the wind farm may draw power from the onshore
grid via the bi-directional export cable. If shore power is not available, power will be supplied by
the WTGs' integrated battery backup system that can provide auxiliary power to the WTGs in
the event of a temporary outage. The battery backup system can be charged by the WTG when
operating. In the unlikely scenario where shore power from the grid is not available, the WTGs
are not producing electricity, and the previous three days did not have wind to charge the battery
backup system, a temporary diesel generator would be used.
The two (2) OSS will have permanently installed 597 kW generators (each) that will be used to
power the OSS(s) in the event of an outage where shore power is not available, and the WTGs
are not providing power. The generators will be used under both emergency and standby
conditions. During O&M, the OSS generators may be used occasionally to provide power during
routine maintenance of the OSS (if grid power is unavailable or the maintenance being
performed requires disconnection from the grid).
It is possible that the project's offshore facilities will require a major repair during the wind
farm's 20- to 35-year lifespan. A major repair to the WTGs or OSSs would closely resemble the
process of installing the WTGs and OSSs. Emission sources during a major repair would be the
same as those used for routine O&M, but more vessels would be at the WDA for a longer period.
Because of the infrequent and uncertain nature of a major repair, RW is not seeking authorization
for major repairs in this OCS air permit. Should such an event occur in future years, RW is
required to seek the appropriate permitting approvals at that time.
The following table contains the RW project's maximum potential emissions during the O&M
phase (post-operational phase start date), as contained in RW's revised emission estimates
provided to the EPA on February 28, 2023. The annual potential emissions during the O&M phase
are anticipated to be equivalent to the source's PTE once construction has been completed and the
wind farm commences operations.
Table 2 Estimated Operations and Maintenance Emissions (tpy)
N2o
CChe
CO
NOx
PM10
PM2.5
SO2
Lead
voc
0.8
19,600
65.8
210.4
8.6
8.3
0.8
<0.01
5.1
(1) N20 emissions were not provided in the February 28 update. Calculations for N20 were completed based on
previous N20 to NOx ratio (.36%).
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D. Stationary Source Combined Emission Total(s)
The South Fork Wind project and the Revolution Wind project are considered one (1) stationary
source for Clean Air Act permitting purposes. More information on the source determination is
found in Section III.D of this Fact Sheet. The following tables contain the combined emissions
for South Fork and Revolution Wind during the construction and O&M phases of the two
projects as provided in the developers' respective applications.
Table 3 Combined Const ruction Emissions for Revolution Wind and South Fork Wind Projects (tpy)
NiO
COie
CO
NOx
PMio
PM2.5
SO2
Lead
VOC
14.5
324,488
1,086
4,298
147.8
143.4
17.4
0.02
91.4
Table 4 Combined O&M Emissions for Revolution Wind and South Fork Wind Pro jects (tpv)
N2O
COie
CO
NOx
PM10
PM2.5
SO2
Lead
VOC
0.90
21,259
69.1
229.6
9.2
8.9
0.9
0.0
5.5
III. Applicability of 40 C.F.R. Part 55 - OCS Air Regulations
A. OCS Statutory and Regulatory Authority
Section 328(a) of the CAA requires that the EPA establish air pollution control requirements for
equipment, activities, or facilities located on the OCS that meet the definition of an OCS source.
Sources located within 25 nm of a state's3 seaward boundary also need to comply with several
onshore requirements. To comply with this statutory mandate, on September 4, 1992, the EPA
promulgated 40 C.F.R. Part 55, which established requirements to control air pollution from
OCS sources in order to attain and maintain federal and state ambient air quality standards.4
The Energy Policy Act of 2005 (See Title III (Oil and Gas), Subtitle G - Miscellaneous, Section
388) amended section 8 of the Outer Continental Shelf Lands Act (OCSLA) to allow the EPA
and the Department of the Interior to authorize activities on the OCS that "produce or support
production, transportation, or transmission of energy from sources other than oil and gas."
Section 4(a)(1) of OCSLA was recently amended to expand the scope of "exploring, developing
or producing resources" to include "non-mineral energy resources" such as offshore wind. See
William M. (Mac) Thornberry National Defense Authorization Act for Fiscal Year 2021, H.R.
6395, 116th Cong. § 9503 (2021). BOEM reviews construction and operation plans from
offshore wind energy developers and approves, approves with modifications, or disapproves
those plans. EPA issues a CAA OCS permit to establish air pollution control requirements for
3 The term "state," when used to reference one of the 50 states within the United States, includes states that are
officially named commonwealths, e.g., the Commonwealth of Massachusetts.
4 Refer to the Notice of Proposed Rulemaking, December 5,1991 (56 Fed. Reg. 63,774), and the preamble to the final
rule promulgated September 4, 1992 (57 Fed. Reg. 40,792) for further background and information on the OCS
regulations.
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such sources when the definition of OCS source is met, as defined in CAA § 328 and 40 C.F.R.
Part 55.5
Under CAA § 328(a)(4)(C) and 40 C.F.R. § 55.2, an OCS source includes any equipment,
activity, or facility which:
(1) Emits or has the potential to emit any air pollutant;
(2) Is regulated or authorized under the OCSLA (43 U.S.C. § 1331 et seq.); and
(3) Is located on the OCS or in or on waters above the OCS.
Furthermore, 40 C.F.R. § 55.2 establishes that for a vessel to be considered an OCS source, the
vessel must also meet one of the two following criteria:
(1) Permanently or temporarily attached to the seabed and erected thereon and used
for the purpose of exploring, developing, or producing resources therefrom,
within the meaning of section 4(a)(1) of OCSLA (43 U.S.C. §1331 et seq.); or
(2) Physically attached to an OCS facility, in which case only the stationary sources
[sic] aspects of the vessels will be regulated.
Finally, under 40 C.F.R. § 55.2, the term "[ojuter continental shelf' shall have the meaning
provided by section 2 of the OCSLA (43 U.S.C. § 1331 et seq.), which in turn defines the "outer
continental shelf' as "all submerged lands lying seaward and outside of the area of lands beneath
navigable waters as defined in section 1301 of this title, and of which the subsoil and seabed
appertain to the United States and are subject to its jurisdiction and control."
Once an activity, facility, or equipment (which may include a vessel) is considered an OCS
source, then the emission sources of that OCS source become subject to the requirements of 40
C.F.R Part 55, which include: (1) obtaining an OCS air permit, as required by 40 C.F.R. § 55.6;
(2) complying with the applicable federal regulations and requirements specified at 40 C.F.R. §
55.13; (3) for an OCS source within 25 nm of a state's seaward boundary, complying with the
state or local air emissions requirements of the corresponding onshore area (COA) specified at
40 C.F.R. § 55.14; (4) monitoring, reporting, inspection, and enforcement requirements specified
at 40 C.F.R. §§ 55.8 and 55.9; and (5) permit fees as specified under 40 C.F.R. § 55.10.
B. Procedural Requirements for OCS Permitting
Regulations developed pursuant to OCS statutory requirements under section 328 of the CAA
are codified at 40 C.F.R. Part 55. The OCS regulations create procedures that require an
applicant seeking to construct and operate an OCS source to identify the federal regulations and
the state and local regulations from the COA that may apply to the source, and to seek to have
those regulations apply, as a matter of federal law, to the OCS source. Once the EPA has
5 A copy of the Construction and Operation Plan may be found at https://www.boem.gov/renewable-energy/state-
activities/revotution-wind-farm-constmction-and-operations-plan (last visited Nov. 7, 2022).
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received a complete permit application, the EPA6 then follows the applicable procedural
requirements for federal permitting contained in 40 C.F.R. Part 124 or 40 C.F.R. Part 71, and the
EPA issues an OCS permit that meets all federal requirements.7 The EPA is following the
applicable procedures in 40 C.F.R. Part 124 in issuing this OCS permit.
The OCS regulations first require the applicant to submit a notice of intent (NOI) to the nearest
EPA regional office. See 40 C.F.R. § 55.4. The NOI provides emissions information regarding
the OCS source, including information necessary to determine the applicability of onshore
requirements and the source's impact in onshore areas. See 40 C.F.R. § 55.5. RW submitted to
the EPA an NOI for the wind farm on November 5, 2021. Information provided in the NOI for
this wind farm indicated that Massachusetts is the nearest onshore area (NOA"). The EPA did
not receive a request from another state to be designated the COA for this project, thus
Massachusetts is designated the COA. See 40 C.F.R. § 55.5(b)(1).
The federal requirements that apply to an OCS source are provided in 40 C.F.R. § 55.13. The
EPA also reviews the state and local air requirements of the COA to determine which
requirements should be applicable on the OCS and revises 40 C.F.R. Part 55 to incorporate by
reference those state and local air control requirements that are applicable to an OCS source. See
40 C.F.R. § 55.12. Once the EPA completes its rulemaking to revise 40 C.F.R. Part 55, the state
and local air regulations incorporated into 40 C.F.R. Part 55 become federal law and apply to any
OCS source associated with that COA.
Under this "consistency update" process, the EPA must incorporate applicable state and local
rules into 40 C.F.R. Part 55 as they exist onshore. This limits the EPA's flexibility in deciding
which requirements will be incorporated into 40 C.F.R. Part 55 and prevents the EPA from
making substantive changes to the requirements it incorporates. As a result, the EPA may be
incorporating rules into Part 55 that do not conform to certain requirements of the CAA or are
not consistent with the EPA's state implementation plan (SIP) guidance. The EPA includes all
state or local air requirements of the COA except any that are not rationally related to the
attainment or maintenance of federal or state ambient air quality standards or part C of Title I of
the Act, that are designed expressly to prevent exploration and development of the OCS, that are
not applicable to an OCS source, that are arbitrary or capricious, that are administrative or
procedural rules, or that regulate toxics which are not rationally related to the attainment and
maintenance of federal and state ambient air quality standards.
Consistency updates may result in the inclusion of state or local rules or regulations into 40
C.F.R. Part 55, even though the EPA may ultimately disapprove the same rules for inclusion as
part of the state's SIP. Inclusion in the OCS rule does not imply that a rule meets the
requirements of the CAA for SIP approval, nor does it imply that the rule will be approved by
the EPA for inclusion in the SIP.
On November 23, 2021 (86 FR 66509), the EPA published a Notice of Proposed Rulemaking
(NPRM) proposing to incorporate various Massachusetts air pollution control requirements into
6 The authority granted to the "Administrator" in 40 C.F.R. Part 55 has been delegated to the Regional Administrator
in EPA Region 1. See Docket for Delegation of Authority.
7 See 40 C.F.R. § 55.6(a)(3).
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40 C.F.R. Part 55. EPA's November 23, 2021 NPRM was initiated in response to the submittal
of an NOI on September 9, 2021, by Sunrise Wind, LLC. However, EPA also received an NOI
on November 5, 2021, from Revolution Wind, LLC, an NOI on January 28, 2022, from New
England Wind, LLC, and an NOI on May 31, 2022, from Mayflower Wind Energy, LLC.8 In
accordance with 40 C.F.R. §55.5, Massachusetts is the designated COA for each of these
projects. Upon receipt of the subsequent NOI's from Revolution Wind, LLC, New England
Wind, LLC, and Mayflower Wind Energy, LLC, EPA conducted a consistency review in
accordance with regulations at 40 C.F.R. § 55.12 and determined that recent changes to the
Massachusetts regulations since the NPRM are non-substantive as they relate to OCS sources,
and that it is not necessary to propose an additional consistency update at this time.9
EPA published a final rulemaking notice for the consistency update to Part 55 on November 15,
2022. See 87 Fed. Reg. 68,364 (Nov. 15, 2022). EPA's November 15, 2022, Federal Register
notice satisfies EPA's obligation under §55.12 to conduct a consistency review for the
subsequent NOI's received from Revolution Wind, LLC, New England Wind, LLC, and
Mayflower Wind Energy, LLC.
The Massachusetts regulations that the EPA incorporated into Part 55 in this action are the
applicable provisions of (1) 310 CMR 4.00: Timely Action Schedule and Fee Provisions; (2) 310
CMR 6.00: Ambient Air Quality Standards for the Commonwealth of Massachusetts; and (3)
310 CMR 7.00: Air Pollution Control, as amended through March 5, 2021. EPA's final rule did
not affect the provisions of 310 CMR 8.00 that were previously incorporated by reference into
Part 55 through EPA's prior consistency update on November 13, 2018. See 83 Fed. Reg. 56,259
(Nov. 13,2018).
The OCS permit applicant then follows the procedural requirements to obtain a federal permit as
outlined in 40 C.F.R. Part 124. The applicant submits an air permit application that provides the
information to show that it will comply with all applicable federal requirements, including those
requirements found in 40 C.F.R. Part 55 (which, because of the consistency update, include
certain state and local requirements incorporated by reference into federal law), and any other
federal standard that may apply to the source. The EPA reviews the application and proposes
either to approve or deny the application. Next, if the EPA decides to propose approval, the EPA
drafts a draft air permit and a fact sheet that documents its proposed permit decision. The EPA
then provides a notice and comment period of at least 30 days for the draft permit and may also
hold a public hearing if there is a significant degree of public interest and/or a hearing might
8 On February 1, 2023, Mayflower Wind Energy LLC notified EPA of a name change to South Coast Wind Energy,
LLC.
9 Since EPA's November 23, 2021 NPRM, Massachusetts revised the regulations at 310 CMR 7.00 (Statutory
Authority; Legend; Preamble; Definitions) and 310 CMR 7.40 (Low Emission Vehicle Program), effective
December 30, 2021. EPA previously determined that the regulations at 310 CMR 7.40 (Low Emission Vehicle
Program) were not applicable to OCS sources and did not propose to incorporate this section of 310 CMR 7.00 into
Part 55 as part of the November 23, 2021 NPRM. Although EPA's NPRM proposed to incorporate by reference the
definitions located at 310 CMR 7.00 (Statutory Authority; Legend; Preamble; Definitions), MassDEP's most recent
revisions to 310 CMR 7.00 (Statutory Authority; Legend; Preamble; Definitions) were related to the amendments to
the regulations at 310 CMR 7.40 (Low Emission Vehicle Program). EPA has reviewed the recent amendments to the
Massachusetts regulations at 310 CMR 7.00 (Statutory Authority; Legend; Preamble; Definitions) and determined
that these changes are non-substantive as they relate to OCS sources.
15
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clarify issues involved in the permit decision. Following the comment period, the EPA responds
to all significant comments raised during the public comment period, or during any hearing, and
issues the final air permit decision.
C. Scope of the "OCS Source"
The CAA permitting analysis for an offshore wind farm located in federal waters must begin
with a determination of the scope of the "OCS source" because the boundaries of the source
determine what activities are attributed to the source for purposes of quantifying its "potential
emissions" and determining what CAA programs apply.10 Once an OCS source is identified,
EPA must then apply the terms of specific regulatory programs, including the New Source
Review (NSR) preconstruction permitting and Title V operating permit programs11, to determine
whether they apply to the OCS source and if so, how. Importantly, under section 328 of the CAA
and EPA's implementing regulations, emissions from vessels "servicing or associated with an
OCS source" must be included in the assessment of the source's "potential emissions" and may
cause the OCS source's emissions to exceed thresholds that subject the source to NSR and Title
V operating permit requirements.
According to RW's permit application, RW is proposing to install up to 100 WTGs and the
associated offshore infrastructure required to transmit the power generated by the WTGs to an
onshore interconnection. These project components require the installation of up to two OSSs
installed on platforms, inter-array cables connecting the WTGs, interconnection cabling to link
the OSSs (OSS-Link Cable), and a bi-directional offshore export cable to bring the power from
the OSSs to shore.
During construction, pollutant-emitting activities from the wind farm include temporary diesel
generators (i.e., engines) used to supply power to the WTGs and OSS(s) during commissioning
activities in the construction phase, as well as engines on vessels that meet the definition of an
OCS source. During the O&M phase of the project, pollutant-emitting activities from the wind
farm include engines on vessels that meet the definition of an OCS source, any generators on the
OSS(s), and any generators on WTGs.
In Appendices A and B to RW's permit application, RW provided its rationale for an alternative
approach to determining applicable permitting regulations and the scope of the source for the
O&M phase of the project. Specifically, RW contended that during the O&M phase, only the
OSS(s) (with accompanying permanent emergency generators) and any jack-up vessels would
meet the definition of an OCS source during operations. The EPA disagrees with the conclusions
presented by RW in Appendices A and B of the application and is proposing the draft permit
based on the remaining application materials consistent with the CAA and 40 CFR Part 55.
EPA is treating all stationary equipment and activities within the proposed wind farm, including
all wind turbines, as part of a single "OCS source" because all such equipment and activities are
10 The OCS regulations themselves do not constitute a permitting program but, instead, make existing federal and
state air pollution control requirements applicable to OCS sources. 40 CFR § 55.1.
11 Applicability of Prevention of Significant Deterioration (PSD) and Nonattainment NSR (NNSR) permit programs
is discussed in Section V and VI of this Fact Sheet.
16
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integral components of a single industrial operation that emits or has the potential to emit any air
pollutant, is regulated or authorized under the OCSLA, and is located on the OCS or in or on
waters above the OCS. The OCS source comprises all offshore WTGs and their foundations,
each OSS and its foundation, the inter-array cables, and vessels when they meet the definition of
an OCS source in 40 C.F.R. § 55.2. Thus, emissions from any vessel "servicing or associated
with" any component of the OCS source (including any WTG or OSS) while at the source and
while en route to or from the source within 25 nautical miles of it must be included in the OCS
source's potential to emit, consistent with the definition of "potential emissions" in 40 C.F.R. §
55.2.
D. Scope of the Stationary Source
For the NSR preconstruction permitting programs, which include Prevention of Significant
Deterioration (PSD) and Nonattainment New Source Review (NNSR"), the EPA regulations
define "stationary source" as "any building, structure, facility, or installation which emits or may
emit a regulated NSR pollutant."12 Those regulations, in turn, define the term "building,
structure, facility, or installation" to mean "all of the pollutant-emitting activities which [1]
belong to the same industrial grouping, [2] are located on one or more contiguous or adjacent
properties, and [3] are under the control of the same person (or persons under common control),"
with "same industrial grouping" referring to the same Major Group, two-digit SIC code. For the
Title V permit operating program, "major source" is similarly defined in relevant part as a
stationary source or group of stationary sources that meet these same three criteria.13' 14
State and local permitting authorities have EPA-approved NSR permitting regulations that
contain identical or similar definitions for the terms "stationary source" and "major source."
Under the EPA-approved Massachusetts NNSR regulations at 310 CMR 7.00, Appendix A
(incorporated by reference into the federal rules at 40 C.F.R. § 55.14), "stationary source" is
defined as follows:
Stationary source means any building, structure, facility, or installation which emits or which
may emit any air pollutant subject to regulation under the Act.
(a) A stationary source may consist of one or more emissions units and:
1. may be a land-based point or area source; or
12 40 C.F.R. § 52.21(b)(5); 40 C.F.R. § 51.165(a)(l)(i); 40 C.F.R. § 51.166(b)(5); see 42 U.S.C. § 7602(z) (defining
"stationary source" as "any source of an air pollutant" except those emissions resulting directly from certain mobile
sources or engines).
13 40 C.F.R. § 70.2; 40 C.F.R. 71.2; see 42 U.S.C. § 7661(2) (defining major source for Title V permitting as "any
stationary source (or any group of stationary sources located within a contiguous area and under common control)"
that is either a major source as defined in CAA section 112 or a major stationary source as defined in CAA section
302 or part D of subchapter I (NNSR)). The EPA was also clear in promulgating its regulatory definitions of "major
source" that the language and application of the Title V definitions were intended to be consistent with the language
and application of the PSD definitions contained in 40 C.F.R. § 52.21 (61 FR 34210 (July 1, 1996)).
14 RW did not apply for a Title V operating permit as part of its OCS air permit application. However, EPA
anticipates the scope of the stationary source analysis will be similar for the Title V operating permit program.
17
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2. may be located in, or on, the OCS or other submerged lands beneath navigable
waters (lakes, rivers, and coastal waters adjacent to Outer Continental Shelf
lands); or
3. may be any internal combustion engine, or engine combination, greater than
175 horsepower (hp) used for any stationary application; or
4. may be any internal combustion engine regulated under Sec. Ill (New Source
Performance Standards (NSPS)) of the Act, regardless of size; or
5. may be any internal combustion engine of less than 175 horsepower (hp) not
actually controlled to meet a regulation under Sec. 213 (Nonroad Engines and
Vehicles) of the Act.
(b) A stationary source does not include:
1. emissions resulting directly from an internal combustion engine for
transportation purposes; or
2. tailpipe emissions from any source regulated under title II of the Act or any
emissions from in-transit, non-OCS marine vessels.
The Massachusetts NNSR regulations at 310 CMR 7.00, Appendix A define "building, structure,
facility, or installation" as follows:
[A]ll of the pollutant-emitting activities which belong to the same industrial
grouping, are located on one or more contiguous or adjacent properties, and are
under the control of the same person (or persons under common control). Any
marine vessel is a part of a facility while docked at the facility. Any marine vessel
is a part of an Outer Continental Shelf (OCS) source while docked at and within 25
nautical miles en route to and from the OCS source. Pollutant-emitting activities
shall be considered as part of the same industrial grouping if they belong to the
same Major Group {i.e., which have the same two-digit code) as described in the
Standard Industrial Classification Manual, 1987.
The Massachusetts Title V operating permit program regulations at 310 CMR 7.00, Appendix C
define a "major source" as follows:
For the purpose of defining "major source," a stationary source or group of
stationary sources shall be considered part of a single industrial grouping if all of
the pollutant emitting activities at such source or group of sources on contiguous or
adjacent properties belong to the same Major Group {i.e., all have the same two-
digit code) as described in the Standard Industrial Classification Manual, 1987.
Additionally, in 2019, EPA issued guidance15 to provide its interpretation of the term "adjacent"
as that term is used in NSR and Title V source determinations. In that guidance, EPA provided
an interpretation of "adjacent" based solely on physical proximity for the purpose of determining
15 See the memo "Interpreting 'Adjacent' for New Source Review and Title V Source Determinations in All
Industries Other Than Oil and Gas" at https://www.epa.gov/sites/production/files/2019-
12/documents/adiacent guidance.pdf
18
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whether separate activities are located on adjacent properties. The guidance indicated that EPA
would no longer consider "functional interrelatedness" in determining whether activities are
located on adjacent properties.
On January 18, 2022, EPA issued an OCS air permit to South Fork Wind, LLC for the
construction and operation of a 132 MW wind farm in lease area OCS-A 0517. The South Fork
Wind project lease area is in close physical proximity to the Revolution Wind project lease area.
In addition, the South Fork Wind project and the Revolution Wind project are both owned and
operated by 0rsted North America, Inc. and Eversource Investment, LLC. Because of the
proximity of the project locations and similar parent company ownership, EPA has applied these
regulatory definitions and interpretive statements to determine the scope of the stationary source
for the Revolution Wind and South Fork Wind offshore wind projects under the applicable NSR
and Title V regulations - i.e., for purposes of determining whether the pollutant-emitting
activities, equipment, or facilities for these projects: [1] belong to the same industrial grouping,
[2] are located on one or more contiguous or adjacent properties, and [3] are under common
control.
Regarding the first criterion, the Revolution Wind project and South Fork Wind projects are
classified under Standard Industrial Code (SIC) 4911, Electric Services. Accordingly, all
pollutant-emitting activities for the Revolution Wind project and South Fork Wind project
belong to the same industrial group, and thus satisfy the first criterion for treatment as a single
stationary source.
Regarding the second criterion, EPA evaluated whether the pollutant-emitting activities are
located on one or more contiguous or adjacent properties. All pollutant-emitting activities for the
Revolution Wind project will be located on a single property. EPA has previously analyzed what
constitutes a single property in other OCS air permits for offshore wind farms.16 As explained in
more detail in those actions, the EPA considers the WD A—here, the lease area held by RW
occupying a relatively small tract of otherwise open ocean, distinct from its surroundings by the
planned installation of a uniform and close-knit pattern of wind turbines—to fit reasonably
within such a meaning of a "property" as "a place or location." EPA has made this determination
for two reasons. First, the WDA is a discrete and clearly identifiable area set apart from the
surrounding open ocean by its man-made features. One could not approach or pass through the
WDA and its towering grid of wind turbines without recognizing that it was a fundamentally
different "place" than the open ocean. Second, although the WDA occupies a relatively large
area, its size is necessarily unique to the expansive spatial scales associated with OCS wind farm
development projects.17 Viewed in context, the WDA is a relatively small property when
compared to the area set aside for future development by the offshore wind industry off the coast
of Massachusetts and is an even smaller property when compared to the OCS and surrounding
open ocean more broadly. See Figure 2.
16 See Source Determination for Vineyard Wind 1 Offshore Wind Farm, which is available online in the
administrative docket at https://www.epa.gov/caa-perniitling/permit-docnments-vinevard-wind-l-Hcs-wind-energy-
development-proiect-8()()mw-offshore.
17 Offshore wind farms require some degree of spacing between turbines, resulting in a single facility or installation
covering a relatively large property. This spacing is necessary to balance navigational concerns, wind energy
generation, and impacts to other resources such as marine mammals, recreational fishing and boating, and
commercial marine fisheries.
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Furthermore, the Revolution Wind project, owned and operated by RW, will be located in OCS
lease area OCS-A 0486. As shown in Figure 2 below, OCS lease area OCS-A 0517 is adjacent to
lease area OCS-A 0486. On January 18, 2022, EPA issued an OCS permit for the South Fork
Wind project, which is located in lease area OCS-A 0517. In that permit action, EPA also
determined that the WDA for the South Fork Wind Farm constitutes a single property for the
same reasons outlined above.18 EPA has evaluated the physical proximity between the
Revolution Wind WDA and the WDA for the South Fork Wind project and determined that the
two properties are contiguous or adjacent. Therefore, the South Fork Wind project and the
Revolution Wind project are located on contiguous or adjacent properties and satisfy the second
criterion for treatment as a single stationary source.19 See Figure 2.
18 See June 24, 2021 Initial Fact Sheet for South Fork Wind, LLC available at
https://www.epa.gov/svstem/files/documents/2021-07/south-fork-draft-permit-fs.pdf
19 EPA also evaluated whether the Sunrise Wind offshore wind farm project, owned and operated by
Orsted/Eversource, is located on property that is contiguous or adjacent to the South Fork wind farm and Revolution
Wind farm. EPA has determined that due to the physical separation between the Sunrise Wind lease area (OCS-A
0487) and the South Fork and Revolution Wind projects caused by Cox Ledge, the Sunrise Wind project is not
located on property contiguous or adjacent to the South Fork Wind and Revolution Wind projects. Cox Ledge is an
"area of concern" for fishery managers that provides habitat for several commercially and recreationally valuable
species. It was removed from the lease areas for wind energy development by BOEM during the leasing process.
Thus, in some instances, physical separation between lease areas may provide a basis for not aggregating two or
more wind farms. A more detailed explanation of EPA's analysis will be provided in the Fact Sheet for the Sunrise
Wind offshore wind farm draft permit when a draft permit decision is proposed.
20
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ATLANTIC
OCEAN
Massachusetts
Rhode
Island
* Cod
OCS-A 0486
A
OCS A 0522
Revolution Wind. LUC
South Fork Wind. LLC
Sunrise Wnd LLC
Bey State Wind LLC
Vineyard Wind LLC - 0534
Vineyard Wind 1 LLC
Beacon Wind LLC
Mayflower \Mnd Energy LLC
Vineyard Wind LLC - 0522
State Boundary
to
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15
J
30
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20
41
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Figure 2 Map of Massachusetts/Rhode Island OCS Lease Area
21
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Regarding the third and final criterion, common control, EPA evaluated the relationship among
Revolution Wind, LLC; South Fork Wind, LLC; and the 0rsted North America, Inc. and
Eversource Investment, LLC. EPA's longstanding policy considers common ownership
sufficient to establish common control for corporate entities under the same corporate
umbrella.20 Both South Fork Wind, LLC and Revolution Wind, LLC are 50/50 joint ventures
between 0rsted North America, Inc. and Eversource Investment, LLC. Therefore, based on EPA
policy, South Fork Wind, LLC and Revolution Wind, LLC are under common control of 0rsted
North America, Inc. and Eversource Investment, LLC. Furthermore, EPA's policy on common
control also considers one entity's power or authority over the other to dictate decisions that
could affect the applicability of, or compliance with, relevant air pollution regulatory
requirements.21 The EPA's understanding is that 0rsted North America, Inc. and Eversource
Investment, LLC have the relevant power or authority over all pollutant-emitting activities,
including the authority to dictate decisions of Revolution Wind, LLC and South Fork Wind,
LLC. As a result of EPA's assessment, the EPA has determined that the South Fork Wind project
and the Revolution Wind project are under common control and meet the third and final criterion
for treatment as a single stationary source.
For the reasons discussed above, the South Fork Wind and Revolution Wind offshore wind
development projects belong to the same industrial grouping, are located on contiguous or
adjacent properties, and are under common control. Therefore, the EPA has determined that the
two projects constitute a single stationary source under the NSR and Title V permit programs.
The scope of the "stationary source" thus coincides with the scope of the "OCS source."
IV. Emission Units Subject to Part 55
The potential emissions of the OCS source are used to determine applicability of the relevant
permit program requirements under 40 C.F.R. Part 55. Part 55.2 defines potential emissions as
follows:
Potential emissions means the maximum emissions of a pollutant from an OCS
source operating at its design capacity. Any physical or operational limitation on
the capacity of a source to emit a pollutant, including air pollution control
equipment and restrictions on hours of operation or on the type or amount of
material combusted, stored, or processed, shall be treated as a limit on the design
capacity of the source if the limitation is federally enforceable. Pursuant to section
328 of the Act, emissions from vessels servicing or associated with an OCS source
shall be considered direct emissions from such a source while at the source, and
while enroute to or from the source when within 25 miles of the source and shall
be included in the "potential to emit" for an OCS source. This definition does not
alter or affect the use of this term for any other purposes under §55.13 or §55.14
20 See Letter from Carl Daly, Acting Director, EPA Region 8 Air & Radiation Division, to Danny Powers, Air
Quality Program Manager, Southern Ute Indian Tribe (July 23, 2019), available at
https://www.epa.gov/sites/defanit/files/2019-10/docnments/iaanes2019.pdf.
21 See Letter from William L. Wehrum, Assistant Administrator, EPA Office of Air and Radiation, to the Honorable
Patrick McDonnell, Secretary, Pennsylvania Department of Environmental Protection (April 30, 2018), available at
https://www.epa.gov/sites/prodnction/files/2018-05/docnments/meadowbrook 2018.pdf.
22
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of this part, except that vessel emissions must be included in the "potential to emit"
as used in §§ 55.13 and 55.14 of this part.
Once the facility meets the definition of an OCS source, emissions from vessels servicing or
associated with any part of the facility are included in the OCS source's potential emissions
while traveling to and from any part of the OCS source when within 25 nautical miles of it.22
Although emissions from propulsion engines contribute to total potential emissions within 25
nautical miles of the OCS source, they are not regulated as part of the OCS source in the draft
permit unless the propulsion engine would be used to supply power for purposes of performing a
given stationary source function (e.g., to lift, support, and orient the components of each WTG
during installation) while that vessel is meeting the three criteria of the definition of an OCS
source. However, these emissions are included when making the following determinations
regarding the equipment and activities that are OCS sources:
1. Applicability of CAA programs and COA requirements, including NNSR and PSD
permitting;
2. When calculating the number of NOx and VOC offsets required due to emissions
during the operational phase; and
3. When determining the impact of emissions on ambient air and Class I and Class II
areas.
Jack-up vessels, support vessels, or other vessels may contain emission equipment that would
otherwise meet the definition of "nonroad engine," as defined in section 216(10) of the CAA.
However, based on the specific requirements of CAA section 328, emissions from these
otherwise nonroad engines on subject vessels are considered direct emissions from the OCS
source they are associated with for the purposes of calculating potential emissions of that OCS
source. Similarly, all engines, including engines on vessels that meet the definition of an OCS
source and are "operating as OCS sources," are regulated as stationary sources and are subject to
the applicable requirements of 40 C.F.R. Part 55, including control technology requirements.
The primary emission units for the wind farm project consist of exhaust from marine vessel
traffic, heavy equipment auxiliary engines, and generator engines on vessels on offshore
platforms. The facility also has emissions of sulfur hexafluoride from gas-insulated switchgear
(GIS) on the OSSs.
22 For the purposes of determining the potential emissions from vessels, Revolution Wind used a minimum travel
distance of 25 nautical miles (50 nm minimum for each vessel) to calculate emissions from vessels servicing or
associated with the wind farm. This is a conservative approach for calculating emissions because it assumes the
maximum possible travel distance for calculating PTE from vessels servicing or associated with the OCS source.
The approach likely overestimates emissions because some of the ports proposed for use by the project are less than
25 nm from the WD A facility.
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A. Wind Turbine Generators and Offshore Substation(s)
As described below, WTGs and OSS(s) will be installed on the seabed within the WD A. The
collection of WTGs, the OSS(s), as well as the vessels operating as OCS sources within the
WDA constitute the Revolution Wind project subject to this OCS air permit.
An offshore wind farm is made up of many WTGs spread out over a wide area of the ocean.
Each WTG is firmly fixed to a foundation piece on the seafloor, with a tower that extends up into
the air where the blades can make use of higher wind speeds. Each WTG has three blades that
rotate due to the movement of air. Within the non-rotating part on top of the turbine known as
the nacelle, the blades' rotation is passed through a drive shaft, often via gear box, to turn
magnets inside a coil of wire which generates an alternating current of electricity. Each WTG
sends its power through cables down the tower and under the seabed to an offshore substation, or
OSS.23
The Revolution Wind project will consist of up to 100 WTGs, sited in a grid with approximately
1 nm by 1 nm spacing. The general process for installation of the wind farm involves the
installation of the foundations to the sea floor and preparation of the structures for the WTGs and
the OSSs. Work vessels then supply all the WTG components and install them on the
foundations. RW plans to install a monopile-style foundation for each WTG.
An OSS is an offshore platform containing the electrical components necessary to collect the
power generated by the WTGs (via the inter-array cable), transform it to a higher voltage and
transmit this power to onshore electricity infrastructure (via the export cables). The purpose of
the OSS is to stabilize and maximize the voltage of power generated offshore, reduce the
potential electrical losses, and transmit electricity to shore.
1. Generator Engines
According to RW's permit application, no generator engines are expected to be used on the
WTGs during the construction phase where WTGs are being installed. Power will be provided
by the jack-up vessel performing the installation work. During the commissioning of the WTGs,
the WTGs will be powered by the integrated battery backup system and are not anticipated to
require the use of a generator engine. However, if the battery backup system were to fail, or not
provide sufficient power for the full duration of commissioning, temporary 37 kW generators on
the WTGs would be required until the WTGs are connected to, and able to be powered by, the
grid. RW anticipates that generator engines are necessary for use on the WTGs during the
operations phase in the unlikely scenario where shore power from the grid is not available.
Specifically, the temporary diesel generators would be used to supply emergency power to the
WTGs when the battery backup system has failed. Therefore, RW is requesting the ability to
construct and operate generator engines for use on the WTGs.
23 More information on the operational nature of an offshore wind farm is available at the Orsted-hosted webpage
entitled, "How do offshore wind turbines work?" https://ns.orsted.com/renewable-energy-solntions/offshore-
wind/what-is-offshore-wind-power/how-do-offshore-wind-turbines-work. Last visited, February 23, 2023.
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RW plans to construct and operate up to two OSSs, each with a maximum nominal capacity of
440 MW, to support the project's maximum production design capacity. Two temporary 156 kW
diesel generators will be installed on each OSS during installation and commissioning. A 455
kW generator will also be installed on each OSS and will remain on the OSS after
commissioning for emergency use and for infrequent use to provide power during maintenance
activities in the operations phase. The generator engine emissions on the OSSs and the WTGs (if
installed) are subject to the OCS air permit and regulated as a stationary source.
2. Gas-Insulated Switchgear (GIS)
Each of the OSSs will contain sulfur-hexafluoride (SFr,) switchgear for insulation purposes. SF6
is used as an electrical and thermal insulator in electrical equipment, but it is also a powerful
greenhouse gas, having a global warming potential (GWP) of 23,500 times that of carbon
dioxide (CO2). SF6 has the highest GWP of all greenhouse gases addressed by the
Intergovernmental Panel on Climate Change (IPCC) inventory protocols. RW proposes that OSS
devices containing SF6 will be equipped with integral low-pressure detectors to detect SF6 gas
leakages should they occur. According to RW, the WTGs will not contain SF6 gas insulated
switchgear.
B. Vessels
Construction of the project will require the use of an array of vessels. During construction, heavy
lift vessels, tugboats, barges, platform supply vessels, and jack-up vessels will be used to
transport the WTG, monopile, and OSS components to the lease area. Installation of the WTGs,
monopiles, and OSSs is expected to be performed using a combination of jack-up vessels and
dynamic positioning system (DPS) crane vessels. It is anticipated that scour protection will be
installed around the WTG and OSS foundations using a specialized rock-dumping vessel. Crew
transport vessels and service operations vessels will be used to support the installation of the
wind farm components. To reduce noise impacts from the construction, a bubble curtain will be
maintained via an anchor handling vessel.24 In addition, four sound field verification vessels will
be positioned around pile driving to monitor for sound.
Crew transfer vessels and helicopters25 are expected to be used to transport personnel to and
from the wind development area. Additional geophysical survey work will likely be conducted to
ensure adequate understanding of seabed conditions around the offshore cable system and scour
protection, which will require the use of survey vessels.
RW described the following vessels with air pollutant emitting equipment in the permit
application.
24 Bubble curtains utilizes a submerged, perforated tube or pipe from which compressed air is released. When laid
on the seafloor around areas where offshore activities are expected to occur, the rising curtain of bubbles reduces
and disperses the amount of underwater noise associated with a particular activity, protecting marine life from
acoustic disturbances.
25 The project's potential emissions include emissions from helicopters which are not required to be part of the
potential to emit calculation for the project. Helicopter emissions are de minimis for the WDA facility, and whether
their emissions are included or not have no impact on determining permitting applicability.
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Table 5 Description of Vessels and Equipment for WTG and OSS Installation Activities Included In the
Potential to Emit
Vessel Type
Description of Vessel 'I'ype
Crew transport
vessels
Transport crew to the WDA.
Heavy lift installation
vessels
Lift, support, and orient the components of each WTG and OSS
during installation. Used for foundation installation.
Cable lay and burial
vessels
Lay and bury transmission cables in the seafloor
Rock dumping
vessels
Pre-lay grapnel runs
vessels
Deposit a layer of stone around the WTG and OSS foundations to
prevent the removal of sediment by hydrodynamic forces.
May place cable protection over limited sections of the offshore cable
system.
Boulder clearance
vessels
Clear the seabed floor of debris prior to laying transmission cables.
Tugboats
Transport equipment and barges to the WDA.
Heavy transport
vessels
Transport large project components to the WDA.
Platform supply
vessels
Transport steel to the WDA.
Anchor handling tug
supply vessels
Install underwater noise mitigation devices (e.g. bubble curtains).
Support offshore export cable installation when needed.
Jack-up vessels
Transport WTG components to the WDA. Extend legs to the ocean
floor to provide a safe, stable working platform. Used for offshore
accommodations.
Sandwave clearance
(dredging) vessels
Used in certain areas prior to cable laying to remove the upper
portions of sand waves.
Survey vessels
Used to perform geophysical and geotechnical surveys.
Sound field
verification vessels
Monitor sound fields during piledriving.
Service operation
vessels
Transport crew to the WDA. Provide offshore living accommodation
and workspace.
Onboard Generators
Supply power for air compressors and power packs.
Temporary diesel
generators
Temporarily supply power to the OSSs during installation and
commissioning.
Permanent diesel
generators
Supply power to the OSS for brief periods during commissioning.
Some of the vessels used as part of the installation activities listed above in Table 5 may not
meet the definition of an OCS source. CAA Section 328 defines an OCS source as "any
equipment, activity, or facility which: (1) emits or has the potential to emit any air pollutant; (2)
is regulated or authorized under the Outer Continental Shelf Lands Act (OCSLA) (43 U.S.C. §
1331 et seq.); and (3) is located on the OCS or in or on waters above the OCS." 42 U.S.C. §
7627(a)(4)(C). Such activities "include, but are not limited to, platform and drill ship
exploration, construction, development, production, processing, and transportation." Id. The
26
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OCS regulations, at 40 C.F.R. § 55.2, define an OCS source by first incorporating the statutory
language referenced previously and then adding that vessels are considered OCS sources only
when they meet either of the following criteria: (1) the vessel is "[permanently or temporarily
attached to the seabed and erected thereon and used for the purpose of exploring, developing or
producing resources therefrom, within the meaning of section 4(a)(1) of OCSLA (43 U.S.C. §
1331 et seq.)26;" or (2) the vessel is "[pjhysically attached to an OCS source, in which case only
the stationary source aspects of the vessels will be regulated." Thus, for a vessel to be considered
an OCS source, it must meet the three statutory criteria of the OCS source definition and one of
the two additional criteria in the portion of the regulatory OCS source definition that specifically
applies to vessels.
The Environmental Appeals Board (EAB) has issued decisions interpreting the OCS source
definitions in CAA Section 328 and the 40 C.F.R. Part 55 regulations that may provide guidance
when determining if a vessel meets the definition of an OCS source. In one decision, the EAB
recognized that "attachment" for purposes of being an OCS source is not ordinarily "so broad" to
mean "any physical connection." In re Shell Gulf ofMex., Inc., 15 E.A.D. 193, 199 (E.A.B.
2011) {Shell 201F). However, in another case, the EAB affirmed EPA Region 10's
determination that a drill ship satisfies the requirement of being "attached to" the seabed when
one of its anchors is deployed. In re Shell GulfofMex., Inc., 15 E.A.D. 470, 488 (E.A.B. 2012)
{Shell 2012"). Therefore, vessels operating in the WDA that deploy an anchor that connects to
the seabed are similarly attached to the seabed and satisfy this requirement.
In Shell 2011, EPA Region 10 determined an icebreaker vessel is not "attached" to a drill ship
when the icebreaker is setting or receiving the drill ship's anchors. Shell 2011 at 194. In making
this determination, EPA Region 10 defined the purpose of "attachment" as to "prevent or
minimize relative movement" between the vessel and the seabed. Id. at 199. Region 10
determined that the icebreaker is not "attached" to the drill ship sufficient to constitute being an
OCS source because the icebreaker's anchor cable is "repeatedly connected and disconnected"
from one of the drill ship's anchors, and is "not intended in any way to restrict the location of'
the icebreaker. Id. at 200. In finding Region 10's definition of "attachment" to be reasonable, the
EAB also noted the anchor cable is "played out" as the icebreaker travels away from the drill
ship, meaning the anchor cable is not intended to restrict the location of the icebreaker. Id. The
EAB compared the intermittent connection of the icebreaker vessel to the drill ship to a vessel at
dockside, noting that "attachment" in the context of an OCS source is more similar to the latter.
Id. at 200.
In the Shell 2012 EAB decision, the EAB found reasonable EPA Region 10's definition of
"erected thereon" as "intended to reflect the process by which a vessel becomes attached to the
seabed and used thereafter for the purpose of exploring, developing, or producing resources from
the seabed." Shell 2012 at 491. EPA supported this definition by looking to the customary
meaning of the verb "to erect," which is defined as "to construct" or "to build," and thus
26 40 C.F.R. § 55.2 references section (4)(a)(l) of OCSLA, which states in relevant part that laws of the United
States are "extended to the subsoil and seabed of the outer Continental Shelf and to all artificial islands, and all
installations and other devices permanently or temporarily attached to the seabed, which may be erected thereon for
the purpose of exploring for, developing, or producing resources, including non-mineral energy resources,
therefrom." 43 U.S.C. § 1333(a)(1).
27
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reasoned that attachment to the seabed must occur "at the location where OCS activity is
reasonably expected to occur." Id. The phrase "erected thereon" for the purposes of an OCS
source definition requires a secure, stationary activity. For example, when a drillship is "erected"
on the seabed, it remains stationary while it conducts its OCS activity, and is at the location
where the OCS activity (e.g., exploratory drilling) is reasonably expected to occur.
The following subsections describe significant categories of vessels and how their operations
related to the definition of an OCS source and, for OCS sources, the stationary source aspects of
those vessels which will be subject to permitting requirements.
1. Jack-up vessels or jack-up barges
A jack-up vessel meets the first part of the definition of an OCS source because it will be
performing an activity (i.e., constructing a WTG or an OSS) that meets all three of the following
criteria:
a) The diesel-fired or gasoline-fired generating sets will emit air pollutants.
b) BOEM will approve, disapprove, or approve with modifications a construction and
operation plan that allows the jack-up vessel to construct the WTGs and OSS(s) thus
demonstrating the windfarm is authorized under the OCSLA (43 U.S.C. § 1331 et seq.)\
and
c) The jack-up vessel will be located on the OCS or in or on waters above the OCS.
Since the jack-up vessel is a vessel, it must meet one of the two criteria for a vessel to be
considered an OCS source and thus be included as part of the OCS source that is covered in this
permit. The EPA considers a jack-up vessel to meet the definition of an OCS source once three
of the jack-up vessel's legs have attached to the seafloor, because the jack-up unit has become
stationary at this point and is no longer operating as a vessel or a barge. Once that occurs, the
jack-up vessel is "erected" on the seabed since the vessel will not be using its engines to
maneuver itself at that time and it is located in a position according to a plan to conduct OCS
activities, i.e., to participate in the exploration, production, or development of resources from the
seabed.
From that point forward, the jack-up vessel's activity and emissions equipment involve
developing or producing resources from the seabed by erecting a WTG on the seabed that will
convert wind energy into electricity or an OSS to convey this electricity to shore. Once a jack-up
vessel becomes an OCS source, all emission units on the jack-up vessel (including the
construction equipment) are subject to the applicable terms and conditions of the permit. At the
conclusion of the jack-up vessel's construction activities at a given location in the WD A, the
construction equipment ceases to operate and the jack-up legs are raised from the seafloor. The
jack-up vessel's stationary source activities thereon remain regulated as part of the OCS source,
and subject to the terms and conditions of the permit, until the point in time when fewer than
three jack-up legs are attached to the seafloor. Once the jack-up vessel is no longer attached to
the seabed and no longer erected thereon for the purpose of exploration, production, or
development of resources from the seabed, it returns to its status as a vessel and is no longer
subject to the stationary source requirements of Part 55. However, the jack-up barge and its
associated emission units are still included in the potential emissions calculations for the project
28
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at all times when such vessel is within 25 nm of the facility. The jack-up vessel is only subject to
the specific emissions limits during the time it meets the definition of an OCS source (is attached
to the seabed, erected thereon, and used for the purpose of producing, exploring, or developing
resources from the seabed) and thus is regulated as a stationary source under Part 55.
2. Cable-laying vessels
According to RW's application, the offshore cable-laying vessel (CLV) will move along the pre-
determined route within the established corridor towards the OSSs. Cable laying and burial may
occur simultaneously using a lay and bury tool, or the cable may be laid on the seabed and then
trenched post-lay. Alternatively, a trench may be pre-cut prior to cable installation.
EPA has previously determined that cable-laying vessels that utilize pull-ahead anchors or DPS
and are not erected on the seabed for the purpose of exploring for, developing, or producing
resources therefrom are not considered part of the OCS source.27 The emissions from these
vessels are, however, included in the PTE of the OCS source when located at or traveling within
25 nm of the WDA.
3. Support and other vessels
In addition to jack-up vessels, other types of vessels may meet the definition of an OCS source at
some point during the construction or operations phase of the project.
These vessels meet the first part of the definition of an OCS source because the vessels will be
performing an activity (i.e., supporting the construction or operations of a WTG or OSS) and will
meet all three of the following criteria:
1. The gasoline or diesel-powered engines on the vessels will emit air pollutants.
2. BOEM will approve, disapprove, or approve with modifications a construction and
operation plan that allows vessels to support the construction of the WTGs and OSS(s)
and authorizes a right-of-way for the cable, thus demonstrating the wind farm is
authorized under the OCSLA (43 U.S.C. § 1331 et seq.); and
3. The vessels will be operating on the OCS or in waters above the OCS.
As stated earlier in this section, the definition of an OCS source in 40 C.F.R. Part 55 has further
criteria that must be met before a vessel can be considered an OCS source. Servicing fleet
vessels used in the windfarm may temporarily attach to a structure that is part of the OCS source,
another vessel that meets the definition of an OCS source, or to the seabed itself and be erected
thereon (the seabed) and used for the purpose of exploring, developing, or producing resources
therefrom. The criteria within the definition of an OCS source for when a vessel becomes an
OCS source depends on how a vessel is, in essence, remaining stationary on the OCS (i.e., how it
attaches itself to an existing OCS facility or to the seabed) and, in the case of attachment to the
27 See EPA's June 24, 2021 Fact Sheet and January 18, 2022 Response to Comments for the South Fork Wind,
LLC's OCS air permit, available at https://www.epa.gov/gH-permitting/soiith-fork-wind-Hcs-soiith-fork-wiiKlFarm-
onter-continental-shelf-air-perniit.
29
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seabed, whether the vessel is also erected thereon and used for the purpose of exploring,
developing, or producing resources therefrom. For service fleet vessels attached to an OCS
facility, only the stationary source activity occurring on the vessel will be regulated by permit
conditions. The EPA has determined that all air emission units on a service fleet vessel, while
that vessel meets the definition of an OCS source, constitute a stationary source activity because
the vessel will be stationary and the reason for the vessel to be on the waters above the OCS is to
assist in the construction of a stationary source, i.e., a WTG or an OSS.
For service fleet vessels that do not attach to an OCS facility, but temporarily or permanently
attach to the seabed, the service fleet vessel will be considered an OCS source when it is erected
on the seabed and is used for the purpose of exploring, developing, or producing resources from
the seabed.28 Like the jack-up vessels, the criteria "erected thereon" is met when in the WDA the
service fleet vessel attaches itself to the seabed and is in a location where it can reasonably be
expected to conduct OCS activities; thus becoming stationary and used thereafter for the purpose
of exploring, developing, or producing resources from the seabed like constructing a WTG or an
OSS. From that point forward, the service fleet vessel's operations and emissions are related to
developing or producing resources from the seabed by erecting a WTG or the OSS on the seabed
that will convert wind energy into electricity.
4. Crew transfer vessels
At least one crew transport vessel will be needed daily during both the construction and
operational phases. During the O&M phase, typically only crew transfer vessels and/or support
vessels/inflatable boats will be used, unless a major repair is needed. For major repairs to heavy
components, jack-up or crane barges may be required. Crew transfer vessels will be subject to
permit requirements when they meet the definition of an OCS source.
28 Per Section 328 of the CAA, emissions from any vessel servicing or associated with an OCS source, including
emissions while at the OCS source or en route to or from the OCS source within 25 miles of the OCS source, shall
be considered direct emissions from the OCS source. Therefore, emission from the service fleet vessel are still
subject to the permit's NNSR offset requirements once the service fleet vessel is no longer meeting the criteria for
an OCS source.
30
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V. Prevention of Significant Deterioration
Once a source locating on the OCS is determined to be subject to PSD, the EPA must then
determine the emission units that are considered part of the major stationary source associated
with the project. This principle of using the definition within the specific CAA program is
articulated in an EAB Decision In Re Shell Offshore, Inc., Kulluk Drilling Unit and Frontier
Discoverer Drilling Unit, 13 E.A.D. 357, 380 (EAB 2007). The EAB stated in that decision:
We find that the Region correctly concluded that, once it determines an emissions
source located on the OCS is properly classified as an "OCS source," then that
emissions source becomes subject to the requirements of 40 C.F.R. Part 55. Further,
the permitting programs and other requirements to which the OCS source is subject
through Part 55, including the PSD permitting program, then apply to the OCS
source based on the regulations that define the scope of those programs. Specifically,
simply because EPA has identified an OCS source as regulated under the CAA, and
subject to the requirements of Part 55, does not mean it can avoid the next necessary
step of determining the scope of the "stationary source" for PSD purposes.
In accordance with the principle articulated in the decision quoted above, the EPA must
determine whether PSD regulations apply to the windfarm based on the regulations that define
the scope of the CAA permitting program. Since all OCS sources are stationary, the EPA
considers engines on a vessel to be stationary sources and not nonroad engines when the engines
are operating while the vessel meets the definition of an OCS source. The EPA has also
determined that all air polluting devices located on a WTG or an OSS are stationary sources. The
OCS source definition in Section 328(a)(4)(C) of the CAA states that the OCS source includes
"any equipment, activity, or facility which - emits or has the potential to emit any air pollutant."
Furthermore, CAA section 328(a)(4)(D) defines the term "new OCS source" to mean "an OCS
source which is a new source within the meaning of section [111(a)] of [the CAA]." Inherent in
the definition of "new source" under Section 111 is that the source to be regulated is a stationary
source. See Section 111(a)(2) of the CAA.
Moreover, the regulatory definition of OCS source in 40 C.F.R. § 55.2 provides that, for vessels
physically attached to an OCS facility, "only the stationary sources [sic] aspects of the vessels
will be regulated." See 40 C.F.R. § 55.2 (definition of OCS source). For these types of OCS
source-vessels, the "stationary source aspects" of the vessel attached to an OCS source are
regulated by the permit beyond inclusion of its emissions (within 25 nm of the OCS source)
counting as direct emissions from the OCS source for purposes of determining potential
emissions. In other words, the nonroad engines on the vessels will be subject to specific permit
conditions, and its operations emissions and to-and-fro vessels emissions within 25 nm of the
OCS source will count as direct emissions from the OCS source for determining the PTE of the
source. Section 328 of the CAA requires that emission units on OCS sources be regulated as
stationary sources except with respect to emissions from engines being used for propulsion of
vessels while attached to an OCS source. Consideration of the emission sources on a typical
vessel that is determined to be an OCS source makes clear that neither Congress nor EPA could
have intended to exclude otherwise nonroad engines from being regulated as stationary sources if
part of an OCS source. Congress's specific grant of authority to EPA in the 1990 CAA
Page 31 of 133
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amendments to regulate OCS sources would be rendered meaningless if emissions from engines
that would otherwise be considered nonroad engines and that comprise the emission units on the
vessels were excluded from regulation as stationary sources. Given that an engine is a stationary
source when located on an OCS source for purposes of Section 111 of the CAA, it is only logical
to determine that these same engines are stationary sources for purposes of other CAA programs,
including the PSD permit program.
A. Project Aggregation
The initial permit application for South Fork Wind was received by EPA on February 1, 2019,
with a major revised permit application submitted on September 30, 2020. The initial permit
application for RW was received by EPA on May 5, 2022.29 Since the two (2) projects, that is
South Fork Wind and RW, were applied for within a short time period, EPA considered whether
these projects should be evaluated for project aggregation.30
The two windfarm projects were determined to be separate projects because they were not
"substantially related." EPA finds these two projects were not jointly planned. They are not
functionally interconnected, nor are they dependent upon each other to be technically or
economically viable. Approval of each project was made entirely independently of each other,
and each project has separate purchase agreements for the sale of their electricity. Because there
is no technical nor economic relationship between the two projects, EPA finds they are not
"substantively related," and the emissions from the two projects should not be aggregated
through EPA's PSD or NNSR project review.
B. Major Modification Applicability
The PSD program, as set forth in 40 C.F.R. § 52.21 (PSD regulations"), is incorporated by
reference into the OCS Air Regulations at 40 C.F.R. § 55.13(d)(1) for OCS sources located
within 25 nm of a state's seaward boundary if the requirements of 40 C.F.R. § 52.21 are in effect
in the CO A. The EPA has determined that the requirements of sections 160 through 165 of the
Clean Air Act (the authority for the PSD program) are not met in Massachusetts law or
regulations; therefore, the provisions of 40 C.F.R. § 52.21, except paragraph (a)(1), are
incorporated and made a part of the applicable state implementation plan for the Commonwealth
of Massachusetts. See 40 C.F.R. § 52.1165. Therefore, the provisions within 40 C.F.R. § 52.21
are in effect in the CO A.31
29 SFW submitted a NOI on February 1,2019. RW submitted an initial NOI on May 5,2020, and subsequently replaced
it on November 5, 2021. SFW's permit was issued in January 2022. Construction has already commenced and SFW
is expected to be fully operational by the end of 2023. Construction for RW is expected to begin in 2023 and last 12
to 18 months.
30 Project aggregation is a "test" to determine the scope of a project and ensures that nominally seperated projects
occuring at a source are treated as a single project for NSR applicability purposes where it is unreasonable not to
consider them a single project. In the 2009 NSR Aggregation Action (effective date of November 15, 2018), the
EPA affirmed the "substantially related" test as an appropriate standard for assessing project aggregation.
31 The Commonwealth of Massachusetts has taken delegation of EPA's PSD permitting program at 40 C.F.R. §
52.21 by virtue of an agreement for delegation signed by then-Regional Administrator Curtis Spaulding on April 11,
2011. See https://www.epa.gov/sites/defanit/files/2015-08/documents/epa-massdep-psd-deiegation-agreement.pdf
32
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The PSD program applies to new major sources of criteria pollutants or major modifications to
existing sources in areas designated as being in attainment with, or unclassifiable with, the
ambient air quality standards in relation to particular pollutants. "Major modification" means any
physical change in or change in the method of operation of a major stationary source that would
result in: (1) significant emissions increase of a regulated NSR pollutant; and (2) a significant net
emission increase of that pollutant from the major stationary source. Regulated NSR pollutants
(and their precursors) for which an area is in nonattainment are not subject to PSD review even if
the project emission increase and net emission increase is significant. Instead, they are subject to
major NNSR permitting.
Since the source32 is considered an existing PSD major source for NO2 and PM2.5, the emissions
increase from the Revolution Wind project must be evaluated for PSD applicability based on
exceedances to the applicable significance levels. The PSD requirements apply to each regulated
pollutant that a "major source emits in significant amounts" per 40 C.F.R. 52.21(j). Fugitive
emissions must also be considered in evaluating Best Available Control Technology (BACT) and
ambient impacts through these regulations, not distinguishing between stack and fugitive
emissions.
1. Emission Increase Calculation (Project Emission Increase)
For projects that only involve the construction of new emission units, like Revolution Wind, the
significant emissions increase is the new emissions unit's PTE33. For a new emission unit, the
baseline actual emissions (BAE) for purposes of determining the emissions increase that will
result from the initial construction and operation of such unit shall equal zero; and thereafter, for
all other purposes, shall equal the unit's PTE. The applicant has considered fugitive emissions in
the PTE of the project.
For assessing the emission increases from the RW project, emissions from the equipment or
activities considered part of the OCS source and all emissions from vessels servicing or
associated with the project, are included. This includes emissions from vessels, regardless of
whether the vessel itself meets the definition of an OCS source, when the vessels are at or going
to or from an OCS source and are within 25 nm of the source. Thus, emissions from vessels
servicing or associated with an OCS source that are within 25 nm of the OCS source are
considered in determining the PTE or "potential emissions" of the OCS source for purposes of
applying the PSD regulations.
The emissions increases from this project are calculated pollutant by pollutant for each regulated
NSR pollutant. The increases include both project emissions and any emissions from the source
associated with the project. The applicant has not identified any existing emission units from the
32 See Section III. D which concluded that Revolution Wind and the previously permitted South Fork Wind Farm are
considered one stationary source.
33 Under the PSD program, "potential to emit" or PTE is defined as the maximum capacity of a source to emit a
pollutant under its physical and operational design (see 40 C.F.R. §52.21(b)(4)). Typically, emissions from mobile
sources and secondary emissions do not count when determining a stationary source's PTE. However, the definition
of "potential emissions" in the OCS Air Regulations is expanded to include emissions from all vessels servicing or
associated with an OCS source when within 25 nm.
33
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source, i.e., sources associated with the South Fork project, that are affected by the RW project.
Emission decreases are not considered in this step.
Table 6 Emission Increase from the Revolution Wind Project
Revolution Wind -
Project Emission Increase
Regulated NSR Pollutant (TPY)
NOi
CO
PM10
pm25
S02
GHG
(As CChe)
H2S
Mist
Pb
BAE
0
0
0
0
0
0
0
0
PTE
3,964.5
1,039
137.1
133.1
15.0
302,957
0
0.02
A (PTE-BAE)
3,964.5
+1,039
+137.1
+133.1
+15.0
+302,957
-
0.02
As shown in Table 7, a significant emissions increase (per the definition of significant at 40
C.F.R. § 52.21(b)(23))34 of at least one regulated NSR pollutant has occurred. In addition, the
pollutant Greenhouse Gases (GHG) is subject to regulation if the stationary source is an existing
major stationary source, a regulated NSR pollutant that is not GHG has triggered the Significant
Emission Rate (SER) and the project results in a GHG emission increase of 75,000 TPY CChe or
more.
Table 7 Worst Case Annual Emission Estimate Compared with PSD Significant Emissions Mate (SER)
Thresholds
NSR Regulated
Pollutant
Project Emission
Increase (TPY)
PSD SER (TPY)
SER Triggered? (Y/N)
no2(1)
3,964.5
40
Y
CO
1,039
100
Y
PM10
137.1
15
Y
PM2.5
133.1
10
Y
S02
15.0
40
N
GHG (as C02e)
302,957
75,000
Y
Sulfuric Acid Mist
0
7
N
Lead
0.02
0.6
N
( V) Nitrogen dioxide is the compound regulated as a criteria pollutant under PSD; however, significant emissions rate
for NSR is based on the sum of all oxides of nitrogen, i.e., NOx. Note that for PSD permitting purposes, NOx = N20
+NO2.
34 Per 40 C.F.R. § 52.21(b)(49), for the pollutant GHGs, an emissions increase shall be based on CC^e, and
shall be calculated assuming the pollutant GHGs is a regulated NSR pollutant and "significant" is defined
as 75,000 TPY C02e.
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2. Emission Netting (Contemporaneous Netting)
Per 40 C.F.R. § 52.21(b)(3), the definition of a "net emission increase" consists of two
components:
1) Any increases in actual emissions from a particular physical change or change in the
method for operation from a stationary source (i.e., Emission Increase Calculation
(Project Emission Increase)); and
2) Any other increase and decrease in actual emission at the source that are
contemporaneous with the change and are otherwise creditable.
In other words, netting looks at the other projects that may have been or will be undertaken at a
given facility over the contemporaneous period.
RW is not pursuing a Step 2 contemporaneous netting analysis.
3. Summary
Based on the emission levels for the project, as presented in Table 7, NO2, CO, PM10, PM2.5, and
GHG are the NSR regulated pollutants that will be emitted by RW in quantities exceeding the
respective PSD SER. The applicant has identified no anticipated contemporaneous creditable
emissions increases or decreases for the proposed project (RW). Therefore, the RW project is
considered a major modification.
Note that ozone (and therefore its precursors NOx and VOC) is subject to NNSR and is therefore
not explored further in this section35. See Section VI.B.
C. Best Available Control Technology (BACT)
BACT is defined in the applicable permitting regulations at 40 C.F.R. § 52.21(b)(12), in relevant
part, as
an emissions limitation (including a visible emission standard) based on the
maximum degree of reduction for each pollutant subject to regulation under the 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 C.F.R. Parts 60, 61, or 63. If the Administrator determines that
35 Duke County is a designated nonattainment area for ozone, and Massachusetts is also part of the Ozone Transport
Region (OTR). Therefore, for permitting purposes Duke County is treated as a moderate nonattainment and the
ozone precursors NOx and VOC are not subject to PSD review. NOx and VOC are subject to major NNSR
permitting. The pollutants subject to LAER are NOx and VOC (See Section VI).
35
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technological or economic limitations on the application of measurement
technology 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.
The CAA contains a similar B ACT definition, although the 1990 CAA amendments added
"clean fuels" after "fuel cleaning or treatment" in the above definition. See CAA § 169(3).
Therefore, the permitting authority must establish a numeric emission limitation that reflects the
maximum degree of reduction achievable for each pollutant subject to BACT through the
application of the selected technology or technique. However, if the permitting authority
determines that technical or economic limitations on the application of a measurement
methodology would make a numerical emission standard infeasible for one or more pollutants, it
may establish design, equipment, work practices, or operational standards to satisfy the BACT
requirements.
1. Methodology
The EPA's longstanding approach to implementing BACT is to require a "top-down" BACT
analysis to demonstrate that the BACT requirement is satisfied for each emission unit that emits
a regulated NSR pollutant subject to PSD review. This methodology is outlined in EPA policy
memoranda and supported by the EAB.36'37
Step 1 - Identify All Control Technologies
Available control technologies are identified for each emission unit in question. The following
methods are used to identify a comprehensive list of potential technologies:
1. Researching the Reasonability Available Control Technology (RACT)/Best Achievable
Control Technology (BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse
(RBLC) database;
2. Researching the CARB (California Air Resource Board) and South Coast Air Quality
Management District (SCAQMD) database;
3. Surveying air pollution control equipment vendors, and
4. Surveying available literature.
5. Previously issued permits
36 See EPA's "Guidance for Determining BACT Under PSD" at https://www.epa.gov/sites/prodiiction/files/2015-
07/documents/bactiipsd.pdf and New Source Review Workshop Manual: Prevention of Significant Deterioration and
Nonattainment Area Permitting (draft Oct. 1990) at https://www.epa.gov/sites/prodiietlon/fites/2015-
07/documents/1990wman.pdf
37 See, e.g., In re: Prairie State Generating Company, 13 E.A.D. 1, 12 (EAB 2006)
36
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Step 2 - Eliminate technically infeasible options
After the identification of control options, an analysis is conducted to eliminate technically
infeasible options. A control option is eliminated from consideration if there are process-specific
conditions that prohibit the implementation of the control technology or if the highest control
efficiency of the option would result in an emission level that is higher than any applicable
regulatory limits.
Step 3 - Rank remaining control technologies
Once technically infeasible options are removed from consideration, the remaining options are
ranked based on their control effectiveness. If there is only one remaining option or if all the
remaining technologies could achieve equivalent control efficiencies, ranking based on control
efficiency is not required.
Step 4 - Evaluate most effective controls and document results.
Beginning with the most efficient control option in the ranking, detailed economic, energy, and
environmental impact evaluations are performed. If a control option is determined to be
economically feasible without adverse energy or environmental impacts, it is not necessary to
evaluate the remaining options with lower control efficiencies. The economic evaluation centers
on the cost effectiveness of the control option.
Step 5 - Select BACT
In the final step, one pollutant-specific control option is proposed as BACT for each emission
unit under review based on evaluations from the previous step.
2. BACT Analysis for the Revolution Wind Project
A BACT analysis is required for each pollutant which exceeds an applicable PSD SER. See 40
C.F.R. § 52.21(j). Based on the emission levels for the project, as presented in Table 7, NO2, CO,
PM, PM10, PM2.5, and GHG are the NSR regulated pollutants that will be emitted by RW and
subject to PSD.
High Level Summary of BACT Determination
For offshore engines on the wind turbine generators and/or offshore substations, BACT has been
determined to be use of the highest Tier EPA Certified Engine (i.e., Tier 3 or 4, dependent on the
final selected engine size and associated displacement) within 40 CFR Part 60, Subpart IIII, and
operated in accordance with a Good Combustion and Operating Practices ("GCOP") Plan.
For marine engines on vessels that operate as an OCS source, BACT has been determined to be
use of the Marine Engine that is certified to the highest Tiered Exhaust Emission Standards (i.e.,
Tier 3 or 4, dependent on the final selected engine size and associated displacement) within 40
CFR Part 60, Subpart IIII and operated in accordance with a Good Combustion and Operating
37
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Practices ("GCOP") Plan. Note that for third party-contracted U.S. vessels where the availability
of the vessel type at the time of the application is unknown, BACT has been determined to be
use of the Marine Engine that is certified to the highest Tiered Exhaust Emission Standards (i.e.,
Tier 3 or 4, dependent on the final selected engine size and associated displacement) within 40
CFR Part 60, Subpart IIII at time of deployment and operated in accordance with a Good
Combustion and Operating Practices ("GCOP") Plan. Specific Conditions related to the time of
deployment are justified in the subsection below. For third party-contracted U.S. or foreign-
flagged vessels where the availability of the vessel type at the time of the application is
unknown, BACT has been determined to be use of the Engines certified to the highest Tiered
Exhaust Emission Standards (i.e., Tier III) within 40 MARPOL Annex VI at time of deployment
and operated in accordance with a Good Combustion and Operating Practices ("GCOP") Plan.
Specific Conditions related to the time of deployment are justified in the subsection below.
For the switchgears on the offshore substations, BACT has been determined to be leak rate of
SF6 not to exceed 0.5% per year (-222 TPY C02e) from all the MV and HV SWGs on the OSS.
The following sections document the top-down BACT determination in more detail.
a. Emission Unit Applicability
The RW project is required to apply BACT to all the new emission units proposed in this project.
The Project's emission sources will primarily be compression-ignition internal combustion
engines (CI-ICE). These include engines on vessels while operating as OCS source(s) and
engines on the wind turbine generators (WTGs) and offshore substations(s) (OSS[s]).
Table 8 Emission Unit Group (EUG) 1 - Offshore Generators on WTGs and OSS(s)
EU ID
Description
Type of
Equipment
Engine
Count
Engine
Rating, kW
(hp)
Hours per
Engine
Construction Equipment
RW-1, RW-2
OSS/OCS Installation &
Commissioning
Auxiliary Generator
on OSS/OCS
2
597 (800)
4,800
RW-3, RW-4,
RW-5, RW-6
Offshore OSS/OCS
Installation &
Commissioning
Temporary
Generator on OSS
4
156 (209)
17,5201
RW-7
Offshore Array Cable
Installation
Generator for Cable
Pull-WTG
1
37 (50)
600
RW-8, RW-9
Offshore Array Cable
Installation
Generator for Cable
Pull-OSS/OCS
2
75 (100)
240
RW-10, 11
Offshore WTG Installation
& Commissioning
Temporary
Generator on WTG
2
24 (32)
120
Operating Equipment
RW-12, 13
OSS/OCS Permanent
Generators
Generator on
OSS/OCS
2
597 (800)
500
RW-14 thru
RW-20
WTG O&M Repair
Generator on WTG
6
120 (160)
720
1 Note that this represents the hours of operation during the entire construction period of the project (i.e., 8,760 hpy
x 2 yrs.)
38
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A marine vessel38 typically has two (2) kinds of engines which are considered OCS emission
sources: 1) Propulsion engines, also referred to as main engines, which supply power to move
the vessel but could also be used to supply power for purposes of performing a given stationary
source function (e.g., to lift, support, and orient the components of each WTG during
installation), and 2) Auxiliary engines, which supply power for non-propulsion (e.g., electrical)
loads. The applicant has identified the anticipated horsepower ratings for propulsion and
auxiliary engines, Table 9. Note that RW does not yet know specifically which engines or
vessels will be utilized for the project. Vessel availability is constrained by the limited number of
vessels capable of conducting the work, availability of those vessels at a given time, and
limitations imposed by the Jones Act39. The procurement of the vessels, which are indicated to
change on short notice, require contracts within short timeframes due to the specific nature of the
OCS project, which is described in more detail below. Thus, the vessel engine types that can be
secured at the projected time of construction are unknown at the time of publication of this fact
sheet. EPA is considering these facts in the analysis.
Table 9 EUG 2 - Marine Engines on Vessels Operating as Potential OCS Source(s)
Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Monopile Installation
Heavy Lift Installation Vessel
26,640
1,100
Monopile Installation
Heavy Lift Installation Vessel
34,560
1,100
Monopile Installation
Heavy Lift Installation Vessel
(Generator Small)
NA
4
Monopile Installation
Heavy Lift Installation Vessel
(Power Pack)
NA
746
Monopile Installation
Towing Tug (for fuel barge)
11,060
238
Monopile Installation
Anchor Handling Tug
11,060
238
Monopile Installation
Rock Dumping Vessel
13,500
1,692
Monopile Installation
Vessel for Bubble Curtain
11,060
874
Monopile Installation
Vessel for Bubble Curtain
(Generator (Large))
NA
358
38 Large Marine Vessels are noted to typically have Category 3 (C3) engines, which have a per cylinder displacement
of 30 L/cylinder or more; however, some could have smaller Category 1 (CI) or Category 2 (C2) engines. To be
classified as a Category 2 (C2) marine engine, it must be rated to have a displacement greater than or equal to 7.0
L/cylinder and less than 30.0 L/cylinder. To be classified as a Category 1 (CI) marine engine, it must be rated to have
a displacement less than 7.0 L/cylinder. For Tier 1 and Tier 2, the line between Category 1 and Category 2 was set at
5.0 L/cylinder rather than 7.0 L/cylinder (40 CFR 1042).
39 Generally, the Jones Act is a U.S. law that requires vessels that ship merchandise and passengers between two
U.S. points to be U.S. built and registered (flagged), as well as owned and crewed by U.S. citizens or residents. See
generally, Charlie Papavizas, Jones Act Considerations for the Development of Offshore Windfarms, 20 BENEDICT'S
Mar. Bull. [1] (First Quarter 2022) (available at https://www.winston.eom/images/content/2/6/v2/262961/First-
Ouarter-2022-Benedict-s-Maritime-Bulletin-Papavizas.pdf). U.S.C. § 55102(b), part of the Merchant Marine Act of
1920, also known as the Jones Act, precludes a vessel from providing "any part of the transportation of merchandise
by water, or by land and water, between points in the United States to which the coastwise laws apply, either directly
or via a foreign port, unless the vessel —(1) is wholly owned by citizens of the United States for purposes of
engaging in the coastwise trade; and (2) has been issued a certificate of documentation with a coastwise
endorsement under chapter 121 or is exempt from documentation but would otherwise be eligible for such a
certificate and endorsement." Also part of the Jones Act, U.S.C. § 55103(a) precludes a vessel from transporting
passengers between ports or places in the United States to which the coastwise laws apply, either directly or via a
foreign port, unless the vessel--(l) is wholly owned by citizens of the United States for purposes of engaging in the
coastwise trade; and (2) has been issued a certificate of documentation with a coastwise endorsement under chapter
121 or is exempt from documentation but would otherwise be eligible for such a certificate and endorsement.
39
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Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Monopile Installation
Heavy Transport Vessel
(Generator (Small))
NA
4
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Crew Transport Vessel
2,352
48
Monopile Installation
PSO Noise Monitoring Vessel
11,060
238
Monopile Installation
Platform Supply Vessel
6,000
874
Monopile Installation
Platform Supply Vessel
1,825
525
OSS Topside Installation
Heavy Transport Vessel
13,000
1,220
Turbine Installation
Jack-up Installation Vessel
21,000
895
Turbine Installation
Jack-up Installation Vessel
(Generator (Small))
NA
4
Turbine Installation
Jack-up Installation Vessel
(Cherry Picker)
NA
67
Turbine Installation
Feeder Barge (Generator (Large))
NA
30
Turbine Installation
Towing Tug (for fuel barge)
11,060
238
Offshore Export Cable &
OSS Link
Pre-Lay Grapnel Run
12,780
968
Offshore Export Cable &
OSS Link
Boulder Clearance Vessel
2,803
964
Offshore Export Cable &
OSS Link
Sandwave Clearance Vessel
7,300
964
Offshore Export Cable &
OSS Link
Cable Lay and Burial Vessel
8,946
2,800
Offshore Export Cable &
OSS Link
Cable Burial Vessel - Remedial
8,946
2,800
Offshore Export Cable &
OSS Link
Tug - Small Capacity
4,049
238
Offshore Export Cable &
OSS Link
Tug - Large Capacity
11,060
238
Offshore Export Cable &
OSS Link
Crew Transport Vessel
2,204
201
Offshore Export Cable &
OSS Link
Guard Vessel/Scout Vessel
400
201
Offshore Export Cable &
OSS Link
Survey Vessel
1,302
418
Offshore Export Cable &
OSS Link
DP2 Construction Vessel
12,780
964
Offshore Export Cable &
OSS Link
Misc. Floating Equipment
Landfall
400
201
Offshore Export Cable
Barge Lay (Generator (Small))
NA
75
Offshore Export Cable
Barge Lay (Crane Type 1)
NA
567
Offshore Export Cable
Barge Lay (Generator (Large))
NA
187
Offshore Export Cable
Barge Lay (Power Pack)
NA
373
Offshore Export Cable
Barge Lay (Cherry Picker)
NA
112
Offshore Export Cable
Barge Lay (Excavator)
NA
567
Offshore Export Cable
Support Barge (Generator (Large))
NA
45
Offshore Export Cable
Support Barge (Cherry Picker)
NA
567
Offshore Array Cable
Pre-Lay Grapnel Run
12,780
964
40
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Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Offshore Array Cable
Boulder Clearance Vessel
2,803
964
Offshore Array Cable
Sandwave Clearance Vessel
7,300
964
Offshore Array Cable
Cable Laying Vessel
8,946
2,800
Offshore Array Cable
Cable Burial Vessel
8,946
2,800
Offshore Array Cable
Crew Transport Vessel
2,204
201
Offshore Array Cable
Walk to Work Vessel (SOV)
6,440
N/A
Offshore Array Cable
Survey Vessel
1,302
418
Offshore Array Cable
Construction Vessel
6,440
N/A
Offshore Cable Transport
Cable Laying Vessel
8,946
2,800
Offshore Cable Transport
Array Cable Transport Freighter
7,950
3,026
All Construction Activities
Safety Vessel 1
400
201
All Construction Activities
Safety Vessel 2
400
201
All Construction Activities
Crew Transport Vessel
2,352
201
All Construction Activities
Crew Transport Vessel
2,162
201
All Construction Activities
Crew Transport Vessel
2,984
100
All Construction Activities
Lift Boat
6,000
N/A
All Construction Activities
Supply Vessel
7,530
N/A
All Construction Activities
Service Operation Vessel
6,920
201
Fisheries Monitoring
for Lobster, Lease Site
400
201
Fisheries Monitoring
for Trawl Survey
400
201
Fisheries Monitoring
for Lease Site Acoustic Telemetry
400
201
Fisheries Monitoring
for Lobster, Export Cable
400
201
Marine Mammal
Mitigation
for Situational Awareness
400
201
Marine Mammal
Mitigation
for Long Term Acoustic
400
201
Marine Mammal
Mitigation
for ST Long Term Studies
400
201
Other units at this facility that are subject to a top-down BACT analysis are the medium voltage
(MV) and high-voltage (HV) gas-insulated switchgears on the OSS because they have the
potential to emit SF6, which is a GHG. The facility has also stated in their permit application that
the WTGs, which are equipped with low voltage (LV) switchgears will not utilize SF6 and not
have any potential emissions. Therefore, only the MV and HV GIS located on the OSS are
required to apply BACT. See Table 10.
Table 10 EUG 3 - Medium, and High Voltage GIS on the OSS
EU ID
Description
Type
Count (# GIS)
Maximum Quantity
MV-GIS
MV GIS (66kV) on OSS/ESP
sf6
2
858 kg per OSS
HV-GIS
HV GIS (220 kV-400 kV) on OSS/ESP
sf6
2
858 kg per OSS
41
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Pollutant Formation and
Reduction Mechanisms
Emission(s) of NOx from
Compression Ignition (CI)-Internal
Combustion Engines (ICE)
Emission(s) of CO from CI-ICE
Emission(s) of VOC from CI-ICE
Emission(s) of PMi 0/2.5 from CI-ICE
Emission(s) of SO2 from CI-ICE
Emission(s) of GHG from CI-ICE
Emission(s) of GHG from GIS
Air emissions of nitrogen oxides occur by two (2) different mechanisms.
The predominant mechanism for engines is thermal NOx. Most of the
NOx formed from CI-ICE is from thermal NOx due to the high flame
temperatures and pressures of engines. The maximum reduction of thermal
NOx generation can be achieved by control of both the combustion
temperature and the stoichiometry. The second mechanism, fuel NOx,
stems from the evolution and reaction of fuel-bound nitrogen compounds
with oxygen. For diesel, little fuel NOx is formed, except in engines that
fire residual and/or crude oils. Here, as with thermal NOx, controlling
excess O2 (stoichiometry) is an important part of controlling NOx
formation.
Carbon monoxide is a colorless, odorless, relatively inert gas formed as an
intermediate combustion product that appears in the exhaust when the
reaction of CO to CO2 cannot proceed to completion. This situation occurs
if there is a lack of available oxygen near the hydrocarbon (fuel) molecule
during combustion, if the gas temperature is too low, or if the residence
time in the cylinder is too short. The oxidation rate of CO is limited by
reaction kinetics and, consequently, can be accelerated only to a certain
extent by improvements in air and fuel mixing during the combustion
process.
Volatile organic carbon compounds that are found in diesel exhaust are
commonly a result of unburned fuel, although some are formed as
combustion products. VOC compounds participate in atmospheric
photochemical reactions. These reactions can result in the formation of
ozone. VOCs do not include methane, ethane, and other compounds that
have negligible photochemical reactivity. Air emissions of VOC from CI-
ICE are generally minimized by ensuring complete combustion.
White, blue, and black smoke may be emitted from CI-ICE. Liquid
particulates appear as white smoke in the exhaust during an engine cold
start, idling, or low load operation. These are formed where the
temperature is not high enough to ignite the fuel. Blue smoke is emitted
when lubricating oil leaks, often past worn piston rings, into the
combustion chamber and is partially burned. Proper maintenance is the
most effective method of preventing blue smoke emissions from all types
of CI-ICE. The primary constituent of black smoke is agglomerated
carbon particles (soot).
Sulfur Dioxide is formed based on the sulfur content in the fuel rather than
any combustion variables. In fact, during the combustion process,
essentially all the sulfur in the fuel is oxidized to SO2.
MA regulations define greenhouses gas as carbon dioxide, CH4, N20, and
hydrofluorocarbons. CO2 emissions are the primary GHG component from
CI-ICE.
SF6 is used as an electrical and thermal insulating gas in electrical
switchgears to prevent electrical arcing and minimize transmission losses.
Page 42 of 133
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(1) Step 1 - Identify All Available Control Technologies
The first step in the top-down BACT process is to identify all "available" control options. To
satisfy the statutory requirements of BACT, EPA believes that the applicant must focus on
technologies that have been demonstrated to achieve the highest levels of control for the
pollutant in question, regardless of the source type in which the demonstration has occurred.
EUG 1—OCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
A RBLC search was completed for the last 10 years of determinations (,August 12, 2012, through
August 12, 2022) using the following process types: 1.) 17.110- Large ICEs (> 500 HP) - Fuel
Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel); 2.) 17.210 - Small ICEs (< 500 HP) -
Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). The resulting determinations
were divided into three searches: large emergency/non-emergency engines (>500 HP), and small
emergency/non-emergency engines (<500 HP). These results are summarized within the permit
application and can be found within the RBLC database after performing a search using the
criteria mentioned above. Identification of other BACT options from previously issued air permit
determinations were also considered.
The applicable air pollution control technologies or techniques (including lower-emitting
processes and practices) that have the potential for practical application to the emissions unit are
listed in Table 11.
Table 11 Options of Control Technologies or Techniques for EUG 1
Control Technology
Pollutant(s)
Note(s)
Good Combustion
Practices
NO2, PM10,2.5,
CO, GHG
Use of good combustion practices based on the most
recent manufacturer's specifications issued for these
engines.
Highest applicable EPA
Tier Marine Engine at
40C.F.R. Part 1042 or
EPA Tier 4 Nonroad
Engine at 40 C.F.R. Part
1039
NO2, PM10,2.5,
CO
Tier 2 and Tier 3 certified engines are designed to
incorporate pre-combustion controls such as fuel injection
timing, exhaust gas recirculation, and other engine-based
technologies to meet emissions standards. In addition to
the pre-combustion controls, Tier 4 certified engines may
be equipped with an integrated Selective Catalytic
Reduction (SCR), Diesel Particulate Filter (DPF), and/or
Diesel Oxidation Catalyst (DOC).
Diesel Particulate Filter
PM10,2.5
Add-on air pollution control devices. One or more DPFs
or DOCs may be installed (retrofitted) on a Tier 2 or Tier
3 engine to further reduce emissions.
Page 43 of 133
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Control Technology
Pollutant(s)
Note(s)
Diesel Oxidation
PMio,2.5, CO
Catalyst1
vfotes:
1 RBLC Determination No. WV-0033 lists a BACT CO emission limit of 0.41 g/kW-hr (overall reduction of 88.3 %
with the use of catalytic oxidation). The RBLC notes that for this case the applicant did not justify why catalytic
oxidation was infeasible for the 2,100 HP Emergency Generator (EG-01). However, the emision limitation in the
RBLC Determination No. WV-003 for this unit might not reflect the BACT achievable in practice since it has not
been verified - particularly since the reduction appears to be applied to an engine already certified to meet Tier 4
emission standards. Nonetheless, Permit No. R14-0038 does appear to require catalytic oxidation on EG-01 and a
CO emission limit of 0.41 g/kW-hr (i.e., BACT). However, Specific Condition 5.1.1 (g) states that, "When in
operation other than startup or shutdown periods, the engine for EG-01 shall be a constant-speed engine." This is
problematic for the engines proposed with the RW project since technical difficulties are assumed to exist when the
engines are operated invariable conditions (and not just in steady state scenarios). RW has stated that the engines
are not intended to operate under constant steady state loads or temperatures for a sufficient time necessary for high
catalyst performance. Although Catalytic Oxidation may be infeasible in practice based on the specific operating
conditions and engine parameters, the highest CO reductions could theoretically be achieved using this technology.
EUG 2—Marine Engines on Vessels when operating as OCS Source(s)
A RBLC search was completed for the last 10 years of determinations (August 12, 2012, through
August 12, 2022). Note that the RBLC only contained permit information from facilities with an
air permit for oil production in the eastern Gulf of Mexico since that is the only part of the Gulf
where EPA has OCS permitting jurisdiction (RBLC ID: FL 0350, FL 0347, FL 0338, FL 0348).
The western and central Gulf of Mexico are under BOEM jurisdiction and are not subject to OCS
permitting requirements. EPA also reviewed the previous OCS Permits Determinations issued to
South Fork Wind and Vineyard Wind 1.
The applicable air pollution control technologies or techniques (including lower-emitting
processes and practices) that have the potential for practical application to the emissions unit are
listed in Table 12.
Table 12 Options of Control Technologies or Techniques for EUG 2
Control Technology
Pollutant(s)
Note(s)
Good Combustion
Practices
NO2, PM10,2.5,
CO, GHG
The RBLC included a requirement for the permittee to
develop a Good Combustion and Operating Practices
(GCOP) Plan. The plan shall be incorporated into the
plant standard operating procedures (SOP) and shall be
made available for inspection. The plan was specifically to
include, but not be limited to: 1) A list of combustion
optimization practices and a means of verifying the
practices have occurred. 2) A list of combustion and
operation practices to be used to lower energy
consumption and a means of verifying the practices have
occurred. 3) A list of the design choices determined to be
BACT and verification that designs were implemented in
the final construction.
44
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Control Technology
Pollutant(s)
Note(s)
Highest applicable EPA
Tier Marine Engine at
40 C.F.R. Part 1042
NO2, PM10,2.5,
CO
Tier 2 and Tier 3 certified engines are designed to
incorporate pre-combustion controls such as fuel injection
timing, exhaust gas recirculation, and other engine-based
technologies to meet emissions standards. In addition to
the pre-combustion controls, Tier 4 certified engines may
be equipped with an integrated SCR DPF, and/or DOC.
Highest applicable
MARPOL Annex VI
Tier NOx emission
limits
N02
U.S. flagged vessels must have an Engine International
Air Pollution Prevention (EIAPP) certificate, issued by
EPA, to document that the engine meets Annex VI NOx
standards. Foreign flagged vessels must have an
International Air Pollution Prevention Certificate (IAPP)
to document that the engine meets Annex VI NOx
standards ^
Diesel Particulate Filter
(DPF)
PM10,2.5
Add-on air pollution control devices. One or more DPFs
or DOCs may be installed (retrofitted) on a Tier 2 or Tier
3 engine to further reduce emissions.
Diesel Oxidation
Catalyst (DOC)
PM10 2 5, CO
(V) The Annex VI requirements40 apply to U.S.-flagged ships wherever located and to foreign-flagged ships operating
in U.S. waters. Vessels that operate only domestically are exempt from the NOx limits of 40 C.F.R. Part 1043 provided
that their engines meet the requirements of 40 C.F.R. Part 1042 (including Appendix I) and have a displacement of
less than 30 liters per cylinder. Foreign-flagged vessels are exempt from having to meet the marine standards within
40 C.F.R. Part 1042 and are required to meet the emission standards in 40 C.F.R. Part 1043.
EUG 3—Medium Voltage, and High Voltage Gas Insulated Switchgears on the OSS
The applicable air pollution control technologies or techniques (including lower-emitting
processes and practices) that have the potential for practical application to EUG 3 are listed as
follows:
• The Commonwealth of MA implements regulations under 310 CMR 7.72 to assist in
GHG emission reduction goals by reducing SF6 emissions from GIS through the
imposition of declining annual aggregate emission limits and other measures, which are
1.) Per 310 CMR 7.72 (4)(a), any newly manufactured GIS that is placed under the
ownership, lease, operation, or control of any GIS owner on or after January 1, 2015,
must be represented by the manufacturer to have a 1.0% maximum annual leak rate, 2.)
Per 310 CMR 7.72 (4)(b), any GIS owner that places GIS under ownership, lease,
operation, or control on or after January 1, 2015, shall comply with any manufacturer-
recommended maintenance procedures or industry best practices that have the effect of
reducing leakage of SF6, and 3.) Annual reporting requirements contained in 310 CMR
7.72 (6), including but not limited, the number of pounds of SF6 emitted from GIS
40 In the United States (US), MARPOL Annex VI is implemented through the Act to Prevent Pollution from Ships
(33 U.S.C. §§ 1901-1905) and 40 C.F.R. Part 1043.
45
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equipment owned, leased, operated, or controlled by the federal reporting GIS owner and
located in Massachusetts during the year, using the equation specified in 40 C.F.R. §
98.303.
The RW project can comply with more stringent requirements based on their equipment
specifications and has proposed the following as BACT:
• A maximum annual leak rate not to exceed 0.5%, which is more stringent than the
requirement contained in 310 CMR 7.72 (4)(a). See Section (4).
• The applicant has proposed operating a Sealed System with leak detection and alarms and
to complete any leak detection repair within 5 days of discovery, which complies with the
requirement contained in 310 CMR 7.72 (4)(a). See Section (4).
The permit applicant is not proposing air insulated switchgear and alternative gas insulation
switchgear technology for Step 1 of the GHG top-down BACT analysis, and the underlying
permit record supports this exclusion, because inclusion of such technology would frustrate the
inherent business purposes of the project and constitute a redefinition of the source (i.e., use of
SF6 containing GIS configuration on the OSS').41 The purpose of the RW project is to provide
renewable energy within a specific timeframe, which provides the opportunity to displace fossil
fuel powered energy, and which will assist states in New England with renewable portfolio
standards and clean energy targets to address climate change. Revolution Wind has entered into
three Power Purchase Agreements with Rhode Island and Connecticut for 704 MW of renewable
energy generation capacity. Air insulated switchgear and alternative gas insulation switchgear
technology was not available to the permit applicant during the initial project design and
equipment acquisition processes, and use of such technology would require a redesign of the
project and lead to a significant delay. For RW to be able to use alternative gas insulation
switchgears in lieu of the traditional SF6 gas insulated switchgear would require a full redesign
of the OSS since dimensions, footprint, and weight for alternative gas insulated switchgear
technology is indicated to be different than traditional SF6 gas insulated switchgears,42 which
would result in a 19-month delay to the current anticipated start date for the project. Further
delays in the anticipated start date would be expected if structural modifications would be
necessary for the OSS topside structure, and if there are delays in the availability of specialized
lifting vessels needed to incorporate air insulated switchgear and/or alternative gas insulation
switchgear technology in the OSS.
41 EPA has recognized that a Step 1 list of options need not necessarily include inherently lower polluting processes
that would fundamentally redefine the nature of the source proposed by the permit applicant. However, any decision
by an applicant to exclude an option because it may "redefine the source" must be explained and documented in the
permit record. EPA states that "BACT should generally not be applied to regulate the applicant's purpose or
objective for the proposed facility." (See PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-
11-001, March 2011).
42 While a conventional air insulated switchgear requires several feet of air insultation to isolate a conductor, SF6 gas
insulation needs only inches, allowing SF6 gas insulated equipment to fit into a much smaller space than air
insulated equipment.
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EPA has reviewed the administrative record and supplemental documentation with respect to
how the applicant has framed the goal, objectives, purpose, and basic design for this proposed
project. Based on the information submitted, EPA concludes that SF6 gas insulated switchgear on
the OSS is considered an essential design element and is necessary to achieve the goals of this
specific RW project (delivering renewable power onshore within the committed timeline, which
will offset fossil fuel powered generation).
(2) Step 2: Eliminate Technically Infeasible Option(s)
Below is a summary of the reasons for eliminating from further consideration, or justification for
not eliminating from further consideration, each of the air pollution control options listed above
for Step 1 of the top down BACT analysis for this project. For more details, please refer to the
permit application and support documents in the docket. In general, the EPA considers a
technology technically feasible if: 1) it has been demonstrated and operated on the same type of
source, or 2) it is "available" and "applicable." Therefore, technical feasibility for "demonstrated
and operated" or "available and applicable" control technologies is included in the analysis for
the different BACT options listed in Step 1 of the top-down BACT analysis.
EUG 1 - PCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
Good combustion practices - Good combustion practices entail operating the engine according
to the manufacturer's recommendations and generally accepted industry practices. Since this
practice is "demonstrated and operated" this potential BACT option is technically feasible.
Purchase the Highest Tier Certified Engine under NSPS IIII - OCS Generator Engine(s)
installed on the OSS and/or WTG that are certified to the highest applicable EPA Tier Marine
Engine Standards at 40 C.F.R. Part 1042 or EPA Nonroad Engine Standards at 40 C.F.R. Part
1039 are equipped with an integrated SCR, DPF, and/or DOC are considered a demonstrated and
operated control technology because the Tier Certified emission standards consider the reduction
in pollution from the integrated technologies in the design. Therefore, this potential air pollution
control option is technically feasible.
As of the release of this fact sheet, Marine Tier 3 and Marine Tier 4 emission standards required
by 40 C.F.R. Part 1042 are fully in effect, and U.S. EPA has not adopted more stringent
certification standards for the marine sector. Therefore, the Marine Tier 3 (Category 3 Marine
Engines) and Marine Tier 4 (Category 1 and 2 Marine Engines) NOx, HC, CO, and PM emission
standards43 represent the most stringent level of emissions control required by 40 C.F.R. Part
1042. Similarly, the Tier 4 Nonroad Standards emission standards required by 40 C.F.R. Part
1039 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
the nonroad sector. Therefore, the Nonroad Tier 4 NOx, HC, CO, and PM emission standards44
represent the most stringent level of emissions control required by 40 C.F.R. Part 1039 as it has
been demonstrated and operated and thus it is technically feasible.
43 The Tier 3 and Tier 4 marine engine emission standards may be certified to NOx, HC, or NOx + HC.
44 Depending on engine size, the Tier 4 nonroad engine emission limits may be certified to nonmethane hydrocarbon
(NMHC) + NOx, or NMHC and NOx separately.
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Retrofit a Tier 1, Tier 2, or Tier 3 Engine with Diesel Oxidation Catalyst and/or Diesel
Particulate Filter - DOCs are flow-through aftertreatment devices containing a catalytic coating
that oxidize CO, gaseous HCs, and liquid HCs, thus lowering PM and CO emissions from diesel
fueled vehicles and equipment. Engine manufacturers have used DOCs in different in-use
applications for many years, and DOCs are widely used as a retrofit technology because of their
simplicity and limited maintenance requirements. DOCs have also been verified in combination
with crankcase ventilation systems for additional emissions reduction. In general, exhaust
temperature increases with engine power and can vary dramatically as engine power demands
vary. A minimum exhaust temperature is required for the catalyst to operate effectively.45 A DPF
Level 3 reduces diesel particulate matter by 85 percent or greater.46 In a DPF, a high temperature
exhaust gas, a fuel burner, or an electric heater is used to increase the temperature of the filter so
that collected PM can be oxidized. The exhaust gas must reach approximately 500 °C in a DPF.
DPFs are verified for use with Ultra Low Sulfur Diesel fuel (ULSD). Fuel additives should not
be used unless explicitly approved by the DPF manufacturer.
Permit No. R14-0038 as referenced in a footnote to Table 11 above, appears to require a catalytic
oxidation on EG-01 and a CO emission limit of 0.41 g/kW-hr, which is the BACT limitation.
However, Specific Condition 5.1.1(g) states that, "[w]hen in operation other than startup or
shutdown periods, the engine for EG-01 shall be a constant-speed engine", which is problematic
for the engines proposed with the RW project since technical difficulties are assumed to exist
when the engines are operated in variable conditions (and not just in steady state scenarios47). In
addition, in a previous permit action EPA Region 4 (June 19, 2014) concluded that DOCs are not
technically feasible for their specific marine internal combustion engine proposed with that
project because the technology would have caused back pressure on the engines, which poses a
safety hazard.
Since there may be significant variations from application to application, the actual operating
conditions (duty cycle, exhaust temperature profiles, and engine backpressure) prior to
retrofitting an engine are essential to ensure compatibility and ensure effective DPF and/or DOC
operation. Specifically, with the operating conditions of nonroad and marine engines, more
technical difficulties might arise when they are located at unmanned (remote) facilities. As a
result, the retrofitted technology could be considered technically infeasible depending on the
actual operating conditions which are engine specific and must be considered prior to
retrofitting 48
Since RW does not yet know specifically which engines will be utilized for the project, EPA
cannot deem the retrofit technology as technically infeasible altogether. Therefore, EPA
proposes that retrofitting a Tier 1, Tier 2, or Tier 3 Engine with DOC or DPFs is available and
applicable, and thus could be a technically feasible option for this project.
45 San Pedro Bay Ports Emissions Inventory Methodology Report I Version 3a (portoflosangeles.org')
46 Verification Procedure: Stationary I California Air Resources Board
47 RW has stated that the OCS Engine(s) on the OSS(s) are not intended to operate under constant steady state loads
or temperatures for a sufficient time necessary for high catalyst performance.
48 CARB has an active current verified technologies for diesel particulate filters for marine engines application.
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EUG 2 - Marine Engines on Vessels when operating as PCS Source(s)
To a large extent, the "applicability" analysis of the potential BACT technologies for EUG 2 is
identical to the EUG 1 "applicability" analysis in terms of the rational of applicable technologies
since the operating conditions are presumed to be the similar. However, the "availability"
analysis of potential BACT options for EUG 2 are constrained in such a way that it needed to be
distinguished from the EUG 1 "applicability" analysis.
The EPA has specifically considered these facts for the following circumstances and has
summarized and addressed the technical feasibility of all these options in Table 13 and the rest of
the section below respectively.
• EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has
secured contracts and the availability of the vessel type at the time of the application is
known.
• EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown.49
• EUG 2 - Scenario 3 - Third-party-contracted U.S. or foreign-flagged vessels proposed
with the project and otherwise regulated under MARPOL Annex VI, where the
availability of the vessel type at the time of the application is unknown.
Table 13 - Summary of Technical Feasible Options for EUG 2 BACT
Control Technology
Technically Feasible (Y/N)
Option 1 - Good Combustion Practices
EUG 2 - Scenario 1
Y
EUG 2 - Scenario 2
Y
EUG 2 - Scenario 3
Y
Option 2 - Highest Tier Certified Marine Engine at 40 C.F.R. Part 1042
EUG 2 - Scenario 1
Y
EUG 2 - Scenario 2
Y1
EUG 2 - Scenario 3
N/A
Option 3 - Highest Tier Certified Marine Engine at MARPOL Annex VI Tier (US and/or Foreign -
third party vessels)
EUG 2 - Scenario 1
N/A
EUG 2 - Scenario 2
N/A
EUG 2 - Scenario 3
Y2
Option 4 - Retrofit a Tier 1, Tier 2, or Tier 3 Engine with DOC and/or DPF
49 Note that NO2 is subject to BACT since the facility is in an NO2 attainment area, while NOx is subject to LAER
as an ozone precursor since the facility is considered part of an ozone nonattainment area. As presented in Section
VLB, the LAER determination considers the CA SIP requirements for certain types of existing marine vessels to be
retrofitted to meet, at a minimum, the EPA Tier 2 Marine Engine Standards at 40 C.F.R. Part 1042. Since LAER is
regulating NOx (and therefore includes N20 and NO2 by proxy) it is presumed to be the more stringent requirement
for this scenario. For those units, the LAER (NOx) requirements will supersede the BACT (NO2) determination.
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Control Technology
Technically Feasible (Y/N)
Scenario 1
N/A
Scenario 2
N
Scenario 3
N
V/A means that this control technology is not intended to be included an a BACT option within Step 1 for
that operating scenario.
Option 2 for Scenario 2 has constraints regarding vessel availability which must be a consideration for Option 2 for
this option to not be excluded from BACT altogether.
9
Option 3 for Scenario 3 has constraints regarding vessel availability which must be a consideration for Option 3 for
this option to not be excluded from BACT altogether.
EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has secured
contracts and the availability of the vessel type at the time of the application is known.
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. Since this practice is
"demonstrated and operated" this potential BACT option is technically feasible.
Option 2 - Marine vessels that are certified to the highest applicable EPA Tier Marine Engine
Standards at 40 C.F.R. Part 1042 are equipped with an integrated SCR, DPF, and/or DOC.
Furthermore, since the Tier Certified emission standards consider the reduction in pollution from
the integrated technologies in the design, they are considered a demonstrated control technology.
This option is technically feasible.
As of the release of this fact sheet, Marine Tier 3 emission standards required by 40 C.F.R. Part
1042 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
Category 3 engines in the marine sector. Furthermore, RW has secured a contract to use the
Charybdis Vessel (Jack-up Installation Vessel) for the WTG installation activities. The engines
installed on the Charybdis vessel are Category 3 Marine Engines and will be EPA-Certified to
meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, CO, and PM emission
standards50 which represent the most stringent level of emissions control required by 40 C.F.R.
Part 1042.
EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown.51
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. Since this practice is
"demonstrated and operated" this potential BACT option is technically feasible.
50 The Tier 3 and Tier 4 marine engine emission standards may be certified to NOx, HC, or NOx + HC.
51 Note that NO2 is subject to BACT since the facility is in an NO2 attainment area, while NOx is subject to LAER
as an ozone precursor since the facility is considered part of an ozone nonattainment area. As presented in Section
VLB, the LAER determination considers the CA SIP requirements for certain types of existing marine vessels to be
retrofitted to meet, at a minimum, the EPA Tier 2 Marine Engine Standards at 40 C.F.R. Part 1042. Since LAER is
regulating NOx (and therefore includes N20 and NO2 by proxy) it is presumed to be the more stringent requirement.
For those units, the NOx LAER requirements will supersede the NO2 BACT determination.
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Option 2 - Marine vessels that are certified to the highest applicable EPA Tier Marine Engine
Standards at 40 C.F.R. Part 1042 are assessed for technical feasibility in terms of applicability
and availability. With certain considerations given for vessel availability, Option 2 for Scenario
2 is considered technically feasible.
Applicable
As of the release of this fact sheet, Marine Tier 3 emission standards required by 40 C.F.R. Part
1042 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
Category 3 engines in the marine sector. Furthermore, RW has secured a contract to use the
Charybdis Vessel (Jack-up Installation Vessel) for the WTG installation activities. The engines
installed on the Charybdis vessel are Category 3 Marine Engines and will be EPA-Certified to
meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, CO, and PM emission
standards46 which represent the most stringent level of emissions control required by 40 C.F.R.
Part 1042. Option 2 for Scenario 2 is applicable.
Available
This scenario prompted a separate analysis based on information from RW which indicates that
there will be marine vessels used in the project owned by third parties. With this considered, the
predictability of vessel availability is indicated to be a large constraint on construction and
operations of the RW windfarm, which inherently limits the number of vessels capable of
conducting the work available at the time needed. Limitations imposed by the Jones Act52 are
also a constraint. The fleet of vessels available that can perform the construction activity is
limited due to the specific vessel requirements needed for performing the work. As described in
the permit application, slowing down, delaying, or extending the project's schedule to wait for a
higher tiered vessel's availability would have significant implications that could prevent the
project from being built because many of the larger, more specialized, vessels are in limited
supply.53 Restricting the use of marine engines to only those which are certified to the highest
applicable Tier Standards for Marine Engine is not a technically feasible option for the RW
project since the "availability" of the highest Tier Engines via commercial channels is the
limiting factor. However, EPA proposes to not eliminate the use of vessels with the highest
52 Generally, the Jones Act is a U.S. law that requires vessels that ship merchandise and passengers between two
U.S. points to be U.S. built and registered (flagged), as well as owned and crewed by U.S. citizens or residents. See
generally, Charlie Papavizas, Jones Act Considerations for the Development of Offshore Windfarms, 20 BENEDICT'S
Mar. Bull. [1] (First Quarter 2022) (available at https://www.winston.eom/iniages/content/2/6/v2/26296.1./First-
Quarter-2022-Benedict-s-Maritime-Bulletin-Papavizas.pdf). U.S.C. § 55102(b), part of the Merchant Marine Act of
1920, also known as the Jones Act, precludes a vessel from providing "any part of the transportation of merchandise
by water, or by land and water, between points in the United States to which the coastwise laws apply, either directly
or via a foreign port, unless the vessel —(1) is wholly owned by citizens of the United States for purposes of
engaging in the coastwise trade; and (2) has been issued a certificate of documentation with a coastwise
endorsement under chapter 121 or is exempt from documentation but would otherwise be eligible for such a
certificate and endorsement." Also part of the Jones Act, U.S.C. § 55103(a) precludes a vessel from transporting
passengers between ports or places in the United States to which the coastwise laws apply, either directly or via a
foreign port, unless the vessel--(l) is wholly owned by citizens of the United States for purposes of engaging in the
coastwise trade; and (2) has been issued a certificate of documentation with a coastwise endorsement under chapter
121 or is exempt from documentation but would otherwise be eligible for such a certificate and endorsement.
53 See https://wwwAmersy.gov/sites/default/files/2022--08/offshore wind market report 2022.pdf.
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tiered marine engines altogether particularly since the "applicability" of the NSPS technology-
based federal standards apply to marine engines and therefore are technically viable options
based on chemical, physical, and engineering principles.
In lieu of eliminating the use of the highest tier marine vessels altogether, EPA proposes
conditions that consider the inherent limitation on the number of specialized vessels that are
currently available to the offshore wind industry. The applicant has agreed to utilize Scenario 2
vessels that are certified to the highest applicable EPA Tier Marine Engine Standards (i.e., Tier 3
or 4, depending on engine size) at 40 C.F.R. Part 1042. In the case that a vessel certified to the
highest applicable EPA Tier Marine Engine Standard (depending on engine size) is not available
within two hours54 of when the vessel must be deployed, the permittee will be allowed to utilize
Marine Engines on Vessels certified to the next highest applicable EPA Tier Marine Engine
Standards (e.g., Tier 3 or Tier 2). At a minimum, all engines within EUG 2 - Scenario 2 shall
comply with emission limits equal to or more stringent than EPA Tier 1 marine engine emission
standards.
It is important to note the distinction in BACT and LAER determination for certain vessel types
in this scenario. Specifically, the LAER determination for EUG 2 - Scenario 2 is presumed to be
the more stringent determination (thus resulting in the more stringent floor requirement) for this
scenario due to NNSR regulating NOx (which thereby including N2O and NO2 by proxy) and
LAER being able to consider the SIP limitations for similar class of sources and NNSR. This
means that specific vessels shall at a minimum comply with emission limits equal to or more
stringent than EPA Tier 2 marine engine emission standards. See Section VI.B.2.b(5). Similarly,
if the total emissions associated with the use of a vessel with the higher Tier engine(s) would be
greater than the total emissions associated with the use of the vessel with the next lower Tier
engine(s), the permittee will be authorized to use the next lower Tier engine(s).55 When
determining the total emissions associated with the use of a vessel with a particular engine, the
permittee will include the emissions of the vessel that would occur when the vessel would be in
transit to the WD A from the vessel's starting location.
Option 4 - Retrofit a Tier 1, Tier 2, or Tier 3 Engine with DOC and/or DPF
While EPA acknowledges that procuring vessels to conduct the work on the project (short term)
is ultimately the responsibility of the facility, it is not technically feasible for RW to require that
third-party contractors replace or retrofit vessel engines to reduce emissions. The vessels that
will be utilized during construction are not owned by RW and are anticipated to largely be
owned by third-party entities. Requiring the replacement or retrofit of specific third-party vessel
engines to meet the highest tier standards for a short-term construction project would prevent
54 EPA understands that offshore wind developers hold contracts with several vessel supply companies that may
have multiple vessels of various tier levels capable of performing certain tasks. The condition was developed to
require the selection of the cleanest vessel available within contracted fleet. Note that the 2-hour requirement is not
relative to the amount of time to travel to the WDA or conduct work on the WDA facilitybut rather to ensure
construction isn't delayed if a cleaner vessel is available after 2 hours from the scheduled deployment time.
55 For example, if the contracted fleet of vessels has a higher tiered vessel that is not located near the project (e.g.,
several hundred miles away), the permittee may compare the total emissions (tons) that would be emitted if a higher
tiered vessel were to travel the longer distance to the project location verses the total emissions (tons) resulting from
the use of a lower tiered vessel located and traveling a shorter distance to the project location.
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RW from being able to substitute vessels on short notice due to schedule changes or other
construction issues. Therefore, this option is not technically feasible.
EUG 2 - Scenario 3 - Third-party-contracted U,S, flagged or foreign-flagged vessels proposed
with the project and regulated under MARPOL Annex VI, where the availability of the vessel
type at the time of the application is unknown.
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. This option is
technically feasible. Since this practice is "demonstrated and operated" this potential BACT
option is technically feasible.
Option 3 -Marine vessels that are certified to the highest applicable MARPOL Annex VI Tier
NOx emission limits are assessed for technical feasibility in terms of applicability and
availability. With certain considerations given for vessel availability. Option 3 for Scenario 3 is
considered technically feasible.
Applicable
As of the release of this fact sheet, the International Maritime Organization's (IMO's)
International Convention for the Prevention of Pollution from Ships (MARPOL) Annex VI Tier
III NOx emission standards for marine vessel engines in Emission Control Areas are fully in
effect, and U.S. EPA has not adopted more stringent certification standards. The Annex VI
requirements apply to U.S.-flagged ships wherever located and to foreign-flagged ships
operating in U.S. waters. Vessels that operate only domestically are exempt from the NOx limits
of 40 C.F.R. Part 1043 provided that their engines meet the requirements of 40 C.F.R. Part 1042
(including Appendix I) and have a displacement of less than 30 liters per cylinder. Foreign-
flagged vessels are exempt from having to meet the marine standards within 40 C.F.R. Part 1042
and are required to meet the emission standards in 40 C.F.R. 1043.The nitrogen oxide (NOx)
emission standards for domestic Category 3 marine engines contained in 40 C.F.R. Part
1042.104 are nearly identical to the IMO's MARPOL Annex VI Tier I, II, and III NOx emission
standards for marine vessel engines in Emission Control Areas (except for a slight variation in
model years). Like the marine engine and nonroad engine emission standards, the Annex VI
emission standards are structured as a tiered progression (Tiers 1 through 3), with each Tier of
emission standards becoming increasingly stringent over time. Option 3 for Scenario 3 is
applicable.
Available
This scenario prompted a separate analysis based on information from RW which indicates that
there will be marine vessels used in the project owned by third parties which are U.S.-flagged
ships and foreign-flagged ships operating in U.S. waters otherwise not subject to the
requirements of NSPS IIII (i.e., marine requirements of 40 C.F.R. Part 1042). Therefore, the
predictability of vessel availability is indicated to be a large constraint to construction and
operations of the RW windfarm, which inherently limits the number of vessels capable of
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conducting the work available at the time needed. Limitations imposed by the Jones Act56 are
also a constraint. The fleet of vessels available that can perform the construction activity is
limited due to the specific vessel requirements needed for performing the work. As described in
the permit application, slowing down, delaying, or extending the project's schedule to wait for a
higher tiered vessel's availability would have significant implications that could prevent the
project from being built because many of the larger, more specialized, vessels are in limited
supply.57
Restricting the use of marine engines to only those which are certified to the highest applicable
Tier Standards for Marine Engine is not a technically feasible option for the RW project. EPA
has concluded that the "availability" of the options via commercial channels is the limiting
factor. EPA acknowledges the "applicability" of the add on control technologies58 when applied
to marine engines as technically viable options based on chemical, physical, and engineering
principles. Therefore, it is proposed that the project will not eliminate the use of vessels with the
highest tiered marine engines, however the use of the next lowest tiered vessel should be allowed
in instances where a higher tiered vessel is not available at the time of deployment.
In lieu of eliminating the use of the highest tier marine vessels altogether, EPA proposes
conditions that consider the inherent limitation on the number of specialized vessels that are
currently available to the offshore wind industry. The applicant has agreed to utilize Scenario 3
vessels that are certified to the highest applicable Annex VI Engine Standards (i.e., Tier III). In
the case that a vessel certified to the highest applicable Annex VI Engine Standards (i.e., Tier III)
is not available within two hours of when the vessel must be deployed, the permittee will be
authorized to utilize Marine Engines on Vessels certified to the next highest applicable Annex VI
Engine Standards (i.e., Tier II or I). Similarly, if the total emissions associated with the use of a
vessel with the higher Tier engine(s) would be greater than the total emissions associated with
the use of the vessel with the next lower Tier engine(s), the permittee will be authorized to use
the next lower Tier engine(s). When determining the total emissions associated with the use of a
vessel with a particular engine, the permittee will include the emissions of the vessel that would
occur when the vessel would be in transit to the WD A from the vessel's starting location. With
these considerations, Option 3 for Scenario 3 is considered available.
EUG 3 - Medium Voltage and High Voltage Gas Insulated Switchgears on the OSS - All
options proposed, listed below, in Step 1 for the MV and HV GIS are technically feasible.
A maximum annual leak rate not to exceed 0.5%, which is more stringent than the requirement
contained in 310 CMR 7.72 (4)(a). See Section (4).
The applicant has proposed operating a Sealed System with leak detection and alarms and to
complete any leak detection repair within 5 days of discovery, which complies with the
requirement contained in 310 CMR 7.72 (4)(a). See Section (4).
56 Supra note 52.
57 See https://www.energy.gov/sjtes/defcmlt/ftks/2022-08/offshore wind market report 2022.pdf.
58 EPA acknowledges marine engines have their own constraints (i.e., operating in a harsher environment, variable
loads, temperature fluxes etc...) when compared to typically stationary engine.
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(3) Step 3 - Rank Control Technologies by Control Effectiveness (each engine described in
Table 8 and controls for each listed below)
EUG 1 - PCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
GCOP and engines certified to the highest applicable EPA Tier Marine Engine59 at 40 C.F.R.
Part 1042 or EPA Tier 4 Nonroad Engine60 at 40 C.F.R. Part 1039 contain the most stringent
emission limitations in the ranking (Step 3) for EUG 1.
Carbon Monoxide (CO)
Offshore Engines (RW-3, RW-4, RW-5, RW-6, RW-7, RW-8, RW-9, RW-10, RW-11, RW-14, RW-
15, RW-16, RW-17, RW-18, RW-19)
• The Tier 4 emission standards for CI engines are only applicable to emission units with a
maximumRW-3 power rating greater than or equal to 600 kW. The applicant has not
identified any offshore generator, as contained in Table 8, to have a maximum power
rating greater than or equal to 600 kW. For CI engines, the Tier 3 CO emission standard
of 5.00 (g/kW-hr) represents the most stringent level of emissions control required by 40
C.F.R. Part 1042.
• For engines with a power rating (kW) between 19 < kW < 37, the CO emission standard
(Tier 4) of 5.5 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 37 < kW < 56, the CO emission standard
(Tier 4) of 5.00 (g/kW-hr) represents the most stringent level of emissions control
required by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 75 < kW < 130, the CO emission standard
(Tier 4) of 5.00 (g/kW-hr) represents the most stringent level of emissions control
required by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 130 < kW < 225, the CO emission
standard (Tier 4) of 3.50 (g/kW-hr) represents the most stringent level of emissions
control required by 40 C.F.R. Part 1039.
Offshore Engines (RW-1, RW-2, RW-12, RW-13)
59 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase.
60 Per 40 C.F.R. Part 1039, the U.S. EPA nonroad compression ignition (CI) engines have emissions standards (Tier
1, 2, 3, and 4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and particulate matter
(PM) that become progressively cleaner as Tier levels increase.
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• The Tier 4 emission standards for C2 engines are only applicable to units with a
maximum power rating greater than or equal to 600 kW. The applicant has not identified
any offshore generator, as contained in Table 8Table 8 , to have a maximum power rating
greater than or equal to 600 kW. Therefore, for C2 engines, the Tier 3 CO emission
standard of 5.00 (g/kW-hr) represents the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 560 < kW < 900, the CO emission
standard (Tier 4) of 3.50 (g/kW-hr) represents the most stringent level of emissions
control required by 40 C.F.R. Part 1039.
Nitrogen Dioxide (NO?)
Offshore Engines (RW-3, RW-4, RW-5, RW-6, RW-7, RW-8, RW-9, RW-10, RW-11, RW-14, RW-
15, RW-16, RW-17, RW-18, RW-19)
• The HC + NOx emission standard for CI engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. The Tier 4 emission standards for CI engines are
only applicable to emission units with a maximum power rating greater than or equal to
600 kW. The applicant has not identified any offshore generator, as contained in Table 8,
to have a maximum power rating greater than or equal to 600 kW. Therefore, for CI
engines, the Tier 3 HC + NOx emission standard range of 5.4-5.8(g/kW-hr) represents the
most stringent level of emissions control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 19 < kW <37, the NMHC + NOx
emission standard (Tier 4) of 4.7 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 37 < kW < 56, the NMHC + NOx emission
standard of 4.7 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 75 < kW < 130, the NOx emission standard
(Tier 4) of 0.40 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 130 < kW < 225, the NOx emission standard
(Tier 4) of 0.40 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
Offshore Engines (RW-1, RW-2, RW-12, RW-13)
• The HC + NOx emission standard for CI engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. The Tier 4 emission standards for CI engines are
only applicable to emission units with a max power rating greater than or equal to 600 kW.
56
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The applicant has not identified any offshore generator, as contained in Table 8, to have a
maximum power rating greater than or equal to 600 kW. Therefore, for CI engines, the
Tier 3 HC + NOx emission standard range of 5.4-5.8(g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 560 < kW < 900, the NOx emission standard
(Tier 4) of 3.5 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
Particulate Matter (PM)
Offshore Engines (RW-3, RW-4, RW-5, RW-6, RW-7, RW-8, RW-9, RW-10, RW-11, RW-14, RW-
15, RW-16, RW-17, RW-18, RW-19)
• The PM emission standard for CI engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. The Tier 4 emission standards for CI engines are
only applicable to emission units with a maximum power rating greater than or equal to
600 kW. The applicant has not identified any offshore generator, as contained in Table 8,
to have a maximum power rating greater than or equal to 600 kW. Therefore, for CI
engines, the Tier 3 PM emission standard range of 0.10-0.40 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 19 < kW < 37, the PM emission standard
(Tier 4) of 0.03 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 37 < kW < 56, the PM emission standard
(Tier 4) of 0.03 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 75 < kW < 130, the PM emission standard
(Tier 4) of 0.02 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 130 < kW < 225, the PM emission standard
(Tier 4) of 0.02 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
Offshore Engines (RW-1, RW-2, RW-12, RW-13)
• The Tier 4 emission standards for C2 engines are only applicable to units with a maximum
power rating greater than or equal to 600 kW. The applicant has not identified any offshore
generator, as contained in Table 8 , to have a maximum power rating greater than or equal
to 600 kW. The PM emission standard for C2 engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. Therefore, for C2 engines, the Tier 3 PM emission
57
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standard range of 0.14-0.27 (g/kW-hr) represents the most stringent level of emissions
control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 560 < kW < 900, the PM emission standard
(Tier 4) of 0.04 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
A good combustion practices plan (GCOP) is selected for all units in EUG 1. Therefore, it is not
represented below. The facility will be required to incorporate the GCOP into the facility
standard operating procedures (SOPs) and shall make the GCOP available for inspection. The
plan should include, but not be limited to i.) A list of combustion optimization practices and a
means of verifying the practices have occurred; ii.) A list of combustion and operation practices
to be used to lower energy consumption and a means of verifying the practices have occurred;
and iii.) A list of the design choices determined to be BACT and verification that designs were
implemented in the final construction.
EUG 2 - Marine Engines on Vessels Operating when operating as PCS Source(s)
The EPA has addressed Step 3 in detail below for the following EUG 2 operating scenarios:
• EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has
secured contracts and the availability of the vessel type at the time of the application is
known.
• EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown.61
EUG 2 - Scenario 3 - Third-party-contracted U,S, flagged or foreign-flagged vessels proposed
with the project and regulated under MARPOL Annex VI, where the availability of the vessel
type at the time of the application is unknown.
EUG 2 — Scenario 1
GCOP and Marine Engines on the Charybdis Vessel certified to the highest applicable EPA Tier
Marine Engine Standards 62 at 40 C.F.R. Part 1042 contains the most stringent BACT emission
limitations in the ranking (Step 3) for EUG 2 - Scenario 1.
61 Note that NO2 is subject to BACT since the facility is in an NO2 attainment area, while NOx is subject to LAER
as an ozone precursor since the facility is considered part of an ozone nonattainment area. As presented in Section
VLB, the LAER determination considers the California SIP requirements for certain types of existing marine vessels
to be retrofitted to meet, at a minimum, the EPA Tier 2 Marine Engine Standards at 40 C.F.R. Part 1042. Since
LAER is regulating NOx (and therefore includes N20 and NO2 by proxy) it is presumed to be the more stringent
requirement. For those units, the LAER (NOx) requirements will supersede the BACT (NO2) determination.
62 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
58
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• RW has secured a contract to use the Charybdis Vessel (Jack-up Installation Vessel) for
the WTG installation activities. The engines installed on the Charybdis vessel are
Category 3 Marine Engines and will be EPA-Certified to meet the Marine Tier 3
(Category 3 Marine Engines) NOx, HC, CO, and PM emission standards which represent
the most stringent level of emissions control required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
GCOP and Marine Engines on the Eco Edison Vessel certified to the highest applicable EPA
Tier Marine Engine Standards 63 at 40 C.F.R. Part 1042 contains the most stringent BACT
emission limitations in the ranking (Step 3) for EUG 2 - Scenario 1.
If considered a Category 3 Marine Engines:
• EPA-Certified to meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO, emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
63 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
59
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If considered a Category 2 Marine Engines:
• EPA-Certified to meet the Marine Tier 4 (Category 2 Marine Engines) NOx, HC, CO,
and PM emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C2 engines (Tier 4) the Tier 4 NOx emission standard range
of 1.8 (g/kW-hr) represents the most stringent level of emissions control required by 40
C.F.R. Part 1042.
• The C3 engines, the Tier 4 HC emission standard of 0.19 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 PM emission standard of 0.04 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
GCOP and Marine Engines on the Primary Crew Transfer Vessel certified to the highest
applicable EPA Tier Marine Engine Standards 64 at 40 C.F.R. Part 1042 contains the most
stringent BACT emission limitations in the ranking (Step 3) for EUG 2 - Scenario 1.
If considered a Category 3 Marine Engines:
• EPA-Certified to meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO, emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
64 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
60
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If considered a Category 2 Marine Engines:
• EPA-Certified to meet the Marine Tier 4 (Category 2 Marine Engines) NOx, HC, CO,
and PM emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C2 engines (Tier 4) the Tier 4 NOx emission standard range
of 1.8 (g/kW-hr) represents the most stringent level of emissions control required by 40
C.F.R. Part 1042.
• The C3 engines, the Tier 4 HC emission standard of 0.19 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 PM emission standard of 0.04 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
EUG 2 — Scenario 2
GCOP and engines certified to the highest applicable EPA Tier Marine Engine58 at 40 C.F.R.
Part 1042 contains the most stringent BACT emission limitations in the ranking (Step 3) for
EUG 2 - Scenario 2. Note that for certain applicable units, the LAER (NOx) requirements will
supersede the BACT (NO2) determination. See Section VLB. 2.
EUG 2 - Scenario 3
As of the release of this fact sheet, the IMO's MARPOL Annex VI Tier III NOx emission
standards for marine vessel engines in Emission Control Areas are fully in effect and MARPOL
has not adopted more stringent certification standards. In the United States, MARPOL Annex VI
is implemented through the Act to Prevent Pollution from Ships (33 U.S.C. §§ 1901-1905) and
40 C.F.R. Part 1043. The Annex VI requirements apply to U.S.-flagged ships wherever located
and to foreign-flagged ships operating in U.S. waters. However, vessels that operate only
domestically are exempt from the NOx limits of 40 C.F.R. Part 1043 provided that their engines
meet the requirements of 40 C.F.R. Part 1042 (including Appendix I) and have a displacement of
less than 30 liters per cylinder.
Table 14 Annex VI NOx Emission Standards (g/kW-hr) 40 C.F.R. 1043.60
Tier
Area of applicability
Implementation date"
Maximum in-use engine speed
Less than
130 RPM
130-2000 RPMb
Over 2000
RPM
Tier I
All U.S. navigable waters and
EEZ
January 1, 2004-
December 31, 2010
17.0
45.0 • n(~a20)
9.8
61
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Tier
Area of applicability
Implementation date3
Maximum in-use engine speed
Less than
130 RPM
130-2000 RPMb
Over 2000
RPM
Tier II
All U.S. navigable waters and
EEZ
January 1, 2011-
December 31, 2015
14.4
44.0 • n(~a23)
7.7
Tier II
All U.S. navigable waters and
EEZ, excluding ECA and ECA
associated areas
January 1, 2016 and
later
14.4
44.0 • n(~a23)
7.7
Tier III
ECA and ECA associated areas
January 1, 2016 and
later0
3.4
9.0 • n(~a20)
2.0
a Standards apply for engines installed on vessels with a build date in the specified time frame, or for engines that
undergo a major conversion in the specified time frame.
b Applicable standards are calculated from n (maximum in-use engine speed, in RPM, as specified in § 1042.140).
Round the standards to one decimal place.
0 In the case of recreational vessels of less than 500 gross tonnage with length at or above 24 meters, the Tier III
standards start to apply January 1, 2021.
A good combustion practices plan (GCOP) is selected for all units in EUG 2. Therefore, it is not
represented below. The facility will be required to incorporate the GCOP into the facility
standard operating procedures (SOPs) and shall make the GCOP available for inspection. The
plan should include, but not be limited to i.) A list of combustion optimization practices and a
means of verifying the practices have occurred; ii.) A list of combustion and operation practices
to be used to lower energy consumption and a means of verifying the practices have occurred;
and iii.) A list of the design choices determined to be BACT and verification that designs were
implemented in the final construction.
EUG 3—Medium Voltage, and High Voltage Gas Insulated Switchgears on the OSS
• A maximum annual leak rate not to exceed 0.5%. See Section (4).
• A Sealed System with leak detection and alarms and to complete leak detection repair
within 5 days of discovery. See Section (4).
(4) Step 4 - Evaluate most effective controls and document results
RW has accepted the highest ranked control technology in Step 3, and therefore lower air
pollutant emitting technology, as BACT for each EUG in this permit application. Therefore,
economic feasibility issues were not considered in the determination of BACT for this permit
action.
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m Step 5 - Select BACT
Based on the preceding analysis, the following combination is proposed as BACT for the
emissions from the compression ignition internal combustion engines in the project.
EUG 1 - PCS Generator Engine(s) on the OSS(s) and WTG(s)
OCS Generator Engine(s) installed on the OSS(s) and WTG(s) certified to the highest applicable
EPA Tier Marine Engine at 40 C.F.R. Part 1042 or EPA Tier 4 Nonroad Engine at 40 C.F.R. Part
1039.
OCS Generator Engine(s) on the OSS(s) and WTG(s) shall be operated in accordance with the
GCOP Plan for the facility. The plan shall be incorporated into the facility SOPs and shall be
made available for inspection. The plan specifically should include, but is not limited to: i.) a list
of combustion optimization practices and a means of verifying the practices have occurred for
each engine type based on the most recent manufacturers' specifications issued for the engines at
the time that they are certified (and any updates from the manufacturer should be noted and
amended in the plan); ii.) a list of combustion and operation practices to be used to lower energy
consumption and a means of verifying the practices have occurred (if applicable); and iii.) a list
of the design choices determined to be LAER/B ACT and verification that designs were
implemented in the final construction.
EUG 2 - Marine Engines on Vessels Operating when operating as OCS Source(s)
The following requirements apply to all Marine Engines on Vessels Operating when operating as
OCS Source(s). This includes any applicable propulsion and auxiliary generator engines utilized
in the construction and operation phases of the project when they meet the definition of an OCS
source. Specifically, where a propulsion engine would be used to supply power for purposes of
performing a given stationary source function, i.e., for example to lift, support, and orient the
components of each WTG during installation.
EUG 2 - All Scenarios
Marine Engines on Vessels when Operating as OCS Source(s) shall be operated in accordance
with the GCOP Plan for the facility. The plan shall be incorporated into the facility SOPs and
shall be made available for inspection. The plan specifically should include, but is not limited to:
i.) a list of combustion optimization practices and a means of verifying the practices have
occurred for each engine type based on the most recent manufacturers' specifications issued for
the engines at the time that they are certified (and any updates from the manufacturer should be
noted and amended in the plan); ii.) a list of combustion and operation practices to be used to
lower energy consumption and a means of verifying the practices have occurred (if applicable);
and iii.) a list of the design choices determined to be LAER/BACT and verification that designs
were implemented in the final construction.
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EUG 2 — Scenario 1
GCOP and Marine Engines on the Charybdis Vessel (Jack-up Installation Vessel), while
operating as an OCS source, shall be EPA certified to the meet the Marine Tier 3 (Category 3
Marine Engines) emission standards which represent the most stringent level of emissions
control required by 40 C.F.R. Part 1042.
GCOP and Marine Engines on the Eco Edison Vessel, while operating as an OCS source, which
is indicated to be used as a Service Operation Vessel, shall be EPA certified to the Marine Tier 3
(Category 3 Marine Engines) NOx, HC, and CO emission standards or Marine Tier 4 (Category
2 Marine Engines) NOx, HC, and CO emission standards specified within 40 C.F.R. Part 1042.
Tier 4 emission standards apply to engine(s) at or above 600 kW, and Tier 3 emission standards
apply to engine(s) below 600 kW.
GCOP and Marine Engines on the Primary Crew Transfer Vessel, while operating as an OCS
source, shall be EPA certified to the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO emission standards or Marine Tier 4 (Category 2 Marine Engines) NOx, HC, and CO
emission standards specified within 40 C.F.R. Part 1042. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
EUG 2 — Scenario 2
All applicable engines on U.S.-flagged vessels when operating as OCS source(s), and otherwise
not subject to scenario 1 or 3, shall be certified to the highest applicable EPA Tier Marine Engine
Standards (i.e., Tier 3 or 4, depending on engine size) as contained within 40 C.F.R. Part 1042,
except if one of the conditions in subparagraph a. or b., below, is met, in which case the
Permittee may use the next lower Tier engine (i.e., Tier 3). Similarly, if one of the conditions in
(a.) or (b.), below, is met regarding the use of a Tier 4 engine, the Permittee may use a Tier 3
engine in lieu of a Tier 4 engine. If one of the conditions in Section IV(C)(iv)(a.) or (b.) is met
regarding the use of a Tier 3 engine, the Permittee may use a Tier 2 engine in lieu of a Tier 3
engine. If one of the conditions in (a.) or (b.) is met regarding the use of a Tier 2 engine, the
Permittee may use a Tier 1 engine in lieu of a Tier 2 engine. To use a lesser Tier engine, as
described above, Permittee shall ensure one of the following conditions is met:
a) A vessel with a higher Tier engine is not available within two hours of when the vessel
must be deployed; or
b) The total emissions associated with the use of a vessel with the higher Tier engine(s)
would be greater than the total emissions associated with the use of the vessel with the
next lower Tier engine(s). For purposes of this subparagraph, when determining the
total emissions associated with the use of a vessel with a particular engine, the
Permittee shall include the emissions of the vessel that would occur when the vessel
would be in transit to the WDA from the vessel's starting location.
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At a minimum, all applicable engines subject to this condition shall comply with emission
standards (in terms of g/kW-hr) equal to or cleaner than EPA Tier 1 marine engine emission
standards contained within 40 C.F.R. Part 1042.
EUG 2 — Scenario 3
All applicable engines on U.S.-flagged or foreign-flagged vessels while those vessels are
operating as an OCS source within the ECA (and otherwise not subject to Scenario 2 or 3 shall
be certified to meet or emit less than the MARPOL Annex VI Tier III NOx emission standards
(in terms of g/kW-hr), except if one of the conditions in (a.) or (b.) below, is met, in which case
the Permittee may use the next lower Tier engine (i.e., Tier II). Similarly, if one of the conditions
in (a.) or (b.), below, is met regarding the use of a Tier II engine, the Permittee may use a Tier I
engine in lieu of a Tier II engine. To use a lesser Tier engine, as described above, Permittee shall
ensure one of the following conditions is met:
a) A vessel with a higher Tier is not available within two hours of when the vessel must be
deployed; or
b) The total emissions associated with the use of a vessel with the higher Tier engine(s)
would be greater than the total emissions associated with the use of the vessel with the
next lower Tier engine(s). For purposes of this subparagraph, when determining the
total emissions associated with the use of a vessel with a particular engine, the
Permittee shall include the emissions of the vessel that would occur when the vessel
would be in transit to the WD A from the vessel's starting location.
At a minimum, all applicable engines subject to this condition shall comply with emission
standards (in terms of g/kW-hr) equal to or cleaner than MARPOL Annex VI Tier I NOx
emission standards contained within 40 C.F.R. Part 1043.
EUG 3—Medium (MV), and High Voltage (HV) Gas Insulated Switchgears (GIS) on the
OSS
The BACT requirements for the MV and HV GIS will consist of a Sealed System with leak
detection and alarms, leak detection repair within 5 days of discovery, and a maximum annual
leak rate not to exceed 0.5%
D. Ambient Air Impact Analysis
The regulations at 40 C.F.R. Part 51, Appendix W (Guideline on Air Quality Models or the
"Guideline) provide the requirements for analyses of ambient air quality impacts. The Guideline
specifies EPA's preferred models and other techniques, as well as guidance for their use in
regulatory application in estimating ambient concentrations of air pollutants. The analyses of
ambient air impacts described in this section were conducted in accordance with the Guideline.
The ambient air impact analysis for the project was conducted to account for two periods: the
construction phase and the operational phase. The construction phase emissions account for the
highest annual emissions from the source, and the analysis of ambient air impacts due to
65
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construction are described in the first section below. Operational phase emissions for the source
are considerably lower than construction period emissions for the source on an annual basis, and
the analysis of ambient air impacts for the source during the operational phase are described in
the second section below. The modeled emissions rely on a conservative estimate of emissions
associated with the source. Even though RW construction vessels will transit between the work
area and several different ports, transiting emissions were conservatively based on all vessel
transits originating from Rhode Island, which represents the ports closest to Lye Brook
Wilderness Area, the closest Class I area to the project. Therefore, ambient air impacts from the
source will be no worse than those shown in this ambient air impact analysis. Table 15 provides
the applicable National Ambient Air Quality Standard (NAAQS"), PSD increment, and
significant impact levels (SILs"), which were used in determining air quality impacts from the
project.
Table 15 NAAQS, PSD Increments, and Significant Impacts Level
Pollutant
Averaging
Time
NAAQS (1)
PSD C*>
Class II
Increment
Class II
SIL
PSD C*>
Class I
Increment
Class I
SIL
Primary
Secondary
CO
1-hr
35 ppm
--
--
2,000
--
--
8-hr
9 ppm
--
--
500
--
--
PM2.5
Annual
12.0 ug/m3
15.0 ug/m3
4
0.2 (3)
1
0.05 (3)
24-hr
35 ug/ m3
35 ug/ m3
9
1.2 (3)
2
0.27 (3)
PM10
Annual
--
--
17
1(5)
4
0.2 W
24-hr
150 ug/ m3
150 ug/ m3
30
5®
8
0.3 (4)
N02
Annual
53 ppb
53 ppb
25
1(5)
2.5
0.1 w
1-hr
100 ppb
--
--
7.5 (6)
--
--
(1) See 310 CMR 6.04: Standards
(2) See 40 C.F.R. 52.21(c)
EPA's April 17, 2018 Guidance and associated legal memorandum and technical support documents, included as
part of the permit record.
(4) Values proposed by the applicant. These values are consistent with values proposed by EPA. See 61 Fed. Reg.
38250, "Prevention of Significant Deterioration (PSD) and Nonattainment New Source Review (NSR)."
(5) See 40 C.F.R. § 51.165(b)(2)
<()> EPA, June 29, 2010, "Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the Prevention of
Significant Deterioration Program." The interim SIL value of 4 ppb (or 7.5 ug/m3) was used
1. Construction Phase
The PSD permitting regulations for proposed major new sources generally require applicants to
perform an air quality impact analysis for those pollutants emitted in significant quantities. For
temporary emission sources subject to the PSD permitting requirements, the PSD regulations at
40 C.F.R. § 52.21(i)(3) require an assessment of the ambient air impact for Class I areas and
areas where the applicable PSD increment is known to be violated. An assessment of the
construction emissions was provided by the applicant in a September 2022 report "Air Quality
Impact Modeling Report - Construction Class I SIL and Visibility," to correspond with the
Revolution Wind OCS Air Permit Application submitted to EPA on August 12, 2022. The
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September 2022 report was supplemented by a memorandum provided by the applicant entitled
"Supplemental Information for Temporary Sources" on February 28, 2023.
The following sections provide the information EPA considered in determining the appropriate
ambient air impacts analysis requirements to which the source is subject for the construction
period, and whether those requirements have been satisfied. Specifically, the sections below
describe, for the construction period: 1) the qualification as temporary; 2) the assessment of
ambient air impacts at areas where PSD increment is known to be violated; 3) the assessment of
ambient air impacts at Class I areas; 4) results of the assessment for the source; and 5) EPA's
overall conclusion about the ambient air impacts during the construction phase for the source.
a. Qualification as a Temporary Source
The subject emissions associated with the construction of the source are anticipated to last no
longer than a period of two years. The EPA considers construction sources operating for two
years to be temporary sources for PSD permitting purposes, however a longer period could be
considered at the Administrator's discretion. See Amended Regulations for Prevention of
Significant Deterioration of Air Quality, 45 Fed. Reg. 52676, 52719, 52728 (Aug. 7, 1980).
Since the construction emissions for the source are anticipated to last no longer than two years,
the construction emissions are considered temporary.
b. Assessment of Ambient Air Impacts at Areas Where PSD Increment Is Known to be Violated
The impact-related criteria that must be met for a temporary source under 40 C.F.R. § 52.21(i)(3)
require that emissions must not impact any area where the applicable increment is known to be
violated. The proposed wind farm will be located approximately 7.5 nautical miles south of the
Nomans Land Island National Wildlife Refuge, Massachusetts. Based on consultation between
Revolution Wind, the Commonwealth of Massachusetts, and EPA, there are no areas in the
vicinity of the proposed project where an applicable PSD increment is known to be violated.
Therefore, because of the absence of areas known to be in violation of the PSD increment in the
vicinity of the source, EPA concludes that construction emissions for the source will not impact
any such area where applicable PSD increment is known to be violated.
c. Assessment of Ambient Air Impacts at Class I Areas
The impact-related criteria that must be met for a temporary source under 40 C.F.R. § 52.21(i)(3)
require that the emissions must not impact any Class I area. Class I areas are defined in 40 C.F.R.
§ 52.21(e). The Class I areas closest to the construction area are the Lye Brook Wilderness Area,
located in southwestern Vermont (within the Green Mountain National Forest), 252 km from the
WDA and the Brigantine Wilderness Area, located in Southeastern New Jersey (within the
Edwin B. Forsythe National Wildlife Refuge), 310 km from the WDA. These distances were
provided by the applicant. A map of the location of these Class I areas with respect to the
windfarm is presented in Figure 3.
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\ ' \
^liye Brook
iraioga Sp'r.ngs V
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d. Assessment of NO 2 Impacts at Class I Areas
Consistent with section 4.2.c.ii of the Guideline, RW assessed the significance of ambient
impacts for NO2 at the Lye Brook Wilderness Area using a second-tier analysis. Even though
RW construction vessels will transit between the work area and several different ports, transiting
emissions were conservatively based on all vessel transits originating from Rhode Island, which
represents the ports closest to Lye Brook. Also, the modeling assumes that all construction phase
vessel and equipment activity will occur in the same year. RW assumed 100% conversion of
NOx to NO2. Assessment of NO2 by the CALPUFF model demonstrated impacts below the Class
I significance level at the Lye Brook Wilderness Area. EPA has evaluated RW's approach for
assessing NO2 impacts and believes it is suitable to identify those impacts resulting from the
source in the Class I area. Comparison of construction period impacts for the source to the
respective SILs are presented in Table 16.
e. Assessment of PM2.5 Impacts at Class I Areas
To determine the total impact on PM2.5 concentrations from the facility at the Lye Brook
Wilderness Area, RW summed the impact of direct PM2.5 emissions with the impact of PM2.5
precursor emissions on the secondary component of PM2.5 concentrations. The total PM2.5
concentration, consisting of the direct and secondary components of PM2.5 impacts, was then
compared to the PM2.5 SILs. Consistent with section 4.2.c.ii of the Guideline, RW assessed the
impacts of direct PM2.5 emissions at the Lye Brook Wilderness Area using a second-tier analysis.
Transiting emissions were based on Rhode Island ports which are closest to Lye Brook. The
short-term modeling assumes that all construction phase vessel and equipment activity will occur
within the same 24 hours. Also, the long-term modeling assumes that all construction phase
vessel and equipment activity will occur in the same year. For assessment of the secondary
component of PM2.5 impacts resulting from the PM2.5 precursor emissions from the facility, RW
used a Tier 1 demonstration tool based on existing technically credible and appropriate
relationships between emissions and impacts developed from previous modeling, as described in
section 5.2(e) of the Guideline. Additional details on the approach used by RW to assess the
direct and secondary component of PM2.5 impacts are provided in the following paragraphs.
As explained in its April 17, 2018, memorandum, "Guidance on Significant Impact Levels (SIL)
for Ozone and Fine Particles in the Prevention of Significant Deterioration Permitting Program"
(EPA's April 17, 2018, Guidance), the EPA has recognized that permitting authorities have the
discretion to apply SILs on a case-by-case basis in the review of individual permit applications.
In 2010, the EPA finalized a rule to codify, among other things, particular PM2.5 SIL values and
specific applications of those values. In litigation over that rule, the EPA conceded the regulation
was flawed because it did not preserve the discretion of permitting authorities to require
additional analysis in certain circumstances. The court granted the EPA's request to vacate and
remand the rule so that the EPA could address the flaw. See Sierra Club v. EPA, 705 F.3d 458
(D.C. Cir. 2013). The EPA subsequently addressed the use of SILs in the EPA's April 17, 2018,
Guidance. For the purposes of this permitting action, the EPA is using PM2.5 SILs as a
compliance demonstration tool based on the technical and legal bases accompanying its April 17,
2018, Guidance. These documents (i.e., the SILs memorandum, technical analysis, and legal
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memorandum) are provided in the administrative record associated with the draft permit.66 The
use of the PM2.5 SIL as an indication of a significant impact on a Class I area was not the basis
for the court's PM2.5 SIL vacatur. Given this fact, the previous use of the PM2.5 SILs as a
significant impact indicator, and the lack of any other objective concentration metric, its use as a
concentration considered small enough to qualify for the temporary source exemption (i.e., no
impact to Class I areas) appears appropriate.
To assess the impact of direct PM2.5 emissions at the Lye Brook Wilderness Area, RW selected
the CALPUFF model (version 5.8.5) consistent with Section 4.2.c.ii of the Guideline. Consistent
with Section 4.2.c.ii of the Guideline, CALPUFF was applied with no chemistry or deposition.
The CALPUFF modeling utilized 103 receptors located in the Lye Brook Wilderness Area.
These receptors were provided by the National Park Service.
For secondary PM2.5 impacts, RW used a Tier 1 demonstration tool based on existing technically
credible and appropriate relationships between emissions and impacts developed from previous
modeling, as described in sections 5.2(e) and 5.4.2(b) of the Guideline. RW's approach for
assessing secondary PM2.5 impacts is consistent with EPA's April 30, 2019, "Guidance on the
Development of Modeled Emission Rates for Precursors (MERPs) as a Tier 1 Demonstration
Tool for Ozone and PM2.5 under the PSD Permitting Program" (EPA's April 30, 2019,
Guidance). In assessing secondary impacts for PM2.5, RW relied on information provided by the
EPA related to the EPA modeling of the secondary formation of PM2.5 constituents due to
precursor emissions for hypothetical NOx and SO2 sources. Information about the EPA
hypothetical source modeling is provided in the EPA's April 30, 2019, Guidance. To identify
atmospheric chemistry that is suitably representative of the area around the WD A, RW evaluated
modeled secondary PM2.5 impacts from the 15 hypothetical sources located in the Northeast
Climate Zone.67 From the 15 hypothetical sources, RW identified the highest annual and 24-hour
nitrate and sulfate impact levels at a distance similar to the distance the project is from the Lye
Brook Wilderness Area (252 km). By selecting the highest impacts from these 15 hypothetical
sources at or near a distance of 252 km, the derived value is suitably conservative (i.e., likely to
overestimate impacts) for use in this screening assessment. Then, RW scaled the hypothetical
source impacts based on the ratio of the emissions to the EPA's hypothetical source modeling
emissions (i.e., 3,000 tpy) to derive an expected secondary impact for nitrate and sulfate
constituents for the 24-hour and annual averaging periods. The sum of these nitrate and sulfate
impacts is the total secondary PM2.5 impact when using this approach.
The sum of the direct PM2.5 impacts predicted by the CALPUFF model and the secondary PM2.5
impacts from the Tier I analysis demonstrated total impacts below the PM2.5 significance levels
at the Lye Brook Wilderness Area. EPA has evaluated RW's approach for assessing PM2.5
impacts and believes it is suitable to identify those impacts resulting from the source in the Class
I area. Comparison of construction period impacts for the source to the respective SILs are
presented in Table 177.
66 The SILs memorandum, technical analysis, and legal memorandum can be found within the docket for this permit
action.
67 Figure 3-4 of EPA's April 30, 2019, "Guidance on the Development of Modeled Emission Rates for Precursors
(MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2.5 under the PSD Permitting Program" (EPA's April 30,
2019 Guidance).
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f Assessment of PMio Impacts at Class I Areas
Consistent with section 4.2.c.ii of the Guideline, RW assessed the impacts of PMio emissions at
the Lye Brook Wilderness Area using a second-tier analysis. Transiting emissions were based on
Rhode Island ports which are closest to the Lye Brook Wilderness Area. The short-term
modeling assumes that all construction phase vessel and equipment activity will occur within the
same 24 hours. Also, the long-term modeling assumes that all construction phase vessel and
equipment activity will occur in the same year. Assessment of PMio by the CALPUFF model
demonstrated impacts below the significance levels at the Lye Brook Wilderness Area. EPA has
evaluated RW's approach for assessing PMio impacts and believes it is suitable to identify those
impacts resulting from the source in the Class I area. Comparison of construction period impacts
for the source to the respective SILs are presented in Table 16.
(1) Ambient Air Impacts for the Construction Phase
Consistent with section 4.2.c.ii of the Guideline, RW assessed the significance of ambient
impacts for NO2, PM2.5, and PMio at the Lye Brook Wilderness Area using a second-tier analysis.
RW assessed the impacts of direct PM2.5 emissions at the Lye Brook Wilderness Area using the
CALPUFF model. To assess secondary PM2.5 impacts, RW used a Tier 1 demonstration tool
based on existing technically credible and appropriate relationships between emissions and
impacts developed from previous modeling, as described in section 5.2(e) of the Guideline. The
total PM2.5 concentration, consisting of the direct and secondary component of PM2.5 impacts,
was then compared to the appropriate SIL.
The total ambient air impacts for pollutants emitted from construction of the source discussed in
this section are presented in Table 16. below. Concentrations in air are given in micrograms per
cubic meter (|ig/m3). Impacts for each pollutant and associated averaging time for which Class I
area SILs have been established are shown to be below significance levels at the Lye Brook
Wilderness Area.
Table 16 Assessment of Const ruction Period Ambient Air Impact for the Source
Pollutant
Averaging Time
Class I
PSD
SIL (ug/m3)
Highest Total
Impact
(ug/m3)(1)
Impact Below SIL?
PM2.5
Annual
0.05
0.02 (2)
Yes
24-hr
0.27
0.266 (3)
Yes
PMio
Annual
0.2
0.0003
Yes
24-hr
0.3
0.1332
Yes
N02
Annual
0.1
0.01
Yes
Note: Concentrations are presented in |ig/m\ though NO2 concentrations are typically reported for non-modeling
applications in parts per billion (ppb).
( V) All impacts are predicted for the Lye Brook Wilderness Area.
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<2> Includes 0.018 ug/m3 predicted secondary PM2 5 impacts.
Includes 0.1372 ug/m3 predicted secondary PM2 5 impacts.
Though the 24-hour PM2.5 impact is only slightly below the level of the SIL, the predicted
impacts are based on conservative modeling assumptions. The short-term modeling assumes that
all construction phase vessel and equipment activity will occur within the same 24 hours. This
approach is extremely conservative, as it does not account for the construction schedule which
will limit how much activity occurs at once, and it does not account for vessels that will be in
limited supply and therefore, will not be numerous enough for multiple construction activities at
once. Some vessels that will be performing several activities on site will possibly be performed
by only one vessel, rather than multiples of the same vessel type. Therefore, the short-term
model predicted impacts at Lye Brook are expected to be higher than would result from the
construction emissions.
The predicted impacts from the proposed RW facility are compared to the Class I PSD
increments in Table 17. As shown in the table, all predicted impacts are well below the Class I
increments.
Table 17 Comparison of Construct km Period Impacts to Class I PSD Increments
Pollutant
Averaging Time
Class I
PSD
Increment
(ug/m3)
Highest Total
Impact
(ug/m3)(2)
Percent of
Increment
PM25
Annual
1.0
0.02 (1)
2%
24-hr
2.0
0.266 (1)
13%
PM10
Annual
4.0
0.0003
<1%
24-hr
8.0
0.1332
2%
N02
Annual
2.5
0.01
<1%
(1) PM2 5 reported as the sum of primary and secondary impacts.
(2) All impacts are predicted for the Lye Brook Wilderness Area.
(2) EPA Conclusion About Ambient Air Impacts During Construction Phase
The EPA has assessed the ambient air quality demonstration submitted by RW and concludes
that it is appropriate for its intended purpose of estimating construction period impacts from the
source. Therefore, the EPA concludes that there will be no significant impacts at Class I areas
resulting from construction of the source. Predicted impacts for all pollutants and averaging
periods are also well below the Class I increments. Details of RW's modeling are provided in the
applicant's modeling reports included in the administrative record.
2. Operational Phase
The PSD permitting regulations for proposed major new sources generally require applicants to
perform an air quality impact analysis for those pollutants with significant emissions. All
pollutants with emissions greater than these thresholds during both the construction and
operational phases must be appropriately assessed to ensure that emissions from the source do
not cause or contribute to a violation of the NAAQS or PSD increment. Assessment of the
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operations and maintenance emissions was provided by the applicant in a September 2022 report
"Air Quality Impact Modeling Report - Operations and Maintenance Emissions," to correspond
with the Revolution Wind OCS Air Permit Application submitted to EPA on August 12, 2022.
The September 2022 report was supplemented by a memorandum provided by the applicant
entitled "Revolution Wind OCS Air Permit Application - Supplemental Tables Summarizing O&M
Class I Impacts" on January 26, 2023, and by a memorandum provided by the applicant entitled
"Supplemental Information for Temporary Generators" on February 28, 2023.
The following sections provide the EPA's assessment of information provided by RW in
determining whether ambient air impacts from the source are protective of air quality standards.
Specifically, the sections below describe: 1) an overview of the air modeling conducted by RW;
2) comparison of operational phase impacts against the SILs; 3) comparison of operational phase
impacts against the NAAQS; 4) comparison of operational phase impacts against the PSD
increments for Class I and Class II areas; 5) assessment of operational phase impairment to
visibility, soils, and vegetation; and 6) EPA's conclusion about the ambient air impacts during
the operational phase of the facility.
a. Overview of the Air Modeling Conducted by RW
To assess direct impacts within a 50-km distance, RW selected the Ocean and Coastal Dispersion
(OCD) model (Version 5), consistent with Section 4.2. c.i of the Guideline. RW prepared hourly
representative onshore and offshore meteorological data for use with the OCD model based on
prognostic meteorological modeling data provided by EPA. The meteorological data were
extracted from the WRF prognostic model for the three-year period of 2018-2020 using the
MMIF, Version 3.4.2. Prior to using the meteorological data with the OCD model, RW
submitted an evaluation to demonstrate the suitability of the prognostic meteorological data for
such a purpose.68 The EPA's assessment of the RW evaluation of the WRF simulation is that it
provides a sufficient basis for use in a screening analysis with the OCD model for estimating
CO, PMio, PM2.5 and NO2 impacts out to 50 km from RW. Emissions included in the analysis
represent the highest emitting activities anticipated for the operational period of the source.
Impacts from multiple emission scenarios (representing different activities) are assessed
separately or combined as appropriate depending on the averaging time for the relevant air
quality standard. For the short-term scenarios, emissions sources were modeled at or near the
WTG located closest to land, and RW assessed impacts at an array of receptors centered at the
WTG closest to land. For the annual modeling, sources were modeled at locations divided across
the lease area, and RW assessed impacts at an array of receptors centered around the project
centroid. The receptor grids used for both short-term and annual modeling consisted of a dense
grid near the center of the receptor grid and less dense receptor spacing farther from the grid
center out to 50 km. No receptors were excluded from analysis.
68 The evaluation is provided as Appendix A to the September 9, 2022, Air Quality Impact Modeling Report-
Operations and Maintenance Emissions, available as part of the administrative record for the draft permit.
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The facility must also account for secondary formation of PM2.5 resulting from precursor
emissions of SO2 and NOx. To do so, RW employed the MERPs approach, which is an
appropriate Tier 1 demonstration tool consistent with requirements in section 5.4.2.b of the
Guideline, as described in the EPA's April 30, 2019, Guidance. Specifically, RW relied on the
most conservative (lowest) MERPs value from all hypothetical sources located in the northeast
climate zone.69 RW combined the maximum predicted secondary PM2.5 impacts with the
modeled primary (i.e., resulting from direct emissions) PM2.5 impacts to calculate total PM2.5
impacts for comparison with the SIL, NAAQS, and Class II PSD increment.
Modeling methodologies, inputs, and techniques were used consistent with the Guideline and
EPA guidance. RW justified treatment of certain emissions as intermittent with regards to the 1-
hour NO2 NAAQS as addressed in the EPA's March 1, 2011, memorandum, "Additional
Clarification Regarding Application of Appendix W Modeling Guidance for the 1-hour NO2
National Ambient Air Quality Standard" (EPA's March 1, 2011, Guidance). As such, RW
applied a ratio of the number of operating hours per year by 8,760 hours to the 1-hour NO2
emissions. The EPA agrees that RW has appropriately represented the intermittent sources and
accounted for their expected operation with respect to the 1-hour NO2 standard. For modeling 1-
hour NO2 impacts, RW applied EPA's ambient ratio method 2 (ARM2) screening method
consistent with Section 4.2.3.4.d of the Guideline. For modeling annual NO2 impacts, RW
assumed 100% conversion of NOx to NCh.The EPA has evaluated the methods and techniques
included in the air quality impact analyses for the operational period provided by RW and
determined that they are appropriate for assessing compliance with the SILs, NAAQS, and PSD
increment.
As discussed earlier in this section, in the short-term modeling scenarios, the assumption was
made that the vessels would be operating continuously at or near one WTG. In reality, the O&M
vessels will be moving from location to location throughout the wind farm spending only one or
two days near each WTG and OSS each year. By modeling the vessels near a single WTG, the
predicted air quality impacts are considered to be concentrated. In reality, the air quality impacts
are presumed to be distributed across all of the WTGs and the OSSs. Also note, as discussed in
Section c., the cumulative analysis for the 1-hour NO2 and 24-hour PM2.5 NAAQS analysis
summarizes the maximum modeled impacts (in units of ug/m3) resulting from the contributions
from RW and the two neighboring wind farms are independent of time and physical location.
Therefore, the maximum impact from each of the facilities individually were added together -
even though those maximum impacts did not occur at the same location. These worse-case
assumptions made in the modeling approach likely results in the impacts being conservative.
Therefore, EPA does not feel it is necessary to include short term, hourly emission limits on any
specific OCS source to support compliance with NAAQS or increment for short term standards,
i.e., 1-hour NO2 NAAQS and the 24-hour PM2.5 increment.
69 Figure 3-4 of EPA's April 30, 2019, "Guidance on the Development of Modeled Emission Rates for Precursors
(MERPs) as a Tier 1 Demonstration Tool for Ozone and PM2 5 under the PSD Permitting Program" (EPA's April 30,
2019, Guidance).
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b. Assessment of Significant Impacts
The PM2.5 SILs used in this portion of the assessment were established in the EPA's April 17,
2018, Guidance, as described earlier, with associated legal memorandum and technical support
documents. The EPA is relying on the SIL recommended in the April 17, 2018, Guidance as
appropriate for the project.
RW's screening model results for CO, NO2, PM10 and PM2.5 are presented in Table 18. This
screening modeling indicates that impacts for annual NO2, annual PM2.5, annual PM10, 24-hour
PM10, 1-hour CO and 8-hour CO, were below the Class II significance threshold and no further
analysis is warranted. Further analysis was required for 1-hour NO2 and 24-hour PM2.5, and the
sections below will provide summaries of these analyses. Because the modeling scenarios for
short-term SILs (24-hour average or less) were representative of maximum emissions around
each foundation that will be operated as part of the windfarm, the EPA considers the significant
impact area radius to extend from each foundation rather than at the individual receptors used in
this modeling assessment.
Table 18 Comparison of the OCS Source Operational Period Impacts Against Class II SILs
Pollutant
Averaging
Time
Class II SIL
(ug/m3)
Impact
(ug/m3)
Significant
Impacts?
Significant Impact
Area Radius
CO
1-hr
2,000
59.1
No
--
8-hr
500
36.8
No
--
PM2.5
Annual
0.2
0.07®
No
--
24-hr
1.2
2.8(1)
Yes
1.5
PM10
Annual
1.0
0.07
No
--
24-hr
5.0
3.4
No
--
N02
Annual
1.0
0.29
No
--
1-hr
7.5
40.3
Yes
4.5 km
Note: Concentrations are presented in |ig/ml though for NO2 concentrations are typically reported for non-modeling
applications in parts per billion (ppb).
^ Includes 0.11 |ig/m3 predicted secondary PM2.5 impacts.
^ Includes 0.004 |ig/m3 predicted secondary PM2.5 impacts.
c. Compliance with the NAAQS
RW completed a refined modeling analysis for 1-hour NO2 and 24-hour PM2.5.
When using results from refined modeling for NAAQS compliance, background concentrations
including impacts from nearby sources must be combined with impacts from the proposed source
to identify total ambient concentrations for comparison with the NAAQS. RW selected onshore
monitoring data as appropriately representative of air quality in the area. The EPA finds that this
assumption is protective of air quality because it likely overestimates concentrations near the
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windfarm. RW evaluated the emissions sources in the area and determined that the only
potentially interactive sources were South Fork Wind which was recently permitted70 and
Sunrise Wind which recently submitted an OCS permit application but has not yet been issued a
permit. South Fork Wind will be located immediately adjacent to RW, and Sunrise Wind will be
located just south of RW. The EPA concludes that the monitored background values account for
all other nearby sources.
The results of South Fork Wind's O&M SIL modeling were presented in their September 2020
Outer Continental Shelf Permit - "Air Quality Impact Modeling Report for Operations and
Maintenance Emissions." Using the OCD model, it was concluded that the O&M phase
exceeded the SILs for 1-hour NO2 and 24-hour PM2.5. The results of Sunrise Wind's O&M SIL
modeling are presented in their February 2023 Outer Continental Shelf Permit Application -
"Offshore Coastal Dispersion Air Quality Impact Analysis Report'' Using the OCD model, it
was concluded that the O&M phase exceeded the SIL for 1-hour NO2 and did not exceed the SIL
for 24-hour PM2.5. Because RW, South Fork Wind, and Sunrise Wind exceeded the SIL for 1-
hour NO2 and RW and South Fork Wind exceeded the SIL for 24-hour PM2.5, a cumulative
analysis was triggered. To determine the combined impacts from RW, South Fork Wind and
Sunrise Wind, RW combined the SIL modeling impacts from the three projects with the
background concentrations for comparison to the 1-hour NO2 and 24-hour PM2.5 NAAQS. This
method is conservative because it takes worst-case impacts for the projects and combines them
without consideration of temporal or spatial alignment. Even though Sunrise Wind did not
exceed the 24-hour PM2.5 SIL, their contribution to PM2.5 concentrations in the area is included
for conservatism and completeness. The results of the total pollutant concentrations using this
method are shown in Table 19 below.
All refined modeling was performed in accordance with the Guideline and in consultation with
the EPA. Total impacts of PM2.5 included both primary and secondary impacts. Assessment of
NO2 impacts predicted by OCD were post-processed with the ARM2 equation tier 2 screening
method in a manner consistent with the Guideline. RW applied this as a post-processing step
because OCD does not have capabilities to implement this approach directly or include more
refined techniques for NO2 impact screening. The EPA concludes that RW's modeling was
appropriate to assess impacts for these pollutants. A summary of the refined modeling, which
demonstrates compliance with the 24-hr PM2.5 and 1-hr NO2 NAAQS, is presented in Table 19
below.
70 See Final Permit for South Fork Wind, issued January 18, 2022. https://www.epa.gov/eaa-perniitting/soiith-fork-
wind-Ucs-sonth-fork-windfarm-onter-continental-shelf-air-permit.
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Table 19 NAAQs Assessment Results
Pollutant
Avg.
Time
RW
Impact
(ug/m3)
Background
Level
(ug/m3)
South
Fork
Wind
Impact
(ug/m3)
Sunrise
Wind
Impact
(ug/m3)
Total
Concentration
(ug/m3)
NAAQs
(ug/m3)
Exceeds
NAAQs
?
N02
1-hr
40.3
74.20
44.9
11.9
171.3
188.0
No
PM2.5
24-hr
2.80(1)
14.50
8.40(2)
0.28(3)
26.0
35.0
No
Note: Concentrations are presented in |ig/m3. though NO2 concentrations are typically reported for non-modeling
applications in parts per billion (ppb).
(1) Includes 0.11 ug/m3 secondary PM25 impacts
(2) Includes 0.002 ug/m3 secondary PM2 5 impacts
(3) Includes 0.02 ug/m3 secondary PM2 5 impacts
The EPA concludes that the assessment provided by RW sufficiently demonstrates that air
quality impacts will not violate the NAAQS for any pollutant.
d. Compliance with Class IIPSD Increment
RW is required to demonstrate compliance with the PSD increment for PM10, PM2.5 and NO2
because the project is a major source for these pollutants. The significance analysis presented
above demonstrates compliance with the PSD increments for 24-hour and annual PM10, annual
NO2 and annual PM2.5. RW provided a PSD increment analysis for 24-hour PM2.5, for which the
project was shown to have significant impacts. There is no PSD increment for 1-hour NO2, so no
PSD increment analysis is required.
RW is required to demonstrate compliance with the PSD increment for PM10, PM2.5 and NO2
because the project is a major source for these pollutants. The significance analysis presented
above demonstrates compliance with the PSD increments for 24-hour and annual PM10, annual
NO2 and annual PM2.5. RW provided a PSD increment analysis for 24-hour PM2.5, for which the
project was shown to have significant impacts (See Table 159). There is no PSD increment for 1-
hour NO2, so no PSD increment analysis is required. Table 1721 presents the maximum PSD
increment consumed for 24-hour PM2.5 within the RW significant impact area. The maximum
PSD increment consumption occurs within 330 meters of each WTG, and no more than 35% of
the increment is consumed beyond 400 meters from each WTG. The PSD increment
consumption for 24-hour PM2.5 around a single RW WTG foundation is shown in Figure 4. In
Figure 4, the RW WTG is depicted by the yellow dot on the left side of the figure.
Nomans Land Island in the Town of Chilmark in Dukes County, Massachusetts is the closest
land area to the OCS area where the windfarm project is located, and this onshore area is the
CO A for the project. In Massachusetts, the PSD increment, the maximum amount of pollution an
area is allowed to increase, is tracked by county for PM2.5 and by municipality for NO2. No
previous major source project has triggered the minor source baseline date, the date used to
determine the baseline concentration in the area, in Dukes County, or any portion thereof.
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Because the windfarm is not located within the jurisdiction of the Town of Chilmark or Dukes
County, the project does not establish a minor source baseline date for the onshore areas
corresponding to the project. Instead, the EPA considers the OCS lease area as the baseline area
for which the minor source baseline date is set for this OCS project. That is, the minor source
baseline date for BOEM Lease Area OCS-A 0486 for PM2.5 and NO2 is the date of receipt of the
RW Permit Application. Similarly, for the neighboring South Fork Wind facility, the minor
source baseline date for BOEM Lease OCS-A 0517 is January 13, 2021 (set by South Fork) for
NO2 and PM2.571 Therefore, the South Fork Wind facility is a PM2.5 increment consumer and
RW performed an analysis to determine the potential cumulative consumption of the 24-hour
PM2.5 increment from RW and South Fork. The proposed Sunrise Wind facility, which will be
located just south of RW, will also be a PM2.5 increment consumer. However, the results of
Sunrise Wind's O&M SIL modeling, presented in their February 2023 Outer Continental Shelf
Permit Application - "Offshore Coastal Dispersion Air Quality Impact Analysis Report'
concluded that the O&M phase did not exceed the SIL for 24-hour PM2.5. The O&M SIL
modeling predicted impacts from Sunrise Wind (.28 |ig/m3) well below the 24-hour PM2.5 SIL
(1.2 |ig/m3). Therefore, Sunrise Wind was not included in the cumulative increment analysis.
In South Fork Wind's O&M significant impact area (SIA) modeling for 24-hour PM2.5, a
scenario was modeled which is representative of larger-scale repairs that will not occur on a set
schedule. Nevertheless, this scenario was modeled as continuous for three years of
meteorological data, although this activity is only anticipated to occur for 14 days every 2 years.
Therefore, emissions sources that only have a 2% chance of occurring in any 24-hour period
were conservatively modeled as though they would occur continuously. This conservative
modeling of this scenario was found to exceed the Class II SIL for 24-hour PM2.5, with an SIA of
2.5 km. The dimensions used to simulate downwash in the South Fork wind modeling were
representative of the South Fork OSS structure, therefore, the South Fork SIA was assumed to
originate from the South Fork OSS. The nearest RW WTG is 3.7 km from the South Fork OSS,
or 1.2 km from the edge of the SFW 24-hr PM2.5 SIA (see Figure 4). As shown in Figure 34, RW
modeled impacts did not equal or exceed the PM2.5 24-hour SIL at any receptor located within
the South Fork Wind SIA circle. This analysis performed by RW is very conservative for several
reasons:
• It assumes that the worst-case 24-hour RW emissions occur at the same time as the worst-
case South Fork Wind 24-hour emissions (which only have a 2% chance of occurring in any
24-hour period).
• It assumes that these worst-case emissions would occur as close as possible out of the many
square kilometers of lease area between these two projects.
• It assumes that these worst-case emissions that are occurring as close as possible are also
occurring on the worst day of dispersion.
71 The PSD regulations at 40 C.F.R. § 52.21(b)(14)(ii) define the minor source baseline date as the earliest date after
the trigger date on which a major stationary source or a major modification subject to 40 C.F.R. § 52.21 or to
regulations approved pursuant to 40 C.F.R. § 51.166 submits a complete application under the relevant regulations.
The trigger date for PM2 5 is October 20, 2011.
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• As depicted in Figure 4, the maximum 24-hour PM2.5 impacts from RW and South Fork
individually occur in very close proximity to each facility (within 350 meters) and the
concentration gradients around each facility decrease rapidly with distance.
• The SIA for South Fork shown in Figure 4 is conservatively drawn. South Fork does not
have impacts greater than the 24-hour PM2.5 SIL at all locations with the SIA circle. Rather,
the concentric rings composing the SIA represent the maximum 24-hour PM2.5 concentration
anywhere within each ring. If a similar conservative SIA circle with a radius of 1.5 km is
drawn for RW, then the SIAs would overlap by about .3 km. The SIAs would overlap in an
area where each facility has impacts in the 1.2 to 1.5 |ig/m3 range. Therefore, the worst-case
cumulative impact would be less than 3 jig/m3 which is similar to the maximum impact from
RW alone (2.7 jig/m3) and well below the 24-hour PM2.5 increment (9 jig/m3).
Based on this conservative analysis, RW determined that the cumulative impact from RW and
South Fork Wind is less than 3 Ltg/m3 which is well below the 24-hour PM2.5 increment of 9
ug/nv\ The EPA has reviewed the modeling assessment for PSD increment performed by RW
and concludes that the analysis was performed appropriately. Figure 4 was submitted by RW as
part of the "Air Quality Impact Modeling Report - Operations and Maintenance Emissions"
dated September 9, 2022.
Revolution Wind
Figure 6-1. Worst-case PM2.5
24-hour Cumulative Impact
Revolution
Wind
Powered b>
0rsted &
Eversource
Figure 4 PM2.5 SIA Comparison Analysis (24-hr)
asnm
1.2 kilometers
1.5 km from
RWF WTG
PSD increment impacts are normally presented based on the high second-high 24-hour value at
each receptor. The value reported in Table 20 is based on the high-first high 24-hour value as an
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additional measure of conservatism. RW assessed impacts at an array of receptors centered
around the WTG closest to land. For conservatism, RW impacts were assumed to occur at the
WTG nearest to the South Fork Wind OSS.
Table 20 Class II PSD Increment Assessment Results
Pollutant
Averaging Time
Impact (ug/m3)
Class II
PSD
Increment (ug/m3)
Percent of
Increment Consumed
PM2.5
24-hr
2.70 W
9
30%
( V) This value includes both primary and secondary PM2 5 impacts. The secondary PM2 5 impact was 0.11 ug/m3
e. Significance at Class I areas
RW assessed the significance levels at Class I areas by assessing the maximum impacts at 50 km
from the source. Table 21 presents these values. The EPA has reviewed the modeling assessment
for Class I area significance and concludes that the analysis was performed appropriately.
Though the 24-hour PM2.5 impact is only slightly below the level of the SIL, the impacts
predicted by OCD are at 50 km from RW. This modeled impact is expected to be higher than
would result from O&M emissions at Lye Brook which is located 252 km from RW.
Table 21 Class I PSD Significance Assessment
Pollutant
Averaging Time
Class I
PSD SIL
(ug/m3)
Impact
(ug/m3)
Significant
Impacts?
PM2.5
Annual
0.05
0.03 W
No
24-hr
0.27
0.25 W
No
PM10
Annual
0.20
0.03
No
24-hr
0.30
0.20
No
N02
Annual
0.10
0.06
No
(1) This value includes both primary and secondary PM2 5 impacts.
f Impairment to Visibility, Soils, Vegetation, and Growth
RW provided an analysis consistent with the requirements of 40 C.F.R. § 52.21(o) to assess air
quality impacts and impairment to visibility, soils, and vegetation due to operational period
emissions of the OCS Source and general commercial, residential, industrial, and other growth
associated with the operational period of the windfarm. The EPA has evaluated the analyses
provided by RW to address these requirements.
Regarding visibility, RW submitted an analysis of impacts from construction emissions on Class
I areas. This analysis is presented in the Construction Class I SIL and Visibility Modeling
Report, submitted by RW and dated September 2022. The visibility modeling was performed at
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the request of the U.S. Forest Service (USFS"). See Section V.3.c of this fact sheet for more
information. This analysis demonstrates acceptable visibility impacts from construction
emissions at the Lye Brook Wilderness Area. Therefore, considering that O&M emissions are
only about 6% of the construction emissions, the results of the construction phase visibility
analysis imply acceptable impacts for the O&M emissions as well. In addition, RW applied the
EPA VISCREEN model to assess visibility impacts at nearby Class II area vistas and found that
visibility impacts were below significance criteria. The EPA finds that the RW analysis is
appropriate to identify impacts on visibility and that impacts are below the screening thresholds.
Therefore, the EPA concludes that operational emissions from the windfarm will not impair
visibility.
RW assessed impacts on soil and vegetation by comparing the maximum concentrations
predicted by OCD against screening values derived from EPA's December 12, 1980 "Screening
Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals: Final Report."
The EPA finds that the RW analysis is appropriate to identify impacts to vegetation and that
impacts are well below the screening thresholds. EPA expects that impacts to soil will be
similarly low based on the presented emissions levels and distance to land areas from the source.
Therefore, EPA concludes that operational emissions from the windfarm will not impair soil or
vegetation.
RW described projected growth resulting from the operation of the windfarm and stated that no
new significant emissions would be associated with population, economic, and employment
growth due to the source.
Based on the results of the analyses and the EPA's evaluation, the EPA finds that the operational
period emissions and associated impacts from commercial, residential, industrial, and other
growth will not result in an impairment to visibility, soils, or vegetation.
g. EPA Conclusion About Ambient Air Impacts During Operational Phase
The EPA has assessed the analyses submitted by RW related to ambient air impacts during the
operational period. Based on this information and the EPA's assessment, as described above, the
EPA concludes that the operational period emissions will not cause or contribute to violations of
the NAAQS or PSD increment. Therefore, the ambient air impact requirements of the PSD
regulations for the operational period of the source have been satisfied. Under the applicable
Massachusetts regulations at 310 CMR 7.00 incorporated into 40 C.F.R. Part 55, EPA has
authority to require additional modeling for pollutants that are non-major for this project. Based
on the location of the project in an area that is remote from residences, the generally diffuse
nature of the emissions sources, and the anticipated environmental benefits of the project, EPA is
choosing not to exercise its authority to require additional modeling for the operational phase of
this project.
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3. Consultation with Federal Land Managers
For sources impacting Federal Class I areas, 40 C.F.R. § 52.21(p) requires the EPA to consider
any demonstration by the Federal Land Manager that emissions from the proposed source would
have an adverse impact on air quality related values, including visibility impairment. If EPA
concurs with the demonstration, the rules require that the EPA shall not issue the PSD permit.
The USFS requested that a Class I visibility analysis be performed for construction emissions
using the CALPUFF Model. In response to this request, RW performed a visibility analysis for
the Lye Brook Wilderness Area located in southern Vermont approximately 252 km northwest of
the RW project. This analysis is presented in Section 6.2 of the Construction Class I SIL and
Visibility Modeling Report, submitted by RW and dated September 2022. The September 2022
report was supplemented by a memorandum provided by the applicant entitled "Supplemental
Information for Temporary Generators" on February 28, 2023. The visibility analysis
demonstrates acceptable visibility impacts at the Lye Brook Wilderness Area from construction
emissions. The USFS has concurred72 with the results of the visibility modeling analysis.
Considering that the O&M emissions are only approximately 6% of the construction emissions,
the results of the construction phase visibility modeling imply acceptable impacts for the O&M
emissions at the Lye Brook Wilderness Area.
72 See February 1, 2023, email from John Sinclair, US Forest Service, available as part of the administrative record
for the draft permit. Note that a slightly revised visibility analysis was presented as a part of the February 28, 2023,
submittal by RW. See March 6, 2023, email to the US Forest Service, available as part of the administrative record
for the draft permit.
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VI. Nonattainment New Source Review (NNSR)
Within Massachusetts, Dukes County is currently designated as a marginal nonattainment area
for the 2008 ozone NAAQS. See 40 C.F.R. § 81.322. However, portions of the OCS source are
closer to Bristol County, Massachusetts, than they are to Dukes County, and Bristol County is
not a nonattainment area for ozone. Nevertheless, because Massachusetts is part of the Ozone
Transport Region (OTR"),73 and areas within the OTR are treated, at a minimum, as moderate
nonattainment areas for ozone, the ozone precursors NOx and VOC are subject to the state's
NNSR program requirements. The NNSR regulations in Massachusetts are implemented under
310 CMR 7.00, Appendix A. The regulations specify that new major stationary sources or major
modifications to an existing major source within an air quality nonattainment area must undergo
a NNSR review and obtain all applicable federal and state preconstruction permits prior to
commencement of construction. The intent of the NNSR review and conditions are to ensure that
the increased emissions from a new or modified source are controlled to the greatest degree
possible; and to ensure that more than an equivalent offsetting emission reduction (emission
offsets) for operational emissions be achieved by existing sources; so that there will be
reasonable further progress toward achievement of the NAAQS. Regulated NSR pollutants (and
their precursors) for which an area is nonattainment are not subject to PSD review even if the
project emission increase and net emission increase is significant. Instead, they are subject to
major NNSR permitting. Therefore, the ozone precursors NOx and VOC are not subject to PSD
review and instead are subject to major NNSR permitting review as described below. The NNSR
program applies to new major sources and major modifications at existing major sources as
defined and described in 310 CMR 7.00, Appendix A.
Per 310 CMR 7.00, Appendix A, "Major Stationary Source means any stationary source of air
pollutants which emits or has the federal potential emissions greater than or equal to, 100 tpy or
more of any pollutant subject to regulation under the Act, except those lower emissions
thresholds shall apply as follows: 50 TPY of volatile organic compounds (VOC), or 50 TPY of
oxides of nitrogen (NOx)." Since the source74 is an existing major source and subject to COA
requirements for NNSR, the emissions increase from the Revolution Wind project must be
evaluated under NNSR to determine if it exceeds the significant emissions rate of Appendix A
(see Table 22). The NNSR requirements apply to each regulated NNSR pollutant that a "major
source emits in significant amounts" per 310 CMR 7.00, Appendix A. See Table 22 below for a
summary of these applicable thresholds.
Table 22 NNSR SER Thresholds under 310 CMR 7.00, Appendix A
NNSR Regulated Pollutant
NNSR Significant Emission Rate (SER)
Ozone
25 tpy of nitrogen oxides (NOx) where an administratively complete
application was received on or after November 15, 1992, for the
physical change or change in the method of operation.
73 In the CAA amendments of 1990, Congress created the OTR, located in the northeast portion of the country, to
address ozone formation due to transport of air emissions. Congress included all of Massachusetts as one of the
states or commonwealths within the OTR.
74 EPA issued an OCS permit to South Fork Wind, LLC on January 18, 2022.
Page 83 of 133
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NNSR Regulated Pollutant
NNSR Significant Emission Rate (SER)
Ozone
40 tpy of VOC
25 tpy of VOC where an administratively complete application was
received on or after November 15, 1992, for the physical change or
change in the method of operation.
A. Major Modification Applicability
"Major Modification" means any physical change in or change in the method of operation of a
major stationary source that would result in a significant net emission increase of any pollutant,
for which the existing source is major, subject to regulation under the Act: (a) Any net emissions
increase that is considered significant for VOCs shall be considered significant for ozone; and (b)
For the purpose of applying the requirements of 310 CMR 7.00: Appendix A to major stationary
sources of NOx, any significant net emissions increase of NOxis considered significant for ozone,
in addition to any separate requirements for NOx under part C or D of Title I of the Act.75
1. Emission Increase Calculation (Project Emission Increase)
For projects that only involve the construction of new emission units, like Revolution Wind, the
significant emissions increase is the new emissions unit's PTE.76 For a new emission unit, the
baseline actual emissions (BAE) for purposes of determining the emissions increase that will
result from the initial construction and operation of such unit shall equal zero; and thereafter, for
all other purposes, shall equal the unit's PTE.
For assessing the emission increases from the Revolution Wind project, emissions from the
equipment or activities considered part of the OCS source, and all emissions from vessels
servicing or associated with the project, are included in the PTE. This includes emissions from
vessels, regardless of whether the vessel itself meets the definition of an OCS source, when the
vessels are at or going to or from an OCS source and are within 25 nm of the facility. Thus,
emissions from vessels servicing or associated with an OCS source that are within 25 nm77 of the
OCS facility are considered in determining the PTE or "potential emissions" of the OCS source
for purposes of applying the NNSR regulations.
The emission increases from this project are calculated on a pollutant-by-pollutant basis for each
regulated NNSR pollutant emitted by the source. The emission increases include both project
emissions and any emissions from the source associated with the project. The applicant has not
75 Per 310 CMR 7.00, Appendix A, "Major Stationary Source" also specifies that OCS sources shall include fugitive
emissions in determining, for any of the purposes of 310 CMR 7.00: Appendix A, whether the stationary source is a
major stationary source. Therefore, fugitive emissions are considered in evaluating LAER and ambient impacts due
to the regulations not distinguishing between stack and fugitive emissions for these purposes.
76 Under 310 CMR 7.00, "potential to emit" is defined as the maximum capacity of a source to emit a pollutant under
its physical and operational design (pg. 430). Typically, emissions from mobile sources and secondary emissions do
not count when determining a stationary source's PTE. However, the definition of "potential emissions" in the OCS
Air Regulations is expanded to include emissions from all vessels servicing or associated with an OCS source when
within 25 NM.
77 1 Nautical Mile (NM) = 1.15077 Miles
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identified any existing emission units from the South Fork Wind project that are affected by the
Revolution Wind project. Emission decreases are not considered in this step.
Table 23 Emission Increase from the Revolution Wind Project (NNSR)
Revolution Wind
Project Emission Increase
Regulated NNSR Pollutant (TPY)
NOx
VOC
BAE
0
0
PTE
3,978
83.6
A (PTE-BAE)
+ 3,978
+ 83.6
As shown in Table 24, a significant emissions increase (per the definition of significant at 310
CMR 7.00, Appendix A) of ozone has occurred. Note that NOx and VOC are considered
precursors for the criteria pollutant ozone.
Table 24 Worst Case Annual Emission Estimate Compared with NNSR SER Thresholds
NNSR Regulated
Pollutant
Project Emission
Increase (TPY)
NNSR Significant
Emission Rate (TPY)
SER
Triggered?
(Y/N)
NOx
3,978
25
Y
VOC
83.6
25
Y
2. Emission Netting (Contemporaneous Netting)
Per 310 CMR 7.00: Appendix A, the definition of a "net emission increase" consists of two
components: (1) Any increases in actual emissions from a particular physical change or change
in the method for operation from a stationary source (i.e., Emission Increase Calculation (Project
Emission Increase)); and (2) Any other increases and decreases in actual emissions at the source
shall be included for netting purposes, that are contemporaneous with the change and are
otherwise creditable as described in 310 CMR 7.00: Appendix A Net Emissions Increase (b), (c),
(d), (e) and (f). In other words, netting looks at the other projects that may have been or will be
undertaken at a given facility over the contemporaneous period. RW is not pursuing a Step 2
contemporaneous netting analysis because either there are no contemporaneous increases or
decreases foreseeable or any increases or decreases would not impact the applicant's conclusions
on NNSR review for the pollutants that exceed the SER threshold.
3. Summary
Based on the emission levels for the project, as presented in Table 24, NOx and VOC will be
emitted by the Revolution Wind project in quantities exceeding the respective NNSR (SER). The
applicant has identified no anticipated contemporaneous creditable emissions increases or
decreases for the proposed project RW, and therefore, the RW project is considered a major
modification to a major source (South Fork Wind) and therefore subject to NNSR requirements
for NOx and VOC.
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B. Lowest Achievable Emission Rate (LAER)
As defined in 310 CMR 7.00, Appendix A, LAER means, for any source, the more stringent rate
of emissions based on: (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. In no event shall LAER allow a proposed new or modified stationary source to
emit any pollutant more than the amount allowable pursuant to an applicable NSPS.
RW does not yet know specifically which vessels will be utilized for the project. The
procurement of the vessels requires contracts within short timeframes due to the specific nature
of the OCS project which is described in more detail below. Thus, the vessel engine types that
can be secured at the projected time of construction are unknown at the time of this fact sheet. In
addition, RW has indicated that some of the marine vessels will be owned by third parties;
however, the procurement of the vessels for purposes of conducting the work on the project is
ultimately decided by the facility (i.e., Revolution Wind). These third-party vessels are noted to
have the potential to be considered an OCS source. The EPA is considering these facts in
determining LAER for those emission units proposed in the project.
1. Methodology
Although the definition for LAER differs from BACT, the BACT and LAER analysis have
overlap in the methodology used to perform this analysis. EPA follows the equivalent Step 1 and
Step 2 procedure78 as outlined in the "top-down" process used to satisfy the BACT requirements
(see Section V.C.I above) in its analysis of paragraph (a) of the definition of LAER. Paragraph
(b) of the definition of LAER follows Steps 3 through 5 of the "top-down" BACT analysis
closely with only one major distinction. In Step 4 of a BACT analysis, where energy,
environmental, and economic impacts are assessed, the EPA can remove a technology from
consideration based on any of those criteria. However, for LAER determinations, when
determining the emission limit and identifying at least one technology that can be used to
achieve the emission limit, the EPA cannot consider the energy, environmental, or economic
impacts associated with that technology, it is the most stringent emissions limitation for the
project. Furthermore, the LAER analysis is on a per pollutant basis, like PSD, but the regulated
NSR pollutants that are evaluated are only the NAAQS for each emission unit that could emit a
NAAQS in a nonattainment area. In the case of this RW permit application, NOx and VOC are
both subject to NNSR and thus LAER review. In light of these similarities, EPA has conducted a
"top-down" LAER analysis consistent with the definition of LAER in 310 CMR 7.00, Appendix
A. The "top-down" process is described in V.B.I above.
78 Paragraph (a) of the definition for LAER is addressed within Steps 1 and 2 of a BACT analysis. Step 1 of the
BACT analysis requires the identification of all emission control technologies that are possible for the sources,
including technologies used to comply with the most stringent emission limit in a state SIP. Step 2 of the BACT
analysis requires the permitting authority, in this case EPA, to document why a particular control technology is
technically infeasible, for that source category. Unless the proposed LAER has been indicated by the applicant to not
be achievable, such that the cost is so great that project could not be built. The remaining highest ranked technically
feasible technology after Step 3 of the BACT analysis was carried through to Step 5.
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2. LAER Analysis for the Revolution Wind Project
a. Emission Unit Applicability
The RW project is required to apply LAER to all the new emission units proposed in this project.
The Project's emission sources will primarily be compression-ignition internal combustion
engines (CI-ICE). These include engines on vessels while operating as OCS source(s) and
engines on the wind turbine generators (WTGs) and offshore substations(s) (OSS[s]).
Table 25 EUG 1 - Offshore Generators on OSS(s) and WTG(s)
EU ID
Description
Type of
Equipment
Engine
Count
Engine
Rating, kW
(hp)
Hours per
Engine
Construction Equipment
RW-1, RW-2
OSS/OCS Installation &
Commissioning
Auxiliary Generator
on OSS/OCS
2
597 (800)
4,800
RW-3, RW-4,
RW-5, RW-6
Offshore OSS/OCS
Installation &
Commissioning
Temporary
Generator on OSS
4
156 (209)
17,520!
RW-7
Offshore Array Cable
Installation
Generator for Cable
Pull-WTG
1
37 (50)
600
RW-8, RW-9
Offshore Array Cable
Installation
Generator for Cable
Pull-OSS/OCS
2
75 (100)
240
RW-10, 11
Offshore WTG Installation
& Commissioning
Temporary
Generator on WTG
2
24 (32)
120
Operating Equipment
RW-12, 13
OSS/OCS Permanent
Generators
Generator on
OSS/OCS
2
597 (800)
500
RW-14 thru
RW-20
WTG O&M Repair
Generator on WTG
6
120 (160)
720
vfotes:
1 This represents the hours of operation during the entire construction period of the project (i.e., 8,760 hpy x 2 yrs.)
A marine vessel79 typically has two (2) kinds of engines which are considered OCS emission
sources: 1) Propulsion engines, also referred to as main engines, which its primary purposes is to
supply power to move the vessel. However, BACT and LEAR would apply to the propulsion
engines in the construction and operation phases of the project if it meets the definition of an
OCS source. Specifically, where a propulsion engine would be used to supply power for
purposes of performing a given stationary source function, i.e., for example to lift, support, and
orient the components of each WTG during installation., and 2) Auxiliary engines, which supply
power for non-propulsion (e.g., electrical) loads. The applicant has identified the anticipated
horsepower ratings for propulsion and auxiliary engines, Table 26. Note that RW does not yet
79 Large Marine Vessels are noted to typically have Category 3 (C3) engines, which have a per cylinder displacement
of 30 L/cylinder or more; however, some could have smaller Category 1 (CI) or Category 2 (C2) engines. To be
classified as a Category 2 (C2) marine engine, it must be rated to have a displacement greater than or equal to 7.0
L/cylinder and less than 30.0 L/cylinder. To be classified as a Category 3 (C3) marine engine, it must be rated to have
a displacement greater than or equal to 30.0 L/cylinder
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know specifically which engines or vessels will be utilized for the project. Vessel availability is
indicated to be constrained by the limited number of vessels capable of conducting the work,
availability of those vessels at a given time, and limitations imposed by the Jones Act. The
procurement of the vessels, which are indicated to change on short notice, require contracts
within short timeframes due to the specific nature of the OCS project, which is described in more
detail below. Thus, the vessel engine types that can be secured at the projected time of
construction are unknown at the time of publication of this fact sheet. EPA is considering these
facts in the analysis.
Table 26 EUG 2 - Marine Engines on Vessels Operating as Potential OCS Souree(s)
Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Monopile Installation
Heavy Lift Installation Vessel
26,640
1,100
Monopile Installation
Heavy Lift Installation Vessel
34,560
1,100
Monopile Installation
Heavy Lift Installation Vessel
(Generator Small)
NA
4
Monopile Installation
Heavy Lift Installation Vessel
(Power Pack)
NA
746
Monopile Installation
Towing Tug (for fuel barge)
11,060
238
Monopile Installation
Anchor Handling Tug
11,060
238
Monopile Installation
Rock Dumping Vessel
13,500
1,692
Monopile Installation
Vessel for Bubble Curtain
11,060
874
Monopile Installation
Vessel for Bubble Curtain
(Generator (Large))
NA
358
Monopile Installation
Heavy Transport Vessel
(Generator (Small))
NA
4
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Heavy Transport Vessel
11,952
3,600
Monopile Installation
Crew Transport Vessel
2,352
48
Monopile Installation
PSO Noise Monitoring Vessel
11,060
238
Monopile Installation
Platform Supply Vessel
6,000
874
Monopile Installation
Platform Supply Vessel
1,825
525
OSS Topside Installation
Heavy Transport Vessel
13,000
1,220
Turbine Installation
Jack-up Installation Vessel
21,000
895
Turbine Installation
Jack-up Installation Vessel
(Generator (Small))
NA
4
Turbine Installation
Jack-up Installation Vessel
(Cherry Picker)
NA
67
Turbine Installation
Feeder Barge (Generator (Large))
NA
30
Turbine Installation
Towing Tug (for fuel barge)
11,060
238
Offshore Export Cable &
OSS Link
Pre-Lay Grapnel Run
12,780
968
Offshore Export Cable &
OSS Link
Boulder Clearance Vessel
2,803
964
Offshore Export Cable &
OSS Link
Sandwave Clearance Vessel
7,300
964
Offshore Export Cable &
OSS Link
Cable Lay and Burial Vessel
8,946
2,800
Offshore Export Cable &
OSS Link
Cable Burial Vessel - Remedial
8,946
2,800
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Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Offshore Export Cable &
OSS Link
Tug - Small Capacity
4,049
238
Offshore Export Cable &
OSS Link
Tug - Large Capacity
11,060
238
Offshore Export Cable &
OSS Link
Crew Transport Vessel
2,204
201
Offshore Export Cable &
OSS Link
Guard Vessel/Scout Vessel
400
201
Offshore Export Cable &
OSS Link
Survey Vessel
1,302
418
Offshore Export Cable &
OSS Link
DP2 Construction Vessel
12,780
964
Offshore Export Cable &
OSS Link
Misc. Floating Equipment
Landfall
400
201
Offshore Export Cable
Barge Lay (Generator (Small))
NA
75
Offshore Export Cable
Barge Lay (Crane Type 1)
NA
567
Offshore Export Cable
Barge Lay (Generator (Large))
NA
187
Offshore Export Cable
Barge Lay (Power Pack)
NA
373
Offshore Export Cable
Barge Lay (Cherry Picker)
NA
112
Offshore Export Cable
Barge Lay (Excavator)
NA
567
Offshore Export Cable
Support Barge (Generator (Large))
NA
45
Offshore Export Cable
Support Barge (Cherry Picker)
NA
567
Offshore Array Cable
Pre-Lay Grapnel Run
12,780
964
Offshore Array Cable
Boulder Clearance Vessel
2,803
964
Offshore Array Cable
Sandwave Clearance Vessel
7,300
964
Offshore Array Cable
Cable Laying Vessel
8,946
2,800
Offshore Array Cable
Cable Burial Vessel
8,946
2,800
Offshore Array Cable
Crew Transport Vessel
2,204
201
Offshore Array Cable
Walk to Work Vessel (SOV)
6,440
N/A
Offshore Array Cable
Survey Vessel
1,302
418
Offshore Array Cable
Construction Vessel
6,440
N/A
Offshore Cable Transport
Cable Laying Vessel
8,946
2,800
Offshore Cable Transport
Array Cable Transport Freighter
7,950
3,026
All Construction Activities
Safety Vessel 1
400
201
All Construction Activities
Safety Vessel 2
400
201
All Construction Activities
Crew Transport Vessel
2,352
201
All Construction Activities
Crew Transport Vessel
2,162
201
All Construction Activities
Crew Transport Vessel
2,984
100
All Construction Activities
Lift Boat
6,000
N/A
All Construction Activities
Supply Vessel
7,530
N/A
All Construction Activities
Service Operation Vessel
6,920
201
Fisheries Monitoring
for Lobster, Lease Site
400
201
Fisheries Monitoring
for Trawl Survey
400
201
Fisheries Monitoring
for Lease Site Acoustic Telemetry
400
201
Fisheries Monitoring
for Lobster, Export Cable
400
201
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Marine Vessel
Vessel Type
Main Engine
Rating (kW)
Auxiliary Engine
Rating (kW)
Marine Mammal
Mitigation
for Situational Awareness
400
201
Marine Mammal
Mitigation
for Long Term Acoustic
400
201
Marine Mammal
Mitigation
for ST Long Term Studies
400
201
b. Pollutant Applicability
A LAER analysis is required for each new emission unit for each pollutant which exceeds the
NNSR SER. Based on the emission levels for the project, as presented in Table 24, NOx and
VOC are the precursors for the Nonattainment NSR regulated pollutant ozone which will be
subject to LAER.
High Level Summary of LAER Determination
For offshore engines on the wind turbine generators and/or offshore substations, LAER has been
determined to be use of the highest Tier EPA Certified Engine (i.e., Tier 3 or 4, dependent on the
final selected engine size and associated displacement) within 40 CFR Part 60, Subpart mi, and
operated in accordance with a Good Combustion and Operating Practices ("GCOP") Plan.
For marine engines on vessels that operate as an OCS source, LAER has been determined to be
use of the Marine Engine that is certified to the highest Tiered Exhaust Emission Standards (i.e.,
Tier 3 or 4, dependent on the final selected engine size and associated displacement) within 40
CFR Part 60, Subpart IIII and operated in accordance with a Good Combustion and Operating
Practices ("GCOP") Plan.
For third party-contracted U.S. vessels where the availability of the vessel type at the time of the
application is unknown, LAER has been determined to be use of the Marine Engine that is
certified to the highest Tiered Exhaust Emission Standards (i.e., Tier 3 or 4, dependent on the
final selected engine size and associated displacement) within 40 CFR Part 60, Subpart IIII at
time of deployment (not to exceed Tier 2 Emission Standards for applicable vessel types covered
by SIP limitations identified for similar class of sources) and operated in accordance with a Good
Combustion and Operating Practices ("GCOP") Plan. Specific Conditions related to the time of
deployment are justified in the subsection below.
For third party-contracted U.S. or foreign-flagged vessels where the availability of the vessel
type at the time of the application is unknown, LAER has been determined to be use of the
Engines certified to the highest Tiered Exhaust Emission Standards (i.e., Tier III) within 40
MARPOL Annex VI at time of deployment and operated in accordance with a Good Combustion
and Operating Practices ("GCOP") Plan. Specific Conditions related to the time of deployment
are justified in the subsection below.
The following sections document the LAER determination in more detail.
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(1) Step 1 - Eligible LAER Controls
EUG 1—OCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
Possible LAER options were derived from EPA and state RACT/BACT/LAER clearinghouses,
recently issued regulations, and permit decisions from similar projects.
A RBLC search was completed for the last 10 years of determinations (August 12, 2012, through
August 12, 2022) using the following process types: 1.) 17.110- Large ICEs (> 500 HP) - Fuel
Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel); 2.) 17.210 - Small ICEs (< 500 HP)
- Fuel Oil (ASTM #1, 2, includes kerosene, aviation, diesel fuel). The resulting determinations
were divided into three searches: from OCS air permit determinations, large emergency/non-
emergency engines (>500 HP), and small emergency/non-emergency engines (<500 HP). These
results are summarized within the permit application and can be found within the RBLC database
after performing a search using the criteria mentioned above.
The applicable air pollution control technologies or techniques (including lower-emitting
processes and practices) that have the potential for practical application to the EUG 1 are listed
in Table 27.
Control Technology
Pollutant(s)
Note(s)
Good Combustion
Practices
NOx, VOC
Use of good combustion practices based on the most
recent manufacturer's specifications issued for these
engines.
Highest applicable EPA
Tier Marine Engine at
40C.F.R. Part 1042 or
EPA Tier 4 Nonroad
Engine at 40 C.F.R. Part
1039
NOx, VOC
Tier 2 and Tier 3 certified engines are designed to
incorporate pre-combustion controls such as fuel injection
timing, exhaust gas recirculation, and other engine-based
technologies to meet emissions standards. In addition to
the pre-combustion controls, Tier 4 certified engines may
be equipped with an integrated SCR, DPF, and/or DOC.
EUG 2—Marine Engines on Vessels when operating as OCS Source(s)
Possible LAER options were derived from EPA and state RACT/BACT/LAER clearinghouses,
recently issued regulations, and permit decisions from similar projects.
A RBLC search was completed for the last 10 years of determinations (August 12, 2012, through
August 12, 2022). Note that the RBLC only contained those facilities with an OCS air permit for
oil production, generally in the Gulf of Mexico off the coast of Florida. However, the previous
OCS Permits Determinations issued to South Fork Wind and Vineyard Wind 1 are also
considered for purposes of BACT selection.
The applicable air pollution control technologies or techniques (including lower-emitting
processes and practices) that have the potential for practical application to the emissions unit are
listed in Table 28.
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Table 28 Control Technologies or Techniques for Marine Engines on Vessels when operating as OCS
Souree(s)
Control Technology
Pollutant(s)
Note(s)
Good Combustion
Practices
NO2, PM10,
2 5, CO, GHG
Included in the RBLC was a requirement for the permittee to
develop a Good Combustion and Operating Practices (GCOP)
Plan. The plan shall be incorporated into the plant standard
operating procedures (SOP) and shall be made available for
inspection. The plan was specific to include, but not be limited
to i.) A list of combustion optimization practices and a means of
verifying the practices have occurred, ii.) A list of combustion
and operation practices to be used to lower energy consumption
and a means of verifying the practices have occurred, iii.) A list
of the design choices determined to be BACT and verification
that designs were implemented in the final construction.
Highest applicable
EPA Tier Marine
Engine at 40 C.F.R.
Part 1042
NO2, PM10,2.5,
CO
Tier 2 and Tier 3 certified engines are designed to incorporate
pre-combustion controls such as fuel injection timing, exhaust
gas recirculation, and other engine-based technologies to
meet emissions standards. In addition to the pre-combustion
controls, Tier 4 certified engines may be equipped with an
integrated SCR DPF, and/or DOC.
Highest applicable
MARPOL Annex
VI Tier NOx
emission limits
N02
U.S.-flagged vessels must have an Engine International Air
Pollution Prevention (EIAPP) certificate, issued by EPA, to
document that the engine meets Annex VI NOx standards.
Foreign-flagged vessels must have an International Air
Pollution Prevention Certificate (IAPP) to document that the
engine meets Annex VI NOx standards ^
(V) The Annex VI requirements80 apply to U.S.-flagged ships wherever located and to foreign-flagged ships operating
in U. S. waters. Vessels that operate only domestically are exempt from the NOx limits of 40 C.F.R. Part 1043 provided
that their engines meet the requirements of 40 C.F.R. Part 1042 (including Appendix I) and have a displacement of
less than 30 liters per cylinder. Foreign-flagged vessels are exempt from having to meet the marine standards within
40 C.F.R. Part 1042 and are required to meet the emission standards in 40 C.F.R. Part 1043.
As part of the LAER review, the following SIP limitations for similar class of sources to EUG 2
were identified:
• Airborne Toxic Control Measure for Auxiliary Diesel Engines Operated on Ocean-Going
Vessels At-Berth in a California Port (13 CCR § 2299.3 and 17 CCR § 93118.3, dated
January 2, 2009).
• Airborne Toxic Control Measure for Commercial Harbor Craft (17 CCR § 93118.5,
excluding (e)(1), dated July 20, 2011)
California's "At-Berth Regulation" at 13 CCR § 2299.3 and 17 CCR § 93118.3 requires vessel
operators visiting California ports to reduce at-berth emissions from auxiliary engines on ocean-
going vessels by either: 1) turning off auxiliary engines and connecting the vessel to some other
80 In the United States (U.S.), MARPOL Annex VI is implemented through the Act to Prevent Pollution from Ships
(33 U.S.C. §§ 1901-1905) and 40 C.F.R. Part 1043.
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source of power (most likely grid-based shore power); or 2) using alternative control
technologies that achieve equivalent emission reductions (CARB 2017b). This requirement does
not apply to the project's OCS sources because project-related vessels will not be OCS sources
while at-berth.
California's "Commercial Harbor Craft Regulation" at 17 CCR § 93118.5 requires all engines in
"newly acquired" harbor craft that are intended to operate in any Regulated California Waters to
be certified to meet the EPA Tier 2, Tier 3, or Tier 4 marine engine emission standards in effect
at the time of acquisition (see 17 CCR § 93118.5(e)(3) and (4)). Under this regulation, marine
engines for newly acquired in-use harbor craft are not required to meet Tier 4 marine standards,
but engines that are already certified as meeting Tier 4 marine standards cannot be replaced with
lower Tier engines (17 CCR § 93118.5(e)(3)). Any engines in newly acquired new harbor craft
must meet applicable EPA Tier 2, 3, or Tier 4 marine standards in effect at the date of vessel
acquisition (17 CCR § 93118.5(e)(4)). At the time of application, EPA is aware of one vessel
that may become an OCS source and will be "newly acquired" by the Proponent. The parent
company of the RW project, has contracted for the custom buildout of a service operations vessel
for use at 0rsted-owned wind farms in northeast United States. Therefore 17 CCR §
93118.5(e)(3) and 17 CCR § 93118.5(e)(4) apply to the project.
The Commercial Harbor Craft Regulation also requires the eventual replacement or cleanup of
pre-Tier 1 or Tier 1 engines used in ferries, excursion vessels, tugboats, towboats, push boats,
crew and supply vessels, barge, and dredge vessels. Under 17 CCR § 93118.5(e)(6), Tier 1 and
earlier engines in these vessel types must be brought into compliance with emission limits equal
to or more stringent than EPA Tier 2 marine engine emission standards through engine
replacement, modification, or retrofit by the dates provided in the compliance schedules (CARB
2017a). The compliance dates are designed to clean up the fleet's oldest and dirtiest engines first,
while giving more time for relatively newer, Tier 1 engines to be upgraded or replaced. Based
on the EPA-approved 2011 version of the Commercial Harbor Craft Regulation that is
incorporated into the California SIP (see 83 Fed. Reg. 23232, May 18, 2018), these vessel types
are defined as:
• Ferry: A harbor craft having provisions only for deck passengers or vehicles, operating
on a short run, on a frequent schedule between two points over the most direct water
route, and offering a public service of a type normally attributed to a bridge or tunnel.
• Excursion vessel: A self-propelled vessel that transports passengers for purposes
including, but not limited to, dinner cruises; harbor, lake, or river tours; scuba diving
expeditions; and whale watching tours. "Excursion Vessel" does not include crew and
supply vessels, ferries, and recreational vessels.
• Tugboat: Any self-propelled vessel engaged in, or intending to engage in, the service of
pulling, pushing, maneuvering, berthing, or hauling alongside other vessels, or any
combination of pulling, pushing, maneuvering, berthing or hauling alongside such vessels
in harbors, over the open seas, or through rivers and canals. Tugboats generally can be
divided into three groups: harbor or short-haul tugboats, ocean-going or long-haul
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tugboats, and barge tugboats. "Tugboat" is interchangeable with "towboat" and "push
boat" when the vessel is used in conjunction with barges.
• Towboat or push boat: Any self-propelled vessel engaged in or intending to engage in the
service of pulling, pushing, or hauling alongside barges or other vessels, or any
combination of pulling, pushing, or hauling alongside barges or other vessels. Push boats
and towboats are interchangeable terms.
• Crew and supply vessel: A self-propelled vessel used for carrying personnel and/or
supplies to and from off-shore and in-harbor locations (including, but not limited to, off-
shore work platforms, construction sites, and other vessels).
• Barge: A vessel having a flat-bottomed rectangular hull with sloping ends and built with
or without a propulsion engine.
• Dredge: A vessel designed to remove earth from the bottom of waterways, by means of
including, but not limited to, a scoop, a series of buckets, or a suction pipe. Dredges
include, but are not limited to, hopper dredges, clamshell dredges, or pipeline dredges.
The following vessel types and engines are exempt from 17 CCR § 93118.5(e)(6), as
incorporated into the California SIP:
• Temporary replacement vessels (a temporary replacement vessel is only exempt upon
written approval and can only be used as a replacement for up to one year
• Temporary emergency rescue/recovery vessels
• Recreational vessels, registered historic vessels, US Coast Guard (USCG) vessels, and
military tactical support vessels
• Near-retirement vessels (must be taken out of service within one year of its engines'
compliance date)
• Engines less than 50 horsepower
• Ocean-going vessels other than ocean-going tugboats and towboats.81 Ocean-going
vessels are defined as a commercial, government, or military vessels meeting any one of
the following criteria:
a) a vessel greater than or equal to 400 feet in length overall as defined in 50 C.F.R.
§ 679.2, as adopted June 19, 1996;
b) a vessel greater than or equal to 10,000 gross tons per the convention
measurement (international system) as defined in 46 C.F.R. 69.51.61, as adopted
September 12, 1989; or
o 1
Ocean-going tugboats and towboats are defined as tugboats and towboats with a "registry" (foreign trade)
endorsement on its USCG certificate of documentation, or tugboats and towboats that are registered under the flag of
a country other than the U.S.
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c) a vessel propelled by a marine compression-ignition engine with a per cylinder
displacement of greater than or equal to 30 liters.
The EPA's review of SIPs found no other NOx or VOC emission limitations relating to marine
compression-ignition internal combustion engines.
(2) Step 2 - Eliminate Technically Infeasible Options
Below is a summary of the reasons for eliminating, or justification for not eliminating, each of
the control options from further consideration in the top down LAER analysis for this project.
For more details, please refer to the permit application and support documents in the docket.
In general, the EPA considers a technology technically feasible if it has been demonstrated and
operated on the same type of source, or it is "available" and "applicable." Each of the criteria is
included in the analysis for the different options to maintain full transparency.
EUG 1 - PCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
Good combustion practices - Good combustion practices entail operating the engine according
to the manufacturer's recommendations and generally accepted industry practices. This option is
technically feasible.
Purchase the Highest Tier Certified Engine under NSPS IIII - OCS Generator Engine(s)
installed on the OSS and/or WTG that are certified to the highest applicable EPA Tier Marine
Engine Standards at 40 C.F.R. Part 1042 or EPA Nonroad Engine Standards at 40 C.F.R. Part
1039 are equipped with an integrated SCR, DPF, and/or DOC. Furthermore, since the Tier
Certified emission standards consider the reduction in pollution from the integrated technologies
in the design, they are considered a demonstrated control technology. This option is technically
feasible.
As of the release of this fact sheet, Marine Tier 3 and Marine Tier 4 emission standards required
by 40 C.F.R. Part 1042 are fully in effect, and U.S. EPA has not adopted more stringent
certification standards for the marine sector. Therefore, the Marine Tier 3 (Category 3 Marine
Engines) and Marine Tier 4 (Category 1 and 2 Marine Engines) NOx, HC, CO, and PM emission
standards82 represent the most stringent level of emissions control required by 40 C.F.R. Part
1042. Similarly, the Tier 4 Nonroad Standards emission standards required by 40 C.F.R. Part
1039 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
the nonroad sector. Therefore, the Nonroad Tier 4 NOx, HC, CO, and PM emission standards83
represent the most stringent level of emissions control required by 40 C.F.R. Part 1039.
EUG 2 - Marine Engines on Vessels Operating when operating as OCS Source(s)
82 The Tier 3 and Tier 4 marine engine emission standards may be certified to NOx, HC, or NOx + HC.
83 Depending on engine size, the Tier 4 nonroad engine emission limits may be certified to nonmethane hydrocarbon
(NMHC) + NOx, or NMHC and NOx separately.
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To a large extent, the "applicability" analysis of the potential LAER technologies for EUG 2 is
identical to the EUG 1 "applicability" analysis in terms of the rational of applicable technologies
since the operating conditions are presumed to be the similar. However, the "availability"
analysis of potential LAER options for EUG 2 are constrained in such a way that it needed to be
distinguished from the EUG 1 "applicability" analysis.
The EPA has specifically considered these facts within a separate analysis addressed in detail
below for the following circumstances:
• EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has
secured contracts and the availability of the vessel type at the time of the application is
known.
• EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown.84
• EUG 2 - Scenario 3 - Third-party-contracted vessels proposed with the project, which
could be U.S.- or foreign-flagged otherwise regulated under MARPOL Annex VI where
the availability of the vessel type at the time of the application is unknown.
Table 29 - Summary of Technical Feasible Options for EUG 2 LAER
Control Technology
Technically Feasible (Y/N)
Option 1 - Good Combustion Practices
EUG 2 - Scenario 1
Y
EUG 2 - Scenario 2
Y
EUG 2 - Scenario 3
Y
Option 2 - Highest Tier Certified Marine Engine at 40 C.F.R. Part 1042
EUG 2 - Scenario 1
Y
EUG 2 - Scenario 2
Y1
EUG 2 - Scenario 3
N/A
Option 3 - Highest Tier Certified Marine Engine at MARPOL Annex VI Tier (U.S.- and/or Foreign-
Flagged Third-Party Vessels)
EUG 2 - Scenario 1
N/A
EUG 2 - Scenario 2
N/A
EUG 2 - Scenario 3
Y2
Option 4 - Tier 1 and earlier engines in meeting the vessel types contained within the CA SIP must be
brought into compliance with emission limits equal to or cleaner than EPA Tier 2 marine engine
emission standards through engine replacement, modification, or retrofit
EUG 2 - Scenario 1
N/A
84 Note that NO2 is subject to BACT since the facility is in an NO2 attainment area, while NOx is subject to LAER
as an ozone precursor since the facility is considered part of an ozone nonattainment area. As presented in Section
VLB, the LAER determination considers the California SIP requirements for certain types of existing marine vessels
to be retrofitted to meet, at a minimum, the EPA Tier 2 Marine Engine Standards at 40 C.F.R. Part 1042. Since
LAER is regulating NOx (and therefore includes N20 and NO2 by proxy) it is presumed to be the more stringent
requirement. For those units, the LAER (NOx) requirements will supersede the BACT (NO2) determination.
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Control Technology
Technically Feasible (Y/N)
EUG 2 - Scenario 2
Y
EUG 2 - Scenario 3
N/A
V/A means that this control technology is not intended to be included an a BACT option within Step 1 for
that operating scenario.
Option 2 for Scenario 2 has constraints regarding vessel availability which must be a consideration for Option 2 for
it to not be excluded from BACT altogether.
9
Option 3 for Scenario 3 has constraints regarding vessel availability which must be a consideration for Option 3 for
it to not be excluded from BACT altogether.
EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has secured
contracts and the availability of the vessel type at the time of the application is known.
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. Since this practice is
"demonstrated and operated" this potential BACT option is technically feasible.
Option 2 - Marine vessels that are certified to the highest applicable EPA Tier Marine Engine
Standards at 40 C.F.R. Part 1042 are equipped with an integrated SCR, DPF, and/or DOC.
Furthermore, since the Tier-Certified emission standards consider the reduction in pollution from
the integrated technologies in the design, they are considered a demonstrated control technology.
This option is technically feasible.
As of the release of this fact sheet, Marine Tier 3 emission standards required by 40 C.F.R. Part
1042 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
category 3 engines in the marine sector. Furthermore, RW has secured a contract to use the
Charybdis Vessel (Jack-up Installation Vessel) for the WTG installation activities. The engines
installed on the Charybdis vessel are Category 3 Marine Engines and will be EPA-Certified to
meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, CO, and PM emission
standards85 which represent the most stringent level of emissions control required by 40 C.F.R.
Part 1042.
EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown.
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. Since this practice is
"demonstrated and operated" this potential BACT option is technically feasible.
Option 2 - Marine vessels that are certified to the highest applicable EPA Tier Marine Engine
Standards at 40 C.F.R. Part 1042 are assessed for technical feasibility in terms of applicability
and availability. With certain considerations given for vessel availability. Option 2 for Scenario
2 is considered technically feasible.
85 The Tier 3 and Tier 4 marine engine emission standards may be certified to NOx, HC, or NOx + HC.
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Restricting the use of marine engines to only those which are certified to the highest applicable
Tier Standards for Marine Engine is not a technically feasible option for the RW project. EPA
has concluded that the "availability" of the options via commercial channels is the limiting
factor. EPA acknowledges the "applicability" of the add on control technologies86 when applied
to marine engines as technically viable options based on chemical, physical, and engineering
principles. Therefore, it is proposed that the project will not eliminate the use of vessels with the
highest tiered marine engines, however the use of the next lowest tiered vessel should be
allowable in instances where a higher tiered vessel is not available at the time of deployment.
Applicable
As of the release of this fact sheet, Marine Tier 3 emission standards required by 40 C.F.R. Part
1042 are fully in effect, and U.S. EPA has not adopted more stringent certification standards for
category 3 engines in the marine sector. Furthermore, RW has secured a contract to use the
Charybdis Vessel (Jack-up Installation Vessel) for the WTG installation activities. The engines
installed on the Charybdis vessel are Category 3 Marine Engines and will be EPA-Certified to
meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, CO, and PM emission standards
which represent the most stringent level of emissions control required by 40 C.F.R. Part 1042.
Option 2 for Scenario 2 is applicable.
Available
This scenario prompted a separate analysis based on information from RW which indicates that
there will be marine vessels used in the project owned by third parties. With this considered, the
predictability of vessel availability is indicated to be a large constraint to construction and
operations of the RW windfarm, which inherently limits the number of vessels capable of
conducting the work available at the time needed. Limitations imposed by the Jones Act87 are
also a constraint. The fleet of vessels available that can perform the construction activity is
limited due to the specific vessel requirements needed for performing the work. As described in
the permit application, slowing down, delaying, or extending the project's schedule to wait for a
higher tiered vessel's availability would have significant implications that could prevent the
project from being built because many of the larger, more specialized, vessels are in limited
supply.88 Restricting the use of marine engines to only those which are certified to the highest
applicable Tier Standards for Marine Engine is not a technically feasible option for the RW
project since the "availability" of the highest Tier Engines via commercial channels is the
limiting factor. However, EPA proposes to not eliminate the use of vessels with the highest
tiered marine engines altogether particularly since the "applicability" of the NSPS technology-
based federal standards apply to marine engines and therefore are technically viable options
based on chemical, physical, and engineering principles.
In lieu of eliminating the use of the highest tier marine vessels altogether, EPA proposes
conditions that consider the inherent limitation on the number of specialized vessels that are
86 EPA acknowledges marine engines have their own constraints (i.e., operating in a harsher environment, variable
loads, temperature fluxes etc...) when compared to typically stationary engine.
87 Supra note 52.
88 See https://www.energy.gov/sjtes/defcmlt/ftks/2022-08/offshore wind market report 2022.pdf
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currently available to the offshore wind industry. The applicant has agreed to utilize Scenario 2
vessels that are certified to the highest applicable EPA Tier Marine Engine Standards (i.e., Tier 3
or 4, depending on engine size) at 40 C.F.R. Part 1042. In the case that a vessel certified to the
highest applicable EPA Tier Marine Engine Standard (depending on engine size) is not available
within two hours of when the vessel must be deployed, the permittee will be allowed to utilize
Marine Engines on Vessels certified to the next highest applicable EPA Tier Marine Engine
Standards (i.e., as an example Tier 3 or Tier 2). Similarly, if the total emissions associated with
the use of a vessel with the higher Tier engine(s) would be greater than the total emissions
associated with the use of the vessel with the next lower Tier engine(s), the permittee will be
authorized to use the next lower Tier engine(s). When determining the total emissions associated
with the use of a vessel with a particular engine, the permittee will include the emissions of the
vessel that would occur when the vessel would be in transit to the WDA from the vessel's
starting location. With these considerations, Option 2 for Scenario 2 is considered available.
At a minimum, all engines subject to this condition shall comply with emission limits equal to or
more stringent than EPA Tier 2 marine engine emission standards. In no event will the marine
engines on applicable vessels covered in Scenario 2 be allowed emit more than the Tier 2
emission limits at 40 C.F.R. Part 1042. Appendix I. This ensures that the Project's OCS sources
will meet the most stringent NOx and VOC emission rates contained in the California SIP.
Option 4 - Tier 1 and earlier engines in meeting the vessel types contained within the CA SIP
must be brought into compliance with emission limits equal to or cleaner than EPA Tier 2 marine
engine emission standards through engine replacement, modification, or retrofit. Since this
requirement has been demonstrated to be feasible within the SIP limitations for similar class of
sources. Option 4 for Scenario 2 is considered technically feasible.
Therefore, retrofitting and/or modifying existing pre-Tier 1 or Tier 1 marine engines to comply
with emission limits equal to or more stringent than EPA Tier 2 marine engine emission
standards is also applicable since the SIP limitations is for similar class of sources. The
Commercial Harbor Craft Regulation requires the eventual replacement or cleanup of pre-Tier 1
or Tier 1 engines used in ferries, excursion vessels, tugboats, towboats, push boats, crew and
supply vessels, barge, and dredge vessels. Under 17 CCR § 93118.5(e)(6), Tier 1 and earlier
engines in these vessel types must be brought into compliance with emission limits equal to or
more stringent than EPA Tier 2 marine engine emission standards through engine replacement,
modification, or retrofit by the dates provided in the compliance schedules.
While EPA acknowledges that the procurement of the vessels for purposes of conducting the
work on the project (short-term) is ultimately the responsibility of the facility, it is not feasible
for RW to require the retrofit of specific third-party vessel engines to meet the highest tier
standards for a short-term construction project. This would prevent RW from being able to
substitute vessels on short notice due to schedule changes or other construction issues. However,
the most stringent emissions limitation contained in any California SIP has been demonstrated
for this category of stationary source.
Therefore, the project will require, at a minimum, that all marine engines on vessels subject to
regulation comply with emission limits equal to or more stringent than EPA Tier 2 marine engine
emission standards for the vessels associated with Scenario 2. In no event will the marine
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engines on vessels covered in Scenario 2 be allowed emit more than the Tier 2 emission limits at
40 C.F.R. Part 1042. Appendix I. This ensures that the Project's OCS sources will meet the most
stringent NOx and VOC emission rates contained in the California SIP.
EUG 2 - Scenario 3 - Third-party-contracted U.S. flagged or foreign-flagged vessels proposed
with the project and regulated under MARPOL Annex VI, where the availability of the vessel
type at the time of the application is unknown.
Option 1 - Good combustion practices entail operating the engine according to the
manufacturer's recommendations and generally accepted industry practices. Since this practice is
"demonstrated and operated" this potential BACT option is technically feasible.
Option 3 -Marine vessels that are certified to the highest applicable MARPOL Annex VI Tier
NOx emission limits are assessed for technical feasibility in terms of applicability and
availability. With certain considerations given for vessel availability. Option 3 for Scenario 3 is
considered technically feasible.
Restricting the use of marine engines to only those which are certified to the highest applicable
Tier Standards for Marine Engine is not a technically feasible option for the RW project. EPA
has concluded that the "availability" of the options via commercial channels is the limiting
factor. EPA acknowledges the "applicability" of the add on control technologies89 when applied
to marine engines as technically viable options based on chemical, physical, and engineering
principles. Therefore, it is proposed that the project will not eliminate the use of vessels with the
highest tiered marine engines, however the use of the next lowest tiered vessel should be
allowable in instances where a higher tiered vessel is not available at the time of deployment.
Applicable
As of the release of this fact sheet, the IMO's MARPOL Annex VI Tier III NOx emission
standards for marine vessel engines in Emission Control Areas are fully in effect, and U.S. EPA
has not adopted more stringent certification standards. The Annex VI requirements apply to
U.S.-flagged ships wherever located and to foreign-flagged ships operating in U.S. waters.
Vessels that operate only domestically are exempt from the NOx limits of 40 C.F.R. Part 1043
provided that their engines meet the requirements of 40 C.F.R. Part 1042 (including Appendix I)
and have a displacement of less than 30 liters per cylinder. Foreign-flagged vessels are exempt
from having to meet the marine standards within 40 C.F.R. Part 1042 and are required to meet
the emission standards in 40 C.F.R. §1043.The NOx emission standards for domestic Category 3
marine engines contained in 40 C.F.R. Part 1042.104 are nearly identical to the IMO's MARPOL
Annex VI Tier I, II, and III NOx emission standards for marine vessel engines in Emission
Control Areas (except for a slight variation in model years). Like the marine engine and nonroad
engine emission standards, the Annex VI emission standards are structured as a tiered
progression (Tiers 1 through 3), with each Tier of emission standards becoming increasingly
stringent over time. Option 3 for Scenario 3 is applicable.
89 EPA acknowledges marine engines have their own constraints (i.e., operating in a harsher environment, variable
loads, temperature fluxes etc...) when compared to typically stationary engine.
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Available
This scenario prompted a separate analysis based on information from RW which indicates that
there will be marine vessels used in the project owned by third parties which are U.S.-flagged
ships and foreign-flagged ships operating in U.S. waters otherwise not subject to the
requirements of NSPS IIII (i.e., marine requirements of 40 C.F.R. Part 1042). Therefore, the
predictability of vessel availability is indicated to be a large constraint to construction and
operations of the RW windfarm, which inherently limits the number of vessels capable of
conducting the work available at the time needed. Limitations imposed by the Jones Act90 are
also a constraint. The fleet of vessels available that can perform the construction activity is
limited due to the specific vessel requirements needed for performing the work. As described in
the permit application, slowing down, delaying, or extending the project's schedule to wait for a
higher tiered vessel's availability would have significant implications that could prevent the
project from being built because many of the larger, more specialized, vessels are in limited
supply.91
In lieu of eliminating the use of the highest tier marine vessels altogether, EPA proposes
conditions that consider the inherent limitation on the number of specialized vessels that are
currently available to the offshore wind industry. The applicant has agreed to utilize Scenario 3
vessels that are certified to the highest applicable Annex VI Engine Standards (i.e., Tier III). In
the case that a vessel certified to the highest applicable Annex VI Engine Standards (i.e., Tier III)
is not available within two hours of when the vessel must be deployed, the permittee will be
authorized to utilize Marine Engines on Vessels certified to the next highest applicable Annex VI
Engine Standards (i.e., Tier II or I). Similarly, if the total emissions associated with the use of a
vessel with the higher Tier engine(s) would be greater than the total emissions associated with
the use of the vessel with the next lower Tier engine(s), the permittee will be authorized to use
the next lower Tier engine(s). When determining the total emissions associated with the use of a
vessel with a particular engine, the permittee will include the emissions of the vessel that would
occur when the vessel would be in transit to the WD A from the vessel's starting location. With
these considerations, Option 3 for Scenario 3 is considered available.
(3) Step 3 - Rank remaining control technologies
GCOP is selected for all units in EUG 1 and EUG 2. Therefore, it is not represented below. The
facility will be required to incorporate the GCOP into the facility SOPs and shall make the
GCOP available for inspection. The GCOP should include, but not be limited to: i.) A list of
combustion optimization practices and a means of verifying the practices have occurred; ii.) A
list of combustion and operation practices to be used to lower energy consumption and a means
of verifying the practices have occurred; iii.) A list of the design choices determined to be LAER
and verification that designs were implemented in the final construction.
90 Supra note 52.
91 See https://www.energy.gov/sjtes/defcmlt/ftks/2022-08/offshore wind market report 2022.pdf.
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EUG 1 - PCS Generator Engine(s) Installed on the OSS(s) and/or WTG(s)
GCOP and engines certified to the highest applicable EPA Tier Marine Engine92 at 40 C.F.R.
Part 1042 or EPA Tier 4 Nonroad Engine93 at 40 C.F.R. Part 1039 contain the most stringent
emission limitations in the ranking (Step 3) for EUG 1.
Nitrogen Dioxide (NOx)
Offshore Engines (RW-3, RW-4, RW-5, RW-6, RW-7, RW-8, RW-9, RW-10, RW-11, RW-14, RW-
15, RW-16, RW-17, RW-18, RW-19)
• The HC + NOx emission standard for CI engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. The Tier 4 emission standards for CI engines are
only applicable to emission units with a max power rating greater than or equal to 600 kW.
The applicant has not identified any offshore generator, as contained in Table 8, to have a
maximum power rating greater than or equal to 600 kW. Therefore, for CI engines, the
Tier 3 HC + NOx emission standard range of 5.4-5.8(g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 19 < kW <37, the NMHC + NOx
emission standard (Tier 4) of 4.7 (g/kW-hr) represents the stringent level of emissions
control required by 40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 37 < kW < 56, the NMHC + NOx emission
standard of 4.7 (g/kW-hr) represents the stringent level of emissions control required by 40
C.F.R. Part 1039.
• For engines with a power rating (kW) between 75 < kW < 130, the NOx emission standard
(Tier 4) of 0.40 (g/kW-hr) represents the stringent level of emissions control required by
40 C.F.R. Part 1039.
• For engines with a power rating (kW) between 130 < kW < 225, the NOx emission standard
(Tier 4) of 0.40 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
Offshore Engines (RW-1, RW-2, RW-12, RW-13)
• The HC + NOx emission standard for CI engines (Tier 3) ranges based on the specific
displacement (L/cylinder) of the engine. The Tier 4 emission standards for CI engines are
only applicable to emission units with a maximum power rating greater than or equal to
92 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tier 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase.
93 Per 40 C.F.R. Part 1039, the U.S. EPA nonroad compression ignition (CI) engines have emissions standards (Tier
1, 2, 3, and 4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and particulate matter
(PM) that become progressively cleaner as Tier levels increase.
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600 kW. The applicant has not identified any offshore generator, as contained in Table 8,
to have a maximum power rating greater than or equal to 600 kW. Therefore, for CI
engines, the Tier 3 HC + NOx emission standard range of 5.4-5.8(g/kW-hr) represents the
most stringent level of emissions control required by 40 C.F.R. Part 1042.
• For engines with a power rating (kW) between 560 < kW < 900, the NOx emission standard
(Tier 4) of 3.5 (g/kW-hr) represents the most stringent level of emissions control required
by 40 C.F.R. Part 1039.
EUG 2 - Marine Engines on Vessels Operating when operating as PCS Source(s)
The EPA has addressed Step 3 in detail below for the following EUG 2 operating scenarios:
• EUG 2 - Scenario 1 - Vessels regulated under 40 C.F.R. Part 1042 where RW has
secured contracts and the availability of the vessel type at the time of the application is
known
• EUG 2 - Scenario 2 - Third-party-contracted vessels regulated under 40 C.F.R. Part 1042
where the availability of the vessel type at the time of the application is unknown94
• EUG 2 - Scenario 3 - Third-party-contracted vessels proposed with the project, which
could be U.S.- or foreign-flagged otherwise regulated under MARPOL Annex VI where
the availability of the vessel type at the time of the application is unknown.
EUG 2 — Scenario 1
GCOP and Marine Engines on the Charybdis Vessel certified to the highest applicable EPA Tier
Marine Engine Standards 95 at 40 C.F.R. Part 1042 contains the most stringent LAER in the
ranking (Step 3) for EUG 2 - Scenario 1.
• RW has secured a contract to use the Charybdis Vessel (Jack-up Installation Vessel) for
the WTG installation activities. The engines installed on the Charybdis vessel are
Category 3 Marine Engines and will be EPA-Certified to meet the Marine Tier 3
(Category 3 Marine Engines) NOx and HC emission standards which represent the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
94 Note that NO2 is subject to BACT since the facility is in an NO2 attainment area, while NOx is subject to LAER
as an ozone precursor since the facility is considered part of an ozone nonattainment area. As presented in Section
VLB, the LAER determination considers the California SIP requirements for certain types of existing marine vessels
to be retrofitted to meet, at a minimum, the EPA Tier 2 Marine Engine Standards at 40 C.F.R. Part 1042. Since
LAER is regulating NOx (and therefore includes N20 and NO2 by proxy) it is presumed to be the more stringent
requirement. For those units, the LAER (NOx) requirements will supersede the BACT (NO2) determination.
95 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase.
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NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
GCPP and Marine Engines on the Eco Edison Vessel certified to the highest applicable EPA Tier
Marine Engine Standards 96 at 40 C.F.R. Part 1042 contains the most stringent BACT emission
limitations in the ranking (Step 3) for EUG 2 - Scenario 1.
If considered a Category 3 Marine Engines:
• EPA-Certified to meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO, emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
If considered a Category 2 Marine Engines:
• EPA-Certified to meet the Marine Tier 4 (Category 2 Marine Engines) NOx, HC, CO,
and PM emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C2 engines (Tier 4) the Tier 4 NOx emission standard range
of 1.8 (g/kW-hr) represents the most stringent level of emissions control required by 40
C.F.R. Part 1042.
• The C3 engines, the Tier 4 HC emission standard of 0.19 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
96 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
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• The C3 engines, the Tier 4 PM emission standard of 0.04 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
GCPP and Marine Engines on the Primary Crew Transfer Vessel certified to the highest
applicable EPA Tier Marine Engine Standards 97 at 40 C.F.R. Part 1042 contains the most
stringent BACT emission limitations in the ranking (Step 3) for EUG 2 - Scenario 1.
If considered a Category 3 Marine Engines:
• EPA-Certified to meet the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO, emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C3 engines (Tier 3) ranges based on N, the maximum test
speed of the engines in revolutions per minute (rpm). Therefore, for C3 engines, the Tier 3
NOx emission standard range of 2.0-3.4 (g/kW-hr) represents the most stringent level of
emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 HC emission standard of 2.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 3 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
If considered a Category 2 Marine Engines:
• EPA-Certified to meet the Marine Tier 4 (Category 2 Marine Engines) NOx, HC, CO,
and PM emission standards which represent the most stringent level of emissions control
required by 40 C.F.R. Part 1042.
• The NOx emission standard for C2 engines (Tier 4) the Tier 4 NOx emission standard range
of 1.8 (g/kW-hr) represents the most stringent level of emissions control required by 40
C.F.R. Part 1042.
• The C3 engines, the Tier 4 HC emission standard of 0.19 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
• The C3 engines, the Tier 4 PM emission standard of 0.04 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
97 Per 40 C.F.R. Part 1042, the U.S. EPA Category 1, 2, and 3 marine compression ignition (CI) engines have
emissions standards (Tiers 1-4) for oxides of nitrogen (NOx), carbon monoxide (CO), hydrocarbons (HC), and
particulate matter (PM) that become progressively cleaner as Tier levels increase. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
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• The C3 engines, the Tier 4 CO emission standard of 5.0 (g/kW-hr) represents the most
stringent level of emissions control required by 40 C.F.R. Part 1042.
EUG 2 — Scenario 2
GCOP and engines certified to the highest applicable EPA Tier Marine Engine 58 at 40 C.F.R.
Part 1042 contain the most stringent LAER emission limitations in the ranking (Step 3) for EUG
2 - Scenario 2. The project will require, at a minimum, that all marine engines on vessels subject
to regulation comply with emission limits equal to or more stringent than EPA Tier 2 marine
engine emission standards for the vessels associated with Scenario 2. In no event, will the marine
engines on vessels covered in Scenario 2 be allowed to emit more than the Tier 2 emission limits
at 40 C.F.R. Part 1042. Appendix I. This ensures that the Project's OCS sources will meet the
most stringent NOx and VOC emission rates contained in the California SIP.
EUG 2 - Scenario 3
GCOP and prioritizing engines IMO's MARPOL Annex VI Tier III NOx emission standards for
marine vessel engines in Emission Control Areas.
In the U.S., MARPOL Annex VI is implemented through the Act to Prevent Pollution from
Ships (33 U.S.C. §§ 1901-1905) and 40 C.F.R. Part 1043. The Annex VI requirements apply to
U.S.-flagged ships wherever located and to foreign-flagged ships operating in U.S. waters.
However, vessels that operate only domestically are exempt from the NOx limits of 40 C.F.R.
Part 1043 provided that their engines meet the requirements of 40 C.F.R. Part 1042 (including
Appendix I) and have a displacement of less than 30 liters per cylinder.
Table 30 Annex VI NOx Emission Standards (g/kW-hr) 40 C.F.R. 1043.60
Tier
Area of applicability
Implementation date3
Maximum in-use engine speed
Less than
130 RPM
130-2000 RPM b
Over 2000
RPM
Tier I
All U.S. navigable waters and
EEZ
January 1, 2004-
December 31, 2010
17.0
45.0 • n(-°-20)
9.8
Tier II
All U.S. navigable waters and
EEZ
January 1, 2011-
December 31, 2015
14.4
44.0 • n(~a23)
7.7
Tier II
All U.S. navigable waters and
EEZ, excluding ECA and ECA
associated areas
January 1, 2016, and
later
14.4
44.0 • n(~a23)
7.7
Tier III
ECA and ECA associated areas
January 1, 2016, and
later0
3.4
9.0 • n(~a20)
2.0
a Standards apply for engines installed on vessels with a build date in the specified time frame, or for engines that
undergo a major conversion in the specified time frame.
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b Applicable standards are calculated from n (maximum in-use engine speed, in RPM, as specified in § 1042.140).
Round the standards to one decimal place.
0 In the case of recreational vessels of less than 500 gross tonnage with length at or above 24 meters, the Tier III
standards start to apply January 1, 2021.
(4) Step 4 - Evaluate most effective controls and document results
The LAER determination does not consider economic, energy, or other environmental factors.
Therefore, the cost effectiveness of each control technology is not necessary for the selection of
LAER.
(5) Step 5 - Select LAER
Based on the proceeding analysis, the following combination(s) are proposed as LAER for NOx
and VOC emissions from the regulated compression ignition internal combustion engines in the
project.
EUG 1 - PCS Generator Engine(s) Installed on the OSS(s) and WTG(s)
OCS Generator Engine(s) installed on the OSS(s) and WTG(s) certified to the highest applicable
EPA Tier Marine Engine at 40 C.F.R. Part 1042 or EPA Tier 4 Nonroad Engine at 40 C.F.R. Part
1039.
OCS Generator Engine(s) Installed on the OSS(s) and WTG(s) shall be operated in accordance
with the GCOP Plan for the facility. The plan shall be incorporated into the facility SOPs and
shall be made available for inspection. The plan specifically should include, but is not limited to:
i.) a list of combustion optimization practices and a means of verifying the practices have
occurred for each engine type based on the most recent manufacturers' specifications issued for
the engines at the time that they are certified (and any updates from the manufacturer should be
noted and amended in the plan); ii.) a list of combustion and operation practices to be used to
lower energy consumption and a means of verifying the practices have occurred (if applicable);
and iii.) a list of the design choices determined to be LAER and verification that designs were
implemented in the final construction.
EUG 2 - Marine Engines on Vessels Operating when operating as OCS Source(s)
The following requirements apply to all Marine Engines on Vessels Operating when operating as
OCS Source(s). This includes any propulsion and auxiliary generator engines utilized in the
construction and operation phases of the project if it meets the definition of an OCS source.
Specifically, where a propulsion engine would be used to supply power for purposes of
performing a given stationary source function, i.e., for example to lift, support, and orient the
components of each WTG during installation.
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EUG 2 — All Scenarios
Marine Engines on Vessels when Operating as OCS Source(s) shall be operated in accordance
with the GCOP Plan for the facility. The plan shall be incorporated into the facility SOPs and
shall be made available for inspection. The plan specifically should include, but is not limited to:
i.) a list of combustion optimization practices and a means of verifying the practices have
occurred for each engine type based on the most recent manufacturers' specifications issued for
the engines at the time that they are certified (and any updates from the manufacturer should be
noted and amended in the plan); ii.) a list of combustion and operation practices to be used to
lower energy consumption and a means of verifying the practices have occurred (if applicable);
and iii.) a list of the design choices determined to be LAER and verification that designs were
implemented in the final construction.
EUG 2 — Scenario 1
The Marine Engines on the Charybdis Vessel(s) while operating as an OCS source, which is
indicated to be used (but not limited to) the WTG installation activities, shall be EPA certified to
the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and CO emission standards specified
within 40 C.F.R. Part 1042.
GCOP and Marine Engines on the Eco Edison Vessel, while operating as an OCS source, which
is indicated to be used as a Service Operation Vessel, shall be EPA certified to the Marine Tier 3
(Category 3 Marine Engines) NOx, HC, and CO emission standards or Marine Tier 4 (Category
2 Marine Engines) NOx, HC, and CO emission standards specified within 40 C.F.R. Part 1042.
Tier 4 emission standards apply to engine(s) at or above 600 kW, and Tier 3 emission standards
apply to engine(s) below 600 kW.
GCOP and Marine Engines on the Primary Crew Transfer Vessel, while operating as an OCS
source, shall be EPA certified to the Marine Tier 3 (Category 3 Marine Engines) NOx, HC, and
CO emission standards or Marine Tier 4 (Category 2 Marine Engines) NOx, HC, and CO
emission standards specified within 40 C.F.R. Part 1042. Tier 4 emission standards apply to
engine(s) at or above 600 kW, and Tier 3 emission standards apply to engine(s) below 600 kW.
EUG 2 — Scenario 2(i) and (ii)
(2)(i) Engines on vessels while operating as OCS sources that satisfy the definition of a tugboat,
towboat, push boat, crew and supply vessel, dredge, or barge (as defined in Section III and
which do not meet definition of an "exempt vesseF (as defined in Section III) shall be certified to
the highest applicable EPA Tier Marine Engine Standards (i.e., Tier 3 or 4, depending on engine
size) as contained within 40 C.F.R. Part 1042, except if one of the conditions in subparagraph
4.a. or 4.b., below, is met, in which case the Permittee may use the next lower Tier engine (i.e.,
Tier 3). Similarly, if one of the conditions in Section IV(C)(iii)(a.) or (b.), below, is met
regarding the use of a Tier 4 engine, the Permittee may use a Tier 3 engine in lieu of a Tier 4
engine. If one of the conditions in Section IV(C)(iii)(a.) or (b.) is met regarding the use of a Tier
3 engine, the Permittee may use a Tier 2 engine in lieu of a Tier 3 engine. To use a lesser Tier
engine, as described above, the Permittee shall ensure one of the following conditions is met:
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a. A vessel with a higher Tier engine is not available within two hours of when the vessel
must be deployed; or
b. The total emissions associated with the use of a vessel with the higher Tier engine(s)
would be greater than the total emissions associated with the use of the vessel with the
next lower Tier engine(s). For purposes of this subparagraph, when determining the
total emissions associated with the use of a vessel with a particular engine, the
Permittee shall include the emissions of the vessel that would occur when the vessel
would be in transit to the WDA from the vessel's starting location.
At a minimum, all applicable engines subject to this condition shall comply with emission
standards (in terms of g/kW-hr) equal to or cleaner than EPA Tier 2 marine engine emission
standards contained within 40 C.F.R. Part 1042.
2 (ii) All applicable engines on U.S.-flagged vessels when operating as OCS source(s), and
otherwise not subject to scenario 1, 2(i) or 3, shall be certified to the highest applicable EPA Tier
Marine Engine Standards (i.e., Tier 3 or 4, depending on engine size) as contained within 40
C.F.R. Part 1042, except if one of the conditions in subparagraph 4.a. or 4.b., below, is met, in
which case the Permittee may use the next lower Tier engine (i.e., Tier 3). Similarly, if one of the
conditions in (a.) or (b.), below, is met regarding the use of a Tier 4 engine, the Permittee may
use a Tier 3 engine in lieu of a Tier 4 engine. If one of the conditions in (a.) or (b.) is met
regarding the use of a Tier 3 engine, the Permittee may use a Tier 2 engine in lieu of a Tier 3
engine. If one of the conditions in (a.) or (b.) is met regarding the use of a Tier 2 engine, the
Permittee may use a Tier 1 engine in lieu of a Tier 2 engine. To use a lesser Tier engine, as
described above, Permittee shall ensure one of the following conditions is met:
a) A vessel with a higher Tier engine is not available within two hours of when the vessel
must be deployed; or
b) The total emissions associated with the use of a vessel with the higher Tier engine(s) would
be greater than the total emissions associated with the use of the vessel with the next lower
Tier engine(s). For purposes of this subparagraph, when determining the total emissions
associated with the use of a vessel with a particular engine, the Permittee shall include the
emissions of the vessel that would occur when the vessel would be in transit to the WDA
from the vessel's starting location.
At a minimum, all applicable engines subject to this condition shall comply with emission
standards (in terms of g/kW-hr) equal to or cleaner than EPA Tier 1 marine engine emission
standards contained within 40 C.F.R. Part 1042.
EUG 2 - Scenario 3
All applicable engines on U.S.-flagged or foreign-flagged vessels while those vessels are
operating as an OCS source within the ECA (and otherwise not subject to Section IV (C)(ii), (iii)
or (iv), shall be certified to meet or emit less than the MARPOL Annex VI Tier III NOx emission
standards (in terms of g/kW-hr), except if one of the conditions in Section IV(C)(v)(a.) or (b.)
below, is met, in which case the Permittee may use the next lower Tier engine (i.e., Tier II).
Similarly, if one of the conditions in Section IV(C)(v)(a.) or (b.), below, is met regarding the use
of a Tier II engine, the Permittee may use a Tier I engine in lieu of a Tier II engine. To use a
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lesser Tier engine, as described above, Permittee shall ensure one of the following conditions is
met:
a) A vessel with a higher Tier is not available within two hours of when the vessel must be
deployed; or
b) The total emissions associated with the use of a vessel with the higher Tier engine(s)
would be greater than the total emissions associated with the use of the vessel with the
next lower Tier engine(s). For purposes of this subparagraph, when determining the total
emissions associated with the use of a vessel with a particular engine, the Permittee shall
include the emissions of the vessel that would occur when the vessel would be in transit
to the WDA from the vessel's starting location.
At a minimum, all applicable engines subject to this condition shall comply with emission
standards (in terms of g/kW-hr) equal to or cleaner than MARPOL Annex VI Tier I NOx
emission standards contained within 40 C.F.R. Part 1043.
C. Offset Requirements
Emissions during the construction phase for the project will end when construction and
commissioning is completed, and the operational phase begins as defined in the draft permit.
EPA and state/local permitting authorities implementing the NNSR program have interpreted the
NNSR CAA requirements as only requiring offsets for operating emissions, not construction
emissions. This is supported by text in the Clean Air Act and is reflected in EPA regulations.
The project will have emissions that are anticipated to occur every year the wind farm operates
after the wind farm commences commercial operations. To offset operating emissions, the draft
permit requires a continuous emission reduction credit (CERC"), or simply an ERC, which is
referred to as a rate-based ERC in 310 CMR 7.00, Appendix B. The unit used to define a rate-
based ERC is in tons per year, to recognize that the emission credit can offset yearly emissions
that will occur each operating year of the source. The application of the NNSR offset
requirements to operating emissions is consistent with the applicable statutes and permitting
regulations, as well as the practice implemented by state and local NNSR programs.
The Operational Phase Start Date is defined as the date RW identifies in its notice to BOEM,
pursuant to 30 C.F.R. §585.636, that the windfarm will commence commercial operations. The
permit requires RW to obtain offsets for operating emissions prior to the beginning of the
operational phase.
Per 310 CMR 7.00, Appendix A, Section 6(e)(1), offsets for the operational phase of the project
are subject to the adjustment factor of 1.2:1 for VOC or NOx. In addition, per the requirement of
310 CMR 7.00, Appendix B, Section 3(e)(2), persons seeking to use ERCs from the
Massachusetts ERC bank must obtain an amount of credit equal to five (5) percent (%) more
than the amount needed for the offset calculation, this results in a 1.26:1 offset ratio.
Based on the potential emissions from the operational phase of the project, the offsets required
for the RW project are presented below.
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Table 31 Maximum NOx Offsets Needed for Operational Phase of Project (assuming a 1.26:1 offset ratio)
Project Phase
NOx Emissions
NOx Offsets Needed
Units
Operation and Maintenance
211
265.86*
tons per year
* 253.2 tpy (adjustment factor of 1.2:1)
Table 32 Maximum VOC Offsets Needed for Operational Phase of Project (assuming a 1.26:1 offset ratio)
Project Phase
VOC Emissions
VOC Offsets Needed
Units
Operation and Maintenance
5.1
6.43**
tons per year
6.12 tpy (adjustment factor of 1.2:1)
RW can obtain rate-based offsets in the following manner:
• Purchasing ERCs identified in the Massachusetts ERC bank which have been created in
accordance with 310 CMR 7.00, Appendix B. Appendix B allows companies to certify
emission reductions by over-controlling their emissions, shutting down emission units or
entire facilities, or taking enforceable restrictions on their operations that lead to emission
reductions. 310 CMR 7.00, Appendix B was approved into the Massachusetts state
implementation plan on August 8, 1996. See 61 Fed. Reg. 4 1 3 3 5 98. Thus, ERCs in the
Massachusetts ERC bank are federally enforceable.
• Enter into a third-party agreement that requires the third-party to lower its emissions.
Such an agreement would need to be made federally enforceable prior to issuance of the
final permit for RW; or,
• From a facility that has ceased operations and had its CAA permits revoked or rescinded
and has not had the resulting emissions reductions certified under the Massachusetts
trading bank regulations under 310 CMR 7.00, Appendix B. Offsets obtained in this
manner must be memorialized in a document from the Commonwealth of Massachusetts
to ensure that the offsets from such a shutdown are fully in compliance with the CAA and
have not been relied on by Massachusetts to meet other CAA requirements. Once the
offsets are used by a source pursuant to this option, the offsets would be retired and
would no longer be available to be used by another company, or by the Commonwealth
in meeting another CAA requirement.
NNSR offsets are required to be obtained from sources within the same nonattainment area or
may be obtained from another area if two criteria are met. See 310 CMR 7.00, Appendix A{6)(b).
Based on 2014 emission data from the EPA's National Emission Inventory database, total
anthropogenic NOx emissions in Dukes County were 1,034 tons. Due to the lack of availability
of potential NOx offsets (i.e., ERCs) within the Dukes County 2008 ozone nonattainment area,
the EPA anticipates that RW will obtain NNSR offsets using ERCs from another classified area.
The two criteria that must be met when obtaining NNSR offsets from another classified area are:
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1. The other area has an equal or higher nonattainment classification than the area in which
the source is located; and
2. Where the proposed new source or modified source is located in a nonattainment area,
emissions from such other area contribute to a violation of a national ambient air quality
standard in the nonattainment area in which the proposed new or modified source would
construct.
Areas within the OTR are required to meet the requirements of a moderate nonattainment area,
regardless of whether the area is classified as marginal nonattainment or
unclassifiable/attainment. Even though all areas within Massachusetts, outside of Dukes County,
were designated unclassifiable/attainment for the 2008 ozone standard." NNSR offsets from
sources within Massachusetts meet the first criterion since all the Commonwealth is required to
meet the nonattainment requirements of a moderate nonattainment area.100 The second criterion
requires a demonstration that emissions from the other area contributes to a violation of the ozone
standard within Dukes County.101 Based on recent air dispersion modeling that EPA conducted
to assist states with their ozone transport analysis for the 2015 ozone NAAQS, sources within
Massachusetts are projected to contribute 10.54 ppb ozone in Dukes County in 2023.102
Therefore, with both criteria met, the EPA is determining that RW can obtain offsets from
anywhere within Massachusetts.
If offsets were obtained from another state, a separate analysis would need to be performed and
submitted to the EPA and concurred upon prior to relying on those offsets for compliance with
offset obligations.
1. Compliance Demonstration
For nonattainment pollutants, the OCS source will have to obtain offsets as required by the CO A,
as presented in Table 31 and Table 32. To ensure the appropriate amount of NNSR offsets are
obtained from the OCS source, EPA has determined that daily emissions tracking is necessary
and appropriate due to the daily variability in vessel emissions from the OCS source.
The averaging period associated with the emission limits will be a daily rolling, 365-day total.
The daily rolling, 365-day total for NOx and VOC allows the facility the benefit and flexibility to
operate vessels as it needs during operation while the daily emission calculations ensure that
NOx and VOC offsets for the operational phase of the project are properly accounted for. See
Permit No. OCS-R1-05.
99 All of Massachusetts is designated attainment/unclassifiable for the 2015 ozone standard, a standard that is more
stringent than the 2008 ozone standard. See 40 C.F.R. § 81.322.
100 The EPA notes that 310 CMR 7.00, Appendix A requires new or modified sources of NOx and VOC to meet the
requirement of NNSR as if the source were being located in a serious nonattainment area
101 The EPA determined that Dukes County attained the 2008 ozone standard by the July 20,2015 attainment date
(See 81 Fed. Reg. 26697, May 4, 2016).
102 See https://www.epa.gov/airmarkets/memo-and-supplemental-information-regarding-interstate-transport-sips-
2015-ozone-naaqs, last visited on October 19, 2021. The 2015 NAAQS Interstate Transport Assessment Design
Values and Contributions spreadsheet can be found in the docket.
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The B ACT and LAER specific conditions of the permit require each engine utilized on the
project to be certified to one (1) of the following: the NOx emission standards under EPA Tier
Marine Engine Standards at 40 C.F.R. Part 1042, EPANonroad Engine Standards at 40 C.F.R.
Part 1039, U.S.-flagged vessels must have an Engine International Air Pollution Prevention
(EIAPP) certificate, issued by EPA, to document that the engine meets Annex VI NOx standards,
and foreign-flagged vessels must have an International Air Pollution Prevention Certificate
(LAPP").
Note that the Annex VI regulations do not require certification to a HC or VOC emissions
standards. Therefore, the specific conditions require that for those cases, the permittee shall use
manufacturing specifications (for any given engine) when a HC or VOC emission factors are
given. If the engine manufacture specifications do not contain HC or VOC emission factors,
permittee shall then utilize the most representative VOC emissions factors for the vessel utilized
as contained in the EPA Ports Emissions Inventory Guidance (EPA-420-B-22-011, April 2022).
D. Alternative Site Analysis
The location of the Rhode Island/Massachusetts Wind Energy Area (RI-MA WEA) has two lease
areas (North Lease OCS-A 0486 and South Lease OCS-A 0487). The RW project is located
within the Lease Area OCS-A 0486. The South Fork Wind project is located within the Lease
Area OCS-A-0487. The lease area auction and siting decisions by BOEM were the result of a
multi-year effort by state and federal regulatory agencies to identify OCS areas suitable for
offshore renewable energy development. An extensive review of site characterization data and
the assessment of potential impacts was conducted, including environmental, economic, cultural,
and visual resources, and use conflicts.
Alternative siting considerations are addressed extensively around BOEM's approval of the
surrounding lease areas for the industry as outlined in the Construction and Operations Plan
(COP) (07/22) for the project. EPA finds that RW sufficiently satisfied the requirements of the
alternative site analysis for the purposes of NNSR and 310 CMR 7.00, Appendix A, Section
(8)(b) for this project by relying on the analysis outlined in the COP that weighed the necessary
environmental, economic, cultural, and social factors and determined the best location for this
project considering those factors.
E. Nonattainment NSR Compliance Certification
Certification that all major facilities owned or operated in the state are in compliance or on a
schedule for compliance with all applicable emissions limitations. RW meets this requirement
because the South Fork Wind project has not begun activities subject to its OCS air permit and
no other facilities are owned or operated by RW in the COA.
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VII. Other COA Emission Control Requirements
As previously stated, the COA for the windfarm is the Commonwealth of Massachusetts. Thus,
the project is subject to applicable provisions of the Massachusetts air pollution control
regulations which are codified at 310 CMR 4.00 (Timely Action Schedule and Fee Provisions),
6.00 (Ambient Air Quality Standards for the Commonwealth of Massachusetts), 7.00 (Air
Pollution Control), and 8.00 (The Prevention and/or Abatement of Air Pollution Episode and Air
Pollution Incident emergencies). These Massachusetts regulations are incorporated by reference
in 40 C.F.R. Part 55, Appendix A. This section identifies which Massachusetts regulations
incorporated into Appendix A apply to the windfarm, including the vessels that meet the
definition of an OCS vessel and which regulations result in terms and condition(s) specified in
Permit No. OCS-R1-05.
For the purposes of fulfilling requirements for pollutants below major source thresholds but
above the state's minor source permitting or plan approval threshold, a BACT determination103 is
made below for sulfur dioxide (SO2). See Section VII.
310 CMR 7.00 contains the following definitions, which are important to note when assessing
the regulatory requirements of the COA.
Building, Structure, Facility, or Installation means all of the pollutant-emitting activities which
belong to the same industrial grouping, are located on one or more contiguous or adjacent
properties, and are under the control of the same person (or persons under common control). Any
marine vessel is a part of a facility while docked at the facility. Any marine vessel is a part of an
OCS source while docked at and within 25 nm en route to and from the OCS source.
Marine Vessel means any tugboat, tanker, freighter, barge, passenger ship, or any other boat,
ship, or watercraft except those used primarily for recreation.
Stationary Source means any building, structure, facility, or installation which emits, or which
may emit any air pollutant subject to regulation under the Act.
a) A stationary source may consist of one or more emissions units, and
1. may be a land-based point or area source; or
2. may be located in, or on, the OCS or other submerged lands beneath navigable waters
(lakes, rivers, and coastal waters adjacent to Outer Continental Shelf lands); or
3. may be any internal combustion engine, or engine combination, greater than 175
horsepower (hp) used for any stationary application; or
4. may be any internal combustion engine regulated under Sec. Ill (NSPS) of the Act,
regardless of size; or
5. may be any internal combustion engine of less than 175 horsepower (hp) not actually
controlled to meet a regulation under Sec. 213 (Nonroad Engines and Vehicles) of the
Act.
b) A stationary source does not include:
103 In accordance with MassDEP's BACT guidance document https://www.mass.gov/doc/best-available-control-
technology -bact-guidance/download
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1. emissions resulting directly from an internal combustion engine for transportation
purposes; or
2. tailpipe emissions from any source regulated under title II of the Act or any emissions
from in-transit, non-OCS marine vessels.
Fuel Utilization Facility means any furnace(s), fuel burning equipment, boiler(s), space heaters
or any appurtenance thereto used for the burning of fuels, for the emission of products of
combustion, or in connection with any process which generates heat and emits products of
combustion but does not mean a motor vehicle or an incinerator.
Distillate Fuel Oil means No. 1 or No. 2 fuel oil.
Residual Fuel Oil weans No. 4, No. 5, or No. 6 fuel oil.
A. 310 CMR 7.02: Plan Approval and Emission Limitations
The project must meet the requirements for a comprehensive plan approval (CPA) under 310
CMR 7.02(5)(a)(7). To comply with a CPA, Massachusetts' regulations indicate that a BACT
analysis. See 310 CMR 7.02(8)(a)(2).
Project emissions for SO2 fall below PSD applicability thresholds but above thresholds for
sources subject to Massachusetts minor NSR permitting and thus require a BACT analysis,104
whereas emissions for lead fall below Massachusetts' permitting and plan approval thresholds.105
State BACT requirements derived from Massachusetts's regulations apply for SO2.
Massachusetts BACT analysis utilizes the federal methodology procedure in that the same five-
step elimination of air pollution control technologies and strategies is performed to arrive at the
selected emission limit for the project, as described above in Section V.C. In some cases, sources
may be subject to a "top case BACT" emission limit106 where the technology has been
demonstrated to be effective for a source from the same industrial sector in the state. For unique
sources such as this windfarm, EPA does not believe "top case BACT" should be applied, and
EPA is applying the top-down BACT determination process as described in Section V.C. See
310 CMR 7.02(8)(a)2.c.
104 310 CMR 7.02(8)(a)(2) stipulates that a BACT analysis per state guidance is required for all plan approvals, i.e.,
comprehensive and limited plan approvals covering either major or minor sources emitting above the "significance"
threshold for an air pollutant.
105 In Massachusetts, a comprehensive plan approval is required for "any facility where the construction, substantial
reconstruction, alteration or subsequent operation would result in an increase in potential emissions of a single air
contaminant equal to or greater than ten tons per year, calculated over any consecutive 12-month time period." See
310 CMR 7.02(5)(a)(l). A limited plan approval is required for "any facility where the construction, substantial
reconstruction, alteration or subsequent operation would result in an increase in potential emissions of a single air
contaminant equal to or greater than one ton per year and less than ten tons per year, calculated over any consecutive
12-month time period." See 310 CMR 7.02(4)(a).
106 See MassDEP's "Top Case Best Available Control Technology (BACT) Guidelines" at
https://www.mass.gov/doc/top-case-bact-giiidelines/download. THIS SHOULD BE PUT IN THE DOCKET.
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1. S02 State BACT
In no event shall application of B ACT result in emissions of any pollutant which would exceed
the emissions allowed by any applicable standard under 40 C.F.R. Parts 60 and 61. SO2 State
BACT is proposed to be equivalent to the fuel sulfur content requirement to utilize ULSD fuel as
required in 40 C.F.R. Part 60, Subpart IIII ULSD and ECA compliant marine fuel as contained in
40 C.F.R. 1090, depending on engine type.
Per the requirements of 40 C.F.R. Part 1090.325, sulfur content in fuel is restricted to using
ULSD (at 15 ppm sulfur content) for all non-Category 3 marine engines and nonroad engines.
ECA marine fuel must meet the 1000 ppm sulfur content limit for fuel used in category 3 vessels
operating in EC As. BACT also includes prioritizing the use of ULSD in Category 3 marine
engines in lieu of ECA-compliant 1,000 ppm sulfur marine diesel fuel when it is feasible to do
so. If ULSD is determined not feasible for use in Category 3 marine engines, the fuel sulfur
limits of 1,000 ppm that apply to ships operating in specially designated EC As is presumed to
satisfy SO2 State BACT.
B. 310 CMR 7.05: Fuels All Districts
310 CMR 7.05(l)(a)(l) specifies that no person owning, leasing, or controlling the operation of a
fossil fuel utilization facility shall cause, suffer, allow or permit the burning therein of any liquid
fossil fuel having a sulfur content in excess of that listed in 310 CMR 7.05(l)(a)l.: Table 1 and
in accordance with the associated timelines contained in the same table. For distillate oil
(statewide), the sulfur content is restricted to 15 ppm which is equivalent to the fuel sulfur
content requirement to utilize ULSD as contained in 40 C.F.R. Part 60, Subpart IIII.
310 CMR 7.05(l)(a)(3) specifies that on and after July 1, 2007, no person owning, leasing or
controlling a stationary engine or turbine subject to the requirements of 310 CMR 7.02(8)(i), 310
CMR 7.03(10), or 310 CMR 7.26(40) through (44) shall accept for delivery for burning any
diesel or other fuel unless said fuel complies with the applicable U.S. Environmental Protection
Agency sulfur limits for fuel pursuant to 40 C.F.R. 80.29, 40 C.F.R. 80.500, and 40 C.F.R.
80.520(a) and (b) as in effect January 18, 2001.
EPA notes that the fuel regulations, previously within 40 C.F.R. Part 80, have been incorporated
into 40 C.F.R. Part 1090 as of January 1, 2022. Per the definitions contained within 310 CMR
7.00, a marine vessel is considered to be an OCS source while docked at and/or within 25 nm en
route to and from the OCS source. Therefore, any marine vessels that meet the definition of an
OCS are subject to this subpart when operating in the manner specified. All engines installed on
WTGs or OSSs are also subject to the requirements of this section. All requirements contained in
this regulation have been incorporated into the permit.
C. 310 CMR 7.06: Visible Emissions
310 CMR 7.06(l)(a) No person shall cause, suffer, allow, or permit the emission of smoke which
has a shade, density, or appearance equal to or greater than No. 1 of the [Ringlemann Scale]
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Chart for a period, or aggregate period of time in excess of six minutes during any one hour,
provided that at no time during the said six minutes shall the shade, density, or appearance be
equal to or greater than No. 2 of the Chart.
310 CMR 7.06(l)(b) No person shall cause, suffer, allow or permit the operation of a facility so
as to emit contaminant(s), exclusive of uncombined water or smoke subject to 310 CMR
7.06(l)(a) of such opacity which, in the opinion of the Department, could be reasonably
controlled through the application of modern technology of control and a good Standard
Operating Procedure, and in no case, shall exceed 20% opacity for a period or aggregate period
of time in excess of two minutes during any one hour provided that, at no time during the said
two minutes shall the opacity exceed 40%.
310 CMR 7.06(3) contain specific requirements that apply to marine vessels. All tailpipe
emissions from OCS marine vessels (in-transit and when docked), and offshore engines installed
on the WTGs and/or OSSs are subject to the visible emission standards contained in this section.
Note that tailpipe emissions from any source regulated under Title II of the Act or any emissions
from in-transit, non-OCS marine vessels are not subject to the requirements of this subpart,
specifies that marine vessels shall be subject to the provisions of 310 CMR 7.06(l)(a) and
7.06(l)(b). 310 CMR 7.06(3) shall apply only in the Merrimack Valley Air Pollution Control
District, Metropolitan Boston Air Pollution Control District, and the Southeastern Massachusetts
Air Pollution Control District.
310 CMR 7.06(6) specifies that no person shall cause, suffer, allow, or permit excessive
emission of visible air contaminants, other than water, from non-stationary source diesel engines.
All requirements contained in this regulation have been incorporated into the permit.
D. 310 CMR 7.11: Transportation Media
310 CMR 7.11(4) contains specific requirements for Marine Vessels. No person owning,
operating, or having control of a seagoing vessel while it is in the district shall cause, suffer,
allow, or permit, aboard said vessel, tube blowing or soot removal activities that cause or
contribute to a condition of air pollution. 310 CMR 7.11 shall apply only in the Merrimack
Valley Air Pollution Control District, Metropolitan Boston Air Pollution Control District, and the
Southeastern Massachusetts Air Pollution Control District. All requirements contained in this
regulation have been incorporated into the permit.
E. 310 CMR 7.12: Source Registration
310 CMR 7.12 requires owners/operators of facilities to submit an annual source registration to
Massachusetts. Per 310 CMR 7.12(1), the regulations apply to any owner/operator of a facility if
such facility meets any of the criteria in 310 CMR 7.12(l)(a)l through 11. This facility meets
criteria 6, 7, and 11 and is subject to the requirements of this section. All requirements contained
in this regulation have been incorporated into the permit.
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F. 310 CMR 7.18: Volatile and Halogenated Organic Compounds
The purpose of 310 CMR 7.18 (30) is to limit VOCs in adhesive, sealant, adhesive primer, or
sealant primer. The RW project has potential to use adhesive, sealant, adhesive primer, or sealant
primer and thus could become subject to the standards contained this section. Per 310 CMR
7.18(30)(4), if the total facility-wide VOC emissions from all adhesives, sealants, adhesive
primers, and sealant primers used are less than 200 pounds per calendar year, or an equivalent
volume, the facility is exempt from the requirement of 310 CMR 7.18(30)(c)3 and 5. Any person
claiming this exemption shall maintain sufficient monthly operational records in accordance with
310 CMR 7.18(30)(e) to demonstrate compliance with this exemption. All requirements
contained in this regulation have been incorporated into the permit.
G. 310 CMR 7.72: SFe
The purpose of 310 CMR 7.72 is to assist the Commonwealth in achieving the greenhouse gas
emissions reduction goals by reducing sulfur hexafluoride (SFr,) emissions from GIS through the
imposition of declining annual aggregate emission limits and other measures on GIS. All
requirements contained in this regulation have been incorporated into the permit.
Per 310 CMR 7.72 (4)(a), Any newly manufactured GIS that is placed under the ownership,
lease, operation, or control of any GIS owner on or after January 1, 2015, must be represented by
the manufacturer to have a 1.0% maximum annual leak rate.
• The applicant has accepted a best achievable control technology limit of a maximum
annual leak rate not to exceed 0.5%, which is more stringent that the requirement
contained in 310 CMR 7.72 (4)(a). See Section V.C.2.a(4).
Per 310 CMR 7.72 (4)(b), any GIS owner that places GIS under ownership, lease, operation, or
control on or after January 1, 2015, shall comply with any manufacturer-recommended
maintenance procedures or industry best practices that have the effect of reducing leakage of
SF6.
• The applicant has a BACT limit of a sealed system with leak detection and alarms and a
commitment to repair detected leaks within 5 days of discovery, which complies with the
requirement contained in 310 CMR 7.72 (4)(a). See Section V.C.2.a(4).
The facility may be required to comply with all annual reporting requirements contained in 310
CMR 7.72 (6), including but not limited to, the number of pounds of SF6 emitted from GIS
equipment owned, leased, operated, or controlled by the federal reporting GIS owner and located
in Massachusetts during the year, using the equation specified in 40 C.F.R. §98.303 if 40 C.F.R.
Part 98 subpart DD applies.
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User Emissions = (Decrease in SF6 Inventory) + (Acquisitions
of SF6) - (Disbursements of SF6) - (Net Increase in Total
Nameplate Capacity of Equipment Operated)
(Eq. DD-1)
Figure 5 - Calculate the annual SF& emissions using the mass-balance approach
Where:
Decrease in SF6 Inventory = (pounds of SF6 stored in containers, but not in energized equipment,
at the beginning of the year) - (pounds of SF6 stored in containers, but not in energized
equipment, at the end of the year).
Acquisitions of SF6 = (pounds of SF6 purchased from chemical producers or distributors in bulk)
+ (pounds of SF6 purchased from equipment manufacturers or distributors with or inside
equipment, including hermetically sealed-pressure switchgear) + (pounds of SF6 returned to
facility after off-site recycling).
Disbursements of SF6 = (pounds of SF6 in bulk and contained in equipment that is sold to other
entities) + (pounds of SF6 returned to suppliers) + (pounds of SF6 sent off site for recycling) +
(pounds of SF6 sent off-site for destruction).
Net Increase in Total Nameplate Capacity of Equipment Operated = (The Nameplate Capacity of
new equipment in pounds, including hermetically sealed-pressure switchgear) - (Nameplate
Capacity of retiring equipment in pounds, including hermetically sealed-pressure switchgear).
Note that Nameplate Capacity refers to the full and proper charge of equipment rather than to the
actual charge, which may reflect leakage.
VIII. Other Federal Requirements
Pursuant to 40 C.F.R. §55.13(c), NSPS apply to OCS sources in the same manner as in the COA.
The broad definition of OCS source contained in the OCS Air Regulations require that some
marine vessel engines and offshore construction equipment (which are typically not considered
stationary sources) be subject to NSPS IIII. Similarly, 40 C.F.R. Part 61, together with any other
provisions promulgated pursuant to section 112 of the Act, e.g., Part 63 standards, apply to OCS
sources in the same manner as in the COA. The broad definition of OCS source contained in the
OCS Air Regulations require that some marine vessel engines and offshore construction
equipment (which are typically not considered stationary sources) be subject to 40 C.F.R. Part 63
subpart ZZZZ (NESHAP ZZZZ).
A. New Source Performance Standards (NSPS)
Subpart IIII. Standards of Performance for Stationary Compression Ignition Internal Combustion
Engines. Subpart IIII affects stationary CI ICE based on power and displacement ratings,
depending on date of construction, beginning with those constructed after July 11, 2005. NSPS
IIII contains a set of technology-based federal standards that apply to specific categories of
stationary sources of air pollution.
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RW expects nearly all engines on the Project's OCS sources to be non-emergency compression-
ignition internal combustion engines.
The Project may require emergency generators to provide secondary back-up power to the
WTGs during O&M in the unlikely event of a failure of the primary and secondary power
sources. To be considered an emergency stationary internal combustion engine, it must satisfy
the criteria within 40 C.F.R. Parts 60.4219 and 60.4211(f).107
The EPA recognizes in its NSPS that an owner of a stationary source in a marine environment
(non-emergency and emergency) can certify its engine based on the marine engine requirements
at 40 C.F.R. Part 1042 (including Appendix I) rather than the nonroad engine requirements at 40
C.F.R. Part 1039 (including Appendix I) (see 40 C.F.R. § 60.4201(f)(2)).
The Proponent will comply with 40 C.F.R. Part 60, Subpart IIII by using engines on the WTGs,
OSS[s], and vessels operating as OCS sources that are certified by the manufacturer to meet the
applicable emission standards in Subpart IIII, by complying with the work practice standards
specified in Subpart IIII (as applicable), and by burning fuel that meets the sulfur content
requirements and other specifications in 40 C.F.R. §60.4207. The Proponent notes that foreign-
flagged vessels are exempt from having to meet the marine standards within 40 C.F.R. Part 1042
(including Appendix I) and instead are required to meet the emission standards in 40 C.F.R. §
1043. See Section VIII.C for additional discussion of EPA and MARPOL Annex VI emission
standards and fuel sulfur content requirements for marine engines.
40 C.F.R. Part 1042 sets NOx, HC, PM, and CO emission standards and certification
requirements for Category 1, Category 2, and Category 3 marine diesel engines installed on U.S.-
flagged vessels. The emission standards are structured as a tiered progression (Tiers 1 through 4),
with each Tier of emission standards becoming increasingly stringent over time. The exact
emission limits (in g/kW-hr) that apply to each engine depend on the engine's size, displacement,
speed, and/or power density.
Per 40 C.F.R. Part 1042, Category 1 marine engines have a displacement of less than 7 liters per
cylinder and Category 2 marine engines have a displacement greater than or equal to 7 liters per
cylinder and less than 30 liters per cylinder. However, in 40 C.F.R. Part 1042, Appendix I,
engines with a displacement between 5 and 7 liters per cylinder are considered Category 2 rather
than Category 1 marine engines. Category 3 marine engines have a displacement at or above 30
liters per cylinder. The NOx emission limits for Category 3 engines at 40 C.F.R. Part 1042 are
the same as the NOx emission standards under 40 C.F.R. Part 1043. See the document within the
docket for this permit, Federal Marine Compression-Ignition (CI) Engines: Exhaust Emission
Standards (EPA-420-B-20-021, July 2020).
107 (1) Must only operate for emergencies, maintenance, and testing, and no more than 50 hours per year in non-
emergency situations. (2) Must operate no more than 100 hours per year for maintenance checks, readiness testing,
and non-emergency situations (limited to 50 hours per year). (3) Cannot be used for peak shaving or non-emergency
demand response, or to generate income for a facility to an electric grid or otherwise supply power as part of a financial
arrangement with another entity, except as described in 40 C.F.R. 60.421 l(f)(3)(i). There is no time limit on the use
of emergency stationary internal combustion engines in emergency situations (see 40 C.F.R. § 60.4211(f)(1)).
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B. National Emission Standards for Hazardous Air Pollutants
Subpart ZZZZ. Reciprocating Internal Combustion Engines. This subpart establishes national
emission limitations and operating limitations for hazardous air pollutants (HAP) emitted from
stationary reciprocating internal combustion engines (RICE) located at major and area sources of
HAP emissions. An affected source is any existing, new, or reconstructed stationary RICE
located at a major or area source of HAP emissions, excluding stationary RICE being tested at a
stationary RICE test cell/stand.
RW expects nearly all engines on the Project's OCS sources to be non-emergency compression-
ignition internal combustion engines, and RW is considered an area source of HAP.
The project's CI-ICE that become OCS sources and were built or reconstructed after June 12,
2006, are considered "a new or reconstructed stationary RICE located at an area source." Per 40
C.F.R. 63.6590(c), An affected source that meets any of the criteria in paragraphs (c)(1) through
(7) of this section must meet the requirements of this part by meeting the requirements of 40
C.F.R. Part 60 subpart IIII, for compression ignition engines. Therefore, RICEs that become
OCS sources and were built or reconstructed after June 12, 2006, must meet the requirements of
NSPS IIII and are not subject to any further requirements under NESHAP ZZZZ.
The Project's existing RICE (constructed or reconstructed before June 12, 2006) that are OCS
sources are subject to emission limitations, operating limitations, and other requirements at 40
C.F.R. § 63.6603, which applies to existing stationary RICEs located at an area source of HAP
emissions (see 40 C.F.R. § 63.6590(a)(l)(iii)). However, existing stationary non- emergency
compression-ignition RICEs with a rating greater than 300 horsepower located on an offshore
vessel that is an OCS source do not have to meet the CO emission limitations specified in Table
2d of Subpart ZZZZ; they must meet the management practices at 40 C.F.R. Part 63.6603(c).
Table 33 Table 2d to Subpart ZZZZ of Part 63 - Requirements for Existing Stationary MICE Located at
Area Sources of HAP Emissions
RICE Category
You must meet the following requirement,
except during periods of startup....
During periods of startup, you
must....
1. Non-Emergency,
non-black start CI
stationary RICE <300
HP
a. Change oil and filter every 1,000 hours of
operation or annually, whichever comes first
0)
Minimize the engine's time spent at
idle and minimize the engine's startup
time at startup to a period needed for
appropriate and safe loading of the
engine, not to exceed 30 minutes, after
which time the non-startup emission
limitations apply.
b. Inspect air cleaner every 1,000 hours of
operation or annually, whichever comes first,
and replace as necessary;
c. Inspect all hoses and belts every 500 hours
of operation or annually, whichever comes
first, and replace as necessary.
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RICE Category
You must meet the following requirement,
except during periods of startup....
During periods of startup, you
must....
2. Non-Emergency,
non-black start CI
stationary RICE
300500
HP
a. Limit concentration of CO in the stationary
RICE exhaust to 23 ppmvd at 15 percent 02;
or
b. Reduce CO emissions by 70 percent or
more.
4. Emergency
stationary CI RICE and
black start stationary
CI RICE.2
a. Change oil and filter every 500 hours of
operation or annually, whichever comes first;
b. Inspect air cleaner every 1,000 hours of
operation or annually, whichever comes first,
and replace as necessary; and
c. Inspect all hoses and belts every 500 hours
of operation or annually, whichever comes
first, and replace as necessary.
1 Sources have the option to utili/e an oil analysis program as described in § 63.6625(1) or {]} in order to extend the
specified oil change requirement in Table 2d of this subpart.
2 If an emergency engine is operating during an emergency and it is not possible to shut down the engine in order to
perform the management practice requirements on the schedule required in Table 2d of this subpart, or if performing
the management practice on the required schedule would otherwise pose an unacceptable risk under federal, state, or
local law, the management practice can be delayed until the emergency is over or the unacceptable risk under
federal, state, or local law has abated. The management practice should be performed as soon as practicable after the
emergency has ended or the unacceptable risk under federal, state, or local law has abated. Sources must report any
failure to perform the management practice on the schedule required and the federal, state or local law under which
the risk was determined to be unacceptable.
C. MARPOL Annex VI, the Act to Prevent Pollution from Ships, and 40 C.F.R. Part 1043
Annex VI of the IMO's MARPOL treaty is the main international treaty that addresses air
pollution from marine vessels. The IMO has also adopted legally binding energy efficiency
measures as amendments to MARPOL Annex VI. It was implemented in the United States
through the Act to Prevent Pollution from Ships (APPS"), 33 U.S.C. §§ 1901-1905. Annex VI
requirements comprise both engine-based and fuel-based standards and apply to U.S.-flagged
ships wherever located and to non-U.S. flagged ships operating in U.S. waters.
• Annex VI establishes:
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o Limits on NOx emissions from marine diesel engines with a power output of more
than 130 kW. The standards apply to both main propulsion and auxiliary engines and
require the engines to be operated in conformance with the Annex VI NOx emission
limits.
o Limits on the sulfur content of marine fuels.
40 C.F.R. Part 1090, Subpart D contains the standards for Diesel Fuel and ECA
Marine Fuel. ECA marine fuels, both ECA marine distillate and ECA marine
residual, is limited to a maximum sulfur content of 1000 ppm for all marine vessels
operating in the ECA area. However, per 40 C.F.R. §1090.325, the use of EC Marine
Fuel (1000 ppm sulfur) is limited to use in Category 3 Marine Engines only. Note that
a Category 3 engine is defined as a marine engine having a displacement greater than
30 L/cylinder. All other engines category's (Category 1, Category 2, and nonroad)
will fall into the ULSD (15 ppm) limitation as contained in 40 C.F.R. § 1090.305 and
Subpart IIII.
• U.S.-flagged vessels are subject to inspection for compliance with Annex VI. Non-U.S.
flagged ships are subject to examination under Port State Control while operating in U.S.
waters. The USCG or EPA may bring an enforcement action for a violation.
• Ships operating up to 200 nautical miles off U.S. shores must meet the most advanced
standards for NOx emissions and use fuel with lower sulfur content. This geographic area
is designated under Annex VI as the ECA.
• Each regulated diesel engine in U.S.-flagged vessels must have an E1APP certificate,
issued by EPA, to document that the engine meets Annex VI NOx standards. Certain
vessels are also required to have an LAPP Certificate which is issued by the USCG. Ship
operators must also maintain records on board regarding their compliance with the
emission standards, fuels requirements and other provisions of Annex VI.
• U.S.-flagged vessels are subject to inspection for compliance with Annex VI. Non-U.S.
flagged ships are subject to examination under Port State Control while operating in U.S.
waters. The USCG or EPA may bring an enforcement action for a violation.
IX. Monitoring, Reporting, Recordkeeping and Testing Requirements
The following reports required by the Specific Conditions of Permit No. OCS-R1-05.
• Self-reporting (i.e., prompt reporting) of deviations from permit terms and conditions.
The EPA is requiring the prompt reporting of permit deviations as a condition of the
preconstruction permitting requirements of the draft permit.
• The draft permit associated with this Fact Sheet contains the exact information that must
be submitted. See Specific Condition No. 1 through 15 of Permit No. OCS-R1-05.
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Demonstrating compliance with the permit requires robust monitoring and recordkeeping of
activities. The monitoring, recordkeeping, and testing requirements can be grouped into several
categories. These categories are:
• Tracking, on a daily rolling, 365-day total, the actual emissions of NOx and VOC
commences on day 1 of the operational phase start date from all OCS sources including
vessels servicing or associated with the OCS source while at or going to or from an OCS
source while within 25 nautical miles of the OCS source.
• Documenting key design parameters and manufacturers certifications for every internal
combustion engine and any other emission unit classified as an OCS source. This
information is necessary to demonstrate compliance with the BACT and LAER emission
limits.
• Records as required by NSPS IIII and NESHAP ZZZZ.
• Certifying that at the time a vessel will become an OCS source, the vessel in question has
the least polluting internal combustion engines on it available to RW or its contractors.
• Demonstrating compliance with the sulfur fuel limits by obtaining the fuel supplier's
certificate that contains information regarding the fuel's sulfur content.
X. Consultations
For the purposes of the Endangered Species Act (ESA"), Magnuson-Stevens Fishery
Conservation and Management Act (MSFCMA"), and the National Historic Preservation Act
(NHPA"), the issuance of an OCS air permit is a federal action undertaken by the EPA. BOEM
is the lead federal agency for authorizing renewable energy activities on the OCS and the RW
wind farm is also a federal action for BOEM. BOEM's regulations at 30 C.F.R. Part 585 require
RW to obtain a COP approval before commencing construction on the windfarm. In conjunction
with the COP approval, BOEM is also responsible for issuing the Record of Decision (ROD) on
the Environmental Impact Statement conducted under the National Environmental Policy
Review Act (NEPA").
The applicant requests a lease, easement, right-of-way, and any other related approvals from
BOEM necessary to authorize construction, operation, and eventual decommissioning of the
proposed action. BOEM's authority to approve, deny, or modify the project derives from the
Energy Policy Act of 2005. Section 388 of the Act amended the OCSLA by adding subsection
8(p), which authorizes the Department of the Interior to grant leases, easements, or rights-of-way
on OCS lands for activities that produce or support production, transportation, or transmission of
energy from sources other than oil and gas, such as wind power.
The EPA assesses its own permitting action (i.e., to issue an OCS air permit for the windfarm) as
interrelated to, or interdependent with, the BOEM's COP approval and issuance of the NEPA
ROD for the RW wind farm. Accordingly, the EPA has designated BOEM as the lead Federal
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agency for purposes of fulfilling statutory obligations under the statutes mentioned
previously.108 BOEM has accepted the designation as lead Federal agency.109
A. Endangered Species Act, Magnuson-Stevens Fishery Conservation and Management
Act, and National Historic Preservation Act
Under Section 7(a)(2) of the ESA, 16 U.S.C. § 1536(a)(2), the EPA must ensure that any action
authorized, funded, or carried out by the EPA is not likely to jeopardize the continued existence
of any federally-listed endangered species or threatened species or result in the destruction or
adverse modification of such species' designated critical habitat. If the EPA's action (i.e., OCS
air permit issuance) may affect a federally-listed species or designated critical habitat, Section
7(a)(2) of the ESA and relevant implementing regulations at 50 C.F.R. Part 402 require
consultation between the EPA and the U.S. Fish and Wildlife Service (FWS) and/or the National
Marine Fisheries Service (NMFS"), depending on the species and/or habitat at issue.
In accordance with Section 305(b)(2) of the MSFCMA, 16 U.S.C. § 1855(b)(2), Federal agencies
are also required to consult with the NMFS on any action that may result in adverse effects to
essential fish habitat (EFH").
Section 106 of the NHPA, 16 U.S.C. 470f, and the implementing regulations at 36 C.F.R. Part
800 require federal agencies to consider the effect of their actions on historic properties and
afford the opportunity for the Advisory Council on Historic Preservation (ACHP) and consulting
parties to consult on the federal undertaking.
The ESA regulations at 50 C.F.R. § 402.07, the MSFCMA regulations at 50 C.F.R. § 600.920(b),
and the NHPA regulations at 36 C.F.R. § 800.2(a)(2) provide that where more than one federal
agency is involved in an action, the consultation requirements may be fulfilled by a designated
lead agency on behalf of itself and the other involved agencies. As previously discussed, BOEM
is the designated lead agency for the purposes of fulfilling EPA's obligations under Section 7 of
the ESA, Section 305(b) [of the] MSFCMA, and Section 106 of the NHPA for offshore wind
development projects on the Atlantic OCS, including the project. As a result of this designation,
BOEM will consider the effects of the EPA's OCS permitting action in fulfilling its consultation
obligations under each of these statutes for the NEPA ROD and COP approval process.
At the time of writing this Fact Sheet and the EPA's associated proposal of the draft permit,
BOEM has commenced but not completed its consultation requirements for ESA, MSFCMA,
and NHPA for the COP approval and NEPA ROD for the project. The EPA understands that
BOEM will satisfy its statutory obligations as lead federal agency under each of these statutes
prior to EPA issuance of a final OCS air permit for the RW windfarm. Should the result of
BOEM's consultation under one or more of these statutes identify any conditions or restrictions
on air emissions for inclusion in the OCS air permit, the EPA will include those conditions or
restrictions in the final permit as necessary. The EPA will also provide an additional opportunity
108 A copy of the July 25, 2018 letter from EPA R1 to the BOEM regarding lead agency designation is included in
the administrative record for this action.
109 A copy of the September 24, 2018 letter from the BOEM to EPA R1 accepting lead agency designation is
included in the administrative record for this action.
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for public comment regarding any such new conditions or restrictions as necessary and
appropriate.
B. Coastal Zone Management Act (CZMA")
Section 307 of the CZMA, 16 U.S.C. § 1456, and the implementing regulations at 15 C.F.R. Part
930 provide a federal consistency process for state programs to use to manage coastal activities
and resources and to facilitate cooperation and coordination with federal agencies. Generally,
federal consistency requires that federal actions, within and outside the coastal zone, which have
reasonably foreseeable effects on any coastal use (land or water) or natural resource of the
coastal zone be consistent with the enforceable policies of a state's federally approved coastal
management program. Federal actions include federal agency activities, federal license or permit
activities, and federal financial assistance activities. Federal agency activities must be consistent
to the maximum extent practicable with the enforceable policies of a state coastal management
program, and license and permit and financial assistance activities must be fully consistent.
Under 15 C.F.R. Part 930, subpart D, a non-federal applicant for a federal license or permit is
required to provide a state with a consistency certification if the state has identified the federal
license or permit on a list of activities subject to federal consistency review in its federally
approved coastal management program. State federal consistency lists identify the federal
agency, federal license or permit, and federal financial assistance activities that are subject to
federal consistency review if the activities occur within a state's coastal zone pursuant to the
applicable subparts of the regulations at 15 C.F.R. Part 930. The EPA has reviewed the listed
federal actions for federal license or permit activities for Massachusetts and Rhode Island. The
EPA's action to issue an OCS air permit under the regulations at 40 C.F.R. Part 55 is not
included on the current list of federal actions for federal consistency review. Thus, issuance of
this OCS air permit is not required to be preceded by a federal consistency review.110
C. Clean Air Act General Conformity
Pursuant to 40 C.F.R. § 93.153(d)(1), a conformity determination is not required for the portion
of an action that includes major or minor new or modified stationary sources that require a
permit under the NSR program.
XI. Environmental Justice
Executive Order (EO) 12898 entitled "Federal Actions to Address Environmental Justice in
Minority Populations and Low-Income Populations" requires that federal agencies identify and
address, as appropriate and to the extent practicable and permitted by existing law,
disproportionately high and adverse human health or environmental effects of its programs,
policies, and activities on minority populations and low-income populations. See Executive
Order 12898, Section 1-101, 59 Fed. Reg. 7629 (Feb. 16, 1994). Consistent with EO 12898 and
110 The EPA confirmed with the State of Rhode Island and the Commonwealth of Massachusetts that the states do
not seek a consistency review for OCS air permits. A copy of the email confirmation from Rhode Island and
Massachusetts is included in the administrative record for this action.
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the EPA's "Plan EJ 2014: Considering Environmental Justice in Permitting," the EPA must (1)
consider the environmental justice issues, on a case-by-case basis, connected with the issuance of
federal permits (particularly when permitting projects for major sources that may involve
activities with significant public health or environmental impacts on already overburdened
communities); and (2) focus on whether the federal permitting action would have
disproportionately high and adverse human health or environmental effects on minority or low
income populations.
The EPA defines "Environmental Justice" (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.
The EPA's goal with respect to Environmental Justice in permitting is to enable overburdened
communities to have full and meaningful access to the permitting process and to develop permits
that address environmental justice issues to the greatest extent practicable under existing
environmental laws. Overburdened is used to describe the minority, low-income, and tribal
nations and indigenous peoples or communities in the United States that potentially experience
disproportionate environmental harms and risks as a result of greater vulnerability to
environmental hazards.
In light of Executive Order 12898, the White House Council on Environmental Quality (CEQ)
issued Environmental Justice: Guidance Under the National Environmental Policy Act (NEPA).
As part of the NEPA process, BOEM conducted an environmental justice analysis in accordance
with this guidance. The guidance includes six principles for environmental justice analyses to
determine any disproportionately high and adverse human health or environmental effects to
low-income, minority, and tribal populations. The EPA evaluated BOEM's analysis of these
principles with regard to environmental justice for the Revolution Wind project. The principles
are:
1. Consider the composition of the affected area to determine whether low-income,
minority or tribal populations are present and whether there may be disproportionately
high and adverse human health or environmental effects on these populations;
2. Consider relevant public health and industry data concerning the potential for multiple
exposures or cumulative exposure to human health or environmental hazards in the
affected population, as well as historical patterns of exposure to environmental hazards;
3. Recognize the interrelated cultural, social, occupational, historical, or economic factors
that may amplify the natural and physical environmental effects of the proposed action;
4. Develop effective public participation strategies;
5. Assure meaningful community representation in the process, beginning at the earliest
possible time; and
6. Seek tribal representation in the process.
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Additionally, EPA has published eight principles to assist each Region to promote environmental
justice in air permitting programs.111 The following principles were also evaluated or
implemented with regard to environmental justice for the Revolution Wind project:
1. Identify communities with potential environmental justice concerns
2. Engage early in the permitting process to promote meaningful participation and fair
treatment
3. Enhance public involvement throughout the permitting process
4. Conduct a "fit for purpose" environmental justice analysis
5. Minimize and mitigate disproportionately high and adverse effects associated with the
permit action to promote fair treatment
6. Provide federal support throughout the air permitting process
7. Enhance transparency throughout the air permitting process
8. Build capacity to enhance the consideration of environmental justice in the air
permitting process
A. Air Quality Review
For purposes of Executive Order 12898 on environmental justice, the Environmental Appeals
Board has recognized that compliance with the National Ambient Air Quality Standards
(NAAQS) is "emblematic of achieving a level of public health protection that, based on the level
of protection afforded by a primary NAAQS, demonstrates that minority or low-income
populations will not experience disproportionately high and adverse human health or
environmental effects due to the exposure to relevant criteria pollutants."112 This is because the
NAAQS are health-based standards, designed to protect public health with an adequate margin of
safety, including sensitive populations such as children, the elderly, and asthmatics. Based on
PSD-required modeling for this project, the EPA has determined that issuance of this OCS
permit will not contribute to NAAQS or increment violations nor have potentially adverse effects
on ambient air quality. See Section V.C of this document for a detailed analysis of the ambient
air impact analysis of the project.
B. Environmental Impacts to Potentially Overburdened Communities
EPA's EJ Screen tool113 is an environmental justice screening and mapping tool that utilizes
standard and nationally consistent data to highlight places that may have higher environmental
burdens and vulnerable populations. In EJ Screen, EPA uses the 80th percentile as a threshold to
identify geographic areas that may warrant further consideration, analysis, or outreach for
environmental justice. CEQ's 1997 guidance document identifies minority populations in an
111 See EPA's December 22, 2022, EJ in Air Permitting - Principles for Addressing Environmental Justice Concerns
in Air Permitting, https://www.epa.gov/caa-peniiitting/ei-air-permitting-principles-addressing-environinental-
iiistlce-coneerns-air.
112 See Environmental Appeals Board order In re Shell Gulf of Mexico, Inc. & In re Shell Offshore, Inc., 15 E.A.D.
103, 156 (December 30, 2010). A copy of the order can be found in the administrative record fortius action.
113 EJSCREEN is an environmental justice mapping and screening tool that provides the EPA with a nationally
consistent dataset and approach for combining environmental and demographic indicators. More information on
EPA's EJ Screen tool is available at https://www.epa.gov/ejscreen.
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affected environment if (a) the minority population of the affected area exceeds 50 percent of the
affected area's total population or (b) the minority population percentage of the affected area is
meaningfully greater than the minority population percentage in the general population or other
appropriate unit of geographic analysis. The Commonwealth of Massachusetts has more
stringent criteria and defines an environmental justice community as one or more U.S. Census
block groups that meet one or more of the following criteria: the annual median household
income is not more than 65 per cent of the statewide annual median household income;
minorities comprise 40 per cent or more of the population; 25 per cent or more of households
lack English language proficiency; or minorities comprise 25 per cent or more of the population
and the annual median household income of the municipality in which the neighborhood is
located does not exceed 150 per cent of the statewide annual median household income.114
In the Draft Environmental Impact Statement (DEIS) for RW, BOEM analyzed potential air
quality impacts as a result of the construction and operation of the Revolution Wind project.115
EPA finds BOEM's analysis helpful in identifying potential environmental justice areas of
concern. Indirect air quality impacts116 to environmental justice communities were evaluated for
the Geographic Analysis Area (GAA"). The GAA includes all counties adjacent to the Lease
Area and any areas where Project offshore infrastructure may be visible. Counties adjacent to
onshore Project infrastructure or ports used to support Project construction, O&M, and
decommissioning activities in the WDA and along the export cable route are also included in the
GAA. In addition, the GAA includes counties adjacent to major ports that support commercial
fisheries potentially affected by the Project. The percentage of minority and low-income
populations in each block group, county, and city/town were determined using EPA's EJ Screen
tool in BOEM's DEIS for RW. Potential environmental justice areas of concern were identified
if 1) the minority population exceeds 50% or 2) the minority or low-income population
percentage is meaningfully greater than the minority or low-income population percentage of a
reference population117. Of the estimated 11,000 block groups, approximately 50% were
identified as EJ areas of concern.118 The analysis area also includes tribal lands and communities
that the Project may affect, and port areas indirectly affected by the project.
Any direct air quality impacts119 during the construction phase of the project are temporary,
occurring over less than two years. Direct air quality impacts from ongoing project activities
regulated by this permit are localized around the WDA (which is 7.5 nm south of Noman's Land
Island, Massachusetts) and insignificant in all onshore areas.
114 See Environmental Justice Policy of the Executive Office of Energy and Environmental Affairs. Available at:
https://www.mass.gov/doc/environmental-justice-policy6242021-update/download. Last accessed November 30,
2022.
115 A copy of BOEM's September 2022 DEIS for the Revolution project can be found in the administrative record
for this action.
116 For the purposes of this discussion, indirect air quality impacts are those that are caused by activities such as
onshore construction, staging of materials, and emissions from vessels associated with the construction and
operation of RW. These emissions are not directly regulated by EPA's CAA OCS permit and are outside the
regulatory authority of EPA within the context of CAA OCS permitting.
117 BOEM (2022). Rev Wind Draft EIS, 3.12-7.
118BOEM (2022). Rev Wind Draft EIS, 3.12-7.
119 For the purposes of this discussion, direct air quality impacts are those that are regulated by EPA's CAA OCS
permit and include emissions associated with the OCS source.
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Many of the air emitting activities analyzed by BOEM's DEIS are not regulated under EPA's
OCS air permit program. Vessel emissions, such as transit vessels and vessel activity at port
communities beyond 25 miles from the OCS source are not subject to EPA's OCS air permit. In
addition, only vessels within the WD A that meet the definition of an OCS source are subject to
the permit terms and conditions. However, these vessels are subject to stringent EPA and IMO
standards for marine engines found at 40 CFR part 1042, 40 CFR part 1043, and IMO Annex VI.
These standards also require the use of ULSD for certain engine categories. These standards
apply to the marine engines on all vessels independent of this OCS air permit.
According to RW's application, the potential port facilities to be used to support construction of
the project include existing ports in New York, Rhode Island, Connecticut, Massachusetts,
Virginia, Maryland, or New Jersey. During O&M the potential ports to be used to support the
Project include existing ports in New York and Rhode Island. EPA and the states operate an
extensive network of air quality monitoring locations to ensure ambient air quality meets the
NAAQS. Many of these air monitoring locations coincide with port communities such as New
Bedford, MA; Fall River, MA; Providence, RI; New London, CT; and Bridgeport, CT, as well as
other northeast and mid-atlantic states.120 See below Figure 6 for a map of Ozone and PM Air
Monitoring Stations in states with potential port facilities. Air quality monitoring data from these
locations is publicly available online at https://www.epa.gov/outdoor-air-qualitv-data.
mr'ifc.i.j *
Of ' Providence V
? f of 1
flalmbur. Mai-Jen
r
t/ ?
Legend for Selected Layers
Ozone - Active
T
PM10-Active
; 91
_J ^ T New York
Figure 6 Map of Ozone and PM Air Monitoring Stations
Over time, the development of offshore wind, a renewable and non-emitting energy source, on
the Atlantic Coast is expected to displace fossil-fuel fired generation of electricity and improve
air quality in the region, in turn significantly reducing adverse health impacts to EJ communities
in the area. RW estimates avoided emissions of offshore wind di splacing fossil fuel generators
for the project are 599 to 749 tons NOx per year, 318 to 398 tons SOx per year and 1,120,189 to
1,400,236 tons C02e per year.121 EPA expects substantial, long-term air quality improvements
An interactive map of air quality monitoring locations is available at ittps://www.epa. gov/outdoor-air-qualitv-
data.
121 Rev Wind 8/12/2022 Application, Table 5-7.
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will have a beneficial impact on the health and safety of EJ populations as a result of this project.
Furthermore, BOEM analyzed the employment and economic activity impacts associated with
offshore wind development and found there to be minor beneficial impacts from new job
formation.122
Direct air emissions from the project are subject to BACT and LAER emission limits as well as
the requirement to obtain emissions offsets (for the operational phase of the project) in advance
under the NNSR permitting programs. Thus, the emissions generating activities at the source will
be controlled by compliance with the OCS air permit. In other words, emissions control and
NNSR offset requirements in the air permit will minimize air pollutant emissions. The emissions
generated during the operation phase of the windfarm engines would be very low and the engines
are certified to meet EPA emissions standards. In addition, work practice standards that will be
employed during the construction and operation of the project include minimizing the idling of
the engines of the vessels; and the use of ultra-low sulfur diesel whenever possible to minimize
sulfur and particulate emissions. The EPA notes that some of the emissions generated by the
vessels' engines, which will depart from and return to the ports, would occur near shore. These
emissions would add a small amount to the current vessel traffic emissions in the area, and, given
their very low-level and very short duration, would have minor (if any) human health or
environmental effects on the overall population, including any minority or low-income
population.123
C. Tribal Consultation
Per the EPA Policy on Consultation and Coordination with Indian Tribes, the EPA Region 1
offers tribal government leaders an opportunity to consult on all OCS air permit actions. On
November 10, 2022, the EPA notified the tribes in Massachusetts, Rhode Island, and
Connecticut that they will be provided the opportunity to conduct government-to-government
consultation prior to issuing the OCS air permit.124 To date the EPA has not received a request
from any tribe requesting consultation on this permit action. However, tribes may request
consultation at any time.
D. Public Participation
In order to comply with Section 5-5(c) (Public Participation and Access to Information) of EO
12898, which requires that each federal agency work to ensure that public documents, notices,
and hearings relating to human health or the environment are concise, understandable, and
readily accessible to the public, the EPA has prepared a Public Notice, available on the EPA
website at https://www.epa.eov/caa-permittine/caa-permittine-epas-new-eneland-reeion.
Interested parties can also subscribe to an EPA email list that notifies them of public comment
opportunities in Region 1 for proposed air pollution control permits via email at
https://www.epa.eov/caa-permittine/caa-permittine-epas-new-eneland-reeion. In addition, the
EPA will hold a virtual public hearing for this permit action. These procedures, along with this
122BOEM (2022). Rev Wind Draft EIS, 3.11-17.
123 BOEM (2022). Rev Wind Draft EIS, 3-12-22.
124 Letters offering government-to-government consultation to each of the affected tribes are included in the
administrative record for this air permit action.
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Fact Sheet, will ensure an opportunity for meaningful involvement for all communities,
including potentially impacted environmental justice communities.
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 in full by the close of the public comment period, in writing. Due to the COVID-19
emergency, EPA prefers that all comments be submitted by electronic means to:
Morgan M. McGrath, P.E.
Email: mcgrath.morgan@epa.gov
If email submittal of comments is not feasible, hard copy comments may be submitted to the
address below.
Morgan M. McGrath, P.E.
Air and Radiation Division
U.S. EPA Region 1
5 Post Office Square, Suite 100
(Mail code: 5-MD)
Boston, MA 02109
Comments may also be submitted electronically through https://www.reeulations.eov (Docket
ID #EPA-R0 l-OAR-2023-0060).
A public hearing will be held during the public comment period. See the public notice for details.
The EPA will consider requests for extending the public comment period for good cause. In
reaching a final decision on the Draft Permit, the EPA will respond to all significant comments
and make these responses available upon request.
Following the close of the public comment period, and after the public hearing, the EPA 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 issuance of the final permit decision, any eligible parties may submit a petition for
review of the final permit decision to the EPA's Environmental Appeals Board consistent with
40 C.F.R. § 124.19.
XIII. EPA Contacts
Additional information concerning the draft permit may be obtained from:
Morgan M. McGrath, P.E.
Telephone: (617)918-1541
Email: mcgrath.morgan@epa.gov
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All supporting information regarding this permitting action can also be found on EPA's website
at https://www.epa.eov/caa-permittine/epa-issued-caa-permits-reeion-l or at
www.regulations.gov Docket ID #EPA-R01-OAR-2023-0060.
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