TRANSMITTAL
Permits Section
Air Quality Division
Michigan Department of Environmental Quality
Constitution Hall, 2nd Floor South
525 West Allegan Street
Lansing, MI 48933-1502
Re:
December 17, 2014
Permit to Install (PTI) Simple-Cycle CTG Project
Alpine Power Plant, Elmira, Michigan
Wolverine Power Supply Cooperative, Inc.
 FOR REVIEW
 FOR YOUR USE
 AS REQUESTED
COPIES
2
DATE
12/15/2014
Project No. G090066NEW
Sent By: John F. Caudell, PE/tc
DESCRIPTION
PTI Simple-Cycle CTG Project, Alpine Power Plant
Elmira, Michigan
COMMENTS
Attached are two copies of the PTI Application. Also attached is the original signature PTI form, along with
three copies of the form.
If you have any questions or require additional information, please contact me at 517.887.4024 or
[email protected].
By Hand Delivery
cc/att: Mr. Brian Warner - Wolverine Power Supply Cooperative, Inc. (By FedEx)
Ms. Jacquelyn F. Linck, PE - FTCH (By email)
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PERMIT TO INSTALL APPLICATION
SIMPLE-CYCLE CTG PROJECT
ALPINE POWER PLANT
ELMIRA, MICHIGAN
PREPARED FOR:
WOLVERINE POWER SUPPLY COOPERATIVE, INC.
CADILLAC, MICHIGAN
DECEMBER 15, 2014
PROJECT NO. G090066NEW
TABLE OF CONTENTS
1.0
INTRODUCTION ................................................................................................................................ 1
2.0
PROJECT DESCRIPTION ................................................................................................................. 2
3.0
REGULATORY REVIEW ................................................................................................................... 3
3.1
Michigan Regulations .............................................................................................................. 3
3.1.1 Air Pollution Control Rule 201 – PTI Requirements ................................................... 3
3.1.2 Air Pollution Control Rules 224 to 230 – T-BACT Requirement for New and
Modified Sources of Air Toxics and Health-Based Screening Level Requirement
for New or Modified Sources of Air Toxics.................................................................. 3
3.1.2.1 Air Pollution Control Rule 224 – T-BACT Requirement for New and
Modified Source of Air Toxics – Exemptions ............................................... 3
3.1.2.2 Air Pollution Control Rule 225 – Predicted Maximum Impacts of TACs ...... 4
3.1.3 Air Pollution Control Rule 301 – Standards for Density of Emissions ........................ 4
3.1.4 Air Pollution Control Rule 331 – Emission of PM ....................................................... 5
3.1.5 Air Pollution Control Rule 371 – Fugitive Dust Emissions .......................................... 5
3.1.6 Air Pollution Control Rule 401 – Emission of SO2 from Fuel Burning Sources at
Power Plants ............................................................................................................... 5
3.1.7 Air Pollution Control Rule 702 – VOC BACT .............................................................. 5
3.1.8 Air Pollution Control Rules 801 thru 834 – Emission of NOX ...................................... 6
3.1.9 Air Pollution Control Rules 901 thru 912..................................................................... 7
3.1.10 Air Pollution Control Rules – Part 18 (PSD) ............................................................... 7
3.2
Federal Regulations ................................................................................................................ 8
3.2.1 NAAQS – Attainment Status Considerations .............................................................. 8
3.2.2 40 CFR 52.21 – PSD .................................................................................................. 8
3.2.3 40 CFR 60 Subparts A, IIII and KKKK – NSPS .......................................................... 9
3.2.4 40 CFR 63 Subparts A, YYYY and ZZZZ – NESHAPs .............................................. 9
3.2.5 Cross-State Air Pollution Rule .................................................................................. 10
4.0
EMISSION CHARACTERISTICS ..................................................................................................... 11
4.1
NSR Regulated Pollutant Emissions ..................................................................................... 11
4.2
TAC and HAP Emissions ...................................................................................................... 12
5.0
CONTROL TECHNOLOGY SUMMARY .......................................................................................... 13
5.1
VOC BACT ............................................................................................................................ 13
5.1.2 New Emergency Generator ...................................................................................... 15
5.2
T-BACT.................................................................................................................................. 16
6.0
AIR QUALITY MODELING AND AIR TOXIC EVALUATION ........................................................... 18
6.1
Model Parameters ................................................................................................................. 18
6.1.1 Model Selection ........................................................................................................ 18
6.1.2 GEP Stack Height Analysis ...................................................................................... 19
6.1.3 Model Input Parameters............................................................................................ 19
6.2
Criteria Pollutant Modeling .................................................................................................... 20
6.2.1 Significant Impact Analysis and Results ................................................................... 20
6.2.2 PSD Increment and NAAQS Analyses ..................................................................... 21
6.3
Secondary PM2.5 Formation .................................................................................................. 22
6.3.1 Emission Profile and USEPA Guidance ................................................................... 22
6.3.2 Qualitative Analysis and Conclusions ....................................................................... 23
6.4
Secondary Ozone Formation ................................................................................................ 24
6.5
TAC Modeling ........................................................................................................................ 25
6.5.1 TAC Emission Rates and Results ............................................................................. 25
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TABLE OF CONTENTS
7.0
SUMMARY AND CONCLUSIONS ................................................................................................... 26
7.1
Proposed Emissions Control Technologies .......................................................................... 26
7.2
NESHAP Compliance ............................................................................................................ 26
7.3
NSPS Compliance ................................................................................................................. 26
7.4
Ambient Impacts .................................................................................................................... 27
7.5
Compliance Demonstrations and Monitoring ........................................................................ 27
LIST OF FIGURES
Figure 1
Figure 2
Location Map
Site Plan
LIST OF TABLES
Table 1
Table 2
Table 3
Table 4
Table 5
Table 6
Table 7
Table 8
Table 9
Table 10
Table 11
Table 12
Table 13
Table 14
Table 15
Table 16
Table 17
Table 18
Table 19
Table 20
Estimated CTG Potential NSR Regulated Pollutant Emissions
Estimated CTG Startup and Shutdown NSR Regulated Pollutant Emissions
Emergency RICE NSR Regulated Pollutant Estimated Emissions
Estimated NSR Pollutant Emissions from Natural Gas Fired Fuel Heaters
Project Related TAC and HAP Emissions
Total NSR Regulated Pollutants
VOC BACT Economic Calculations for Each CTG
VOC BACT Economic Calculations for the Emergency Generator
VOC BACT Economic Calculations for the Backup Fire Pump
VOC BACT Economic Calculations for Each Fuel Heater
Fabric Filter Economic Analysis for Each Fuel Gas Heater
Structure Heights
Model Input Parameters
Hourly Average Stack Parameters per CTG
SIL Model Results Summary
PSD Increment Model Results Summary
NAAQS Model Results Summary
Illustrative Analysis of Possible Secondary PM2.5 Impacts
Unitized Model Results
Maximum PAI
LIST OF APPENDICES
Appendix 1
Appendix 2
CD Containing Modeling-Related File
MDEQ Data
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TABLE OF CONTENTS
LIST OF ABBREVIATIONS/ACRONYMS
AERMOD
AQD
BACT
CAA
CAIR
CEMS
CFR
CH4
CO
CO2
CO2e
CPM
CSAPR
CTG
EGU
⁰F
FTCH
GEP
GHG
GWP
HAP
HP
HRSG
hr/yr
IRSL
ITSL
kWe
lb/hr
lb/MMBtu
LRC
MACT
MDEQ
MISO
MMBtu/hr
MWe
MWh
NAAQS
NESHAP
N2O
NO2
NOx
NSPS
NSR
O2
O3
PAH
Pb
PAI
PM
PM2.5
PM10
ppm
ppmvd
ppmw
PSD
American Meteorological Society/Environmental Protection Agency Regulatory Model
Air Quality Division (of the Michigan Department of Environmental Quality)
Best Available Control Technology
Clean Air Act
Clean Air Interstate Rule
Continuous Emissions Monitoring System
Code of Federal Regulations
methane (a greenhouse gas)
carbon monoxide
carbon dioxide (a greenhouse gas)
carbon dioxide equivalent (GHG mass emissions including their GWPs)
condensable particulate matter
Cross-State Air Pollution Rule
combustion turbine generator
electrical generating unit
degrees Farhenheit
Fishbeck, Thompson, Carr & Huber, Inc.
Good Engineering Practice (as it relates to stack height)
greenhouse gas
global warming potential of GHGs
hazardous air pollutant
horsepower
heat recovery steam generator
hours per year
Initial Risk Screening Level
Initial Threshold Screening Level
kilowatt (electric)
pound(s) per hour
pound(s) per million British thermal units per hour
Lima Refining Company
Maximum Achievable Control Technology
Michigan Department of Environmental Quality
Midcontinent Independent System Operator
Million British thermal units per hour
Megawatt (electric)
Meagawatt hour
National Ambient Air Quality Standards
National Emission Standards for Hazardous Air Pollutants
nitrous oxide (a greenhouse gas)
nitrogen dioxide
nitrogen oxides
New Source Performance Standards
New Source Review
diatomic oxygen
ozone
polycyclic aromatic hydrocarbons
elemental lead
Predicted Ambient Impacts
particulate matter
Fine Particulate Matter less than 2.5 microns
Particulate Matter less than 10 microns
part(s) per million
part(s) per million, by volume, dry basis
part(s) per million, by weight
Prevention of Significant Deterioration
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TABLE OF CONTENTS
PTE
PTI
PVMRM
RH
RICE
SCR
SER
SIL
SIP
SNCR
SO2
SS
TAC
T-BACT
tpy
µg/m³
USEPA
VE
VOC
Wolverine
potential to emit
Permit to Install
Plume Volume Molar Ratio Method
relative humidity
reciprocating internal combustion engine
selective catalytic reduction
significant emission rate
Significant Impact Level
State Implementation Plan
Selective Noncatalytic Reduction System
sulfur dioxide
Startup and Shutdown
toxic air contaminant
Best Available Control Technology for Toxics
ton(s) per year
microgram(s) per cubic meter
United States Environmental Protection Agency
visible emissions
volatile organic compound(s)
Wolverine Power Supply Cooperative, Inc.
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1.0
INTRODUCTION
Fishbeck, Thompson, Carr & Huber, Inc. (FTCH) has been retained by Wolverine Power Supply
Cooperative, Inc. (Wolverine) to submit a Permit to Install (PTI) application for two gas-fired, simple-cycle
combustion turbine generators (CTGs), a new diesel-fired emergency generator, a new diesel-fueled fire
pump, and two new natural gas-fired fuel heaters at a Greenfield site located near Elmira, Michigan (west
of the City of Gaylord, Michigan). The plant will generate electricity as required by the Midcontinent
Independent System Operator (MISO) primarily during peak electric demand time periods.
The new facility will be located near the east corner of M-32 and Flott Road in Elmira Township, Otsego
County, Michigan. The site location is identified in Figure 1.
This document contains the information necessary to demonstrate compliance with all currently
applicable state and federal air quality requirements as they apply to the project. A description of the new
project, proposed maximum operating scenarios, proposed emission rates, and all other required
information to support this permit application are also included.
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2.0
PROJECT DESCRIPTION
The project consists of installing the following process equipment (emission units):
•
Two new simple-cycle CTGs. Each CTG will be rated at a nominal 2,015 Million British thermal units
per hour (MMBtu/hr) heat input and nominal 205.3 Megawatt (electric) [MWe] output at 100% load
and 59⁰F, and 2,045 MMBtu/hr and 203.3 MWe output at an ambient temperature of 81⁰F. These
new CTGs will only be capable of firing natural gas. Air pollution control technology for each CTG
includes burner designs and modern combustion controls that will inherently minimize NOX, carbon
monoxide (CO), volatile organic compound (VOC), particulate matter (PM), potential organic toxic air
contaminants (TACs) and organic hazardous air pollutants (HAPs). Using natural gas fuel also limits
potential condensable particulate matter (CPM) and greenhouse gas (GHG) due to the use of low
sulfur and lower carbon content fuel.
•
A new diesel-fired emergency generator rated at 1,500 kilowatt (electric) [kWe] (approximately
2011 horse power [HP]) output for emergency electrical generation. The emergency generator’s
annual operation will be limited to 100 hours per year (hr/yr).
•
A new diesel-fueled reciprocating internal combustion engine (RICE) Fire Pump, rated at 347 HP
output for emergency backup operation will be installed in the event the normal electrically driven fire
pump(s) be out of service for any reason (such as loss of electrical power). The backup fire pump’s
operation will also be limited to 100 hr/yr.
•
Two new natural gas-fired indirectly heated CTG natural gas fuel heaters (1 per CTG). Each will be
rated at a nominal 3.5 MMBtu/hr heat input.
A site plan for the facility is presented in Figure 2.
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3.0
REGULATORY REVIEW
3.1
MICHIGAN REGULATIONS
3.1.1
AIR POLLUTION CONTROL RULE 201 – PTI REQUIREMENTS
Any process or process equipment installed after August 15, 1967, which may emit an air contaminant
requires a PTI prior to installation, construction, reconstruction, relocation, or modification, unless
specifically exempt. The proposed new process equipment requires a PTI prior to commencement of
physical onsite installation.
3.1.2
AIR POLLUTION CONTROL RULES 224 TO 230 – T-BACT REQUIREMENT FOR NEW
AND MODIFIED SOURCES OF AIR TOXICS AND HEALTH-BASED SCREENING LEVEL
REQUIREMENT FOR NEW OR MODIFIED SOURCES OF AIR TOXICS
Rules 224 to 230, effective November 10, 1998, apply to any proposed, new, or modified process or
process equipment for which an application for a PTI is required and which emits a TAC. A TAC is
defined in Michigan rules as:
. . . any air contaminant for which there is no National Ambient Air Quality Standard
(NAAQS) and which is or may become harmful to public health or the environment when
present in the outdoor atmosphere in sufficient quantities and duration.
Rules 224 and 225 require emissions of TACs not exceed the following:
●
Rule 224 – The maximum allowable emission rate that results from the application of Best Available
Control Technology for Toxics (T-BACT).
●
Rule 225 – The maximum allowable emission rate that results in a predicted maximum ambient
impact above the Initial Threshold Screening Level (ITSL), the Initial Risk Screening Level (IRSL),
or both.
Compliance with T-BACT and health-based screening level requirements are presented later in this
document.
3.1.2.1
AIR POLLUTION CONTROL RULE 224 – T-BACT REQUIREMENT FOR NEW AND
MODIFIED SOURCE OF AIR TOXICS – EXEMPTIONS
Pursuant to Rule 224(2)(c), the T-BACT requirements do not apply to emissions of PM and/or VOCs that
comply with BACT or the Lowest Achieveable Emission Rate for PM and/or VOCs.
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Organic HAPs and TACs, along with CO, will be minimized by the use of modern combustion controls
implemented on each new CTG and fuel heater. PM-bound toxics (such as trace metals) will be
minimized by the use of natural gas fuel that does not contain trace metals.
Each new RICE will have modern combustion technology to minimize the specific heat input rate and will
use ultra low sulfur diesel fuel to minimize TACs.
A T-BACT analysis is provided in Section 5, which also includes VOC BACT (Rule 702) analyses for all of
the proposed emission units.
3.1.2.2
AIR POLLUTION CONTROL RULE 225 – PREDICTED MAXIMUM IMPACTS OF TACS
Rule 225 requires the predicted maximum ambient impact from the emission of TACs from new and
modified sources not exceed applicable health-based screening levels. The screening level for a TAC is
the maximum allowable concentration in the ambient air, outside a reasonable barrier that prevents public
access to the source’s property, averaged over a specified period of time (1 hour, 8 hour, 24 hour or
annual averaging times). The concentration of a TAC is predicted using an air dispersion modeling
computer program. A detailed emission modeling demonstration is included in Section 6.0 of this
document and demonstrates compliance with Rule 225.
3.1.3
AIR POLLUTION CONTROL RULE 301 – STANDARDS FOR DENSITY OF EMISSIONS
Rule 301 establishes limitations for the visible density of emissions. The proposed CTGs and emergency
generator are not expected to have any effect on the ability to comply with the visible emissions (VE)
limitations of Rule 301. Rule 301 limits VE as follows:
●
A 6-minute average of 20% opacity, except for one 6-minute average per hour of not more than
27% opacity.
●
A limit specified by an applicable federal Standard for the Performance of New Source Performance
Standards (NSPS).
●
A limit specified as a condition of a PTI or Permit to Operate.
The use of natural gas fuel and modern combustion controls for each CTG and fuel heaters, and using
ultra low sulfur diesel fuel in the emergency generator and backup fire pump as well as modern
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combustion controls in all combustion devices, will assure compliance with the opacity limitations
contained in Rule 301.
3.1.4
AIR POLLUTION CONTROL RULE 331 – EMISSION OF PM
The estimated PM emissions for the CTGs are provided in Table 1 and demonstrate compliance with the
requirements in Rule 331. The PM emissions from the new emergency generator and backup fire pump
RICE will comply with the NSPS Subpart IIII requirements. Table 31 of Rule 331 does not include natural
gas-fired process equipment or RICE.
3.1.5
AIR POLLUTION CONTROL RULE 371 – FUGITIVE DUST EMISSIONS
Pursuant to Rule 371, the Michigan Department of Environmental Quality (MDEQ) may request a Fugitive
Dust Control Plan in certain circumstances. No solid fuel handling will be performed onsite, there is
infrequent traffic onsite and the main roadway into the plant and vehicle parking areas will be paved.
Therefore, a Fugitive Dust Control Plan is not warranted for this project.
3.1.6
AIR POLLUTION CONTROL RULE 401 – EMISSION OF SO2 FROM FUEL BURNING
SOURCES AT POWER PLANTS
Rule 401 restricts the emissions of sulfur dioxide (SO2) for fuel burning equipment in a power plant.
Michigan Air Pollution Control Rule 106(i) defines “fuel burning equipment” as indirect heating where the
media being heated does not directly contact the exhaust gases generated from combustion. Rule 401
only applies to solid and liquid fuels.
The proposed CTGs and the proposed emergency equipment RICE do not meet the definition of “fuel
burning equipment” as contained in R 336.1106(i). Furthermore, the proposed fuel heaters will only use
pipeline quality natural gas fuel. Therefore, the requirements of Rule 401 will not apply to the project.
3.1.7
AIR POLLUTION CONTROL RULE 702 – VOC BACT
New sources of VOC are subject to Rule 702, which requires an emission limitation based upon the
application of BACT. New sources are defined in Rule 701 as:
. . . any process or process equipment which is either placed into operation on or after
July 1, 1979, or for which an application for a Permit to Install, pursuant to the provision
of Part 2 of these rules, is made to the department on or after July 1, 1979, or both,
except for any process or process equipment which is defined as an existing source
pursuant to R336.1601 (Rule 601).
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Rule 702 requires a new source of VOC to meet all the provisions in the following Subrules:
a) The maximum allowable emission rate listed by the department on its own initiative or
based upon the application of the best available control technology.
b) The maximum allowable emission rate specified by a new source performance
standard promulgated by the USEPA under authority enacted by Title I, Part A,
Section 111 of the Clean Air Act (CAA), as amended, 42 U.S.C. §7413.
c) The maximum allowable emission rate specified as a condition of a permit to install or
a permit to operate.
d) The maximum allowable emission rate specified in Part 6 of these rules which would
otherwise be applicable to the new source except for the date that the process or
process equipment was placed into operation or for which an application for a permit
to install, under the provisions of Part 2 of these rules, was made to the department.
If the Part 6 allowable emission rate provides for a future compliance date, then the
future compliance date shall also be applicable to a new source pursuant to
this subdivision.
Wolverine believes that the use of natural gas fuel with modern, state-of-the-art combustion design meets
the intent of Rule 702(a) for VOC BACT. This position is also supported by other very similar Michigan
projects that have been approved by the MDEQ Air Quality Division (AQD) for the past several years.
3.1.8
AIR POLLUTION CONTROL RULES 801 THRU 834 – EMISSION OF NOX
Part 8 of the Michigan Air Pollution Control Rules limits the emissions of NOX from stationary sources
within the State of Michigan. Rules 801 through 822 apply to NOX State Implementation Plan (SIP) Call
sources. These sources are required to obtain a NOX Budget Permit. Sources not subject to the NOX
Budget Permit requirements must also evaluate whether they are subject to the NOX Ozone Season
Trading Program for sources found in Rules 823 through 834. Applicability of the Michigan NOX rules
relies upon the applicability criteria found in the federal Clean Air Interstate Rule (CAIR), 40 CFR 97.104
and 40 CFR 97.304.
Based upon the promulgation of the Cross-State Air Pollution Control Rule (CSAPR), 76 Fed Reg 48208
(August 8, 2011), federal court decisions related to CSAPR, and the USEPA’s Interim Direct Final Rule of
November 21, 2014,
1
all CAIR requirements, including SIPs implementing CAIR, sunset as of
December 31, 2014. Accordingly, we do not believe any Part 8 requirements will remain applicable to
this project.
1
http://www.epa.gov/crossstaterule/pdfs/CSAPRinterimfinal11_12_14.pdf
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3.1.9
AIR POLLUTION CONTROL RULES 901 THRU 912
The Part 9 Rules are applicable to all sources, including this project. These Rules include:
•
Rule 901 – General Nuisance (for fugitive emissions and odors).
•
Rule 910 – Installation and Operation of Emissions Control Equipment.
•
Rule 911 – Malfunction Abatement Plans.
•
Rule 912 – Abnormal Conditions, including Startup, Shutdown, Malfunctions, and Reporting of
abnormal conditions.
The facility will comply with the provisions of these Rules. Fugitive emissions and odors are not inherent
to natural gas-fired and diesel-fired emission units. The new power plant will install and maintain all air
pollution control technologies associated with the project. Wolverine will prepare a malfunction abatement
plan for each emission unit associated with the project. Wolverine will also comply with the requirements
of Rule 912.
3.1.10
AIR POLLUTION CONTROL RULES – PART 18 (PSD)
As noted previously, the facility will be located in Otesgo County, which currently complies with the
NAAQS for PM10, PM2.5, SO2, nitrogen dioxide (NO2), CO, ozone (O3), and elemental lead (Pb). In
attainment areas, the federal NSR program is implemented under the Prevention of Significant
Deterioration (PSD) program as specified in 40 CFR 52.21. The MDEQ implements the Part 18 PSD
program in the state as an approved program from the USEPA. The Part 18 rules incorporate the federal
PSD New Source Review (NSR) requirements contained in 40 CFR 52.21 into the state rules.
The primary provisions of the PSD requirements are, in part, that proposed new major stationary sources
and proposed major modifications to existing major stationary sources be reviewed prior to construction
to ensure compliance with the NAAQS, the applicable PSD increments, the requirement to apply BACT
on the project’s emissions of air pollutants equal to or greater than their respective major and significance
thresholds, and evaluate air contaminants due to secondary growth as a result of a project.
A “major stationary source” is any source type belonging to a list of 28 source categories that emits or has
the potential to emit (PTE) 100 tons per year (tpy) or more of any NSR regulated pollutant or any other
source type that emits or has the PTE any NSR regulated pollutant in amounts equal to, or greater than,
250 tpy. Previously, a major stationary source would have also needed to include any source whose
potential GHG emissions are 100,000 tpy, or more, as carbon dioxide equivalent (CO2e), and a major
modification would also include a project whose net increase in GHG emissions are 75,000 tpy, or more,
as CO2e. However, in June of 2014 the U.S. Supreme Court ruled that GHG emissions should only be
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reviewed if any of the “anyway” pollutants (or traditional NSR regulated pollutants) has triggered the PSD
requirements. A stationary source generally includes all pollutant-emitting activities that belong to the
same industrial grouping, located on contiguous or adjacent properties, and are under common control.
A major modification is generally a physical change or a change in the method of operation of an existing
major stationary source that would result in both a significant emissions increase and a significant net
emissions increase of any traditional NSR regulated pollutant(s). In determining if a specific project would
become subject to the PSD program, the modification must be determined to result in both a significant
emissions increase and a significant net emissions increase. Since Wolverine’s project is a new source, a
major modification analysis is not applicable.
The proposed CTGs are not included in the list of 28 source categories as a plant with fossil fuel-fired
boilers (also called steam generating units) with a combined total heat input over 250 MMBtu/hr.
Furthermore, the proposed facility will have enforceable provisions that will restrict the annual PTE of
each traditional NSR regulated pollutants at a level less than 250 tpy.
Therefore, the Part 18 PSD major source program regulations will not apply to the proposed project.
3.2
FEDERAL REGULATIONS
3.2.1
NAAQS – ATTAINMENT STATUS CONSIDERATIONS
As noted previously in this document, the facility will be located in Otsego County, which is currently in
compliance (attainment) with the NAAQS for PM10, PM2.5, SO2, NO2, CO, O3, and Pb.
3.2.2
40 CFR 52.21 – PSD
The federal PSD program applies in geographic areas that are in attainment with the NAAQS. Since the
facility is located in Otsego County, the PSD program would apply if the proposed project met or
exceeded the applicable major source thresholds. The federal NSR program is implemented pursuant to
40 CFR 52.21. The MDEQ implements the PSD program in Michigan as an approved state from
the USEPA.
As noted previously, annual allowed NSR regulated pollutant emissions will be below the PSD
applicability thresholds and, therefore, the project is not subject to the PSD regulatory requirements.
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3.2.3
40 CFR 60 SUBPARTS A, IIII AND KKKK – NSPS
Subpart A of the NSPS addresses general requirements that apply to all new stationary sources subject
to a specific subpart, such as IIII or KKKK. Subpart A includes general provisions for compliance with
applicable emission limits (as specified in a specific subpart for an affected facility), notifications,
performance testing, continuous compliance monitoring, recordkeeping and reporting requirements.
Some provisions in Subpart A may be “trumped” by a specific NSPS subpart that contains more stringent
requirements or exclusion(s) from Subpart A.
The proposed CTGs will be subject to the more recent (February 18, 2005) 40 CFR 60 Subparts A and
KKKK requirements, not the former Subpart GG requirements, because the date regarding
commencement of construction for these new CTGs is well after the effective date for Subpart KKKK.
Subpart KKKK currently regulates NOX and SO2 emissions from stationary simple-cycle or combinedcycle combustion turbines.
The new diesel-fired emergency RICE will be subject to the NSPS Subpart IIII requirements, since they
will be new units that commenced construction (the date an owner/operator places an order for
purchasing the RICE from a RICE manufacturer) after April 1, 2006, for non-fire pump RICE, and model
year 2009 for fire pump RICE that have a HP range from 175 to 750. The applicable commenced
construction dates are contained in 40 CFR 60.4202(a).
The proposed, new natural gas-fired CTG fuel heaters are too small to be subject to an NSPS
requirement as the lowest NSPS threshold for indirect fired equipment is 10 MMBtu/hr heat input (as
contained in NSPS Subpart Dc).
The NSPS contains emission limitations, notifications, performance testing (if applicable), continuous
compliance monitoring, recordkeeping, and reporting requirements.
3.2.4
40 CFR 63 SUBPARTS A, YYYY AND ZZZZ – NESHAPS
Projects of this nature may also be subject to the federal requirements for the control of HAP emissions.
The first step to determining applicability is to review the source-specific regulations contained in 40 CFR
Part 63. Part 63 is part of the NESHAP with the other being Part 61. Part 61 does not apply since the
proposed emission units will not be one of the categories contained in Part 61.
A major source of HAPs is defined in Section 112 of the CAA as a stationary source that has a PTE of
10 tpy or more of any individual HAP or 25 tpy of the total combined HAPs subject to regulation under the
CAA. Using the design capacity of the new proposed equipment, it has been determined that the total
HAPs will be less than the NESHAP major source applicability thresholds (both the 10 tpy and 25 tpy
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thresholds). This is based on HAP emissions data available from stack tests from similar combustion
turbine equipment (such as formaldehyde) and use of USEPA AP-42 emission factors. Potential HAP
emissions for the entire facility are discussed in Section 4.2 and provided in Table 5. Based on the
calculations contained within Table 5, the Wolverine Alpine Power Plant will be a minor (area) source of
HAP emissions.
NESHAP Subpart YYYY applies to combustion turbines and associated heat recovery equipment that are
located at a major source of HAP emissions. Therefore, this NESHAP will not apply to the proposed
CTGs.
NESHAP Subpart ZZZZ applies to RICE at either a major source or area source of HAPs. The new
diesel-fired emergency generator and backup fire pump RICE will comply with the applicable
requirements in NESHAP Subparts A and ZZZZ. Pursuant to 40 CFR 63.6590(c)(1), any RICE subject to
the requirements of NSPS Subpart IIII (including Subpart JJJJ that applies to spark ignition RICE)
“automatically” meets the requirements in NESHAP Subpart ZZZZ. Therefore, the new emergency RICE
will comply with the NESHAP ZZZZ via compliance with NSPS IIII.
NESHAP JJJJJJ will not apply to the proposed CTGs’ fuel heaters as they will be exclusively fired with
natural gas fuel.
3.2.5
CROSS-STATE AIR POLLUTION RULE
As indicated in Section 3.1.8, CSAPR’s applicable requirements become effective January 1, 2015.
New power plants must acquire CSAPR emission allowances to allow operation of these new sources of
SO2 and NOX emissions. The new Wolverine Alpine Power Plant project will be subject to CSAPR and will
require SO2 and NOX emission allowances (commonly referred to as a “new source set aside allowance”)
equal to its actual annual emissions. Wolverine acknowledges that it will need to hold allowances as
required by the CSAPR rule. As acquisition of these allowances occurs well after issuance of this permit
and is a function of the Federal Implementation Plan for CSAPR. CSAPR requirements are outside the
scope of the PTI review process.
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4.0
EMISSION CHARACTERISTICS
There will be NSR regulated pollutants, HAP, and TAC emissions associated with the combustion of
natural gas fuel in the proposed CTGs and fuel heaters, and combustion of diesel fuel in the emergency
RICE.
The facility will be an area (minor) source of HAP emissions and a minor source for purposes of the NSR
PSD program.
4.1
NSR REGULATED POLLUTANT EMISSIONS
The maximum emission rates of all NSR regulated pollutants have been determined. The project’s
potential short-term emissions were calculated based on the worst case basis, the maximum capacity of
the diesel fuel-fired emergency RICE and the maximum capacity of the fuel heaters. The total annual
emissions for the CTGs have been determined based on their maximum, worst case short-term capacity
and a combined total operating scenario. The annual PTE for the proposed Alpine Power Plant will be
based on total annual (or 12-month rolling time period) fuel use in lieu of any annual (or 12-month rolling)
operating schedule (such as a maximum allowed annual hourly operation). The annual emissions for the
proposed emergency RICE are based on their short-term maximum capacity and 100 hr/yr (or 12-month
rolling time period).
The maximum potential emissions as a result of operating the new facility will be less than the applicable
major source threshold of 250 tpy for any “traditional” (or “anyway”) NSR regulated pollutant. For this
project, the “traditional” NSR regulated pollutants consist of CO, NOX, PM, PM10, PM2.5, SO2, VOC, lead
and sulfuric acid mist (idenitifed as “H2SO4”). Based on the June 23, 2014, U.S. Supreme Court’s decision
regarding applicability of GHG emissions triggering major NSR review for new stationary sources, GHG
emissions from the proposed project being greater than 100,000 tpy will not require major NSR PSD
review in and of itself where the “traditional” or “anyway” NSR regulated pollutants will be less than
250 tpy. Wolverine requests that restrictions be placed on the facility’s “traditional” NSR regulated
pollutants’ annual (12-month rolling) PTE to remain a minor stationary source for purposes of the major
NSR PSD program.
Tables 1, 2, 3, 4 and 6 identify the emissions from the CTGs, both new emergency RICE, new fuel
heaters and total project emissions, respectively. Table 2 represents an estimate of the Startup and
Shutdown (SS) NSR regulated pollutant emissions, based on an assumed total number of events per
year. The total annual number of SS events will be determined by MISO and other entities outside the
control of Wolverine; therefore, the total number of SS events per year included within this permit
application is a best estimate. The emissions that occur during these SS events will be included in the
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total annual (12-month) rolling emission limitations contained within the AQD-issued permit. The
estimated SS emissions have been incorporated into Table 1 for the overall NSR regulated pollutant
emissions from the CTGs.
4.2
TAC AND HAP EMISSIONS
The federally regulated HAP emissions associated from the proposed project will be a subset of the TAC
emissions. The TAC and HAP emissions from the project were determined by reviewing currently
available emission factors for the proposed equipment and associated fuel. The basis for the emission
estimates and methods for calculating TAC and HAP emissions are contained in the tables included in
this application describing the emissions. Table 5 describes the TAC and HAP emissions related to the
proposed process equipment.
The facility will be an area (minor) source of HAPs (less than 10 tpy for a single HAP and less than 25 tpy
for all HAPs combined) after the proposed Alpine Power Plant is commissioned.
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5.0
CONTROL TECHNOLOGY SUMMARY
This project is not subject to the PSD BACT requirements for any NSR regulated pollutant, since the
annual potential emissions for any “traditional” NSR regulated pollutant will not equal, or exceed, 250 tpy.
Nonetheless, the project will need to demonstrate that the process equipment will comply with the
T-BACT and VOC BACT requirements contained in Rules 224 and 702(a), respectively. According to
Rule 224(2)(c), for those TACs that are VOC, compliance with VOC BACT meets the requirement for
T-BACT.
The following are analyses of the T-BACT and VOC BACT requirements proposed for this project,
although the use of natural gas for all proposed major combustion sources identified within this permit
application should be self evident to demonstrate compliance with the T-BACT and VOC BACT.
5.1
VOC BACT
All combustion equipment will generate VOC emissions as a result of incomplete oxidation of the fuel(s).
No combustion device achieves 100% complete oxidation of the constituents (primarily carbon and
hydrogen) in the fuel. Controlling VOC from combustion equipment primarily includes the following types
of technologies:
•
Design of the combustion technology to achieve as complete (as is possible) oxidation of the carbon
and hydrogen in the fuel; and,
•
Add-on control technology such as a thermal oxidizer or catalytic oxidizer.
Catalytic oxidation and thermal oxidation work on the principal of using heat to initiate conversion of the
volatile components in the exhaust gas to CO2 and water. Catalytic oxidizers use a bed of precious
metal(s), such as platinum, deposited on a substrate to enhance the oxidation reaction that can occur at
lower temperatures than thermal oxidizers that do not employ a catalyst. Catalytic oxidizers are generally
the add-on VOC control of choice due to their lower cost of operation with reduced fuel use to heat the
exhaust gases to the required minimum temperature than is necessary without a catalyst present. The
minimum temperature for a catalytic oxidizer to achieve decent VOC control (90% or more) is
approximately 550⁰F to 600⁰F.
Thermal oxidation does not use a catalyst and relies on a higher temperature to initiate the oxidation
reaction of the VOC in the exhaust gas. Thermal oxidation requires more auxiliary fuel use and, therefore,
have higher annual operating costs associated with achieving the same level of control efficiency as
catalytic oxidizers. The minimum temperature for a thermal oxidizer to achieve decent VOC control (90%
or more) is approximately 1,400⁰F to 1,500⁰F. A thermal oxidizer also requires a residence time of
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approximately 0.5 second (or more depending on the turbulence inside the oxidizer) to allow for proper
exhaust gas heating and exposure to available oxygen to complete the reaction.
Since CO emissions will be minimized as a collateral pollutant, the potential CO emissions have been
added to the VOC emissions to properly evaluate whether an add-on control device will reflect the true
economic impacts.
Furthermore, a negative related environmental impact due to auxiliary fuel use would be additional NOX
and GHG emissions generated from the combustion of auxiliary fuel to heat the exhaust gases from the
emission unit (if applicable). It has been presumed that any VOC and CO generated from the combustion
of the auxiliary fuel will be controlled by an add-on catalytic oxidizer. Note that where a catalytic oxidizer
could be implemented on the emergency generator, fire pump and each CTG, there will not be any
auxiliary fuel necessary to heat the exhaust gases as the exhaust gases from these emission units have
sufficient temperature for proper function of a catalytic oxidizer. Auxiliary fuel will be required for each
emission unit using a thermal oxidizer as the exhaust gas temperature from each emission unit is not
sufficient for proceeding with the oxidation reaction.
The following subsections provide an analysis of VOC BACT for each proposed emission unit.
5.1.1
EACH NEW CTG
Each proposed CTG will utilize modern, state-of-the-art combustion technology that reduces the potential
for incomplete combustion. With the need to reduce fuel usage per kW of electrical output, including
increased energy efficiency, combustion turbine manufacturers are designing turbine combustion systems
to meet these requirements.
There is a delicate balance between obtaining low VOC emissions with low NOX emissions. Generally,
VOC is controlled by providing a hot flame to ensure adequate temperature for oxidation of the carbon
and hydrogen in the fuel to reduce the products of incomplete combustion. NOX formation is more
probable with higher flame temperatures that breaks down the diatomic nitrogen and oxygen in the
combustion air to form NOX. Turbine manufacturers have developed combustion systems that balance
lower flame temperature with staged combustion to achieve the desired result of low VOC with collateral
low NOX emissions.
The following add-on control technologies are technically feasible for each CTG:
•
Good combustion practices inherent to the design of the turbine;
•
Catalytic oxidation;
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•
Thermal oxidation; and,
•
A combination of good combustion practices with add-on control technology.
All of these control technologies are considered to be technically feasible for each CTG. Good
combustion practices will be incorporated into each CTG. The potential VOC emissions will be 4.1 tpy
without additional add-on control.
Table 7 provides an economic analysis of adding catalytic oxidation and thermal oxidation to each
proposed CTG. The minimum economic impact of an oxidizer is over $138,000 per ton of controlled VOC
plus CO. This economic impact is greater than typically considered to be economically feasible for VOC
emissions and, therefore, is considered to be infeasible for each CTG.
Although a catalytic oxidizer would control some of the VOC and CO during startup and shutdown phases
of operation, the control efficiency is unknown and is presumed to be negligible. VOC BACT during these
modes of CTG operation are considered to be minimizing the amount of time during each startup and
shutdown event.
Therefore, VOC BACT for each CTG is considered to be implementing good CTG combustion practices
with a VOC emission limit of 4.6 tpy during normal (baseload) operation.
5.1.2
NEW EMERGENCY GENERATOR
The new diesel-fired emergency generator will meet the VOC emission requirements contained in NSPS
Subpart IIII. The new RICE will use modern combustion control that will minimize the formation of VOC as
a result of combustion of the diesel fuel.
Additionally, the potential VOC emissions from the new emergency generator will be 0.02 tpy.
Table 8 provides an economic analysis of adding catalytic oxidation and thermal oxidation to the
proposed emergency generator. The minimum economic impact of an oxidizer is over $791,000 per ton of
controlled VOC plus CO. This economic impact is greater than typically considered to be economically
feasible for VOC emissions and, therefore, is considered to be infeasible for the emergency generator.
We have determined that the use of modern combustion design represents VOC BACT for the new
emergency generator.
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5.1.3
NEW BACKUP FIRE PUMP
The new diesel-fired backup fire pump will meet the VOC emission requirements contained in NSPS
Subpart IIII. The new RICE will use modern combustion control that will minimize the formation of VOC as
a result of combustion of the diesel fuel.
Additionally, the potential VOC emissions from the new backup fire pump are estimated at 0.005 tpy.
Table 9 provides an economic analysis of adding catalytic oxidation and thermal oxidation to the
proposed backup fire pump. The minimum economic impact of an oxidizer is over $473,000 per ton of
controlled VOC plus CO. This economic impact is greater than typically considered to be economically
feasible for VOC emissions and, therefore, is considered to be infeasible for the backup fire pump.
We have determined that the use of modern combustion design represents VOC BACT for the new
backup fire pump.
5.1.4
NEW FUEL HEATERS
Table 10 provides an economic analysis of adding catalytic oxidation and thermal oxidation to each
proposed fuel heater. The minimum economic impact of an oxidizer is over $38,000 per ton of controlled
VOC plus CO. This economic impact is greater than typically considered to be economically feasible for
VOC emissions and, therefore, is considered to be infeasible for each proposed fuel heater.
5.2
T-BACT
T-BACT for organic-based (or VOC) TAC is the use of VOC BACT as provided in Rule 224(2)(c) and as
determined in Section 5.1 for each proposed emission unit.
For non-organic TAC, such as metal TACs, an analysis of add-on control technology is presented below.
Since the fuel heaters will be the only emission units that have potential non-organic TACs, and will be
metal TACs attached to PM, no additional T-BACT is provided for each CTG, emergency generator and
backup fire pump.
The metal TACs will be associated with PM emissions. The technically feasible PM control technologies
for controlling PM from each fuel heater include:
•
Fabric filter;
•
Electrostatic precipitator;
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•
Wet scrubber; and
•
Cylcone(s).
Since a fabric filter would provide the highest control efficiency of the options above, and the least annual
operating costs, a fabric filter has been evaluated for economic feasibility. An ESP and wet scrubber
would generally have a higher initial capital cost and annual operating cost than a fabric filter. Cyclone
control would not provide for as high a control efficiency due to the particle size of the PM in a fuel
heater’s exhaust gas. Particle sizes of PM exiting a combustion device would be 1 micron or less.
Cyclones are highly inefficient for PM with a size range this small.
Table 11 provides the economic impact as a result of using a fabric filter control device to control PM
TACs from each fuel heater. The economic impact would be over $13,000,000 per ton of PM removed
and is economically infeasible from each fuel heater.
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6.0
AIR QUALITY MODELING AND AIR TOXIC EVALUATION
Emissions associated with the proposed project are below major source thresholds with respect to PSD,
but exceed the significant emission rates for the following criteria pollutants: NO2, CO, PM10, and PM2.5.
Otsego County is attainment for all the listed criteria pollutants. Although the project is not subject to PSD,
Wolverine is voluntarily providing a dispersion modeling analysis for criteria pollutants above their
individual significant emission rates as part of the PTI application. The criteria pollutant analysis is
presented in Section 6.2.
In recent PSD permits, the MDEQ and USEPA required that sources address secondary formation of O3
and PM2.5. Although this project in not subject to PSD, the MDEQ has requested that a secondary
formation analysis be performed as part of the application. Secondary formation assessments are
provided in Sections 6.3 and 6.4.
As stated in Rule 225 (R 336.1225) of the Air Pollution Control Commission General Rules, the MDEQ
requires that the ambient impact of the TACs released from a rule-subject source be estimated and
compared to established air quality standards. An air toxics demonstration is presented in Section 6.5.
Model selection and input parameters, used for both criteria pollutant and TAC modeling analyses, are
presented in Section 6.1.
6.1
MODEL PARAMETERS
The modeling selection and input parameters used for both criteria pollutant modeling and TAC analyses
are presented in the following sections.
6.1.1
MODEL SELECTION
The model selected for the air dispersion analysis was AERMOD, Version 14134. This model was
established as the USEPA-preferred air dispersion model effective December 9, 2005, for steady-state
operations. AERMOD is a modeling analysis which incorporates air dispersion based on planetary
boundary layer turbulence structure and scaling concepts, including treatment of both surface and
elevated sources, and both simple and complex terrain.
BEE-line software, which incorporates the USEPA algorithm for the AERMOD program, was used. The
software, referred to as “BEEST”, Version 10.13, was developed by a Division of Bowman Environmental
Engineering, Inc.
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6.1.2
GEP STACK HEIGHT ANALYSIS
Prior to running the air dispersion model, the potential for building downwash to affect the stack plume
must be evaluated. Building downwash represents the effect that nearby structures have on the air flow
near the stack. If the stack is within the area of influence of the building, the swirls and eddies caused by
obstruction of the air flow near buildings can affect the plume dispersion characteristics.
The GEP analysis was performed using software developed by Bowman Environmental Engineering, Inc.
The software includes the USEPA BPIP-Prime Version 04274 code for calculating projected building
widths. This analysis was run for all buildings illustrated in Figure 2 greater than 10 feet in height.
Structures and equipment less than 10 feet in height were considered insignificant and not included in the
assessment. Structure heights for the buildings and equipment considered in the model are provided in
Table 12. The highest calculated GEP stack height of any structure was 175 feet (53.3 meters). The stack
heights listed in Table 13 are less than the GEP stack height; therefore, direction-specific building effects
calculated for each wind direction were entered into the dispersion model as described in the next
section. A summary of the results of the GEP analysis are provided electronically in Appendix 1.
6.1.3
MODEL INPUT PARAMETERS
The direction-specific building dimensions calculated during the GEP stack height analysis were input into
the model.
Figure 1 presents the site location. The origin of the grid used in the model is located at the center of the
north CTG stack. However, all coordinates are provided in UTM NAD 83 coordinate system. Because the
property will be fenced north of M-32, receptors were placed at 25-meter intervals around this portion of
the property line. Dense grids of 25-meter and 50-meter intervals surround the property, and a grid of
100 meters and 250 meters covers the outlying areas.
Terrain elevations at receptors were obtained using BEE-Line Software’s BEEST program and USGS
National Elevation Dataset (NED) 1/3 arc-second data. BEEST implements the AERMAP model
(Version 11103), which includes processing routines that extract NED data to determine receptor terrain
elevations for air quality model input. The NED data used in the modeling had a resolution of 10 meters
(1/3 arc-second) and NAD83 datum.
The meteorological data used in the model was 1-minute data from Otsego County Airport, Gaylord,
2009-2013 (Surface Station No. 14854), and Green Bay, 2009-2013 (Upper Air Station No. 4837). The
meteorological data was provided by the MDEQ and was processed using AERMET, Version 14134. The
model for 1-hr NOX and 24-hr PM2.5 was run using a combined 5-year meteorological dataset to
determine the 5-year average impact at each receptor.
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All emissions sources included in this analysis will have emissions exhausted from a stack, and were
considered point sources in the model. Stack parameters for these sources are provided in Table 13.
6.2
CRITERIA POLLUTANT MODELING
A dispersion modeling analysis has been conducted for the criteria pollutants for which emissions are
above the significant emission rate criteria. As presented in Table 6, these include NO2, CO, PM10, and
PM2.5. If emissions result in impacts that exceed the Significant Impact Levels (SILs), a detailed
dispersion modeling impact analysis to demonstrate compliance with the federal PSD increments and
NAAQS was conducted as a part of the application, as discussed in Sections 6.2.1 and 6.2.2.
Emission rates for the two CTGs were conservatively determined for use in the modeling demonstration.
The maximum emission rates for either a start-up hour or a baseload hour were used in the modeling
along with the minimum hourly average exhaust flow rate, as summarized in Table 13. Based upon the
proposed restriction concerning total annual operating hours, the two units will not often operate
simultaneously at their maximum proposed emission rates. However, it was conservatively assumed for
modeling purposes that both units will operate simultaneously at their maximum proposed emission rates.
Emission rate calculations and associated exhaust flow rates for a start-up hour are provided in Table 14.
6.2.1
SIGNIFICANT IMPACT ANALYSIS AND RESULTS
The significant impact analysis is the first step in the modeling study. Emissions for each criteria pollutant
with proposed emissions above the significant emission rate are modeled to determine if the impact will
exceed the SILs defined in 40 CFR 52.21. Model input parameters for the SIL analysis are provided in
Table 13. Maximum hourly emission rates for all sources were used in the model, unless otherwise noted
on Table 13. If the impact for a pollutant are above the SIL, PSD increment and NAAQS modeling was
performed for the facility. If the impact for a pollutant meets the SIL, no further modeling was conducted.
As presented in Table 15, maximum predicted impacts from the project are below the SILs for CO and for
annual PM10. Therefore, no further modeling was performed for these specific pollutants and averaging
times. Predicted impacts, however, were above the applicable SILs for all other pollutants and averaging
times, including the previously promulgated 24-hour SIL for PM2.5. Therefore, PSD increment and NAAQS
analyses have been conducted for the remaining pollutants and averaging times, as discussed in
Section 6.2.2. A CD containing the electronic model input/output files is provided in Appendix 1 (of the
original MDEQ application only).
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6.2.2
PSD INCREMENT AND NAAQS ANALYSES
Because predicted ambient impacts from the proposed project are above the various applicable SILs,
additional analyses have been performed for the following pollutants and averaging times as follows:
●
Annual NO2 (increment and NAAQS)
●
1-hour NO2 (NAAQS only; no increment established)
●
Annual and 24-hour PM2.5 (increment and NAAQS)
●
24-hour PM10 (increment and NAAQS)
The MDEQ was contacted to obtain background concentration data and to determine what additional
sources should be considered in the PSD increment and NAAQS analyses. The MDEQ performed a
screening analysis and determined that no additional sources had a significant concentration gradient at
the proposed site. Therefore, there are no additional sources that need to be included in the increment or
NAAQS modeling. Documentation of current background concentrations and additional source data is
provided as Appendix 2.
Typically, the first step in the additional analysis is to define the significant impact receptors for the
project. (These are the receptors from the SIL analysis where the impacts from the project were
determined to be above the SIL.) The significant impact receptors are then usually used for the increment
and NAAQS modeling demonstrations. However, because there are no additional sources to include, the
full grid was used for the increment and NAAQS modeling.
The USEPA revoked the previously promulgated SIL for 24-hour PM2.5. However, USEPA guidance
(March 4, 2013) indicates that if the difference between the NAAQS and the background is greater than
the SIL, then the USEPA believes it would be sufficient to conclude that the NAAQS would not be violated
3
with an impact below the SIL. As the regional background is 16.8 µg/m , net impacts less than 1.2 µg/m
3
3
(revoked PM2.5 SIL) would not jeopardize the NAAQS (35 µg/m ). In recent, similar recent modeling
studies, the MDEQ has not required further refined modeling if the project impact is below the revoked
PM2.5 SIL. Because this project’s predicted maximum impacts are above the previous SIL, NAAQS and
increment analyses were performed for 24-hour PM2.5
The model was run for the proposed maximum emission rates for each pollutant from each stack, unless
otherwise noted on Table 13, with a combined impact from all stacks; therefore, the model PAI is equal to
the actual PAI in µg/m³. The results of the PSD increment and NAAQS analyses demonstrate compliance
and are presented in Tables 16 and 17, respectively. A CD containing the electronic model input/output
files is provided in Appendix 1 (of the original MDEQ application only).
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6.3
SECONDARY PM2.5 FORMATION
Project emissions of direct fine particulate (PM2.5) exceed the significant emission rate (SER) of 10 tpy.
Project emissions of NOX also exceeds the SER of 40 tpy; NOX is a precursor for secondary formation of
PM2.5. Therefore, an assessment of their potential impact on ambient PM2.5 air quality in the area is being
provided as part of the permit application process. This analysis represents a qualitative assessment of
the potential impact to air quality as a result of secondary PM2.5 formation. This approach is consistent
2
with the guidelines of the USEPA’s March 4, 2013, draft guidance for PM2.5 modeling and is similar to the
analysis conducted for the Husky Lima Refinery Crude Oil Flexibility Project recently accepted in Ohio for
Lima Refining Company (LRC). This analysis also follows the secondary formation analysis recently
submitted and approved for Gerdau MacSteel’s proposed plant expansion at the Monroe, Michigan,
facility (PTI No. 102-12A).
6.3.1
EMISSION PROFILE AND USEPA GUIDANCE
This project’s emission profile (i.e., significant emissions for NOX and direct PM2.5) is most consistent with
“Case 3” from Table II-1 in USEPA’s March 4, 2013, draft guidance for PM2.5 modeling in that the project
is significant for at least one precursor emission (NOX), as well as for direct PM2.5 emissions. For Case 3
projects, USEPA specifies that primary impacts of direct PM2.5 emissions must be addressed. Further,
secondary impacts of precursor emissions of NOX and/or SO2 must also be addressed. (SO2 emissions
do not need to be addressed for Wolverine, as proposed emissions are below the SER.) The impacts of
direct PM2.5 emissions have been included in the modeling analysis presented in Section 6.2 and have
been shown to be compliant with PSD increment and NAAQS requirements, satisfying the first
requirement presented in Table II-1. The assessment of the secondary impacts due to precursor
emissions is the second requirement presented in Table II-1 and is being addressed within this section.
The USEPA’s draft guidance for assessing the secondary PM2.5 impacts from the precursor emissions of
new or modified sources allows for three possible approaches: the “accounting of the precursor emissions
impact on secondary PM2.5 formation may be completely qualitative in nature, may be based on a hybrid
of qualitative and quantitative assessments utilizing existing technical work, or may be a full quantitative
3
photochemical grid modeling exercise.” The USEPA has indicated that the last option, photochemical
modeling, would only be required in rare circumstances.
At present, the March 4, 2013, draft guidance has not been finalized and, therefore, does not represent
the USEPA’s final guidance. However, in December 2013, the USEPA notified the MDEQ that a
2
Draft
Guidance
for
PM2.5
Permit
Modeling,
USEPA,
March
http://www.epa.gov/ttn/scram/guidance/guide/Draft_Guidance_for_PM25_Permit_Modeling.pdf
3
Draft Guidance for PM2.5 Permit Modeling, USEPA, March 4, 2013, pages 18 and 19.
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2013
22
qualitative assessment may be preferable for addressing the potential secondary impacts due to
precursor emissions and provided the LRC analysis as an example. Therefore, the following analysis,
which is patterned after the LRC assessment, is consistent with the USEPA’s guidance for conducting a
qualitative analysis for the purpose of demonstrating that the secondary formation of PM2.5 from
precursors SO2 and NOX for this project will not cause or significantly contribute to a violation of
the NAAQS.
6.3.2
QUALITATIVE ANALYSIS AND CONCLUSIONS
This analysis details why modeling secondary PM2.5 emissions is not needed in order to determine that
emissions of PM2.5 precursors from this project would not cause or contribute significantly to a violation of
the annual and 24-hour PM2.5 NAAQS.
1)
Background concentrations used in near-field dispersion modeling should represent all current air
pollution sources other than those explicitly modeled. The Houghton Lake, Michigan, monitor is the
only PM2.5 monitor in the northern lower peninsula of Michigan and has been determined by the
MDEQ to be the most representative background data for PM2.5. This area has some of the lowest
background concentrations of PM2.5 in the state. The 24-hour average design value (average
3
percentile value of three years, 2011-2013) of 16.8 µg/m is well below the 24-hour PM2.5 NAAQS
3
3
of 35 µg/m . The 3-year annual design value of 5.9 µg/m is also well below the annual PM2.5
3
NAAQS of 12 µg/m . These values leave room under the NAAQS for new source impacts of up to
18.2 µg/m
3
(24-hour) and 6.1 µg/m
3
(annual). As discussed below, the maximum potential
Wolverine project secondary PM2.5 impacts are anticipated to be well below these levels.
2)
Table 18 documents how insignificant the secondary PM2.5 formation from this project is likely to be.
Shown in this table is a screening level assessment of project PM2.5 impacts of precursors based
on the described assumption for conversion of NOX to PM2.5 This conversion is based on the
preferred/presumptive interpollutant trading ratios originally set forth in the USEPA’s 2008 PM2.5
NSR implementation rule for use for emission offsets in non-attainment area NSR permitting.
Although the USEPA no longer supports the use of these offset trading ratios as they are not
necessarily representative of the exact precursor conversion in all areas of the country, they do
provide perspective as to how insignificant the impacts due to precursor emissions are anticipated
4
to be. It has further been conservatively assumed that the conversion to PM2.5 occurs immediately,
and that maximum NOX impacts occur at the same place and time. Based on these assumptions,
4
The USEPA subsequently revised its policy on July 21, 2011 (Revised Policy to Address Reconsideration of
Interpollutant Trading Provisions for Fine Particulate (PM2.5)). The revised policy no longer supports the 2008
interpollutant trading ratios as presumptively approvable and instead suggests that any ratio involving PM2.5
precursors adopted by the state for use in the interpollutant offset program must be accompanied by a technical
demonstration. This is because the USEPA determined that the 2008 ratios, which were based on analyses of nine
urban areas across the country, are not sufficiently representative of conditions in all areas of the country and would
need to be considerably more conservative to be presumptively applied nationwide in an offset program.
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the secondary impacts of PM2.5 from the project would be significantly below the SIL and would
consume no more than 1% of the room under the NAAQS on a 24-hour basis and no more than
0.1% of the room under the NAAQS on an annual basis, as shown in Table 18.
Wolverine believes that use of the ratios provides an order-of-magnitude that demonstrates the
insignificance of the anticipated impacts due to precursor emissions.
3)
Actual NO2 conversion to PM2.5 would need to be considerably greater than the assumptions used
in these calculations (as identified in Item 2) for the project to have a significant impact on PM2.5
ambient air quality due to precursor emissions.
4)
Secondary formation of PM2.5 from NOX is not instantaneous but occurs over time due to chemical
reactions in the atmosphere, generally downwind of the project site. The maximum direct NOX
impacts used in the calculations above occur near the facility. At locations close to the original
source, there likely would not be adequate time for the conversion of precursor emissions to
secondary PM2.5. Therefore, it is expected that secondary PM2.5 impacts near the facility are less
than those shown in the table. Generally, the secondary impacts are expected to increase farther
from the facility, as there has been more time for the chemical reactions to occur. However, direct
emissions and impacts of NOX decrease at further distances from the facility, leaving less precursor
emissions to convert to secondary PM2.5. Therefore, the actual impacts of secondary PM2.5 are
anticipated to be much lower than those shown in the table.
Based on these factors, and consistent with current guidance, Wolverine believes that an adequate
assessment has been made to demonstrate that the PM2.5 NAAQS will be protected. This evaluation
considered potential contributions due to PM2.5 precursors from the Wolverine project. A further analysis
utilizing photochemical modeling is not necessary to demonstrate that the proposed project is not
expected to have significant impacts to ambient air quality or to cause or significantly contribute to a
violation of the PM2.5 NAAQS.
6.4
SECONDARY OZONE FORMATION
Project emissions of VOC are well below the SER of 40 tpy; however, NOX emissions from the project are
above the SER of 40 tpy. NOX is considered a precursor for secondary formation of ground-level
(tropospheric) ozone. Therefore, an assessment of the potential impact on ambient ozone air quality in
the area is also part of the permit application process.
Ozone impacts due to direct emissions of VOC are not generally modeled as part of the application
process, as ozone modeling is complex and resource-intensive. As such, it is not feasible to quantify
impacts of secondary ozone formation via dispersion modeling. Further, many factors impact tropospheric
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24
ozone development, including temperature, wind speed and direction, and time of day. Therefore, it is not
possible to conclusively determine how much of the precursor NOX emissions from the Wolverine project
will chemically react in the atmosphere to produce the tropospheric ozone.
Conversion of NOX and VOC emissions to tropospheric ozone is not instantaneous, but rather occurs
over time, with the rate of conversion highly dependent upon weather conditions. Further, ozone
formation is recognized as a regional and long-range transport issue. Studies have even shown that
transpacific transport of pollution from Asia influences North America’s air quality, especially during the
ozone season. Therefore, it is very unlikely that secondary formation of ozone from NOX emissions
attributable to the Wolverine project will have a significant impact on the ozone levels in the area.
Otsego County is currently designated as attainment for ozone. Otsego County and surrounding counties
are rural with relatively few industrial sources and have low background concentrations of ozone as
compared to other areas of the state. Given that secondary formation of ozone is more of long-range
transport issue, precursor NOX emissions from the proposed Wolverine project are not expected to have
significant impacts to ambient air quality or to cause or significantly contribute to a violation of the ozone
NAAQS.
6.5
TAC MODELING
In Rule 225 (R 336.1225) of the Air Pollution Control Commission General Rules, the MDEQ requires that
the ambient impact of the TACs released from a rule-subject source be estimated and compared to
established air quality standards. To estimate the ambient air concentrations, each contaminant
concentration is calculated at the stack, assuming peak loading conditions. The contaminant loading from
the stack is then subjected to air dispersion modeling to simulate the effect of local meteorological
conditions. The ambient concentration at hypothetical ground level receptors is then calculated and
compared to the air quality screening levels as developed by the MDEQ.
6.5.1
TAC EMISSION RATES AND RESULTS
The input parameter emission rate was a generic 1 lb/hr for each TAC emission source. Therefore, the
model output is in units of µg/m³ per lb/hr for each TAC source. The unitized model results are included
as Table 19. A summary of the results from the AERMOD model run are presented in Appendix 1.
To estimate the actual PAI for each TAC, the model PAI was multiplied by the maximum emission rate in
lb/hr, with the contributions from each TAC emission source summed to give a conservative combined
impact for that TAC. As presented in Table 20, the PAIs for all TACs from the proposed process are
below the applicable air quality screening levels obtained from the MDEQ-AQD List of Screening Levels.
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25
7.0
SUMMARY AND CONCLUSIONS
This application submittal represents a minor source NSR PTI application for all “traditional” NSR
regulated pollutants and HAPs. The Alpine Power Plant project will help Wolverine meet the growing
electrical capacity needs of Wolverine, provide additional grid stability, and partially make up for the loss
of Michigan-based electric power generation capacity from the retirements of older fossil fuel-fired EGUs.
7.1
PROPOSED EMISSIONS CONTROL TECHNOLOGIES
This project will include VOC BACT and T-BACT emission controls for VOC and TACs emissions (natural
gas fuel and proper combustion designs) pursuant to Rules 702(a) and 224, respectively. The CTGs and
fuel heaters will incorporate modern combustion controls for all PMs, NOX, CO, and VOC as well as the
use of natural gas fuel to minimize SO2, GHG, and CPM emissions. The emergency RICE will also utilize
modern combustion controls as well as ultra low sulfur diesel fuel to minimize potential emissions related
to combustion.
7.2
NESHAP COMPLIANCE
This application demonstrates the project will be an area (minor) source of HAPs, primarily based on the
use of emission factors derived from the USEPA AP-42 database and other similar tested combustion
turbine units. Therefore, each proposed CTG is not subject to the NESHAP requirements contained in
40 CFR 63 Subparts A and YYYY. The new diesel-fired emergency RICE are subject to the area source
requirements of 40 CFR 63 Subparts A and ZZZZ (which is demonstrated via compliance with NSPS
Subpart IIII). The small fuel heaters are not subject to the requirements in NESHAP 40 CFR 63
Subpart JJJJJJ due to the exclusive use of natural gas fuel.
7.3
NSPS COMPLIANCE
Each proposed CTG will be subject to, and comply with, NSPS Subparts A and KKKK.
The new diesel-fired emergency RICE will be subject to, and comply with, the provisions contained within
NSPS Subparts A and IIII.
The proposed fuel heaters are each less than 10 MMBtu/hr heat input that is the minimum size threshold
of NSPS Subpart Dc. Therefore, each fuel heater is not subject to any NSPS requirements.
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26
7.4
AMBIENT IMPACTS
The results of the dispersion modeling analyses demonstrates compliance with all state and federal
ambient standards for criteria pollutants and all Michigan TAC ambient health-based screening level
requirements.
7.5
COMPLIANCE DEMONSTRATIONS AND MONITORING
Wolverine is proposing to utilize parametric NOx monitoring for each CTG in accordance with 40 CFR 97
Subpart H (which includes reference to 40 CFR 75 Appendix E) to verify compliance with the permitted
emission rates. A 40 CFR 75 NOx monitoring plan will be developed prior to operation in accordance with
the Federal Monitoring Plan requirements and schedule (this Plan will also address 40 CFR 60 monitoring
requirements). Onsite performance testing will begin within 180 days of the proposed power plant’s
commissioning to demonstrate compliance with emission limits. Should either CTG at the Alpine Power
Plant exceed an annual capacity factor of 20% for any 1 calendar year or an average of 10% for
3 consecutive calendar years, Alpine Power Plant will install a certified NOX continuous emission
monitoring system (CEMS) by December 31 of the following calendar year for the affected CTG. This is
consistent with the current CSAPR regulations and allows a source a reasonable amount of time to
select, install and certify a NOX CEMS. The following language is proposed as Special Conditions for
each CTG to enforce this requirement:
Permittee shall install, certify and operate no later than December 31 of the following
calendar year a NOX CEMS for monitoring actual NOX emissions from EU-CTG1 if the
capacity factor during any calendar year is greater than 20% or if the 3-calendar year
average capacity factor is greater than 10%. Capacity factor is the actual utilization (as
MWh) of EU-CTG1 divided by its potential capacity (as MWh) based on 8,760 hours per
calendar year multiplied by 100. (40 CFR 97.70, 40 CFR 75.12(d)(2))
Permittee shall install, certify and operate no later than December 31 of the following
calendar year a NOX CEMS for monitoring actual NOX emissions from EU-CTG2 if the
capacity factor during any calendar year is greater than 20% or if the 3-calendar year
average capacity factor is greater than 10%. Capacity factor is the actual utilization (as
MWh) of EU-CTG2 divided by its potential capacity (as MWh) based on 8,760 hours per
calendar year multiplied by 100. (40 CFR 97.70, 40 CFR 75.12(d)(2))
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27
A parametric monitoring plan will also be developed for other NSR regulated pollutants, which will likely
be based on performance (emission) testing results and using appropriate surrogate pollutants wherever
possible (such as VOC or CO for organic HAP emissions).
Compliance with the emission requirements for the new emergency RICE will be based on the RICE
manufacturer’s certification that the emissions will meet the emission limits (if available).
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28
Figures
VICINITY MAP
MICHIGAN
engineers
scientists
_
^
architects
constructors
ELMIRA
OTSEGO COUNTY
fishbeck, thompson,
carr & huber, inc.
Hard copy is
intended to be
11"x17" when
plotted. Scale(s)
indicated and
graphic quality may
not be accurate for
any other size.
PLOT INFO: Z:\2009\090066NEW\CAD\GIS\MAP_DOC\Alpine\FIG02_SITE PLAN.mxd Date: 12/3/2014 11:32:47 AM User: acs
LEGEND
Property Boundary
LOCATION MAP
NORTH 0
500
FEET
1,000
Source: Esri, DigitalGlobe, GeoEye, i-cubed, Earthstar Geographics, CNES/Airbus DS, USDA, USGS, AEX, Getmapping, Aerogrid, IGN, IGP, swisstopo,
and the GIS User Community, Esri, HERE, DeLorme, MapmyIndia, © OpenStreetMap contributors, Esri, HERE, DeLorme, TomTom, MapmyIndia, ©
OpenStreetMap contributors, and the GIS user community
Air Permit Application
Wolverine Power
Alpine Power Plant, Elmira, Otsego County, Michigan
LOCATION OF SITE
PROJECT NO.
G090066NEW
1
FIGURE NO.
©Copyright 2014
All Rights Reserved
Tables
Page 1 of 1
Table 1 - NSR Regulated Pollutant Emissions From CTGs
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
203.3
Maximum CTG Generator Capacity (1 CTG) =
MWe at 81 °F and 100% load
2,045
MMBtu/hr at 81°F and 100% load (HHV Basis)
One CTG 100% Load Heat Input Rate =
72.8%
(represents total annual operation for both CTGs divided by 8,760 hr/yr)
Annual Capacity Factor =
6,380
hr/yr (represents total, combined annual operation for both CTGs at 100% load)
Annual Operation =
Total Annual Heat Input Rate = 13,044,676 MMBtu/yr and represents baseload operation at 100% load only for both CTGs (HHV basis)
Annual Natural Gas Usage Rate = 12,714.1 MMCF/yr at 1,026 Btu/CF natural gas and represents baseload operation only at 100% load for both CTGs (HHV basis)
Total Annual Natural Gas Usage Rate = 12,850.3 MMCF/yr at 1,026 Btu/CF natural gas (HHV basis), and includes baseload at 100% load + startup and shutdown events
Emission Factor
(Baseload Operation)
(See Footnotes for Emission
Factor Basis)
Short-Term Emissions
per CTG
(Baseload Operation)
(lb/hr)
Short-Term Emissions
Both CTGs Combined
(Baseload Operation)
(lb/hr)7
Annual Emissions
Both CTGs Combined
(Baseload Operation)
(tpy)
Startup and
Shutdown
Emissions 1
(tpy)
Total Annual
Emissions 2 (tpy)
CO 3
2.0000E-02 lb/MMBtu
NOX 3
3.2652E-02 lb/MMBtu
40.9
81.8
130.4
82.0
212.4
66.8
133.5
213.0
6.9
PM (Filterable Only) 4
219.8
6.6E-03 lb/MMBtu
13.5
27.0
43.0
1.4
44.4
PM10 (Filterable + Condensable)4
6.6E-03 lb/MMBtu
13.5
27.0
43.0
1.4
44.4
PM2.5 (Filterable + Condensable)4
6.6E-03 lb/MMBtu
13.5
27.0
43.0
1.4
44.4
SO2 3
2.1666E-03 lb/MMBtu
4.4
8.9
14.1
0.2
14.3
VOC 3
1.4025E-03 lb/MMBtu
2.9
5.7
9.1
14.9
24.0
2.12E-05 lb/MMBtu
0.04
0.1
0.14
0.001
0.14
770,530
14.5
NSR Regulated Pollutant
H2SO4 5
CO2 3
238,983
477,966
762,356
8,174
CH4 6
2.20E-03 lb/MMBtu
4.5
9.0
14.4
0.15
N 2O 6
2.20E-04 lb/MMBtu
0.5
0.9
1.4
0.02
1.5
239,230
478,460
763,144
8,182
771,327
CO2e 6
----
----
1
Based on Table 2 at 250 startup/shutdown events per 12-month rolling time period.
2
Represents the sum of 100% load and startup/shutdown events. See Table 2 for emissions related to startup/shutdown events.
3
Emission factors based on CTG manufacturer, except for CO. CO emission rate is based on 13 ppmv at 12% CO2, which is an approximate 50% increase over
vendor provided emission information. CO2 mass emission rate provided by CTG manufacturer is in units of lb/hr.
4
PM/PM10/PM2.5 emission factor from AP-42 Table 3.1-2a. To be conservative, PM emissions have been estimated to be equivalent to PM 10 and PM2.5, even though PM is only to include filterable
portion (PM determined from performance testing using USEPA Methods 5 or 17 of 40 CFR 60 Appendix A).
5
The H2SO4 emission factor presumes approximately 0.8% of the SO2 is emitted as SO3 and then converts to H2SO4 in the presence of moisture. This is then multiplied by the ratio of the molecular
weight of H2SO4 to SO3 (which is 98/80).
6
Based on GWP and emission factors obtained from 40 CFR 98 Subparts A and C, respectively, for natural gas fuel. A factor of 2.20462 is used to convert kg/MMBtu to lb/MMBtu.
7
Emissions for 2 CTGs are twice the Short-Term Emissions per CTG (Baseload Operation) .
Table 1.1 Emission Calculation Methods
E ST = C ST X EF
E A = E ST X Annual Operation at 100% Load / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = CTG Heat Input Capacity (MMBtu/hr); and
EF = emission factor (lb/MMBtu)
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Page 1 of 1
Table 2 - Estimated CTG Startup and Shutdown NSR Regulated Pollutant Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
250
Estimated Total 12-month Rolling Startup and Shutdown Events
Estimated Startup and Shutdown Emissions, Single CTG
Mode of Operation
Cold Start
Shutdown
Fuel
MMBtu/Event
292
267
NOx
lb/Event
30
25
CO
lb/Event
320
336
VOC
lb/Event
49
70
PM10/PM2.5
SO2
H2SO4
lb/Event
5.8
5.3
lb/Event
0.63
0.58
lb/event
0.006
0.006
GHG
lb/event
34,193
31,265
Duration
Minutes
8
8
Hours
0.13
0.13
Notes:
1. NOX, CO and VOC emission rates provided by CTG manufacturer.
2. Conservatively estimated that PM10 and PM2.5 are emitted at a rate of 0.02 lb/MMBtu (to account for less efficient combustion of carbon in fuel) and SO 2 is 0.0022 lb/MMBtu during startup and shutdown events.
3. For H2SO4 emissions, see footnote 4 related to Table 1.1.
4. GHG emissions based on 40 CFR 98 Subparts A and C for GWP and Emission Factors, respectively, for natural gas fuel. A factor of 2.20462 is used to convert kg/MMBtu to lb/MMBtu.
5. Duration in minutes provided by potential CTG manufacturer.
12-Month Rolling Time Period Heat Input and Emissions Due to Startup and Shutdown Events
Fuel
(MMBtu/yr)
139,750
NOx
(tpy)
6.9
CO
(tpy)
82.0
VOC
(tpy)
14.9
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
PM10/PM2.5
(tpy)
1.4
SO2
(tpy)
0.2
H2SO4
(tpy)
0.001
GHG
(tpy)
8,182
Duration
Minutes
4,000
Hours
66.67
12/4/2014
Page 1 of 2
Table 3 - Emergency RICE NSR Regulated Pollutant Estimated Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Table 3.1 - NSR Regulated Pollutant Emissions from Diesel Fired Emergency Generator
Nominal RICE Rating =
Nominal Generator Rating =
Nominal RICE Heat Input =
Annual Operating Hours =
NSR Regulated Pollutant
Emission Factor
(See Notes)
1
CO
NOx 1
1
2,011
1,500
13.44
100
0.44 g/HP-hr
4.08 g/HP-hr
HP
kW
MMBtu/hr
hr/yr
Hourly Emissions Annual Emissions
(lb/hr)
(tpy)
2.0
18.1
0.1
0.9
0.1
0.2
0.007
0.01
PM
PM10 2
0.03 g/HP-hr
1.76E-02 lb/MMBtu
PM2.5 2
1.76E-02 lb/MMBtu
0.2
0.01
SO2 3
1.52E-03 lb/MMBtu
0.02
0.001
0.11 g/HP-hr
163.6 lb/MMBtu
0.5
2,199
0.02
110
1
VOC
CO2e 4
1
Emission factors are based on potential engine manufacturer for emergency generators and are less than the requirements contained in NSPS Subpart IIII, 40 CFR
60.4202(a)(2) which refers to Table 1 of 40 CFR 89.112 for emission limits.
2
PM10 and PM2.5 emission factor is from the vendor provided PM rate (as g/HP-hr and converted to lb/MMBtu) plus the condensable PM (as lb/MMBtu) from USEPA
AP-42, Chapter 3.4, Table 3.4-2.
3
SO2 emissions are based on USEPA AP-42, Chapter 3.4, Table 3.4-1. Sulfur content of diesel fiel is 0.0015%.
4
CO2e global warming potential and emission factors obtained from 40 CFR 98 Subparts A and C, respectively. The global warming potential for CH 4 (25) and N2O
(298) are consistent with the USEPA published changes on November 29, 2013. A factor of 2.20462 is used to convert kg/MMBtu to lb/MMBtu.
Table 3.1 Emission Calculation Methods
Using lb/MMBtu Emission Factors
E ST = C HI X EF
E A = E ST X Annual Operating Hours / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C HI = RICE Heat Input Capacity (MMBtu/hr); and
EF = emission factor (lb/MMBtu)
Using g/kW-hr Emission Factors
E ST = C kW X EF / 453.59 g/lb
E A = E ST X Annual Operating Hours / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C kW = RICE Power Output Capacity (kW); and
EF = emission factor (g/kW-hr)
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Page 2 of 2
Table 3 - Emergency RICE NSR Regulated Pollutant Estimated Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Table 3.2 - NSR Regulated Pollutant Emissions from Diesel Fired Back Up Fire Pump
Nominal RICE Rating (Each) =
Each RICE Nominal Heat Input =
Annual Operating Hours =
NSR Regulated Pollutant
Emission Factor
(See Notes)
1
CO
1
NOx
1
347
2.3
100
HP
MMBtu/hr
hr/yr
Hourly Emissions Annual Emissions
(lb/hr)
(tpy)
1.4 g/HP-hr
1.1
2.2 g/HP-hr
1.7
0.1
0.1
PM
2
PM10
1.18E-01 g/HP-hr
4.67E-02 lb/MMBtu
0.1
0.00
0.1
0.01
2
4.67E-02 lb/MMBtu
0.1
0.01
1.52E-03 lb/MMBtu
0.004
0.0002
0.1 g/HP-hr
0.1
0.00
163.6 lb/MMBtu
378
19
PM2.5
SO2
3
1
VOC
CO2e 4
1
Emission factors are based on potential engine manufacturer and are less than the requirements contained in NSPS Subpart IIII, 40 CFR 60.4202(d) for emergency
fire pumps, which refers to Table 4 of NSPS Subpart IIII for emission limits.
2
PM10 and PM2.5 emission factor is from the vendor provided PM rate (as g/HP-hr and converted to lb/MMBtu) plus the condensable PM (as lb/MMBtu) from USEPA
AP-42, Chapter 3.4, Table 3.4-2. AP-42 Chapter 3.3 does not provide condensable PM. Thus, the condensable PM is from Chapter 3.4.
3
SO2 emissions are based on USEPA AP-42, Chapter 3.4, Table 3.4-1. Sulfur content of diesel fiel is 0.0015%. Emission factor is lb/MMBtu (HHV).
4
CO2e global warming potential and emission factors obtained from 40 CFR 98 Subparts A and C, respectively. Emission factor is lb/MMBtu (HHV). The global warming
potential for CH4 (25) and N2O (298) are consistent with the changes made by the USEPA on November 29, 2013.
Table 3.2 Emission Calculation Methods
Using lb/MMBtu Emission Factors
E ST = C HI X EF
E A = E ST X Annual Operating Hours / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C HI = RICE Heat Input Capacity (MMBtu/hr); and
EF = emission factor (lb/MMBtu)
Using g/HP-hr Emission Factors
E ST = C HP X EF / 453.59 g/lb
E A = E ST X Annual Operating Hours / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C HP = RICE Power Output Capacity (HP); and
EF = emission factor (g/HP-hr)
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12/4/2014
Page 1 of 1
Table 4 - Estimated NSR Pollutant Emissions from Natural Gas Fired Fuel Heaters
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Heat Input Capacity =
Natural Gas HHV =
Equivalent Annual Fuel Usage Rate per
Fuel Heater =
Equivalent Annual Fuel Usage Rate per
Fuel Heater =
Total Annual Heat Input Limit or
Capacity =
Annual Operation =
1
1
NOX
MMBtu/hr
Btu/CF
3.41E-03
MMCF/hr
21.8
MMCF/yr
22,330
MMBtu/yr
6,380
hr/yr
0.09 lb/MMBtu
Short-Term
Emissions per Fuel
Heater
(lb/hr)
0.3
0.12 lb/MMBtu
0.4
1.3
Emission Factor
(See Notes)
NSR Regulated Pollutant
CO
3.5
1,026
2
Total Annual
Emissions
(tpy)
1.0
1.9 lb/MMCf
0.01
0.02
PM10 (Filterable + Condensable)
1
0.023 lb/MMBtu
0.1
0.3
PM2.5 (Filterable + Condensable)
1
0.023 lb/MMBtu
0.1
0.3
0.6 lb/MMCf
0.002
0.007
PM (Filterable)
SO2
2
VOC
1
Lead
2
0.1
0.2
5.00E-04 lb/MMCf
1.71E-06
5.44E-06
2.18E-02 lb/MMCf
7.43E-05
2.37E-04
0.017 lb/MMBtu
H2SO4 3
CO2
4
117 lb/MMBtu
409
1,306
CH4
4
2.20E-03 lb/MMBtu
0.01
0.02
N2 O
4
2.20E-04 lb/MMBtu
0.0008
0.002
410
1,307
GHG as CO2e
4
117 lb/MMBtu
1
Emission factors for CO, NOX, PM10, PM2.5, and VOC are based on vendor data.
2
Emission factors are based on USEPA AP-42 Chapter 1.4, Tables 1.4-1 and 1.4-2.
3
The H2SO4 emission factor assumes approximately 0.8% of the SO2 is emitted as SO3 and then converts to H2SO4 in the presence of
moisture. This is then multiplied by the ratio of the molecular weight of H2SO4 to SO3 (which is 98/80).
4
Based on GWP and emission factors obtained from 40 CFR 98 Subparts A and C, respectively, for natural gas fuel.
A factor of 2.20462 is used to convert kg/MMBtu to lb/MMBtu.
Emission Calculation Methods
E ST = C ST X EF / HHV
E A = C A X EF / HHV / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = Total Heat Input Capacity (MMBtu/hr);
C A = Annual Maximum Heat Input Capacity based on 6,380 hours/yr of operation (MMBtu/yr);
EF = emission factor (lb/MMBtu); and
HHV = Natural Gas Higher Heating Value (Btu/CF)
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Page 1 of 4
Table 5 - Project Related TAC and HAP Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Total Potential HAP Emissions =
2.7
tpy
(Since the total HAPs are less than 10 tpy, the project is, by default, minor for a single HAP.)
Table 5.1 - Short-Term and Annual TAC and HAP Emission Rates for CTGs
Maximum Heat Input Rate =
Annual Operation =
TAC / HAP
1,3-Butadiene
Acetaldehyde
Acrolein
Benzene
Ethylbenzene
Formaldehyde 3
Naphthalene
PAH 4
Propylene Oxide
Toluene
Xylenes
1
2,045
MMBtu/hr
6,380
hr/yr
CAS Number
106-99-0
75-07-0
107-02-8
71-43-2
100-41-4
50-00-0
91-20-3
---75-56-9
108-88-3
1330-20-7
Potential HAPs
Emission Factor 1
Emission Rates 2
(lb/hr)
(tpy)
8.79E-04
2.80E-03
8.18E-02
2.61E-01
1.31E-02
4.17E-02
2.45E-02
7.83E-02
6.54E-02
2.09E-01
(lb/MMBtu)
4.30E-07
4.00E-05
6.40E-06
1.20E-05
3.20E-05
9.00E-05
1.30E-06
1.84E-01
2.66E-03
5.87E-01
8.48E-03
2.20E-06
2.90E-05
1.30E-04
6.40E-05
4.50E-03
5.93E-02
2.66E-01
1.31E-01
Total CTG HAPs =
1.43E-02
1.89E-01
8.48E-01
4.17E-01
2.7
HAP?
(Yes or No)
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Except for formaldehyde, the HAP emission factors are based upon the emissions factors of AP-42 Chapter 3.1, Table 3.1-3.
2
The short-term emissions are based on the hourly maximum heat input rate and the annual emissions are based on the annual operation at 100%
capacity. Annual emissions reflect the potential for both CTGs.
3
4
Formaldehyde emission factor is based on a GE 7FA turbine from the June 2007 stack test for Zeeland Power Company, Zeeland, Michigan.
"PAH" consists of a grouping of sixteen HAP polycyclic aromatic hydrocarbons.
Table 5.1 Emission Calculation Methods
E ST = C ST X EF
E A = E ST X Annual Operation / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = Total Heat Input Capacity (MMBtu/hr); and
EF = emission factor (lb/MMBtu)
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Page 2 of 4
Table 5 - Project Related TAC and HAP Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Table 5.2 - Short-Term and Annual TAC and HAP Emission Rates for One Emergency Generator
Mechanical Power =
Equivalent Heat Input Rate =
Annual Operation =
TAC / HAP
Acenaphthene
Acenaphthylene
Acetaldehyde
Acrolein
Anthracene
Benzene
Benzo (a) anthracene
Benzo (b) fluoranthene
Benzo (a) pyrene
Benzo (g,h,i) perylene
Benzo (k) fluoranthene
Chrysene
Dibenz(a,h)anthracene
Fluoranthene
Fluorene
Formaldehyde
Indeno(1,2,3-c,d)pyrene
Naphthalene
PAH 4
Phenanthrene
Propylene
Pyrene
Toluene
Xylenes
6
2,011
13.44
100
CAS Number
83-32-9
208-96-8
75-07-0
107-02-8
120-12-7
71-43-2
56-55-3
205-99-2
50-32-8
191-24-2
207-08-9
218-01-9
53-70-3
206-44-0
86-73-7
50-00-0
193-39-5
91-20-3
---85-01-8
115-07-1
129-00-0
108-88-3
1330-20-7
HP
MMBtu/hr
hr/yr
Emission Factor 6
(lb/MMBtu)
Short-term
Emission Rate
(lb/hr)
Annual Emission
Rate
(tpy)
4.68E-06
9.23E-06
2.52E-05
7.88E-06
1.23E-06
7.76E-04
6.22E-07
1.11E-06
2.57E-07
5.56E-07
2.18E-07
1.53E-06
3.46E-07
4.03E-06
1.28E-05
7.89E-05
4.14E-07
1.30E-04
6.29E-05
1.24E-04
3.39E-04
1.06E-04
1.65E-05
1.04E-02
8.36E-06
1.49E-05
3.45E-06
7.47E-06
2.93E-06
2.06E-05
4.65E-06
5.42E-05
1.72E-04
1.06E-03
5.56E-06
1.75E-03
3.14E-06
6.20E-06
1.69E-05
5.30E-06
8.27E-07
5.21E-04
4.18E-07
7.46E-07
1.73E-07
3.74E-07
1.46E-07
1.03E-06
2.33E-07
2.71E-06
8.60E-06
5.30E-05
2.78E-07
8.74E-05
2.12E-04
2.85E-03
4.08E-05
5.48E-04
2.79E-03
3.75E-02
3.71E-06
4.99E-05
2.81E-04
3.78E-03
1.93E-04
2.59E-03
Total Emergency Generator HAPs =
1.42E-04
2.74E-05
1.87E-03
2.49E-06
1.89E-04
1.30E-04
0.001
HAP?
(Yes or No)
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
Emission factors obtained from USEPA AP-42, Chapter 3.4, Tables 3.4-3 and 3.4-4.
Table 5.3 Emission Calculation Methods
E ST = C ST X EF
E A = E ST X Annual Operation / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = Total Heat Input Capacity (MMBtu/hr); and
EF = emission factor; (lb/MMBtu)
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Page 3 of 4
Table 5 - Project Related TAC and HAP Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Table 5.3 - Short-Term and Annual TAC and HAP Emission Rates for One Backup Fire Pump
Mechanical Power =
Equivalent Heat Input Rate =
Annual Operation =
TAC / HAP
1,3-Butadiene
Acenaphthene
Acenaphthylene
Acetaldehyde
Acrolein
Anthracene
Benzene
Benzo (a) anthracene
Benzo (b) fluoranthene
Benzo (a) pyrene
Benzo (g,h,i) perylene
Benzo (k) fluoranthene
Chrysene
Dibenz(a,h)anthracene
Fluoranthene
Fluorene
Formaldehyde
Indeno(1,2,3-c,d)pyrene
Naphthalene
PAH 4
Phenanthrene
Propylene
Pyrene
Toluene
Xylenes
7
347
2.31
100
HP
MMBtu/hr
hr/yr
CAS Number
106-99-0
83-32-9
208-96-8
75-07-0
107-02-8
120-12-7
71-43-2
56-55-3
205-99-2
50-32-8
191-24-2
207-08-9
218-01-9
53-70-3
206-44-0
86-73-7
50-00-0
193-39-5
91-20-3
---85-01-8
115-07-1
129-00-0
108-88-3
1330-20-7
Emission Factor 7
(lb/MMBtu)
3.91E-05
1.42E-06
5.06E-06
7.67E-04
9.25E-05
1.87E-06
9.33E-04
1.68E-06
9.91E-08
1.88E-07
4.89E-07
1.55E-07
3.53E-07
5.83E-07
7.61E-06
2.92E-05
1.18E-03
3.75E-07
8.48E-05
Short-term
Emission Rate
(lb/hr)
Annual Emission
Rate
(tpy)
HAP?
(Yes or No)
9.04E-05
4.52E-06
Yes
3.28E-06
1.17E-05
1.77E-03
2.14E-04
4.32E-06
2.16E-03
3.89E-06
2.29E-07
4.35E-07
1.13E-06
3.58E-07
8.16E-07
1.35E-06
1.76E-05
6.75E-05
2.73E-03
8.67E-07
1.96E-04
3.89E-04
6.80E-05
5.97E-03
1.11E-05
9.46E-04
6.59E-04
1.64E-07
5.85E-07
8.87E-05
1.07E-05
2.16E-07
1.08E-04
1.94E-07
1.15E-08
2.17E-08
5.65E-08
1.79E-08
4.08E-08
6.74E-08
8.80E-07
3.38E-06
1.36E-04
4.34E-08
9.81E-06
1.94E-05
3.40E-06
2.98E-04
5.53E-07
4.73E-05
3.30E-05
0.0005
No
No
Yes
Yes
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
1.68E-04
2.94E-05
2.58E-03
4.78E-06
4.09E-04
2.85E-04
Total Backup Fire Pump HAPs =
Emission factors obtained from USEPA AP-42, Chapter 3.3, Table 3.3-2.
Table 5.3 Emission Calculation Methods
E ST = C ST X EF
E A = E ST X Annual Operation / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = Total Heat Input Capacity (MMBtu/hr); and,
EF = emission factor; (lb/MMBtu)
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Page 4 of 4
Table 5 - Project Related TAC and HAP Emissions
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Table 5.4 - Short-Term and Annual TAC and HAP Emissions From Two Fuel Heaters
Heat Input Capacity =
Annual Heat Input =
Natural Gas HHV =
TAC / HAP
Metals
Arsenic
Barium
Beryllium
Cadmium
Chromium
Cobalt
Copper
Manganese
Mercury
Molybdenum
Nickel
Selenium
Vanadium
Zinc
Organics
2-Methyl Naphthalene
3-Methylcholanthrene
Acenaphthene
Acenaphthylene
Anthracene
Benzene
Benzo (a) anthracene
Benzo (a) pyrene
Benzo (b) fluoranthene
Benzo (g,h,i) perylene
Benzo (k) fluoranthene
Chrysene
Dibenzo(a,h) anthracene
Dichlorobenzene, mixed isomers
Dimethylbenz(a)anthracene
Fluoranthene
Fluorene
Formaldehyde
Indeno(1,2,3-cd)pyrene
Naphthalene
n-Butane
N-Hexane
N-Pentane
Phenanthrene
Pyrene
Toluene
Total Fuel Heaters HAPs =
8
7.0
61,320
1,026
MMBtu/hr (2 Heaters at 3.5 MMBtu/hr Each)
MMBtu/yr
Btu/CF
Emission Factor
Units
Short-Term
Emissions per
Fuel Heater
(lb/hr)
Combined ShortTerm Emissions
(lb/hr)
2.00E-04
4.40E-03
1.20E-05
1.10E-03
1.40E-03
8.40E-05
8.50E-04
3.80E-04
2.60E-04
1.10E-03
2.10E-03
2.40E-05
2.30E-03
2.90E-02
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
6.82E-07
1.50E-05
4.09E-08
3.75E-06
4.78E-06
2.87E-07
2.90E-06
1.30E-06
8.87E-07
3.75E-06
7.16E-06
8.19E-08
7.85E-06
9.89E-05
1.36E-06
3.00E-05
8.19E-08
7.50E-06
9.55E-06
5.73E-07
5.80E-06
2.59E-06
1.77E-06
7.50E-06
1.43E-05
1.64E-07
1.57E-05
1.98E-04
2.40E-05
1.80E-06
1.80E-06
1.80E-06
2.40E-06
2.10E-03
1.80E-06
1.20E-06
1.80E-06
1.20E-06
1.80E-06
1.80E-06
1.20E-06
1.20E-03
1.60E-05
3.00E-06
2.80E-06
7.50E-02
1.80E-06
6.10E-04
2.10E+00
1.80E+00
2.60E+00
1.70E-05
5.00E-06
3.40E-03
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
lb/MMCF
8.19E-08
6.14E-09
6.14E-09
6.14E-09
8.19E-09
7.16E-06
6.14E-09
4.09E-09
6.14E-09
4.09E-09
6.14E-09
6.14E-09
4.09E-09
4.09E-06
5.46E-08
1.02E-08
9.55E-09
2.56E-04
6.14E-09
2.08E-06
7.16E-03
6.14E-03
8.87E-03
5.80E-08
1.71E-08
1.16E-05
1.64E-07
1.23E-08
1.23E-08
1.23E-08
1.64E-08
1.43E-05
1.23E-08
8.19E-09
1.23E-08
8.19E-09
1.23E-08
1.23E-08
8.19E-09
8.19E-06
1.09E-07
2.05E-08
1.91E-08
5.12E-04
1.23E-08
4.16E-06
1.43E-02
1.23E-02
1.77E-02
1.16E-07
3.41E-08
2.32E-05
Emission Factor
Value 8
(lb/MMCF)
7440-38-2
7440-39-3
7440-41-7
7440-43-9
18540-29-9
7440-48-4
7440-50-8
7439-96-5
7439-97-6
7439-98-7
7440-02-0
7782-49-2
7440-62-2
7440-66-6
91-57-6
56-49-5
83-32-9
208-96-8
120-12-7
71-43-2
56-55-3
50-32-8
205-99-2
191-24-2
207-08-9
218-01-9
53-70-3
25321-22-6
57-97-6
206-44-0
86-73-7
50-00-0
193-39-5
91-20-3
106-97-8
110-54-3
109-66-0
85-01-8
129-00-0
108-88-3
CAS No.
Emission factors obtained from USEPA AP-42, Chapter 1.4, Tables 1.4-3 and 1.4-4.
Table 5.4 Emission Calculation Methods
E ST = C ST X EF / HHV
E A = C A X EF / HHV / 2,000 lb/ton
where:
E ST = Short Term Emissions (lb/hr);
E A = Annual Maximum Emissions (tpy);
C ST = Total Heat Input Capacity (MMBtu/hr);
C A = Annual Maximum Heat Input Capacity based on 8,760 hours/yr of operation (MMBtu/yr);
EF = emission factor (lb/MMCF); and,
HHV = Natural Gas Higher Heating Value (Btu/CF)
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Page 1 of 1
Table 6 - Total Annual Project NSR Regulated Pollutant Emissions Summary
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
NSR Regulated Pollutant
CTG
1
Emergency
Generator
Backup Fire
Pump
Fuel Heaters
Total Cumulative
Emissions
Major Source
Threshold
Major Source?
Significance
Threshold
Significant
Emissions?
(tpy)
0.1
0.9
0.007
0.01
(tpy)
0.1
0.1
0.00
0.005
(tpy)
1.0
1.3
0.021
0.257
(tpy)
213.6
222.2
44.5
44.7
(tpy)
250
250
250
250
(Yes or No)
No
No
No
No
(tpy)
100
40
25
15
(Yes or No)
Yes
Yes
Yes
Yes
PM
PM10
(tpy)
212.4
219.8
44.4
44.4
PM2.5
44.4
0.01
0.005
0.257
44.7
250
No
10
Yes
SO2
14.3
24.0
---0.14
0.001
0.02
-------
1.75E-04
0.00
-------
0.007
0.2
0.00001
0.0002
14.3
24.2
0.00001
0.1
250
250
250
250
No
No
No
No
40
40
0.6
7
No
No
No
No
771,327
110
19
1,307
772,763
NA
CO
NOX
VOC
Lead
H2SO4
GHG (as CO2e)
1
2
NA
2
NA
2
NA
2
CTG emissions are total for both CTGs and includes startup and shutdown emissions.
2
Based on the June 23, 2014 US Supreme Court decision, GHG emissions do not trigger a major source requirement in and of itself. At least one of the "traditional" ("anyway" or "conventional") NSR regulated pollutants would need to trigger
a major source requirement before GHG emissions are evaluated pursuant to the major NSR PSD program. Since none of the "traditional" NSR regulated pollutants are major, the major and significant thresholds are NA (not applicable) for
GHG emissions.
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Page 1 of 1
Table 7 – VOC BACT Economic Calculations for Each CTG
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Parameters
Assumptions
Heat Recovery
Operating Temperature
Oxidation efficiency
Capital Cost Components
Equipment Costs:
-- Basic Equipment, e.g., Incinerator:
-- Other (auxiliary equipment, etc.):
Total Equipment Cost--base:
Total Equipment Cost --escalated:
Purchased Equipment Cost :
Total Capital Investment (1995 $):
Total Capital Investment (1998 $):
Annualized Cost Components
Direct Operating Costs:
Operating labor
Supervisory labor
Maintenance labor
Maintenance materials
Natural gas
Electricity
Catalyst replacement
Recuperative Combustion
0,35,50 or 70
Total Annualized Cost($):
Tons of VOCs Controlled (TPY):
Cost Effectiveness: ($/ton Controlled)
956,150
1138
50.7
0
40
44
0.067
3.49
0.07
0.824404522
Operating hours (hours/year)
3,190
Regenerative Combustion
70% 85 or 95
1,400
99%
$13,362,784.82
$0.00
$13,362,784.82
$17,817,164.10
$21,024,253.64
$33,849,048.36
$41,058,785.41
Sub total
Indirect Operating Costs:
Overhead
Taxes, insurance, administrative
Capital recovery
Input Parameters
Waste stream flow rate (scfm)
Waste stream temperature (deg F)
Annual VOC + CO emission (tpy)
Gross heat of combustion (btu/lb, toluene)
Operating Labor Rate ($/hr)
Maintenance Labor Rate ($/hr, OLR*1.1)
Electricity Price ($/kwh)
Natural Gas Price ($/mmBtu or $/mscf)
Annual interest rate (fraction):
Means CPI (1995 to 2014)
Catalytic Combustion
95% 0,35,50 or 70
1,400
99%
$26,076,857.01
$31,631,142.62
0%
600
99%
$11,134,066.99
$0.00
$11,134,066.99
$12,938,353.99
$15,267,257.71
$24,580,284.91
$29,815,805.54
$7,975.00
$1,196.25
$8,772.50
$8,772.50
$2,950,066.04
$2,263,683.14
$0.00
$5,240,465.42 Sub total
$7,975.00
$1,196.25
$2,288.00
$2,288.00
$457,937.99
$797,567.55
$0.00
$1,269,252.80 Sub total
$16,029.75
$1,642,351.42
$5,845,847.33
$8,248.35
$1,265,245.70
$4,503,563.09
$16,029.75
$1,192,632.22
$4,060,443.62
$12,744,693.92
50.2
$253,913.77
$7,046,309.95
50.2
$140,384.32
$6,976,522.62
50.2
$138,993.94
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\TBL 7_VOC BACT_CTG_2014_1113.xlsx
$7,975.00
$1,196.25
$8,772.50
$8,772.50
-$1,468,215.14
$2,484,719.94
$664,195.97
$1,707,417.03
12/4/2014
Page 1 of 1
Table 8 – VOC BACT Economic Calculations for the Emergency Generator
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Parameters
Assumptions
Heat Recovery
Operating Temperature
Oxidation efficiency
Capital Cost Components
Equipment Costs:
-- Basic Equipment, e.g., Incinerator:
-- Other (auxiliary equipment, etc.):
Total Equipment Cost--base:
Total Equipment Cost --escalated:
Purchased Equipment Cost :
Total Capital Investment (1995 $):
Total Capital Investment (1998 $):
Annualized Cost Components
Direct Operating Costs:
Operating labor
Supervisory labor
Maintenance labor
Maintenance materials
Natural gas
Electricity
Catalyst replacement
Recuperative Combustion
0,35,50 or 70
Total Annualized Cost($):
Tons of VOCs Controlled (TPY):
Cost Effectiveness: ($/ton Controlled)
4,743
759
0.12
0
40
44
0.067
3.49
0.07
0.824404522
Operating hours (hours/year)
3,190
Regenerative Combustion
70% 85 or 95
1,400
99%
$177,426.51
$0.00
$177,426.51
$236,570.24
$255,495.86
$319,369.83
$387,394.56
Sub total
Indirect Operating Costs:
Overhead
Taxes, insurance, administrative
Capital recovery
Input Parameters
Waste stream flow rate (scfm)
Waste stream temperature (deg F)
Annual VOC + CO emission (tpy)
Gross heat of combustion (btu/lb, toluene)
Operating Labor Rate ($/hr)
Maintenance Labor Rate ($/hr, OLR*1.1)
Electricity Price ($/kwh)
Natural Gas Price ($/mmBtu or $/mscf)
Annual interest rate (fraction):
Means CPI (1995 to 2014)
$0.00
$0.00
$8,772.50
$8,772.50
$22,523.44
$8,587.14
$0.00
$48,655.58 Sub total
Catalytic Combustion
95% 0,35,50 or 70
1,400
99%
$763,644.76
$926,298.61
$0.00
$0.00
$2,288.00
$2,288.00
$3,108.46
$3,957.43
$0.00
$11,641.89 Sub total
0%
600
99%
$155,255.27
$0.00
$155,255.27
$180,414.55
$194,847.71
$243,559.64
$295,437.05
$0.00
$0.00
$8,772.50
$8,772.50
$307.08
$9,424.90
$3,302.70
$30,579.68
$10,527.00
$15,495.78
$55,156.27
$2,745.60
$37,051.94
$131,884.08
$10,527.00
$11,817.48
$41,145.39
$129,834.63
0.1188
$1,092,884.12
$183,323.52
0
$1,543,127.24
$94,069.56
0.1188
$791,831.28
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12/4/2014
Page 1 of 1
Table 9 – VOC BACT Economic Calculations for the Backup Fire Pump
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Parameters
Assumptions
Heat Recovery
Operating Temperature
Oxidation efficiency
Capital Cost Components
Equipment Costs:
-- Basic Equipment, e.g., Incinerator:
-- Other (auxiliary equipment, etc.):
Total Equipment Cost--base:
Total Equipment Cost --escalated:
Purchased Equipment Cost :
Total Capital Investment (1995 $):
Total Capital Investment (1998 $):
Annualized Cost Components
Direct Operating Costs:
Operating labor
Supervisory labor
Maintenance labor
Maintenance materials
Natural gas
Electricity
Catalyst replacement
Recuperative Combustion
0,35,50 or 70
Total Annualized Cost($):
Tons of VOCs Controlled (TPY):
Cost Effectiveness: ($/ton Controlled)
759
961
0.14
0
40
44
0.067
3.49
0.07
0.824404522
Operating hours (hours/year)
3,190
Regenerative Combustion
70% 85 or 95
1,400
99%
$112,195.63
$0.00
$112,195.63
$149,595.17
$161,562.78
$201,953.47
$244,968.91
Sub total
Indirect Operating Costs:
Overhead
Taxes, insurance, administrative
Capital recovery
Input Parameters
Waste stream flow rate (scfm)
Waste stream temperature (deg F)
Annual VOC + CO emission (tpy)
Gross heat of combustion (btu/lb, toluene)
Operating Labor Rate ($/hr)
Maintenance Labor Rate ($/hr, OLR*1.1)
Electricity Price ($/kwh)
Natural Gas Price ($/mmBtu or $/mscf)
Annual interest rate (fraction):
Means CPI (1995 to 2014)
$0.00
$0.00
$8,772.50
$8,772.50
$2,932.87
$1,600.55
$0.00
$22,078.42 Sub total
Catalytic Combustion
95% 0,35,50 or 70
1,400
99%
$658,785.24
$799,104.35
$0.00
$0.00
$2,288.00
$2,288.00
$387.56
$633.46
$0.00
$5,597.02 Sub total
0%
600
99%
$56,365.44
$0.00
$56,365.44
$65,499.52
$70,739.49
$88,424.36
$107,258.46
$0.00
$0.00
$8,772.50
$8,772.50
-$598.53
$1,756.77
$528.10
$19,231.34
$10,527.00
$9,798.76
$34,878.06
$2,745.60
$31,964.17
$113,774.48
$10,527.00
$4,290.34
$15,124.37
$77,282.23
0.1386
$557,591.88
$154,081.28
0
$1,111,697.52
$49,173.05
0.1386
$354,783.91
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\TBL 9_VOC BACT_Fire Pump_2014_1113.xlsx
12/4/2014
Page 1 of 1
Table 10 – VOC BACT Economic Calculations for Each Fuel Heater
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Parameters
Assumptions
Heat Recovery
Operating Temperature
Oxidation efficiency
Capital Cost Components
Equipment Costs:
-- Basic Equipment, e.g., Incinerator:
-- Other (auxiliary equipment, etc.):
Total Equipment Cost--base:
Total Equipment Cost --escalated:
Purchased Equipment Cost :
Total Capital Investment (1995 $):
Total Capital Investment (1998 $):
Annualized Cost Components
Direct Operating Costs:
Operating labor
Supervisory labor
Maintenance labor
Maintenance materials
Natural gas
Electricity
Catalyst replacement
Recuperative Combustion
0,35,50 or 70
Total Annualized Cost($):
Tons of VOCs Controlled (TPY):
Cost Effectiveness: ($/ton Controlled)
529
441
1.2
0
40
44
0.067
3.49
0.07
0.824404522
Operating hours (hours/year)
3,190
Regenerative Combustion
70% 85 or 95
1,400
99%
$102,607.16
$0.00
$102,607.16
$136,810.44
$147,755.28
$184,694.10
$224,033.34
Sub total
Indirect Operating Costs:
Overhead
Taxes, insurance, administrative
Capital recovery
Input Parameters
Waste stream flow rate (scfm)
Waste stream temperature (deg F)
Annual VOC + CO emission (tpy)
Gross heat of combustion (btu/lb, toluene)
Operating Labor Rate ($/hr)
Maintenance Labor Rate ($/hr, OLR*1.1)
Electricity Price ($/kwh)
Natural Gas Price ($/mmBtu or $/mscf)
Annual interest rate (fraction):
Means CPI (1995 to 2014)
$0.00
$0.00
$8,772.50
$8,772.50
$3,252.91
$709.91
$0.00
$21,507.82 Sub total
Catalytic Combustion
95% 0,35,50 or 70
1,400
99%
$652,741.23
$791,772.98
$0.00
$0.00
$2,288.00
$2,288.00
$467.11
$441.87
$0.00
$5,484.98 Sub total
0%
600
99%
$46,260.71
$0.00
$46,260.71
$53,757.30
$58,057.89
$72,572.36
$88,030.04
$0.00
$0.00
$8,772.50
$8,772.50
$745.13
$779.12
$369.38
$19,438.64
$10,527.00
$8,961.33
$31,897.31
$2,745.60
$31,670.92
$112,730.66
$10,527.00
$3,521.20
$12,430.80
$72,893.47
1.188
$61,358.14
$152,632.16
1
$128,478.25
$45,917.64
1.188
$38,651.21
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\TBL 10_VOC BACT_Fuel Heater_2014_1113.xlsx
12/4/2014
Page 1 of 2
Table 11 - Fabric Filter Economic Analysis for Each Fuel Gas Heater
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
CAPITAL COSTS
Direct Costs
Purchased Equipment Costs
Control Device
$74,288
Based on vendor estimate and adjusted for
exhaust gas flow rate from fuel heater using an
algorithm called the "Six Tenths Rule" for
estimating capital costs.
Instrumentation
Freight
Purchased Equipment Cost, PEC (B)
10% of control device cost (A)
5% of control device cost (A)
21%
$7,429
$3,714
$85,431
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
Direct Installation Costs
Foundations & supports
Handling & erection
Electrical
Piping
Insulation
Painting
Direct Installation Costs
4%
50%
8%
1%
7%
4%
74%
$3,417
$42,715
$6,834
$854
$5,980
$3,417
$63,219
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
Retrofit Cost
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
30% Site Specific
$22,286
Site Specific
$0
Buildings, as required
Total Direct Costs, DC
Indirect Costs
Engineering
Construction and field expenses
Contractor fees
Start-up
Performance test
Contingencies
Total Indirect Costs, IC
Total Capital Investment = DC + IC
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\TBL 11_Metal TAC_BACT BH (PM) Fuel Heater Cost Estimate 2014_1114.xls
EPA Cost Manual 6th Edition for Retrofit on Existing
Process
Assumed not necessary.
$170,936
10%
20%
10%
1%
1%
3%
35%
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
of purchased equip cost (B)
$8,543
$17,086
$8,543
$854
$854
$2,563
$29,901
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
$200,837
12/4/2014
Page 2 of 2
ANNUAL COSTS
Direct Annual Costs, DC
Operating Labor
Operator
Supervisor
Operating Materials
Bag replacement
Electricity for Fan, 7" pressure drop (water), 92,970 acfm
Maintenance
Labor
Materials
2.00 hr/shift, 3 shifts/day, 342 days/yr
15% of operator
965,903 KwH
1.00 hr/shift, 3 shifts/day, 342 days/yr
100% of maintenance labor
Total Direct Annual Costs, DC
Indirect Annual Costs
Overhead
Administrative Charges
Property tax
Insurance
Capital Recovery 8.72% for a 20 - year equipment life and a 6% interest rate
Total Indirect Annual Costs, IC
$61,560
$9,234
Effort required to operate the baghouse
Effort required to operate the baghouse
$19,000
EPA Air Pollution Control Cost Manual 6th Edition
$64,715
EPA Air Pollution Control Cost Manual 6th Edition
$30,780
$30,780
Effort required to maintain the baghouse
Effort required to maintain the baghouse
$151,354
60%
2%
1%
1%
8.72%
Total Annual Costs = DC + IC
Pollutant Removed (tons/yr)
Cost per Ton of PM Removed
of total labor and material costs
of Total Capital Investment
of Total Capital Investment
of Total Capital Investment
$90,812
$4,017
$0
$2,008
$17,513
$114,350
EPA Air Pollution Control Cost Manual 6th Edition
EPA Air Pollution Control Cost Manual 6th Edition
Property taxes are exempt in Michigan.
EPA Air Pollution Control Cost Manual 6th Edition
$265,704
0.02
See Note
$13,419,419
NOTE - Based on PM removal of 99%. Uncontrolled PM emissions from one fuel heater is 0.02 tpy.
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12/4/2014
Page 1 of 1
Table 12 – Structure Heights
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Structure
CTG North Unit
CTG South Unit
1
1
ID on Figure 2
Base
Air Intake
Unit#1
Base
Air Intake
Unit#2
Generator
Pumphouse
Warehouse2
Administration Building
Water Tank
2
Maximum
Structure Height
(feet)
47
70
21
25
47
70
12
14
26
25
26
24
15
38
1
Individual portions of CTGs listed separately in legend of Figure 2. The
portions of the CTGs considered as structures in the model include IDs 1, 6
and 30. Each CTG was conservatively modeled as a structure with two tier
heights: the base of the entire structure was modeled at 47 ft, while the air
intake was modeled at a height of 70 ft. Actual structure heights may be
lower.
2
The warehouse and administration building are both shown as ID #26 on
Figure 2. The warehouse (25 ft) is the west portion of the structure; the
administration building (15 ft) is the east portion of the structure.
Note: This table represents the structures for which a stack is located within
the downwash area of the structure ("5L"). Note that the blocks shown on the
diagram for the fuel gas metering and conditioning areas represent area
designations and not buildings.
Note: Structures and equipment less than 10 feet in height were considered
insignificant and not included in the assessment.
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Page 1 of 1
Table 13 – Model Input Parameters
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Source
CTG North Unit1
CTG South Unit1
Fuel Gas Heater North
Fuel Gas Heater South
Emergency Generator 2
Fire Pump
2
Model Name
NAD 83 UTM Coordinates
Base
(m)
Elevation
Easting
Northing
(feet)
Stack
Height
(feet)
Stack
Diameter
(feet)
Exhaust
Temperature
(deg F)
Exhaust
Flow Rate
(acfm)
Exit
Velocity
(fps)
NOx
CO
Emission PM10/PM2.5 Emission
Rate
Emission
Rate
(lbs/hr) Rate (lbs/hr) (lbs/hr)
CTGN
671,105
4,992,377
1,313.5
85
22
1,093
2,482,731
108.9
87.9
13.5
371.4
CTGS
FGHN
FGHS
671,107
671,199
671,199
4,992,336
4,992,301
4,992,297
1,313.5
1,313.5
1,313.5
85
16
16
22
0.83
0.83
1,093
441
441
2,482,731
900
900
108.9
27.5
27.5
87.9
0.42
0.42
13.5
0.081
0.081
371.4
0.32
0.32
EMGEN
671,093
4,992,321
1,313.5
14
1
759
10,909
231.5
0.21
0.24
2.0
FIREPUMP
671,109
4,992,286
1,313.5
16
0.67
1076
1,900
90.7
0.019
0.11
1.1
1
The maximum emission rates for either a start-up hour or a baseload hour was used in the modeling along with the hourly average exhaust flow rate. Details are provided in Table 14.
The annual average hourly emission rates from the Fire Pump and Emergency Generator (based on 100 hours/year operation) were utilized for NO2 modeling. The maximum hourly emission
rates were utilized for all other pollutants.
2
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12/4/2014
Page 1 of 1
Table 14 – Hourly Average Stack Parameters per CTG during Startup/Shutdown
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Maximum
Startup/Shutdown
NOx Emissions1
(lbs/event)
Maximum
Startup/Shutdown
Duration (mins)
NOx Baseload
Emissions
(lbs/hr/stack)
NOx Baseload
Emissions
(lbs/min/stack)
Duration of Baseload
Operation During
Startup/Shutdown
Hour (mins)
Baseload Emissions
During
Startup/Shutdown
Hour (lbs)
Total NOx Emissions
for
Startup/Shutdown2
(lbs/hr/stack)
30
8
66.76
1.11
52
57.86
87.9
Maximum
Startup/Shutdown CO
Emissions1
(lbs/event)
Maximum
Startup/Shutdown
Duration (mins)
CO Baseload
Emissions
(lbs/hr/stack)
CO Baseload
Emissions
(lbs/min/stack)
Duration of Baseload
Operation During
Startup/Shutdown
Hour (mins)
Baseload Emissions
During
Startup/Shutdown
Hour (lbs)
Total CO Emissions
for
Startup/Shutdown2
(lbs/hr/stack)
336
8
40.9
0.68
52
35.44
371.4
Duration of Baseload
Operation During
Startup/Shutdown
Hour (mins)
52
Baseload Emissions
During
Startup/Shutdown
Hour (lbs)
0.01
Total PM10/PM2.5
Emissions for
Startup/Shutdown2
(lbs/hr/stack)
5.8
Maximum
Startup/Shutdown
PM10/PM2.5
Emissions1
(lbs/event)
5.84
Maximum Startup
Exhaust Flow Rate
(acfm)3
332,830
1
Maximum
Startup/Shutdown
Duration (mins)
8
PM10/PM2.5 Baseload PM10/PM2.5 Baseload
Emissions
Emissions
(lbs/hr/stack)
(lbs/min/stack)
6.60E-03
1.10E-04
Startup Exhaust Temp Startup Exhaust Flow
(deg F)
Rate (scfm)
800
140,000
Duration of Startup
(mins)
Baseload Exhaust
Flow Rate (acfm)
Baseload Exhaust
Temp (deg F)
Baseload Exhaust
Flow Rate (scfm)
Baseload Duration
during Startup Hour
(mins)
8
2,882,883
1,138
956,150
52
Hourly Average
Exhaust Flow Rate Hourly Average Hourly Average
During Startup Hour Temperature
Exhaust Flow
(scfm)
(deg F)
Rate (acfm)
847,330
1,093
2,482,731
Both startup and shutdown emissions (per event) were considered and the higher emission rate was selected.
2
This emission rate represents the total worst-case emission rate during a startup or shutdown hour.
Manufacturer data indicated an exhaust flow rate of 175 pounds per second at the midpoint of the start-up operations. This was converted to an acfm based on an exhaust flow temperature of 800 degrees Fahrenheit. Shutdown exhaust
flow rates were assumed to be proportional to startup.
3
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12/4/2014
Page 1 of 1
Table 15 – SIL Model Results Summary
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Maximum Predicted Impacts
SIL
2011
2012
2013
Maximum
Pollutant
(µg/m3)
CO
142.1
141.6
151.0
151.0
2000
CO
71.0
81.3
82.2
98.8
500
NO2
0.9
1.1
1.1
1.2
1
NO2
37.0
37.0
7.6
PM25
0.4
0.5
0.4
0.5
0.4
0.5
0.3
PM25
3.5
3.5
1.2
PM10
0.4
0.5
0.4
0.5
0.4
0.5
1
PM10
5.4
3.8
4.0
4.3
3.7
5.4
5
Note: The impact for 1-hour NO2 represents Tier 1, where 100% of NOx is conservatively assumed to be NO2.
2009
147.8
98.8
0.9
2010
139.1
80.7
1.2
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
SIL Averaging Period
1-hr
8-hr
Annual
1-hr
Annual
24-hr
Annual
24-hr
Exceeds SIL
No
No
Yes
Yes
Yes
Yes
No
Yes
12/4/2014
Page 1 of 1
Table 16 – PSD Increment Model Results Summary
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Maximum Predicted Impacts
Increment
2009
2010
2011
2012
2013
Maximum
Pollutant
(µg/m3)
NO2
0.9
1.2
0.9
1.1
1.1
1.2
25
PM25
0.4
0.5
0.4
0.5
0.4
0.5
4
PM25
5.4
3.8
4.0
4.3
3.7
5.4
9
PM10
5.4
3.8
4.0
4.3
3.7
5.4
30
Note: The impact for 1-hour NO2 represents Tier 1, where 100% of NOx is conservatively assumed to be NO2.
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
Increment
Averaging
Period
Annual
Annual
24-hr
24-hr
Exceeds
Increment
No
No
No
No
12/4/2014
Page 1 of 1
Table 17 – NAAQS Model Results Summary
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Maximum Predicted Impacts
(µg/m3)
Pollutant
NO2
NO2
PM25
PM25
PM10
2009
2010
0.9
1.2
0.4
0.5
5.4
3.8
2011
0.9
24.3
0.4
2.3
4.0
2012
2013
Maximum
1.1
1.1
0.5
0.4
4.3
3.7
1.2
24.3
0.4
2.3
5.4
Background
Concentration
(µg/m3)
2.6
15.7
5.9
16.8
29.0
Combined
Impact
(µg/m3)
3.8
39.9
6.3
19.0
34.4
NAAQS
(µg/m3)
100
188
12
35
150
NAAQS
Averaging
Period
Annual
1-hr
Annual
24-hr
24-hr
Exceeds
NAAQS
No
No
No
No
No
Averaging Period
Annual
8TH-HIGHEST MAX DAILY 1-HR
Annual
8TH-HIGHEST 24-HR
24-hr
Note: The impact for 1-hour NO2 represents Tier 1, where 100% of NOx is conservatively assumed to be NO2.
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
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Page 1 of 1
Table 18 – Illustrative Analysis of Possible Secondary PM2.5 Impacts
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Short Term
Annual
Max. Project NO2 Impacts (1-hour, Annual)
37.0
1.2
Maximum Possible Project PM2.5 Impact from
Precursor Emissions (based on conversion to PM2.5
using Interpollutant Trading Ratios (below))
0.19
0.0061
PM2.5 24-hour and Annual Class II Significant Impact
Levels (SILs)
NAAQS
Background Concentration (provided by MDEQ)
Otsego County "room" under the NAAQS
Possible Project Impact vs Room (percent)
1.2
35
16.8
18.2
1.0%
0.3
12
5.9
6.1
0.10%
Interpollutant Trading Ratio assumption (2008 USEPA)
Tons NO2 equating to one Ton PM2.5
200
Note: See Section 6.0 of the application text for additional information.
Note: The impacts in this table are estimations and are intended for illustrative purposes
only. These estimated impacts show that contributions from secondary formation of
PM2.5 are anticipated to be very low and do not warrant quantitative impact modeling.
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
12/4/2014
Page 1 of 1
Table 19 – Unitized Model Results
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
Averaging
Period
Annual
1-HR
3-HR
8-HR
24-HR
CTG North Model CTG South Model FGH North Model FGH South Model
Results (CTGN)
Results (CTGS)
Results (FGHN)
Results (FGHS)
(ug/m3)/(lb/hr) (ug/m3)/(lb/hr) (ug/m3)/(lb/hr) (ug/m3)/(lb/hr)
0.00064
0.00068
1.01599
0.99369
0.09818
0.09923
39.12213
39.59705
0.0565
0.07377
30.24523
30.58928
0.02534
0.03915
29.08055
29.54403
0.01324
0.01614
22.71918
23.0741
Emergency
Fire Pump Model
Generator Model
Results
Results (EMGEN)
(FIREPUMP)
(ug/m3)/(lb/hr) (ug/m3)/(lb/hr)
0.99802
1.28649
43.58403
97.85197
31.1687
56.49831
23.71752
42.06824
8.93468
24.99401
Note: The impacts presented in this table represent the unitized impact from each TAC emission source modeled at 1 lb/hr.
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Page 1 of 1
Table 20 – Maximum PAI
Air Permit to Install Application
Alpine Power Plant, Elmira, Michigan
CTGN
Toxic Air Contaminant
CAS No.
Formaldehyde
50-00-0
Benzene
71-43-2
Xylene
1330-20-7
Acetaldehyde
75-07-0
Propylene Oxide
75-56-9
Acenaphthene
Phenanthrene
Fluorene
83-32-9
85-01-8
86-73-7
Naphthalene
91-20-3
2-Methyl Naphthalene
91-57-6
Ethylbenzene
100-41-4
n-Butane
106-97-8
1,3-Butadiene
106-99-0
Acrolein
107-02-8
Toluene
N-Pentane
N-Hexane
Propylene
Anthracene
Pyrene
Benzo (g,h,i) perylene
Fluoranthene
Acenaphthylene
Manganese
Molybdenum
Nickel
Arsenic
Barium
108-88-3
109-66-0
110-54-3
115-07-1
120-12-7
129-00-0
191-24-2
206-44-0
208-96-8
7439-96-5
7439-98-7
7440-02-0
7440-38-2
7440-39-3
Beryllium
7440-41-7
Cadmium
7440-43-9
Chromium
18540-29-9
Cobalt
7440-48-4
Copper
7440-50-8
Selenium
7782-49-2
Polynuclear Aromatic Compounds
Benzo (a) pyrene
50-32-8
Dibenz(a,h)anthracene
53-70-3
Benzo (a) anthracene
56-55-3
Dimethylbenz(a)anthracene
57-97-6
Indeno(1,2,3-c,d)pyrene
193-39-5
Benzo (b) fluoranthene
205-99-2
Benzo (k) fluoranthene
207-08-9
Chrysene
218-01-9
PAH TOTAL
---No Screening Level Compounds
3-Methylcholanthrene
56-49-5
Vanadium
7440-62-2
Zinc
7440-66-6
Dichlorobenzene, mixed isomers 25321-22-6
CTGS
CTG North
CTG North
Model Results
Emission Rate
(ug/m3)/
(lb/hr)
(lb/hr)
1.84E-01
0.01
1.84E-01
0.00
2.45E-02
0.00
2.45E-02
0.00
2.45E-02
0.01
1.31E-01
0.01
8.18E-02
0.01
8.18E-02
0.00
5.93E-02
0.01
5.93E-02
0.00
-0.01
-0.00
-0.01
2.66E-03
0.00
2.66E-03
0.00
2.66E-03
0.03
-0.00
6.54E-02
0.01
6.54E-02
0.00
-0.03
8.79E-04
0.01
8.79E-04
0.00
1.31E-02
0.00
1.31E-02
0.10
2.66E-01
0.01
-0.03
-0.01
-0.01
-0.01
-0.01
-0.01
-0.01
-0.01
-0.00
-0.03
-0.00
-0.00
-0.03
-0.01
-0.00
-0.00
-0.01
-0.00
-0.03
-0.03
-0.03
--------4.50E-03
-----
CTG North
PAI
2.44E-03
1.18E-04
1.57E-05
1.57E-05
3.25E-04
1.73E-03
1.08E-03
5.23E-05
7.85E-04
3.79E-05
---1.70E-06
1.70E-06
6.74E-05
-8.66E-04
4.19E-05
-1.16E-05
5.63E-07
8.37E-06
1.28E-03
3.52E-03
----------------------
0.00 --------0.00
0.00
0.00
0.00
0.00
-----
CTG South
Emission Rate
(lb/hr)
1.84E-01
1.84E-01
2.45E-02
2.45E-02
2.45E-02
1.31E-01
8.18E-02
8.18E-02
5.93E-02
5.93E-02
---2.66E-03
2.66E-03
2.66E-03
-6.54E-02
6.54E-02
-8.79E-04
8.79E-04
1.31E-02
1.31E-02
2.66E-01
------------------------------
2.88E-06
4.50E-03
-----
Z:\2009\090066NEW\WORK\Rept\PTI\DRAFT PTI\WP_PTIApp_Emission Tables_2014_1204.xlsx
FGHN
CTG South
Model Results
(ug/m3)/
(lb/hr)
0.02
0.00
0.00
0.00
0.02
0.02
0.02
0.00
0.02
0.00
0.02
0.00
0.02
0.00
0.00
0.04
0.00
0.02
0.00
0.04
0.02
0.00
0.00
0.10
0.02
0.04
0.02
0.02
0.02
0.02
0.02
0.02
0.02
0.00
0.04
0.00
0.00
0.04
0.02
0.00
0.00
0.02
0.00
0.04
0.04
0.04
CTG South
PAI
2.97E-03
1.25E-04
1.67E-05
1.67E-05
3.96E-04
2.11E-03
1.32E-03
5.56E-05
9.57E-04
4.03E-05
---1.81E-06
1.81E-06
1.04E-04
-1.06E-03
4.45E-05
-1.42E-05
5.98E-07
8.90E-06
1.30E-03
4.29E-03
----------------------
0.00 --------0.00
0.00
0.00
0.00
0.00
-----
3.06E-06
FGHS
FGH North
FGH North
Model Results
Emission Rate
(ug/m3)/
(lb/hr)
(lb/hr)
2.56E-04
22.72
2.56E-04
1.02
7.16E-06
1.02
7.16E-06
1.02
7.16E-06
22.72
-22.72
-22.72
-1.02
-22.72
-1.02
6.14E-09
22.72
5.80E-08
1.02
9.55E-09
22.72
2.08E-06
1.02
2.08E-06
1.02
2.08E-06
29.08
8.19E-08
1.02
-22.72
-1.02
7.16E-03
29.08
-22.72
-1.02
-1.02
-39.12
1.16E-05
22.72
8.87E-03
29.08
6.14E-03
22.72
-22.72
8.19E-09
22.72
1.71E-08
22.72
4.09E-09
22.72
1.02E-08
22.72
6.14E-09
22.72
1.30E-06
1.02
3.75E-06
29.08
7.16E-06
1.02
6.82E-07
1.02
1.50E-05
29.08
4.09E-08
22.72
4.09E-08
1.02
3.75E-06
1.02
4.78E-06
22.72
4.78E-06
1.02
2.87E-07
29.08
2.90E-06
29.08
8.19E-08
29.08
4.09E-09
4.09E-09
6.14E-09
5.46E-08
6.14E-09
6.14E-09
6.14E-09
6.14E-09
1.56E-08
6.14E-09
7.85E-06
9.89E-05
4.09E-06
FGH North
PAI
5.81E-03
2.60E-04
7.28E-06
7.28E-06
1.63E-04
-----1.40E-07
5.89E-08
2.17E-07
2.11E-06
2.11E-06
6.05E-05
8.32E-08
--2.08E-01
----2.64E-04
2.58E-01
1.40E-01
-1.86E-07
3.88E-07
9.30E-08
2.33E-07
1.40E-07
1.32E-06
1.09E-04
7.28E-06
6.93E-07
4.36E-04
9.30E-07
4.16E-08
3.81E-06
1.09E-04
4.85E-06
8.33E-06
8.43E-05
2.38E-06
FGH South
FGH South
Model Results
Emission Rate
(ug/m3)/
(lb/hr)
(lb/hr)
2.56E-04
23.07
2.56E-04
0.99
7.16E-06
0.99
7.16E-06
0.99
7.16E-06
23.07
-23.07
-23.07
-0.99
-23.07
-0.99
6.14E-09
23.07
5.80E-08
0.99
9.55E-09
23.07
2.08E-06
0.99
2.08E-06
0.99
2.08E-06
29.54
8.19E-08
0.99
-23.07
-0.99
7.16E-03
29.54
-23.07
-0.99
-0.99
-39.60
1.16E-05
23.07
8.87E-03
29.54
6.14E-03
23.07
-23.07
8.19E-09
23.07
1.71E-08
23.07
4.09E-09
23.07
1.02E-08
23.07
6.14E-09
23.07
1.30E-06
0.99
3.75E-06
29.54
7.16E-06
0.99
6.82E-07
0.99
1.50E-05
29.54
4.09E-08
23.07
4.09E-08
0.99
3.75E-06
0.99
4.78E-06
23.07
4.78E-06
0.99
2.87E-07
29.54
2.90E-06
29.54
8.19E-08
29.54
FGH South
PAI
5.90E-03
2.54E-04
7.12E-06
7.12E-06
1.65E-04
-----1.42E-07
5.76E-08
2.20E-07
2.07E-06
2.07E-06
6.15E-05
8.14E-08
--2.12E-01
----2.68E-04
2.62E-01
1.42E-01
-1.89E-07
3.94E-07
9.45E-08
2.36E-07
1.42E-07
1.29E-06
1.11E-04
7.12E-06
6.78E-07
4.43E-04
9.45E-07
4.07E-08
3.73E-06
1.10E-04
4.75E-06
8.47E-06
8.57E-05
2.42E-06
Emergency
Generator
Emission Rate
(lb/hr)
1.06E-03
1.06E-03
1.04E-02
1.04E-02
1.04E-02
2.59E-03
3.39E-04
3.39E-04
--6.29E-05
5.48E-04
1.72E-04
1.75E-03
1.75E-03
1.75E-03
------1.06E-04
1.06E-04
3.78E-03
--3.75E-02
1.65E-05
4.99E-05
7.47E-06
5.42E-05
1.24E-04
--------------
1.02
4.16E-09
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
1.58E-08
4.09E-09
4.09E-09
6.14E-09
5.46E-08
6.14E-09
6.14E-09
6.14E-09
6.14E-09
1.56E-08
0.99
4.07E-09
0.00E+00
0.00E+00
0.00E+00 -0.00E+00
0.00E+00
0.00E+00
0.00E+00
1.55E-08
1.02
1.02
1.02
1.02
6.24E-09
7.97E-06
1.01E-04
4.16E-06
6.14E-09
7.85E-06
9.89E-05
4.09E-06
0.99
0.99
0.99
0.99
6.10E-09
7.80E-06
9.83E-05
4.07E-06
1.02
0.99
-----
3.45E-06
4.65E-06
8.36E-06
EMGEN
Emergency
Generator
Model Results
(ug/m3)/
(lb/hr)
8.93
1.00
1.00
1.00
8.93
8.93
8.93
1.00
8.93
1.00
8.93
1.00
8.93
1.00
1.00
23.72
1.00
8.93
1.00
23.72
8.93
1.00
1.00
43.58
8.93
23.72
8.93
8.93
8.93
8.93
8.93
8.93
8.93
1.00
23.72
1.00
1.00
23.72
8.93
1.00
1.00
8.93
1.00
23.72
23.72
23.72
FIREPUMP
Emergency
Generator
PAI
9.47E-03
1.06E-03
1.04E-02
1.04E-02
9.32E-02
2.32E-02
3.03E-03
3.38E-04
--5.62E-04
5.47E-04
1.54E-03
1.74E-03
1.74E-03
4.14E-02
------1.06E-04
4.62E-03
3.37E-02
--3.35E-01
1.48E-04
4.45E-04
6.68E-05
4.84E-04
1.11E-03
-------------3.45E-06
0.00E+00
0.00E+00
1.00
-5.56E-06
1.49E-05
2.93E-06
2.06E-05
1.10E-05
4.35E-07
1.35E-06
3.89E-06
-----
--8.21E-05
8.75E-05
1.69E-03
2.52E-04
2.52E-04
8.25E-03
----2.26E-03
1.16E-04
2.75E-04
2.09E-02
2.36E-02
--1.49E-01
1.08E-04
2.76E-04
2.83E-05
4.40E-04
2.92E-04
-------------5.59E-07
0.00E+00
0.00E+00
--
8.67E-07
2.29E-07
3.58E-07
8.16E-07
2.29E-06
-----
Fire Pump
PAI
6.82E-02
3.51E-03
2.78E-03
2.78E-03
5.39E-02
1.65E-02
4.43E-02
2.28E-03
1.29
-0.00E+00
0.00E+00
0.00E+00
0.00E+00
1.10E-05
1.00
1.00
1.00
1.00
1.00
Fire Pump
Fire Pump
Model Results
Emission Rate
(ug/m3)/
(lb/hr)
(lb/hr)
2.73E-03
24.99
2.73E-03
1.29
2.16E-03
1.29
2.16E-03
1.29
2.16E-03
24.99
6.59E-04
24.99
1.77E-03
24.99
1.77E-03
1.29
-24.99
-1.29
3.28E-06
24.99
6.80E-05
1.29
6.75E-05
24.99
1.96E-04
1.29
1.96E-04
1.29
1.96E-04
42.07
-1.29
-24.99
-1.29
-42.07
9.04E-05
24.99
9.04E-05
1.29
2.14E-04
1.29
2.14E-04
97.85
9.46E-04
24.99
-42.07
-24.99
5.97E-03
24.99
4.32E-06
24.99
1.11E-05
24.99
1.13E-06
24.99
1.76E-05
24.99
1.17E-05
24.99
-1.29
-42.07
-1.29
-1.29
-42.07
-24.99
-1.29
-1.29
-24.99
-1.29
-42.07
-42.07
-42.07
0.00E+00
0.00E+00
0.00E+00
0.00E+00
2.94E-06
1.29
1.29
1.29
1.29
1.29
-----
PAI
Averaging
Period
Screening
3
(µg/m )
9.48E-02
5.33E-03
1.32E-02
1.32E-02
1.48E-01
4.35E-02
4.98E-02
2.73E-03
1.74E-03
7.83E-05
6.44E-04
6.35E-04
3.23E-03
2.00E-03
2.00E-03
5.00E-02
1.65E-07
1.92E-03
8.64E-05
4.20E-01
2.29E-03
1.17E-04
3.98E-04
2.81E-02
6.57E-02
5.20E-01
2.81E-01
4.84E-01
2.56E-04
7.23E-04
9.52E-05
9.24E-04
1.40E-03
2.61E-06
2.20E-04
1.44E-05
1.37E-06
8.80E-04
1.87E-06
8.23E-08
7.54E-06
2.19E-04
9.60E-06
1.68E-05
1.70E-04
4.80E-06
4.01E-06
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
0.00E+00
1.99E-05
1.23E-08
1.58E-05
1.99E-04
8.23E-06
3
Level (µg/m )
30
0.08
30
0.1
30
100
9
0.5
30
0.3
210
0.1
140
3
0.08
520
10
1000
3
23800
2
0.03
0.16
5
5000
17700
700
1500
1000
100
12
140
35
0.3
30
0.0042
0.0002
5
0.02
0.0004
0.0006
0.008
0.000083
0.2
2
2
3
(µg/m )
Basis
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
ITSL
IRSL
IRSL
ITSL
ITSL
IRSL
IRSL
ITSL
IRSL
ITSL
ITSL
ITSL
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
PASS
0.0005 annual
IRSL
0.8%
PASS
0.0005 annual
IRSL
4.0%
PASS
TRACE*
TRACE*
TRACE*
TRACE*
0.0%
0.0%
0.2%
0.0%
PASS
PASS
PASS
PASS
annual
annual
annual
annual
ITSL
IRSL
ITSL
IRSL
2nd ITSL
ITSL
ITSL
IRSL
ITSL
IRSL
ITSL
ITSL
ITSL
ITSL
IRSL
2nd ITSL
ITSL
ITSL
IRSL
ITSL
ITSL
IRSL
ITSL
Pass/Fail
0.3%
6.7%
0.0%
13.2%
0.5%
0.0%
0.6%
0.5%
0.0%
0.0%
0.0%
0.6%
0.0%
0.1%
2.5%
0.0%
0.0%
0.0%
0.0%
0.0%
0.1%
0.4%
0.2%
0.6%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.0%
0.3%
0.7%
0.0%
0.0%
0.0%
1.3%
2.7%
11.6%
0.0%
0.0%
0.0%
0.1
0.1
0.1
0.1
24 hr
annual
annual
annual
24 hr
24 hr
24 hr
annual
24 hr
annual
24 hr
annual
24 hr
annual
annual
8 hr
annual
24 hr
annual
8 hr
24 hr
annual
annual
1 hr
24 hr
8 hr
24 hr
24 hr
24 hr
24 hr
24 hr
24 hr
24 hr
annual
8 hr
annual
annual
8 hr
24 hr
annual
annual
24 hr
annual
8 hr
8 hr
8 hr
Percent of
Screening
Level
12/4/2014
Appendix 1
CD Containing
Modeling-Related File
Appendix 2
MDEQ Data
From:
To:
Cc:
Subject:
Date:
Attachments:
Haywood, Jim (DEQ)
Dean, Amy L.
Kuieck, Susan; Caudell, John F.
RE: Data Request - Gaylord Area
Thursday, November 13, 2014 1:55:28 PM
Dean_Otsego_Background.xlsx
Houghton_Lake-O3-2009.dat
Houghton_Lake-O3-2010.dat
Houghton_Lake-O3-2011.dat
Houghton_Lake-O3-2012.dat
Houghton_Lake-O3-2013.dat
I did a search of all off-site sources which could significantly contribute to your proposed project. All
sources within 10km were checked, using AERSCREEN, to see if any had a Significant Concentration
Gradient (SCG) at your location. No facility had a SCG, therefore, there are no off-site emissions
which need to be included in your NAAQS or PSD Increment analyses.
Attached is a spreadsheet of representation background concentrations.
Also attached are the annual O3 files from 2009-2013.
Jim
From: Dean, Amy L. [mailto:[email protected]]
Sent: Thursday, November 06, 2014 11:46 AM
To: Haywood, Jim (DEQ)
Cc: Kuieck, Susan; Caudell, John F.
Subject: Data Request - Gaylord Area
Hi Jim,
We are going to be working on a project in the Gaylord area. Can you please provide data for UTM
coordinates 671165.64 m E, 4992273.72 m N, Zone 16? We will need background and additional
source data for NO2, PM10, PM2.5, SO2, and CO.
We are planning to use the 1-minute Gaylord met data from the MDEQ website, but anticipate that
we may need a version processed with the ADJ_U* option? Can you please provide that?
Also, can you please provide ozone data?
Thanks! Let me know if you have any questions.
Amy
Year
2011
2012
2013
NO2
Houghton Lake
1-hr
Annual
98th pctl
Avg
8.0
1.0
9.0
1.4
8.0
1.4
8.3
1.4
ppb
ppb
PM-2.5
Houghton Lake
24-hr
Annual
98th pctl
Avg
17.8
6.2
15.4
5.9
17.1
5.5
16.8
5.9
ug/m3
ug/m3
PM-10
Grand Rapids
24-hr
Annual
Max
Avg
41.0
13.6
29.0
12.8
28.0
12.6
13.6
ppb
1-hr
99th pctl
8.4
9.7
10.2
9.4
ppb
SO2
Grand Rapids
3-hr
24-hr
Max
Max
8.0
4.5
7.1
4.2
8.6
2.9
8.6
4.5
ppb
ppb
Annual
Avg
0.7
0.8
0.7
0.8
ppb
CO
Grand Rapids
1-hr
8-hr
Max
Max
6.3
1.4
2.4
1.5
2.0
1.3
6.3
1.5
ppm
ppm
NAAQS MODELING BACKGROUND SUMMARY
NO2
15.7
ug/m3
PM-2.5
2.6
ug/m3
16.8
ug/m3
5.9
ug/m3
PM-10
29.0
ug/m3
(3-yr 4th High)
SO2
13.6
ug/m3
24.7
ug/m3
22.5
ug/m3
CO
11.8
ug/m3
2.1
ug/m3
7,308.0
ug/m3
1,740.0
ug/m3