AQ_GEN_PLNG_20220404_SIP_RH-SIP_AppF2e

Appendix F-2e

VISTAS Consultation with PA Bureau of Air Quality

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VISTAS Consultation with PA Bureau of Air Quality
Genon NE Mgmt Co/Keystone Sta (42005-3866111)

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Correspondence Record
Date From To Description
June 22,
2020
VISTAS PA Bureau of
Air Quality
Request for Regional Haze Reasonable
Progress Analyses for Pennsylvania
Sources Impacting VISTAS Class I Areas
January
11, 2021
AECOM/ PA
Bureau of Air
Quality
VISTAS Four Factor Analysis Regional Haze Rule Second
Decadal Review - Keystone Generating Station
Units 1 and 2, Rev. 1
February
11, 2021
AECOM/ PA
Bureau of Air
Quality
VISTAS Four Factor Analysis Regional Haze Rule Second
Decadal Review - Keystone Generating Station
Units 1 and 2, Rev. 2

- 1 -

Visibility Improvement State and Tribal Association of the Southeast

June 22, 2020

Virendra Trivedi, Acting Director
Pennsylvania Bureau of Air Quality
PO Box 8468
Harrisburg, Pennsylvania 17105-8468

RE: Request for Regional Haze Reasonable
Progress Analyses for Pennsylvania
Sources Impacting VISTAS Class I Areas

Dear Mr. Trivedi:

The Regional Haze Regulation 40 CFR § 51.308(d) requires each state to “address regional haze
in each mandatory Class I Federal area located within the State and in each mandatory Class I
Federal area located outside the State which may be affected by emissions from within the
State.” 40 CFR § 51.308(f) requires states to submit a regional haze implementation plan
revision by July 31, 2021. As part of the plan revision, states must establish a reasonable
progress goal that provides for reasonable progress towards achieving natural visibility
conditions for each mandatory Class I Federal area (Class I area) within their state . 40 CFR §
51.308(d)(1) requires that reasonable progress goals “must provide for an improvement in
visibility for the most impaired days over the period of the implementation plan and ensure no
degradation in visibility for the least impaired days over the same period.”

In establishing reasonable progress goals, states must consider the four factors specified in §
169A of the Federal Clean Air Act and in 40 CFR § 51.308(f)(2)(i). The four factors are: 1) the
cost of compliance, 2) the time necessary for compliance, 3) the energy and non-air quality
environmental impacts of compliance, and 4) the remaining useful life of any potentially
affected sources. Consideration of these four factors is frequently referenced as the “four-
factor analysis.”

To assist its member states, the Visibility Improvement State and Tribal Association of the
Southeast1 (VISTAS) and its contractors conducted technical analyses to help states identify

1 The VISTAS states are Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina,
Tennessee, Virginia, and West Virginia.

- 2 -

sources that significantly impact visibility impairment for Class I areas within and outside of the
VISTAS region. VISTAS initially used an Area of Influence (AoI) analysis to identify the areas and
sources most likely contributing to poor visibility in Class I areas. This AoI analysis involved
running the HYSPLIT Trajectory Model to determine the origin of the air parcels affecting
visibility within each Class I area. This information was then spatially combined with emissions
data to determine the pollutants, sectors, and individual sources that are most likely
contributing to the visibility impairment at each Class I area. This information indicated that the
pollutants and sector with the largest impact on visibility impairment were sulfur dioxide (SO2)
and nitrogen oxides (NOx) from point sources. Next, VISTAS states used the results of the AoI
analysis to identify sources to “tag” for PM (Particulate Matter) Source Apportionment
Technology (PSAT) modeling. PSAT modeling uses “reactive tracers” to apportion particulate
matter among different sources, source categories, and regions. PSAT was implemented with
the Comprehensive Air Quality Model with extensions photochemical model (CAMx Model) to
determine visibility impairment due to individual sources. PSAT results showed that in 2028 the
majority of visibility impairment at VISTAS Class I areas will continue to be from point source
SO2 and NOx emissions. Using the PSAT data, VISTAS states identified, for reasonable progress
analysis, sources shown to have a sulfate or nitrate impact on one or more Class I areas greater
than or equal to 1.00 percent of the total sulfate plus nitrate point source visibility impairment
on the 20 percent most impaired days for each Class I area. This analysis has identified the
following sources in Pennsylvania that meet this criterion:

• NRG Wholesale Gen/Seward Gen Sta (42063-3005111)
• Homer City Gen LP/Center TWP (42063-3005211)
• Genon NE Mgmt Co/Keystone Sta (42005-3866111)

Information regarding projected 2028 SO2 and NOx emissions and visibility impacts on VISTAS
Class I areas is shown in the tables attached to this letter (Attachment 1).

As required in 40 CFR § 51.308(d)(1)(i)(A), VISTAS, on behalf of Georgia, North Caroli na, South
Carolina, Tennessee, Virginia, and West Virginia, requests that Pennsylvania conduct, or require
that the sources in question initiate, and share when completed, the results of a reasonable
progress analysis for each noted source with VISTAS. This will be helpful to the VISTAS states as
they begin the formal Federal Land Manager consultation process for their individual draft
Regional Haze Plans in early 2021. So that the VISTAS states can include the results of your
state's reasonable progress analyses in developing the long-term strategies for Class I areas in
their states, we request that you submit this information to VISTAS no later than October 30,
2020. If any reasonable progress analyses cannot be completed by this date, please provide, no
later than this date, notice of an attainable date for completion of the analysis. If you
determine that a four-factor analysis is not warranted for one or more of the identified sources,
please provide the rationale for this determination by the requested date.

In developing projected 2028 emissions for these sources, VISTAS utilized ERTAC_16.0
emissions projections and sought additional input from Pennsylvania in February 2020. Please

- 3 -

review these projections to verify that they are reasonable. Should you be aware of significantly
different emission projections for 2028 for any of the sources or pollutants, please provide
revised estimates within thirty (30) days of the date of this letter. The applicable VISTAS states
will review any revised emission estimates, determine if reasonable progress analyses are not
needed to meet their regional haze obligations, and notify you accordingly.

Updated 2028 emission projections, if necessary, the results of your state’s reasonable pr ogress
analyses for the requested sources, and any necessary ongoing communications should be sent
via email to [e-mail].

Should you have any questions concerning this request, please contact me through September
30, 2020, at 404-361-4000 or [e-mail].

Sincerely,

John E. Hornback
Executive Director
Metro 4/SESARM/VISTAS

Attachment

Copies: Karen Hays, Georgia Air Protection Branch
Mike Abraczinskas, North Carolina Division of Air Quality
Rhonda Thompson, South Carolina Bureau of Air Quality
Michelle Walker Owenby, Tennessee Division of Air Pollution Control
Mike Dowd, Virginia Air and Renewable Energy Division
Laura Crowder, West Virginia Division of Air Quality
Marc Cone, Mid-Atlantic Regional Air Management Association
Paul Miller, Northeast States for Coordinated Air Use Management

- 4 -

Attachment 1: Projected 2028 SO2 and NOx Emissions and VISTAS Class I Area Impacts

Table 1. NRG Wholesale Gen/Seward Gen Sta (42063-3005111)
Modeled SO2 = 6,813.9 tpy, Modeled NOx = 1,632.9 tpy

Table 2. Homer City Gen LP/Center TWP (42063-3005211)
Modeled SO2 = 9,274.9 tpy, Modeled NOx = 4,962.3 tpy

Table 3. Genon NE Mgmt Co/Keystone Sta (42005-3866111)
Modeled SO2 = 21,066.4 tpy, Modeled NOx = 5,086.3 tpy

Impacted VISTAS Class I Area
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.172 0.003 15.375 1.12% 0.02%

Impacted VISTAS Class I Areas
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.274 0.010 15.375 1.78% 0.06%
Swanquarter Wilderness Area 0.151 0.008 10.894 1.38% 0.07%

Impacted VISTAS Class I Areas
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.740 0.009 15.375 4.81% 0.06%
Swanquarter Wilderness Area 0.375 0.009 10.894 3.44% 0.09%
Cape Romain Wilderness 0.320 0.002 14.028 2.28% 0.01%
Linville Gorge Wilderness Area 0.235 0.000 12.884 1.82% 0.00%
James River Face Wilderness 0.217 0.005 14.404 1.51% 0.04%
Dolly Sods Wilderness 0.246 0.001 19.349 1.27% 0.00%
Shining Rock Wilderness Area 0.151 0.000 12.313 1.23% 0.00%
Great Smoky Mountains NP 0.166 0.001 13.916 1.19% 0.01%
Wolf Island Wilderness 0.149 0.002 12.957 1.15% 0.01%
Joyce Kilmer-Slickrock Wilderness 0.154 0.000 13.694 1.12% 0.00%
Cohutta Wilderness Area 0.137 0.002 13.229 1.04% 0.01%
Okefenokee Wilderness Area 0.137 0.002 13.400 1.02% 0.01%
Otter Creek Wilderness 0.190 0.001 19.077 1.00% 0.00%
Four Factor Analysis
Regional Haze Rule
Second Decadal Review
Keystone Generating Station
Units 1 and 2
AECOM Project number: 60634468-1
Original Submittal: July 29, 2020
Revised (Rev.01): January 11, 2021
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
i
Quality information
Prepared by Prepared by Checked by Approved by
Robert R. Hall
Senior Air Quality
Engineer
Robert J. Paine
Associate Vice President
Seemantini Deshpande
Project Manager
Seemantini Deshpande
Project Manager
Prepared for:
Keystone Generating Station
313 Keystone Dr, Shelocta, PA 15774
Prepared by:
Robert R. Hall
Senior Air Quality Engineer
T: 978-905-2230
E:[e-mail]
AECOM
250 Apollo Drive
Chelmsford, MA 01824
aecom.com
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
ii
Table of Contents
1. Introduction ............................................................................................................. 1
2. Source Description.................................................................................................. 2
3. First Regional Haze Planning Period Reasonable Progress Determination............ 3
4. Source Emissions ................................................................................................... 3
5. Existing Emission Controls ..................................................................................... 6
5.1 SO2 Control Measures .................................................................................... 6
5.2 NOx Control Measures ................................................................................... 6
6. Emissions Control Options ...................................................................................... 6
6.1 Identification of Potentially Available SO2 Emissions Reduction Options ....... 6
6.1.1 Costs of Compliance (Factor 1) ...................................................................... 7
6.1.2 Time Necessary for Compliance (Factor 2) .................................................... 8
6.1.3 Energy and Non-Air Quality Environmental Impacts (Factor 3) ...................... 9
6.1.4 Remaining Useful Life (Factor 4) .................................................................... 9
6.2 Identification of Potentially Available NOX Emissions Reduction Options ....... 9
6.2.1 Costs of Compliance (Factor 1) .................................................................... 10
6.2.2 Time Necessary for Compliance (Factor 2) .................................................. 14
6.2.3 Energy and Non-Air Quality Environmental Impacts (Factor 3) .................... 14
6.2.4 Remaining Useful Life (Factor 4) .................................................................. 14
7. Additional 5th Factor Consideration - Visibility Impacts ......................................... 14
7.1 EPA Guidance Regarding Considerations of Visibility Impacts ..................... 15
7.2 Class I Areas Near Keystone Generating Station ......................................... 16
7.3 MANE-VU CALPUFF Modeling .................................................................... 18
7.4 VISTAS CAMx Modeling Analysis ................................................................ 18
7.5 Visibility Impact of Keystone Station’s Units 1 and 2 SO2 and NOx
Emissions ..................................................................................................... 20
8. Conclusion ............................................................................................................ 22
List of Tables
Table 4-1 Keystone Generating Station – Unit 1 and Unit 2 Actual Annual Operation
and Emissions .............................................................................................. 5
Table 6-1 Annual SO2 Emissions from Keystone Station Units 1 and 2 ........................ 8
Table 6-2 NOx Control Technologies ........................................................................... 9
Table 6-3 Low-NOx Burner Replacement/Tuning Capital Cost Estimate – Per Boiler 11
Table 6-4 Low-NOx Burner Replacement/Tuning Annual Cost Estimate ................... 12
Table 6-5 Low-NOx Burner Replacement/Tuning Cost-Effectiveness ($/ton NOx
Removed) ................................................................................................... 13
Table 7-1 Haze Impact from Keystone Generating Station’s Total 2019 Emissions of
SO2 and NOx at Class I Areas Within 400 km ............................................ 21
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
iii
List of Figures
Figure 4-1 Johnstown Airport 5-Year (2009 -2013) Wind Rose ..................................... 4
Figure 7-1 Class I Areas in the Vicinity of Keystone Generating Station ..................... 17
Figure 7-2 Visibility Trends at Shenandoah National Park ........................................... 20
List of Appendices
Appendix A PA DEP Four-Factor Analysis Request Letter
Appendix B Summary of VISTAS Visibility Modeling Results
Appendix C PA DEP Request for a Case-by-Case RACT Analysis
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
1
1. Introduction
The Pennsylvania Department of Environmental Protection (PA DEP) Bureau of Air Quality
notified the Keystone Generating Station (Keystone Station) that PA DEP is developing a State
Implementation Plan (SIP) for the Second Decadal Review period of the federal Regional Haze
Rule (42 USC §7491 – Visibility Protection for Federal Class I Areas). The Regional Haze Rule
(RHR) requires state and federal agencies to work to improve visibility in U.S. National Parks
and Wilderness Areas throughout the country (see 40 CFR §§ 81.401 through 81.437) with the
ultimate goal of achieving “natural background” visibility in these Class I areas by the year 2064.
Every ten years, agencies are required to evaluate their plans and consider whether additional
emission reductions at certain major sources are warranted to continue realizing “reasonable
progress” in visibility improvement. PA DEP identified the Keystone Station Units 1 and 2 as
sources requiring an analysis for potential reductions of sulfur dioxide (SO2) emissions and
nitrogen oxides (NOx) emissions. Primary PM10 is another pollutant that may contribute to
visibility impairment (although to a much lesser extent relative to SO2 and NOx), but emissions
of this pollutant are not required to be evaluated for this analysis – see Section 3 of this report
for details.
As outlined in the RHR, this analysis, referred to as a “Four-Factor Analysis”, needs to first
identify all technically feasible control technologies for additional SO2 and NOx emissions
control. Each feasible control option then needs to be evaluated relative to the following four
statutory factors:
1) Cost of implementing emission controls;
2) Time necessary to install such controls;
3) Energy and non-air quality impacts associated with installing controls; and
4) The remaining useful life of the facility.
In May 2020, the PA DEP requested Keystone Station to perform the subject analysis for Units
1 and 2, and submit their findings to the PA DEP. Appendix A provides a copy of the PA DEP’s
letter request. Keystone Station contracted AECOM to assist with the analysis. Although not
required to be included in the analysis, states have the option to consider a fifth factor –
evaluation of visibility benefits - in addition to the four statutory factors when making their
reasonable progress determinations. This analysis includes the fifth factor (see Section 7) to
provide additional information to PA DEP to assist in their consideration for the need of
additional controls for visibility improvement.
The initial analysis was submitted to the PA DEP in July 2020. This revised (Rev. 01) analysis
was prepared in response to comments from the PA DEP and other reviewers that were
received by Keystone Station (and forwarded to AECOM) on August 18, 2020.
This report provides a description of the affected source (Section 2), a summary of the actions
taken during First Decadal Review period of the RHR (Section 3), a summary of actual baseline
emissions (Section 4), a discussion of existing emission controls (Section 5), and identification
of potentially feasible control options and an assessment of each of the four statutory factors for
these options (Section 6). Additionally, Section 7 provides a “fifth factor” analysis of the
prospective visibility impacts to Class I areas of potential SO2 controls for PA DEP’s
consideration. Finally, Section 8 presents a summary of this report’s findings.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
2
2. Source Description
Keystone Generating Station, which is located at 313 Keystone Dr, Shelocta, PA 15774, is
licensed to operate under environmental permits issued to Keystone-Conemaugh Projects, LLC.
The Station operates under PA DEP’s Title V Operating Permit No. 03-00027 (Expiration date –
March 31, 2025).
Keystone Station Unit 1 and Unit 2 are each identical bituminous coal-fired boilers with a steam
turbine-driven electric generator that provide electricity to the regional electric grid.
Manufactured by Combustion Engineering, Units 1 and 2 were commissioned in 1967 and 1968,
respectively, and fire bituminous coal mined in Pennsylvania. The nominal maximum operating
conditions for each boiler and generator are heat input of 8,717 MMBtu/hr and gross electrical
output of 910 MW, respectively. No. 2 fuel oil is used as the boiler start-up fuel and for
supplemental firing as needed.
Each boiler is equipped with the following emissions control devices: Low-NOx burners,
selective catalytic reduction (SCR, installed in 2003) for NOx control, electrostatic precipitator
(ESP) for particulate matter (PM) control, hydrated lime (sorbent) injection system for sulfuric
acid mist (H2SO4) control, and a wet flue gas desulfurization (FGD, installed in 2009) system for
SO2 and additional PM control. These control devices also provide co-beneficial emissions
control for a suite of other pollutants such as mercury and acid gas emissions. Process gases
at each unit are routed through the emission control systems using induced draft (ID) booster
fans. Process gases from each FGD system are discharged to the atmosphere through a single
exhaust flue contained in one concrete stack (designated as S12 in the Title V permit).
Unit 1 and Unit 2 are subject to, and compliant with, the Cross-State Air Pollution Rule (CSAPR
or Transport Rule) and the related requirements promulgated under 25 Pa. Code Chapter 139
and 40 CFR 75 - Continuous Emissions Monitoring. Keystone Station operates and maintains
(i) certified continuous emission monitoring systems (CEMs) for NOx, SO2 and carbon dioxide
(CO2) and (ii) a certified exhaust gas stream flow monitor at the exhaust duct. Certified
emissions, heat input and gross electrical load data are submitted quarterly to the PA DEP and
U.S. Environmental Protection Agency (EPA).
Units 1 and 2 are also subject to, and compliant with, the following EPA and PA DEP
regulations:
Ø 2010 SO2 National Ambient Air Quality Standard (NAAQS) – a compliance modeling
study completed by AECOM for the Indiana, PA designated non-attainment area
demonstrated that current SO2 emission impacts from the Keystone Station’s units are
compliant with the NAAQS
Ø PA DEP RACT II Rule – Units 1 and 2 demonstrate compliance with the presumptive
NOx RACT limits for coal-fired electric generating boilers equipped with SCR
Ø Coal- and Oil-Fired Electric Utility Steam Generating Units (EGU) National Emission
Standards for Hazardous Air Pollutants (NESHAP) Rule, also known as the Mercury Air
Toxics Standards (MATS) Rule. Under the MATS Rule, Units 1 and 2:
· Have attained Low-Emitting EGU (LEE) status for non-mercury metals using
filterable PM as the surrogate pollutant;
· Have attained LEE status for acid gas (HCl) standard; and,
· Monitor mercury emissions using a sorbent trap sampler (nominal weekly
sampling period).
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
3
In summary, contemporary emission control devices are already installed, operated and
maintained at Units 1 and 2, and these devices provide for effective control of criteria and
hazardous air pollutants.
3. First Regional Haze Planning Period Reasonable Progress
Determination
During the First Decadal Review period of the RHR (i.e., 40 CFR 51 Subparts 308 and 309),
Units 1 and 2 were subject to Best Available Retrofit Technology (BART) review because they
had been placed into service within the rule-specified BART applicability window (between
August 7, 1962 and August 7, 1977) and satisfied the other eligibility criteria. BART
requirements for SO2 and NOx emissions were satisfied by compliance with U.S. EPA’s Clean
Air Interstate Rule (CAIR), now superseded by the more stringent CSAPR, per U.S. EPA who
ruled that CAIR achieved greater reasonable progress than BART for SO2 and NOx emissions
at BART-eligible electric generating units located in CAIR-affected states. A BART analysis
(dispersion modeling study) for primary PM10 emissions was completed by AECOM and
submitted to the PA DEP in January 2007, and that study concluded that visibility impacts from
primary PM10 emissions from the Units 1 and 2 were imperceptible at the nearest Class I areas
(Shenandoah National Park, Dolly Sods and Otter Creek Wilderness Areas). The Keystone
Station has since further reduced its actual SO2 and NOx emissions, as described in the next
section.
4. Source Emissions
Actual emissions for Units 1 and 2 are summarized in Table 4-1. At the Keystone Station,
actual emissions of SO2 have been reduced between 2006-2008 (indicative of the baseline
emissions prior to implementation of the regional haze program) and 2019 by more than 89%
and emissions of NOx have been reduced by 48% over the same period. The emission
reductions are indicative of the reductions achieved since commencement of the regional haze
program and are attributable to installation of a wet flue gas desulfurization (FGD) system in
2009, the use of SCR and compliance with PA DEP’s RACT II rule, compliance with other
environmental programs such as CSAPR and the SO2 NAAQS implementation, and to a lesser
extent, the reduced level of utilization of these units.
AECOM understands that the PA DEP requested NOx and SO2 four-factor analyses for Units 1
and 2 based, in part, on a metric used by the National Park Service (NPS) for evaluating
potential impacts to visibility at the nearby Class I Areas (Dolly Sods and Otter Creek
Wilderness and Shenandoah National Park). The metric is equal to the source annual
emissions (tons) divided by distance between the source and the Class I Area (km). The NPS
selected a ratio of 1.0 or greater as the threshold for identifying sources that could affect
visibility conditions in the Class I Areas. While the metric may be appropriate as a screening
tool, it does not consider the direction of the prevailing winds from the source to the Class I
Areas (Figure 7-1 presents the location of the Keystone Generating Station in relation to nearby
Class I Areas). For Keystone Generating Station, wind direction data were generated using five
years (2009 - 2013) of wind speed / wind direction data at the Johnstown, PA airport. As
depicted in the resultant wind rose presented in Figure 4-1, winds from the north and north-
northwest (i.e., from the Keystone Generating Station toward the nearby Class I areas to the
south) are very infrequent, which suggests that emissions from Units 1 and 2 rarely impact
visibility conditions in those Class I areas.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
4
Figure 4-1 Johnstown Airport 5-Year (2009 -2013) Wind Rose
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
5
Table 4-1 Keystone Generating Station – Unit 1 and Unit 2 Actual Annual Operation and Emissions
Time
Period Unit
Annual
Operating
Hours(a)
Power
Output (a)
Capacity
Factor
based
on MW (b)
Annual
Fuel Use (a) SO2 Emissions (a) NOx Emissions (a)
NOx
Emissions
when flue
gas
temperature
at SCR inlet
≥ 600°F (c)
(hr/yr)(MW)%(MMBtu/yr) (ton/yr) (lb/MMBtu)(ton/yr) (lb/MMBtu)(lb/MMBtu)
2006
through
2008
1 8,101 6,993,291 88%62,799,882 89,735 2.86 7,137 0.227 Not
applicable
2 8,023 6,823,606 86%60,103,001 85,408 2.84 6,466 0.215 Not
applicable
Average 8,062 6,908,448 87%61,451,441 87,571 2.85 6,801 0.221 Not
applicable
Total 175,143 --13,603 ----
2019
1 8,185 6,498,402 82%61,842,784 11,868 0.384 3,937 0.127 0.104
2 6,884 5,377,298 67%50,498,750 7,939 0.314 3,203 0.127 0.103
Average 7,534 5,937,850 74%56,170,767 9,903 0.353 3,570 0.127 0.104
Total 19,806 --7,140 ----
Emission Reduction 89%--48%----
(a) USEPA Air Markets Program Data (https://ampd.epa.gov.ampd/).
(b) Rated capacity for each unit is 910 MW, gross.
(c) Per PA DEP RACT II Rule, presumptive NOx emission limits for a coal-fired EGU boiler with SCR is 0.12 lb/MMBtu when flue gas temperature at
SCR inlet ≥ 600°F, 0.35 lb/MMBtu when flue gas temperature at SCR inlet is < 600°F (rolling 30-boiler operating day averaging period)1
1 25 Pa. Code §129.97(g)(1)(viii) and 25 Pa. Code §§129.97(g)(1)(vi)(B)
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
6
5. Existing Emission Controls
EPA’s regional haze guidance2 includes several criteria that, if applicable, would indicate that a
source already has effective controls in place as result of a previous regional haze decision or
other Clean Air Act (CAA) requirements and as such, it may be reasonable for the state to not
select that source for further analysis.3 In addition, EPA guidance for effectively controlled
sources suggests that a full four-factor analysis would likely result in a conclusion that no
additional controls are necessary.
5.1 SO2 Control Measures
In addition to the certified CEMs noted in Section 2, Keystone Station operates and maintains
diagnostic SO2 and CO2 CEMs at the inlets to the FGD absorbers. Data from these diagnostic
CEMs are not reported to the agencies, but are rather used by Station Operations to gauge
performance of the FGD and other systems. The inlet diagnostic CEMS are calibrated
periodically, so the data are reliable. Using 2019 hourly-averaged data from the diagnostic
(inlet) and certified (i.e., actual stack emissions) CEMs yields SO2 control efficiencies of 90.7%
and 92.7% for Units 1 and 2, respectively.
5.2 NOx Control Measures
The Keystone Station Units 1 and 2 use low-NOx burners and SCR systems to control NOx
emissions. NOx emissions from Units 1 and 2 prior to the installation of the low-NOx burners
(1995) were approximately 0.7 lb/MMBtu (see RACT 1993-1995 proposals submitted to the PA
DEP). When operating conditions are sufficient to allow aqueous ammonia injection in the SCR
(close to the threshold specified in the PA DEP RACT II Rule, see Table 4-1), average NOx
emissions from Units 1 and 2 were 0.104 and 0.103 lb/MMBtu, respectively, in 2019, which
equates to an overall NOx control efficiency of 85% achieved by the low NOx burners and
SCRs. Therefore, based on the current actual NOx emission rate and control efficiency, the
existing NOx controls are highly effective.
6. Emissions Control Options
This section presents an evaluation of potential emissions reduction options applicable to SO2
and NOx emissions from Units 1 and 2. The evaluation starts with listing potential control
options and determining if the option is technically infeasible. For those options considered
technically feasible, an analysis will be conducted considering the four statutory factors: (1)
costs of compliance; (2) the time necessary for compliance; (3) the energy and non-air quality
environmental impacts of compliance; and (4) the remaining useful life of the emission unit.
Following that evaluation are conclusions related to the feasibility and reasonability of
implementing the remaining approaches.
6.1 Identification of Potentially Available SO2 Emissions Reduction Options
There are multiple options for controlling the emissions of SO2 from coal-fired EGUs. These
options fall in three general categories:
─ Wet Flue Gas Desulfurization (wet FGD),
2 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019.
3 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019 (Page 23).
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
7
─ “Dry” FGD (e.g.; spray dryer absorber (SDA), circulating dry scrubbers (CDS), or novel
integrated desulfurization (NID)), or
─ Dry Sorbent Injection (DSI).
Among these, the most effective at controlling SO2 emissions from coal-fired boilers is a wet
FGD system. Units 1 and 2 at the Keystone Station already have wet limestone FGD, which is
the top level of control in terms of overall efficiency.
The use of dibasic acid, an organic acid buffer, to increase SO2 control was considered. A
buffer increases SO2 control by decreasing the drop in pH at the gas-liquid interface which
occurs as SO2 is absorbed. However, this option was rejected because it can inhibit mercury
control. Increasing the limestone stoichiometric ratio (LSR, moles of Ca per moles of SO2
absorbed) may provide a marginal improvement in SO2 removal. However, the FGD system
already operates at the preferred LSR needed for scrubber operation.
6.1.1 Costs of Compliance (Factor 1)
At the Station, SO2 emissions are controlled by wet limestone FGD, and as such, SO2
emissions are already well controlled (> 90 percent removal). Therefore, the potentially
available control options to further reduce SO2 emissions are limited to process improvements.
Keystone Station has already implemented several process improvements designed to increase
the efficacy of the wet FGD system during the past eleven years, which overlap with the first
and second decadal review periods of the RHR. The process improvements included the
following:
Ø Optimized the performance of the slurry recycle pumps for the FGD absorber to allow
for consistent feed of limestone slurry to the spray banks;
Ø Optimized the performance of the limestone ball mill to allow for a finer grade of
pulverized limestone, which in turn allows for a more consistent limestone slurry;
Ø Configured the distributed control system to automatically adjust process variables to
ensure that absorber pH and limestone slurry density are maintained within the
specified tolerances; and,
Ø Implemented a preventative maintenance plan to proactively address potential
equipment issues related to FGD performance.
The regulatory drivers for the process improvements included the following:
Ø EPA’s MATS Rule - compliance with this rule began in April 2015. FGD efficacy
improvements were implemented during the years 2014 through 2020 to ensure
compliance with the MATS mercury emissions limits. These improvements also
resulted in co-beneficial reductions in SO2 emissions as demonstrated in the
summary table below. (The exhaust gas flues for Units 1 and 2 are in a single
chimney, the flue gas streams merge upon discharge to the atmosphere.)
Ø EPA’s 2010 SO2 NAAQS compliance demonstration – A dispersion model analysis
was performed to determine the Units 1 and 2 SO2 emission limit required to
demonstrate compliance with the 1-hour SO2 NAAQS. For Keystone Station, the
modeling exercise showed that the new SO2 emission limit, which became applicable
in October 2018 (during the second decadal review period for the RHR) is
approximately 50 percent of the previous emission limit that was applicable when the
FGD systems began operations in late 2009.
Ø Keystone Station also utilizes a dry sorbent (hydrated lime, calcium hydroxide)
injection system at Units 1 and 2 to reduce sulfur trioxide / sulfuric acid mist emissions
as necessary in order to maintain compliance with PA DEP exhaust gas opacity limits.
Four Factor Analysis
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Keystone Station believes that the alkaline sorbent (injected before the FGD system)
also provides for co-beneficial reductions in SO2 emissions. In 2019, Keystone
Station changed from using a standard hydrated lime product to an “enhanced”
(higher porosity) hydrated lime product, which improved oxidized sulfur removal.
Annual SO2 emissions (tons/year, lb/MMbtu and lb/MWh) for the past eleven years are shown in
Table 6-1 below.
Table 6-1 Annual SO2 Emissions from Keystone Station Units 1 and 2
Unit IDs Year Gross Load
(MW-h)
Heat Input
(MMBtu)
SO2
(tons)
SO2
(lb/MMBtu)
SO2
(lb/MWh)
1 & 2
Combined 2010 14,574,271 130,161,394 39,113 0.60 5.4
1 & 2
Combined 2011 11,998,124 110,717,647 46,441 0.84 7.7
1 & 2
Combined 2012 10,222,266 95,680,332 29,420 0.61 5.8
1 & 2
Combined 2013 13,285,780 120,607,139 26,397 0.44 4.0
1 & 2
Combined 2014 12,317,305 112,359,466 28,138 0.50 4.6
1 & 2
Combined 2015 10,255,389 97,146,022 24,447 0.50 4.8
1 & 2
Combined 2016 11,019,360 105,560,720 22,403 0.42 4.1
1 & 2
Combined 2017 12,672,885 118,766,848 23,250 0.39 3.7
1 & 2
Combined 2018 13,338,898 123,507,053 23,951 0.39 3.6
1 & 2
Combined 2019 11,875,700 112,341,534 19,806 0.35 3.3
1 & 2
Combined 2020*7,931,484 77,364,300 13,011 0.34 3.3
* Preliminary data
Keystone Station believes that the FGD efficacy improvements implemented during the past
eleven years are sufficient to satisfy the PA DEP’s reasonable progress goals for visibility
improvement during the second decadal review period, and that this outcome is consistent with
EPA’s guidance that “reasoned decision-making is a core component of the regional haze
program, and thus of states’ regional haze SIP submissions.”4 Consequently, there are no new
compliance costs to be considered.
6.1.2 Time Necessary for Compliance (Factor 2)
Wet limestone FGD, which is already used at the Station and has been optimized throughout its
service life, is the top level of SO2 control; therefore, no additional SO2 emissions controls are
being evaluated for this four-factor analysis. As such, no additional time is needed for
compliance.
4 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019 (Page 1).
Four Factor Analysis
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6.1.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)
Since a wet limestone FGD system already exists on Units 1 and 2 at the Station, the energy
and non-air quality environmental impacts have already been taken into account.
6.1.4 Remaining Useful Life (Factor 4)
Units 1 and 2 were commissioned in 1967 and 1968, respectively. Although the units have
achieved over 50 years of service, no specific retirement date has been set. Therefore, for
Station planning purposes, the remaining useful life of these units is assumed to be at least 20
years.
6.2 Identification of Potentially Available NOX Emissions Reduction Options
Several NOX control options were considered as additions to the current SCR controls for
application to the Keystone Generating Station including Selective Noncatalytic Reduction
(SNCR), Powerspan ECO® system, rich reagent injection, natural gas reburn, coal reburn,
NOxStar, water injection, LoTOX, PerNOxide, ROFA, and ROTAMIX. These technologies were
evaluated for technical feasibility (availability and applicability to Units 1 and 2) based on a
review of possible performance, engineering principals, and an assessment of commercial
availability. The findings are listed in Table 6-2.
Table 6-2 NOx Control Technologies
NOx Control
Option
Description
Rich reagent
injection Similar to SNCR. Only available for cyclone fired boilers.(1)
Natural gas
reburn
Performance is affected by baseline NOx concentration; reburn zone
temperature, residence time, and stoichiometry; overfire burnout zone
temperature and residence time; and mixing of the reburn fuel with the bulk flue
gas. Extensive testing required to make a meaningful prediction of performance.(1)
Based on very limited, if any, applications, natural gas reburn is not expected to
offer a significant emission reduction relative to other options such as an SNCR
and SCR.
Coal reburn Similar to natural gas reburn.
NOxStar
Uses an ammonia-based reagent and small amounts of hydrocarbon injected to
the flue gas at the convective pass of the boiler to reduce NOx. Only one full
scale demonstration project. An emerging technology that would require
extensive design engineering and a long-term full scale demonstration to evaluate
technical feasibility, cost, and performance.(1)
Water injection To date, only bench scale testing on coal firing. Extensive design engineering and
testing would be needed to determine scale-up potential, cost and performance.(1)
LoTOX
A low temperature oxidation system that uses ozone to convert NO and NO2 to
N2O5 for eventual removal by a wet scrubber. No known full-scale, coal-fired
EGU applications.
PerNOxide
Uses hydrogen peroxide injected into the duct ahead of the air preheater. Has
only been tested on a pilot scale. Extensive design engineering and testing would
be needed to determine scale-up potential, cost and performance.(1)
Four Factor Analysis
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NOx Control
Option
Description
ROFA Rotating opposed overfire air. CFD modelling required to determine performance
but expected to be inferior to an SNCR or an SCR.
ROTAMIX Similar to an SNCR (Proprietary SNCR technology)
(1) Coyote Station Unit 1, North Dakota Regional Haze Second Planning Period Four-Factor Analysis.
Sargent & Lundy, May 8, 2019.
All the above options were rejected for one or more of the following reasons:
1. No commercial availability,
2. Emission control performance of these options is inferior to an SCR, which is already
being used on Units 1 and 2. EPA’s top-down approach suggests that if the top level of
control is chosen or as in this case, already installed on the units, no further analysis is
required.
We are, however, presenting costs of tuning/upgrading the existing low-NOx burners to achieve
a small NOx emissions reduction, as discussed in the subsequent sections.
6.2.1 Costs of Compliance (Factor 1)
For both Units 1 and 2, NOx emissions are controlled by low-NOx burners and SCR. The
controlling NOx emission limits are those specified in the PA DEP RACT II Rule, which are as
follows:
Presumptive NOx emission limits for a coal-fired EGU boiler with SCR is 0.12 lb/MMBtu
when flue gas temperature at SCR inlet ≥ 600 deg. F, 0.35 lb/MMBtu when flue gas
temperature at SCR inlet is < 600 deg. F (rolling 30-boiler operating day averaging
period).
In addition, the Keystone Generating Station received a letter from PA DEP on November 17,
2020 requesting submittal of a case-by-case NOx RACT analysis by April 1, 2021. A copy of
this letter is included as Appendix C of this report. The Station expects the proposed NOx
limits of this case-by-case analysis will be more stringent than the current NOx limits. The
revised NOx limits are expected to become effective by January 1, 2023.
Performance of the SCR systems is affected by recent operating modes for the Station. The
Station was originally designed for base load operation. However, due to a decrease in
electrical demand by the regional grid operator (PJM) and increase in supply from (i) newly-
constructed natural gas-fired EGUs (in response to abundant and low-cost natural gas that
became available following development of advanced drilling practices in Pennsylvania) and, to
a much lesser extent, (ii) renewable energy sources over the last few years, operations of Units
1 and 2 now typically cycle on a daily basis. This operation features higher or full load
conditions during daylight hours on the business weekdays with high regional electric demand
and often at loads in the 40% to 70% range or off-line at all other times. The performance of the
SCR system is adversely affected by the low flue gas temperatures that occur at low loads. At
loads below 70%, the flue gas temperature drops below 600°F. At 40% load, the flue gas
temperature drops below 540°F. Injection of aqueous ammonia at these lower flue gas
temperatures results in ammonium bisulfate formation, which deposits on the downstream air
pre-heater and ESP, thus fouling these devices. This issue is the underlying basis for the
bifurcated NOx emission limit scheme in the PA DEP RACT II Rule. Optimization of the existing
SCR systems will be addressed as part of the forthcoming case-by-case NOx RACT analysis.
Four Factor Analysis
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Project No. 60634468-1
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In order to present a complete and thorough four-factor analysis, the Station discussed with R-V
Industries, Inc., additional NOx reduction options specifically around improving performance of
low-NOx burners at the Conemaugh Station. Since the Conemaugh and Keystone Stations are
sister facilities, equipment retrofit costs for the Conemaugh Station are reasonably applicable to
the Keystone Station units as well.
R-V Industries stated that there is no available low-NOx tip that can be bolted onto the existing
burners. Therefore, R-V Industries’ approach, based on prior experience with tangentially-fired
boilers of a similar size and design, was to install venturis in the windbox ductwork to resize the
burner tips to help minimize excess air and NOx formation and optimize the overall air flow. The
budgetary cost information from R-V Industries is presented in Tables 6-3 and 6-4 and the cost-
effectiveness is presented in Table 6-5.
The replacement burners can achieve a 17% NOx reduction (~ 0.22 lb/MMBtu NOx emission
rate) when the minimum continuous operating temperature is less than 611°F (i.e., temperature
below which ammonia injection into the SCR cannot commence).
Table 6-3 Low-NOx Burner Replacement/Tuning Capital Cost Estimate – Per
Boiler
Cost Item
Computation
Method Factor Cost Notes
Direct Costs
Purchased
Equipment (PE)
Vendor Quote x
factor 1.00 $1,901,250 Quote provided by R-V Industries,
Inc.
Taxes PE x factor 0 $0 PE exempt from 6% PA sales tax
Freight PE x factor 0.05 $95,063
Table 2.4 of EPA's OAQPS
Control Cost Manual, Sixth
Edition, January 2002.
Total Purchased
Equipment Costs
(PEC)
Sum ----$1,996,313 PE + Taxes + Freight
Direct Installation
Costs
Conemaugh
Station Estimate
(applicable to
Keystone
Station as well)
----$1,700,000
The budgetary estimate does not
consider that all existing dampers
on the current burners would
need to be replaced, which is an
extremely labor intensive effort
that is not accounted for in the
vendor quote. The listed cost
(based on a comparable project)
accounts for this omission.
Total Direct Costs
(TDC)
Sum PEC +
Installation
Costs
----$3,696,313
Installation Costs,
Indirect
Engineering /
supervision TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Construction / field
expenses TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition, January 2002
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Project No. 60634468-1
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Cost Item
Computation
Method Factor Cost Notes
Construction fee TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Start-up TDC x factor 0.01 $36,963
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Performance test TDC x factor 0.01 $36,963
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Contingencies TDC x factor 0.20 $739,263
Due to the uncertainties
associated with the preliminary,
budgetary nature of the cost
information, a contingency of 20%
is warranted.
Modeling and
Optimization Studies
Conemaugh
Station Estimate
(applicable to
Keystone
Station as well)
----$500,000
This budgetary estimate does not
consider a critical analysis of
potential changes in combustion
zone conditions such as lower
temperatures, decreased
combustion efficiency (related to
decreased oxygen availability and
resultant increase in carbon
monoxide) and increase in
corrosion potential around the
furnace walls. The listed cost
(based on a comparable project)
accounts for this omission.
Loss of Revenue
Associated with
Special Outage
Required to Install
Equipment
Lost generation
x factor 25.00 $10,710,000
Factor = Estimated generation
revenue price ($/MWh), 28 day
outage, 850 MW generation
capacity, 75% annual capacity
factor
Total Indirect Costs
(TIC)Sum ----$13,132,083
Total Capital
Investment (TCI)Sum TDC + TIC ----$16,828,395 TDC + TIC
Table 6-4 Low-NOx Burner Replacement/Tuning Annual Cost Estimate
Cost Item
Computation
Method Factor Cost Notes
Direct Operating Costs
Operating Labor -
Operator (OL)---------
No additional OL costs
expected
Operating Labor -
Supervision ---------
No additional Supervisory
Labor costs expected
Maintenance Labor
(ML)---------
No additional ML costs
expected
Maintenance Materials ---------
No additional Maintenance
Material costs expected
Total Direct Operating
Costs (DOC)Sum $0
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Cost Item
Computation
Method Factor Cost Notes
Indirect Operating Costs
Overhead (OL + ML) x
factor 0.80 $0
No change from current
conditions; i.e., Overhead is
included in the current
overhead cost of the existing
burners
Property Taxes TCI x factor 0.01 $168,284 OAQPS Control Cost Manual,
Sixth Edition, January 2001
Insurance TCI x factor 0.01 $168,284 OAQPS Control Cost Manual,
Sixth Edition, January 2002
Administration TCI x factor 0.02 $336,568 OAQPS Control Cost Manual,
Sixth Edition, January 2002
Capital Recovery (1)TCI x factor 0.0944 $1,588,481
Factor per Equation 2.8a of
EPA's OAQPS Control Cost
Manual, Sixth Edition, 2002.
(20 year life and 7% interest
rate).
Total Indirect
Operating Costs (IOC)Sum ----$2,261,617
Total Annualized
Cost (TAC)
Sum DOC+
IOC ----$2,261,617 Per unit
(1) Based on information available from the Station, the firm-specific nominal interest rate for the
Keystone Station is at least 7%. A 7% interest rate has been set by the United States Office of
Management and Budget (OMB) and is described in the January 2002 EPA Air Pollution Control Cost
Manual. Over the years, 7% has been used as a consistent basis for evaluating emission control
options for BACT, RACT and BART analyses. As shown in Table 23 on Page 70 in PA DEP’s June
2018 Technical Support Document for General Operating Permit for Unconventional Natural Gas Well
Site Operations and Remote Pigging Stations (GP-5A) and the General Plan Approval and General
Operating Permit for Natural Gas Compression Stations, Processing Plants, and Transmission
Stations (GP-5), PA DEP also supports use of an interest rate of 7%.
Table 6-5 Low-NOx Burner Replacement/Tuning Cost-Effectiveness ($/ton NOx
Removed)
Unit
No.
NOx Before
Control (1)
(tons/yr)
NOx After
Control (2)
(tons/yr)
Total
Annualized
Cost (3) ($/yr)
Cost
Effectiveness
($ / ton NOx
Removed)
1 3,937 3,780 $2,261,617 $14,405
2 3,203 3,079 $2,261,617 $18,239
Average $16,322
(1) Based on CY2019 actual annual emissions. See Table 4-1.
(2) Based on available emissions and operating data for CY2019, the LNB upgrades are
expected to reduce emissions by 157 tons/year for Unit 1 and 124 tons/year for Unit 2.
(3) See Table 6-4 for calculation of annual costs.
Four Factor Analysis
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As shown in Table 6-5, the cost of installation of per ton of NOx removed is excessive at an
average of $16,300/ton of NOx removed.
6.2.2 Time Necessary for Compliance (Factor 2)
Considering the extent, cost and duration of the outage associated with the low-NOx burner
tune-up project, if determined to be required, the Station expects that this project would not be
able to be completed for at least five years following an approval to proceed (plans for major
capital projects and major outages at the Station are prepared with five-year forecasts).
Permitting can take up to nine months (to ensure that appropriate federally enforceable
operating limits and conditions are established in the Plan Approval / construction permit as
issued by the PA DEP) with an additional twelve months required for completion of the modeling
study, final design, purchase and implementation. As noted above, optimization of the existing
SCR systems will be addressed as part of the forthcoming case-by-case NOx RACT analysis,
and the revised NOx limits are expected to become effective by January 1, 2023 (within two
years).
6.2.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)
There are no unacceptable energy or non-air quality environmental impacts associated with
operation of the existing or the upgraded low-NOx burners and SCR systems on Units 1 and 2
at the Keystone Generating Station.
6.2.4 Remaining Useful Life (Factor 4)
EPA’s 2019 regional haze guidance states that the remaining useful life is the number of years
that the “new control equipment” is expected to be in service. Therefore, for in-service dates in
the 2025 to 2028 range, a 20-year useful life means that the coal-fired EGU on which the control
is installed, is expected to be operating in the 2045 to 2048-time frame. A 30-year useful life
means that the EGU is expected to be in operation in the 2055 to 2058-time frame. Although
the projected life of a new control system may be 30 years, the remaining useful life of an
existing EGU may be less than 30 years due to its current age and the current economic
dispatch competition from other sources of electricity (nuclear, combined-cycle natural gas and
renewable energy).
During the first regional haze planning period, a 20-year useful life was accepted as a default by
the EPA. This has proven to be overly optimistic as approximately 30% of the coal-fired
generation capacity in the U.S. has been retired in the 10-year period since 2009. Additional
retirements have been announced and are expected to continue (e.g., see the following link:
https://www.genon.com/genon-news/genon-holdings-inc-announces-retirement-of-morgantown-
coal-units) due to competition from natural gas-fired EGUs, renewable energy and other
environmental and non-environmental factors.
Units 1 and 2 were commissioned in 1967 and 1968, respectively and as mentioned previously,
no specific retirement date has been set for either of them. Therefore, for Station planning
purposes, the remaining useful life of these units is assumed to be 20 years.
7. Additional 5th Factor Consideration - Visibility Impacts
The goal of the RHR is to improve the visibility in Class I areas. Accordingly, when evaluating
possible emissions reduction projects or programs, it is appropriate to consider the degree to
which individual control projects might contribute towards that goal. Although states have a
Four Factor Analysis
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statutory requirement to consider the “4 factors” addressed in the earlier portion of this report,
EPA’s guidance5 also allows inclusion of a “5th factor” which involves consideration of visibility
impacts of candidate control options. This section addresses the visibility impacts of current
operations as well as the impact of the marginal SO2 control offered by operating a fourth level
of spray pumps. As explained below, because the visibility impacts attributable to the Keystone
Station are low, further controls and/or lower emission limits, even if technically and
economically feasible, would not yield material visibility benefits at any of the regional Class I
areas because the Station’s Units 1 and 2’s current emissions have a very low visibility impact.
7.1 EPA Guidance Regarding Considerations of Visibility Impacts
The EPA issued “Guidance on Regional Haze State Implementation Plans for the Second
Implementation Period” in August 2019. This guidance allows a state, as part of its
consideration of emission controls, to include a “5th factor” consideration of visibility impacts of
candidate control options.
On pages 36 and 37 of this guidance, the EPA notes that concerning the underlying regulation
for ascertaining reasonable further progress, the regulation:
“assumes that the state will consider visibility benefits as part of the analysis. Section
51.308(f)(2)(i) of the Regional Haze Rule requires consideration of the four factors listed
in CAA section 169A(g)(1) and does not mention visibility benefits. However, neither the
CAA nor the Rule suggest that only the listed factors may be considered. Because the
goal of the regional haze program is to improve visibility, it is reasonable for a state to
consider whether and by how much an emission control measure would help achieve
that goal.” . . .
“. . . EPA interprets the CAA and the Regional Haze Rule to allow a state reasonable
discretion to consider the anticipated visibility benefits of an emission control measure
along with the other factors when determining whether a measure is necessary to make
reasonable progress.”
Consequently, an expectation of a very low impact to Class I visibility impairment from control of
certain facility pollutants is appropriate for consideration when evaluating the need for further
control of these emissions for Regional Haze Reasonable Progress.
EPA’s 2019 RHR guidance does not specifically state what would constitute an insignificant
visibility impact, but the preamble to the 1999 RHR (64 FR 35730) does specify a “no
degradation” visibility change if the impact is less than 0.1 deciview. In addition, MANE-VU
determined in the first decadal review that a visibility improvement less than 0.1 deciview
individual impact does not warrant consideration of additional controls6. This amount of visibility
change (for the worst 20% haze days) is on the order of 1% or less of the 2028 glidepath target,
so it constitutes a very low value. It should be noted that the 0.1 deciview benchmark is not in
and of itself an “off-ramp” for disqualifying the candidate control options being considered.
States need to review the already-installed emissions controls, the feasibility, effectiveness and
cost of an additional control option, as well as its visibility impact together in order to arrive at a
decision.
5 US EPA; “Guidance on Regional Haze State Implementation Plans for the Second Implementation Period” in August 2019. Available at
https://www.epa.gov/sites/production/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf.
6 77 FR 17367 (March 26, 2012).
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7.2 Class I Areas Near Keystone Generating Station
Class I areas in the eastern United States near Pennsylvania are shown in Figure 7-1. The
closest Class I areas are Dolly Sods and Otter Creek Wilderness Areas in West Virginia and
Shenandoah National Park in Virginia. Other Class I areas within 400 km include Brigantine
Wilderness Area (New Jersey) and James River Face Wilderness Area (Virginia).
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Figure 7-1 Class I Areas in the Vicinity of Keystone Generating Station
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7.3 MANE-VU CALPUFF Modeling
Pennsylvania is one of the states within the Mid-Atlantic/Northeast Visibility Union (MANE-VU)
Regional Planning Organization. In 2016, MANE-VU conducted visibility modeling using 2015
Electrical Generating Unit (EGU) to determine visibility impacts of emission sources at Class I
areas within MANE-VU. This modeling was conducted with the CALPUFF model, which was
used for visibility modeling for the first decadal review.
Specific aspects of the MANE-VU modeling that are worth noting are as follows:
· 2011 and 2015 emissions were considered (emission reductions since 2011 and 2015
are not accounted for, making this analysis significantly dated and questionable for
accuracy)
· 95th percentile emission rates were assumed to occur continuously (this approach can
significantly overstate actual emissions, even for the outdated inventory used)
· CALPUFF was applied for distances from sources to Class I areas far exceeding the
Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 advisory7 that use of
CALPUFF for distances beyond 200 km could introduce significant overprediction biases
in the results.
· CALPUFF is a screening model that has been delisted as an EPA-preferred long-range
transport model (Appendix W updates in 2017, as proposed in 2015). It is puzzling why
MANE-VU relied upon this screening model for determining sources that are asked to
conduct four-factor analyses; no other Regional Planning Organizations have used
CALPUFF modeling for the Second Decadal Review.
· CALPUFF evaluations8 indicate large overpredictions of nitrate haze, especially in
winter, due the dated formulation used in the model. The default MESOPUFF-II
formulation has limitations for winter applications, where it results in overpredictions
approaching a factor range of 4-6 in the evaluations noted in the reference.
· The statistic reported from the CALPUFF modeling was the highest day’s impact, which
is a significant departure from the 8th highest day for the first decadal review and the
average of the 20% most impaired days for the second decadal review.
Due to widespread use of photochemical grid models such as CAMx by every other Regional
Planning Organization in the country, the next sub-section discusses available CAMx modeling
for some Pennsylvania EGUs (including the Keystone Generating Station) conducted by the
southeastern states Regional Planning Organization, VISTAS / SESARM.
7.4 VISTAS CAMx Modeling Analysis
The impact to Class I area visibility of current Station emissions and hypothetical reductions to
SO2 and NOx emissions can be determined by analyzing the results of visibility modeling
conducted by the VISTAS / SESARM9 Regional Planning Organization that included emissions
for some Pennsylvania power plants including the Keystone Generating Station. The VISTAS
modeling was conducted by Alpine Geophysics and utilized advanced CAMx modeling including
modeling particulate matter simulations and source apportionment studies. Determinations of
the haze contributions of specified large sources was accomplished by “tagging” the selected
sources for determining their contribution to impairment at each Class I area of interest. The
tagged sources included the Keystone Generating Station. The results of VISTAS modeling
7 IWAQM Phase 2 report, Appendix D. Available at http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
8 Joseph Scire presentation at the EPA 10th Modeling Conference, available at https://www3.epa.gov/scram001/10thmodconf/presentations/3-5-
CALPUFF_Improvements_Final.pdf.
9 “VISTAS” is an acronym for Visibility Improvement -State and Tribal Association of the Southeast and “SESARM” stands for Southeastern
States Air Resource Managers, Inc. Their web site for Regional Haze Rule modeling results is https://www.metro4-sesarm.org/content/vistas-
regional-haze-program.
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analysis of Keystone Station’s total emissions can be used, with emissions scaling, to estimate
the visibility impacts of Keystone Station Units 1 and 2’s current (2019) actual emissions.
Visibility impairment is commonly expressed using two parameters to characterize the visibility
impairment:
·Light Extinction (bext) is the reduction in light due to scattering and absorption as it
passes through the atmosphere. Light extinction is directly proportional to pollutant
particulate and aerosol concentrations in the air and is expressed in units of inverse
megameters or Mm-1.
·Deciview (DV)is a unitless metric of haze which is proportional to the logarithm of the
light extinction. Deciview correlates to a person’s perception of a visibility change, with a
change of 1 deciview being barely perceptible. The “no degradation” value of 0.1 DV
stated in the 1999 Regional Haze Rule is only 10% of this perceptibility threshold.
Both metrics are helpful in understanding changes to visibility impairment, but while the
deciview is the best parameter to relate the significance of a perceived visibility change,
modeling produces results in the form of light extinction using the new IMPROVE equation that
converts particulate concentrations to visibility impairment. A chart shown in Figure 7-2 is taken
from the VISTAS Regional Haze modeling project update (webinar) updated on September 10,
2020 (after being originally presented on May 20, 2020). It shows, in units of deciview, the
actual visibility measurements and projected modeling results of visibility for most impaired days
at the Shenandoah National Park.
Figure 7-2 shows that actual visibility measurements (the diamonds) confirm a strong trend of
improved visibility in the past 10 years from about 27 DV to about 16 DV. This rate of actual
improvement is much faster than the RHR target to maintain a “uniform rate of progress” or
“glide path” (the pink line), which could be revised to a less-steep revised glide path to account
for internationally-caused haze. However, VISTAS believes that since the Class I areas in this
region are so far ahead of projections, that refinement is not necessary at this time.
Additionally, VISTAS modeling of the expected emissions reductions in the coming years (on-
the-books / on-the-way controls) projects (the blue line) that visibility should continue to
significantly improve, reaching approximately 14.47 DV by the next RHR milestone year of
2028. This chart shows that visibility in this Class I area is currently running at least 20 years
ahead of the RHR targets and is expected to continue to do so. VISTAS modeling of other
regional Class I areas shows very similar trends and are all far ahead of their glide path targets.
Therefore, no additional emissions reductions at any regional facilities, beyond those already
planned, are needed to continue to meet the RHR interim goals.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Figure 7-2 Visibility Trends at Shenandoah National Park
7.5 Visibility Impact of Keystone Station’s Units 1 and 2 SO2 and NOx Emissions
The VISTAS modeling used 2011 annual emissions for the tagged stations to develop the units’
projected 2028 emissions, and these values can be scaled to current representative emissions
for the Keystone Generating Station. PA DEP has stipulated that 2019 emissions should be
considered as representative for this analysis. The adjusted 2028 emissions modeled for
Keystone were 21,066 tons of SO2 and 5,086 tons of NOx. The representative current
emissions (2019) for the Keystone Generating Station were 19,806 ton of SO2 and 7,140 tons of
NOx. Keystone Station’s current best estimate is that Unit 1 and 2’s 2019 actual emissions are
a reasonable projection of their 2028 emissions. With linear scaling, this results in a modeled
impact at the Shenandoah National Park and other nearby Class I areas based upon the
VISTAS modeling as shown in Table 7-1.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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Table 7-1 Haze Impact from Keystone Generating Station’s Total 2019
Emissions of SO2 and NOx at Class I Areas Within 400 km
Class I Areas Nearest to the
Keystone Generating Station
Total Haze Impact from
2019 SO2 Emissions from
the Keystone Generating
Station
Total Haze Impact
from 2019 NOx
Emissions from the
Keystone Generating
Station
Mm-1 DV * Mm-1 DV *
Shenandoah National Park 0.696 0.083 0.013 0.002
Brigantine Wilderness Area 0.342 0.041 0.055 0.007
Dolly Sods Wilderness Area 0.232 0.028 0.001 0.000
Otter Creek Wilderness Area 0.179 0.021 0.001 0.000
James River Face Wilderness Area 0.204 0.025 0.008 0.001
* Potential Improvement in DV is listed for the 20% most impaired days for each Class I
area. Conversion between deciviews and extinction is based upon the 2028 glidepath goal
extinction as a reference point.
The VISTAS CAMx modeling results for tagged individual source visibility impacts are expressed as light extinction, in
units of inverse megameters. Another visibility metric is deciviews, which can be determined from extinction through a
logarithmic relationship, as noted in an EPA 2003 reference10 for tracking progress under the Regional Haze Rule. That
reference indicates (in Section 3.9) that a change of 1 deciview is equivalent to about a 10% change in extinction
coefficient, and Internet tools such as that available at http://vista.cira.colostate.edu/Improve/haze-metrics-converter/
can easily do the conversion. Recent guidance from EPA, issued in 2018, is “Technical Guidance on Tracking Visibility
Progress for the Second Implementation Period of the Regional Haze Program”11. This guidance indicates that the total
anthropogenic impairment:
“is the difference (the ‘delta deciviews’) between the total deciview value that exists (or is projected to exist) and the
deciview value that would have existed if there were only natural sources causing reduced visibility. This is the metric
that EPA recommends be used. We recommend that states use Equation 2 to calculate anthropogenic visibility
impairment:
∆ dv (anthropogenic visibility impairment) = dv (total) – dv (natural) (Eqn. 2),
where dv (total) is the overall deciview value for a day, and dv (natural) is the natural portion of the deciview value for a
day.
We are considering the question: What is the difference in anthropogenic visibility impairment due to a proposed
emission control? To determine this, one would use above equation twice to take the difference of two ∆dv
(anthropogenic visibility impairment) values. In so doing, the term dv (natural) cancels out. To determine the difference
caused by a proposed control action, we conservatively use the 2028 extinction goal to determine the conversion of
extinction to deciviews. With a 2028 extinction goal of approximately 80 Mm-1, the conversion between a difference of 1
Mm-1 (relative to the 2028 goal of 80 Mm-1) would be about 0.12 delta-dv.
Table 7-1 shows that total actual 2019 emissions of SO2 from the Keystone Generating Station
contributed only 0.696 Mm-1 light extinction at the Shenandoah National Park Class I area,
based upon 2019 actual emissions of 19,806 tons. This equates to a deciview value of 0.083
DV, which is a 0.58% contribution to total impairment – an insignificant portion of the 2028
projected ~14.47 DV visibility at the Shenandoah National Park. As indicated previously, EPA
has indicated that a DV change of less than 0.1 DV can be considered “no-degradation.”
Therefore, current SO2 emissions from Units 1 and 2 do not significantly contribute to visibility
degradation at Shenandoah National Park. Likewise, the Station’s current NOx emissions’
visibility impact (0.007 DV at Brigantine Wilderness) is well below the no degradation threshold
of 0.1 DV and less than 0.04% of the 2028 projected visibility at the Brigantine Wilderness Area
10 https://www3.epa.gov/ttnamti1/files/ambient/visible/tracking.pdf.
11 Available at https://www.epa.gov/sites/production/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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(18.4 DV). Therefore, any projects that reduce NOx emissions at the Station would have a
potential visibility improvement far less than the no-degradation threshold.
8. Conclusion
Emissions of SO2 and NOx from Units 1 and 2 at the Station are already well controlled by wet
FGD and SCR. Substantial SO2 and NOx emission reductions have already been achieved with
the existing emission controls. Since the 2006-2008 period, annual SO2 emissions have been
reduced by 89% and NOx emissions have been reduced by 48%. Improvements in visibility at
the nearest Class I areas are well ahead of the uniform rate of progress glide path.
The existing wet FGD and SCR are the best available emission control options and no other
technically feasible, more efficient controls have been identified. The combination of the FGD
and SCR also provides for effective emissions control for the MATS Rule pollutants (acid gases,
mercury and other non-mercury metals) and particulate matter. Replacement/tuning of the
existing low-NOx burners was evaluated and the cost effectiveness of this control measure is
excessive at $16,300/ton NOx removed. Additionally, recent VISTAS visibility modeling
conducted using advanced photochemical grid modeling suggests that visibility impacts of the
Station’s 2019 NOx emissions are less than one-tenth of the threshold designated as a “no
degradation” visibility change. Lastly, the Station will be submitting a case-by-case NOx RACT
analysis to the PA DEP by April 21, 2021 which is expected to result in more stringent NOx
limits.
Therefore, for Keystone Generating Station’s Units 1 and 2, no additional controls are needed in
order for PA DEP to meet their reasonable progress goal for the Second Decadal Review.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Appendix A
PA DEP Four-Factor Analysis Request Letter
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Appendix B
Summary of VISTAS Visibility Modeling Results
SO2 (tpy):21,066 SO2 (tpy):19,806
NOX (tpy):5,086 NOX (tpy):7,140
Extinction for 20% Worst Haze Days
Class I Area
Total
Modeled
Sulfate
Extinction
Mm-1
Total
Modeled
Nitrate
Extinction
Mm-1
Scaled
Modeled
Impacts
Results:
Sulfate
Extinction
Mm-1
Scaled
Modeled
Impacts
Results:
Nitrate
Extinction
Mm-1
Shenandoah NP 0.7400 0.0093 0.6957 0.0130
Brigantine WA 0.3637 0.0394 0.3419 0.0554
Dolly Sods WA 0.2464 0.0008 0.2317 0.0011
Otter Creek WA 0.1902 0.0008 0.1788 0.0011
James River Face
WA 0.2172 0.0054 0.2042 0.0076
Data from ATTACHMENT_A_PSAT_TAG_RESULTS_adjusted_08-11-2020.xlsx.
Projected 2028 Visibility at Current Emissions Levels
Mm-1 DV Mm-1 DV
0.696 0.083 0.013 0.002
0.342 0.041 0.055 0.007
0.232 0.028 0.001 0.000
0.179 0.021 0.001 0.000
0.204 0.025 0.008 0.001
0.12 DV per Mm-1 (See explanation in report)
Table B-1 Estimated Haze based on Current Emissions from Units 1 and 2 at the Keystone
Station
Keystone Adjusted 2028
Emissions Modeled 2019 Keystone Emissions
Class I Areas Nearest to Keystone
Generating Station
Total Haze Impact from 2019
SO2 Emissions
Total Haze Impact from 2019
NOx Emissions
Shenandoah National Park
Brigantine Wilderness Area
Dolly Sods Wilderness Area
Otter Creek Wilderness Area
James River Face Wilderness Area
Keystone Station
Four Factor Analysis Table B-1 (Haze Calcs)January 2021
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Appendix C
PA DEP Request for a Case-by-Case RACT Analysis

November 25, 2020

Via Email Delivery – [e-mail]
Mr. Eric A. Gustafson
Regional Air Quality Program Manager
Pennsylvania Department of Environmental Protection
Northwest Regional Office
230 Chestnut Street
Meadville, PA 16335

Re: Keystone Generating Station – Title V Operating Permit No. 03-00027
Acknowledgement of Department’s Request for Case-by-Case RACT Analysis for
Two Existing Coal-Fired Combustion Units Equipped with Selective Catalytic
Reduction (SCR) System

Dear Mr. Gustafson:
Keystone Station is in receipt of the attached letter, which includes the following request:

Please confirm in writing, within 10 days of receipt of this correspondence, that your
facility will submit complete case-by-case RACT II determinations for existing coal-fired
combustion units which are equipped with SCR to DEP, along with a significant operating
permit modification application, on or before April 1, 2021.

Keystone Station is planning to submit the above-mentioned determination and application on or
before April 1, 2021. It is our understanding that once the determination is approved, the
applicable requirements will be captured in an updated Title V operating permit and will both
supersede the existing RACT II Rule requirements and satisfy the Department’s forthcoming
RACT III Rule requirements.

If you have questions or concerns regarding this letter, then please contact me at [phone]
or [e-mail].

Very truly yours,
Nathan J. Rozic
Environmental Specialist – Keystone Generating Station

Cc: Joseph Kushner, Strategy & Compliance Manager – Keystone and Conemaugh Stations
Keystone Generating Station
313 Keystone Drive
Shelocta, PA 15774

November 17, 2020

Nathan J. Rozic – Environmental Specialist mailto:[e-mail]
Keystone Conemaugh Project LLC
175 Cornell RD STE 1
Blairsville, PA 15717

Re: RACT II regulation Implementation, §§ 129.96 to 129.100
Keystone Station
Title V Permit No: 03-00027
Plumcreek Township, Armstrong County

Dear Mr. Nathan J. Rozic:

On August 27, 2020, the U.S. Third Circuit Court of Appeals issued an opinion in Sierra Club v.
EPA, 3d. Cir. No. 19-2562 (“Sierra Club”) vacating and remanding three aspects of the U.S.
Environmental Protection Agency’s (EPA) May 19, 2019 approval of DEP’s 2016 reasonably
available control technology (RACT II) Rule to reduce ozone pollution from coal-fired power
plants (84 FR 20274). Sierra Club challenged EPA’s approval of the RACT II Rule’s oxides of
nitrogen emission limit for coal-fired power plants with selective catalytic reduction (SCR)
pollution controls; the inlet operating temperature threshold for power plants to operate SCR
pollution controls; and operating temperature data recordkeeping and reporting requirements.
The Court found EPA’s approval of these three provisions of the RACT II Rule to be arbitrary
and capricious, because they were not supported by the administrative record. As a result, the
Court vacated EPA’s approval of these three provisions and remanded them back to the agency
for further action. The vacated portion of the RACT II Rule affects your facility.

As a result of the Court’s decision in Sierra Club, DEP is required to address RACT II
requirements for existing coal-fired combustion units with SCR systems. DEP has determined
that the best method to do this is through requiring the owner or operator of each unit affected by
the Court’s decision to submit case-by-case RACT II determinations that satisfy 25 Pa. Code §
129.99 (relating to alternative RACT proposal and petition for alternative compliance schedule)
requirements. Case-by-case RACT determinations must be developed in accordance with the
procedures in §129.92(a)(1)—(5) and (b), which includes a top-down analysis. DEP will review
the proposed case-by-case determinations and incorporate the final determinations and associated
conditions into your facility’s Title V operating permit in accordance with 25 Pa. Code §
127.542 (relating to revising an operating permit for cause). The RACT determinations
incorporated into the Title V operating permit will then be submitted to EPA as a state
implementation plan revision.

Please confirm in writing, within 10 days of receipt of this correspondence, that your facility will
submit complete case-by-case RACT II determinations for existing coal-fired combustion units
Nathan J. Rozic Keystone Station November 17, 2020
which are equipped with SCR to DEP, along with a significant operating permit modification
application, on or before April 1, 2021. If you are planning to modify any existing equipment or
install a control device as a result of your RACT II determination, please contact us regarding the
need to submit a plan approval application. Please note that DEP is waiving permit fees for
review of the significant operating permit modification application.

If you have any questions, please contact me at 814-656-1346 or [e-mail].

Sincerely,

Eric A. Gustafson

Eric A. Gustafson
Program Manager
Northwest Region Air Quality Program

cc: Mark Hammond, Bureau Director
Hbg. – Permits
File

Four Factor Analysis
Regional Haze Rule
Second Decadal Review
Keystone Generating Station
Units 1 and 2
AECOM Project number: 60634468-1
Original Submittal: July 29, 2020
Revised (Rev.01): January 11, 2021
Revised (Rev.02): February 11, 2021
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
i
Quality information
Prepared by Prepared by Checked by Approved by
Robert R. Hall
Senior Air Quality
Engineer
Robert J. Paine
Associate Vice President
Seemantini Deshpande
Project Manager
Seemantini Deshpande
Project Manager
Prepared for:
Keystone Generating Station
313 Keystone Dr, Shelocta, PA 15774
Prepared by:
Robert R. Hall
Senior Air Quality Engineer
T:978-905-2230
E:[e-mail]
AECOM
250 Apollo Drive
Chelmsford, MA 01824
aecom.com
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Table of Contents
1.Introduction .............................................................................................................1
2.Source Description..................................................................................................2
3.First Regional Haze Planning Period Reasonable Progress Determination............3
4.Source Emissions ...................................................................................................3
5.Existing Emission Controls .....................................................................................6
5.1 SO2 Control Measures....................................................................................6
5.2 NOx Control Measures ...................................................................................6
6.Emissions Control Options......................................................................................6
6.1 Identification of Potentially Available SO2 Emissions Reduction Options .......6
6.1.1 Costs of Compliance (Factor 1)......................................................................7
6.1.2 Time Necessary for Compliance (Factor 2)....................................................9
6.1.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)......................9
6.1.4 Remaining Useful Life (Factor 4)....................................................................9
6.2 Identification of Potentially Available NOX Emissions Reduction Options.......9
6.2.1 Costs of Compliance (Factor 1)....................................................................11
6.2.2 Time Necessary for Compliance (Factor 2)..................................................14
6.2.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)....................15
6.2.4 Remaining Useful Life (Factor 4)..................................................................15
7.Additional 5th Factor Consideration -Visibility Impacts .........................................15
7.1 EPA Guidance Regarding Considerations of Visibility Impacts .....................16
7.2 Class I Areas Near Keystone Generating Station .........................................16
7.3 MANE-VU CALPUFF Modeling ....................................................................18
7.4 VISTAS CAMx Modeling Analysis ................................................................18
7.5 Visibility Impact of Keystone Station’s Units 1 and 2 SO2 and NOx
Emissions .....................................................................................................20
8.Conclusion ............................................................................................................22
List of Tables
Table 4-1 Keystone Generating Station –Unit 1 and Unit 2 Actual Annual Operation
and Emissions ..............................................................................................5
Table 6-1 Annual SO2 Emissions from Keystone Station Units 1 and 2........................8
Table 6-2 NOx Control Technologies .........................................................................10
Table 6-3 Low-NOx Burner Replacement/Tuning Capital Cost Estimate –Per Boiler 12
Table 6-4 Low-NOx Burner Replacement/Tuning Annual Cost Estimate ...................13
Table 6-5 Low-NOx Burner Replacement/Tuning Cost-Effectiveness ($/ton NOx
Removed)...................................................................................................14
Table 7-1 Haze Impact from Keystone Generating Station’s Total 2019 Emissions of
SO2 and NOx at Class I Areas Within 400 km ............................................21
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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List of Figures
Figure 4-1 Johnstown Airport 5-Year (2009 -2013) Wind Rose .....................................4
Figure 7-1 Class I Areas in the Vicinity of Keystone Generating Station .....................17
Figure 7-2 Visibility Trends at Shenandoah National Park...........................................20
List of Appendices
Appendix A PA DEP Four-Factor Analysis Request Letter
Appendix B Summary of VISTAS Visibility Modeling Results
Appendix C PA DEP Request for a Case-by-Case RACT Analysis
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
1
1.Introduction
The Pennsylvania Department of Environmental Protection (PA DEP)Bureau of Air Quality
notified the Keystone Generating Station (Keystone Station)that PA DEP is developing a State
Implementation Plan (SIP) for the Second Decadal Review period of the federal Regional Haze
Rule (42 USC §7491 –Visibility Protection for Federal Class I Areas). The Regional Haze Rule
(RHR)requires state and federal agencies to work to improve visibility in U.S. National Parks
and Wilderness Areas throughout the country (see 40 CFR §§81.401 through 81.437)with the
ultimate goal of achieving “natural background” visibility in these Class I areas by the year 2064.
Every ten years, agencies are required to evaluate their plans and consider whether additional
emission reductions at certain major sources are warranted to continue realizing “reasonable
progress” in visibility improvement.PA DEP identified the Keystone Station Units 1 and 2 as
sources requiring an analysis for potential reductions of sulfur dioxide (SO2) emissions and
nitrogen oxides (NOx) emissions.Primary PM10 is another pollutant that may contribute to
visibility impairment (although to a much lesser extent relative to SO2 and NOx), but emissions
of this pollutant are not required to be evaluated for this analysis –see Section 3 of this report
for details.
As outlined in the RHR, this analysis, referred to as a “Four-Factor Analysis”, needs to first
identify all technically feasible control technologies for additional SO2 and NOx emissions
control.Each feasible control option then needs to be evaluated relative to the following four
statutory factors:
1)Cost of implementing emission controls;
2)Time necessary to install such controls;
3)Energy and non-air quality impacts associated with installing controls; and
4)The remaining useful life of the facility.
In May 2020, the PA DEP requested Keystone Station to perform the subject analysis for Units
1 and 2,and submit their findings to the PA DEP. Appendix A provides a copy of the PA DEP’s
letter request.Keystone Station contracted AECOM to assist with the analysis. Although not
required to be included in the analysis,states have the option to consider a fifth factor –
evaluation of visibility benefits -in addition to the four statutory factors when making their
reasonable progress determinations.This analysis includes the fifth factor (see Section 7) to
provide additional information to PA DEP to assist in their consideration for the need of
additional controls for visibility improvement.
The initial analysis was submitted to the PA DEP in July 2020. The first revised (Rev. 01)
analysis was prepared in response to comments from the PA DEP and other reviewers that
were received by Keystone Station (and forwarded to AECOM) on August 18, 2020.The
second revised (Rev. 02)analysis was prepared in response to comments from the PA DEP
that were received by the Keystone Station in January 2021 following PA DEP’s review of the
Rev. 01 analysis.
This report provides a description of the affected source (Section 2), a summary of the actions
taken during First Decadal Review period of the RHR (Section 3),a summary of actual baseline
emissions (Section 4), a discussion of existing emission controls (Section 5),and identification
of potentially feasible control options and an assessment of each of the four statutory factors for
these options (Section 6). Additionally, Section 7 provides a “fifth factor”analysis of the
prospective visibility impacts to Class I areas of potential SO2 controls for PA DEP’s
consideration.Finally, Section 8 presents a summary of this report’s findings.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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2.Source Description
Keystone Generating Station, which is located at 313 Keystone Dr, Shelocta, PA 15774,is
licensed to operate under environmental permits issued to Keystone-Conemaugh Projects, LLC.
The Station operates under PA DEP’s Title V Operating Permit No.03-00027 (Expiration date –
March 31, 2025).
Keystone Station Unit 1 and Unit 2 are each identical bituminous coal-fired boilers with a steam
turbine-driven electric generator that provide electricity to the regional electric grid.
Manufactured by Combustion Engineering, Units 1 and 2 were commissioned in 1967 and 1968,
respectively, and fire bituminous coal mined in Pennsylvania.The nominal maximum operating
conditions for each boiler and generator are heat input of 8,717 MMBtu/hr and gross electrical
output of 910 MW, respectively.No. 2 fuel oil is used as the boiler start-up fuel and for
supplemental firing as needed.
Each boiler is equipped with the following emissions control devices: Low-NOx burners,
selective catalytic reduction (SCR, installed in 2003) for NOx control,electrostatic precipitator
(ESP) for particulate matter (PM) control,hydrated lime (sorbent) injection system for sulfuric
acid mist (H2SO4)control,and a wet flue gas desulfurization (FGD, installed in 2009) system for
SO2 and additional PM control.These control devices also provide co-beneficial emissions
control for a suite of other pollutants such as mercury and acid gas emissions.Process gases
at each unit are routed through the emission control systems using induced draft (ID) booster
fans.Process gases from each FGD system are discharged to the atmosphere through a single
exhaust flue contained in one concrete stack (designated as S12 in the Title V permit).
Unit 1 and Unit 2 are subject to, and compliant with, the Cross-State Air Pollution Rule (CSAPR
or Transport Rule) and the related requirements promulgated under 25 Pa. Code Chapter 139
and 40 CFR 75 -Continuous Emissions Monitoring.Keystone Station operates and maintains
(i) certified continuous emission monitoring systems (CEMs) for NOx, SO2 and carbon dioxide
(CO2) and (ii) a certified exhaust gas stream flow monitor at the exhaust duct.Certified
emissions, heat input and gross electrical load data are submitted quarterly to the PA DEP and
U.S. Environmental Protection Agency (EPA).
Units 1 and 2 are also subject to, and compliant with, the following EPA and PA DEP
regulations:
Ø 2010 SO2 National Ambient Air Quality Standard (NAAQS)–a compliance modeling
study completed by AECOM for the Indiana,PA designated non-attainment area
demonstrated that current SO2 emission impacts from the Keystone Station’s units are
compliant with the NAAQS
Ø PA DEP RACT II Rule –Units 1 and 2 demonstrate compliance with the presumptive
NOx RACT limits for coal-fired electric generating boilers equipped with SCR
Ø Coal-and Oil-Fired Electric Utility Steam Generating Units (EGU)National Emission
Standards for Hazardous Air Pollutants (NESHAP) Rule, also known as the Mercury Air
Toxics Standards (MATS) Rule.Under the MATS Rule, Units 1 and 2:
·Have attained Low-Emitting EGU (LEE)status for non-mercury metals using
filterable PM as the surrogate pollutant;
·Have attained LEE status for acid gas (HCl)standard;and,
·Monitor mercury emissions using a sorbent trap sampler (nominal weekly
sampling period).
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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In summary, contemporary emission control devices are already installed, operated and
maintained at Units 1 and 2, and these devices provide for effective control of criteria and
hazardous air pollutants.
3.First Regional Haze Planning Period Reasonable Progress
Determination
During the First Decadal Review period of the RHR (i.e., 40 CFR 51 Subparts 308 and 309),
Units 1 and 2 were subject to Best Available Retrofit Technology (BART) review because they
had been placed into service within the rule-specified BART applicability window (between
August 7, 1962 and August 7, 1977)and satisfied the other eligibility criteria.BART
requirements for SO2 and NOx emissions were satisfied by compliance with U.S. EPA’s Clean
Air Interstate Rule (CAIR), now superseded by the more stringent CSAPR, per U.S. EPA who
ruled that CAIR achieved greater reasonable progress than BART for SO2 and NOx emissions
at BART-eligible electric generating units located in CAIR-affected states. A BART analysis
(dispersion modeling study) for primary PM10 emissions was completed by AECOM and
submitted to the PA DEP in January 2007, and that study concluded that visibility impacts from
primary PM10 emissions from the Units 1 and 2 were imperceptible at the nearest Class I areas
(Shenandoah National Park,Dolly Sods and Otter Creek Wilderness Areas).The Keystone
Station has since further reduced its actual SO2 and NOx emissions, as described in the next
section.
4.Source Emissions
Actual emissions for Units 1 and 2 are summarized in Table 4-1.At the Keystone Station,
actual emissions of SO2 have been reduced between 2006-2008 (indicative of the baseline
emissions prior to implementation of the regional haze program) and 2019 by more than 89%
and emissions of NOx have been reduced by 48%over the same period.The emission
reductions are indicative of the reductions achieved since commencement of the regional haze
program and are attributable to installation of a wet flue gas desulfurization (FGD)system in
2009,the use of SCR and compliance with PA DEP’s RACT II rule, compliance with other
environmental programs such as CSAPR and the SO2 NAAQS implementation, and to a lesser
extent, the reduced level of utilization of these units.
AECOM understands that the PA DEP requested NOx and SO2 four-factor analyses for Units 1
and 2 based, in part, on a metric used by the National Park Service (NPS) for evaluating
potential impacts to visibility at the nearby Class I Areas (Dolly Sods and Otter Creek
Wilderness and Shenandoah National Park). The metric is equal to the source annual
emissions (tons) divided by distance between the source and the Class I Area (km). The NPS
selected a ratio of 1.0 or greater as the threshold for identifying sources that could affect
visibility conditions in the Class I Areas. While the metric may be appropriate as a screening
tool, it does not consider the direction of the prevailing winds from the source to the Class I
Areas (Figure 7-1 presents the location of the Keystone Generating Station in relation to nearby
Class I Areas). For Keystone Generating Station, wind direction data were generated using five
years (2009 -2013) of wind speed / wind direction data at the Johnstown, PA airport. As
depicted in the resultant wind rose presented in Figure 4-1, winds from the north and north-
northwest (i.e., from the Keystone Generating Station toward the nearby Class I areas to the
south) are very infrequent, which suggests that emissions from Units 1 and 2 rarely impact
visibility conditions in those Class I areas.
Four Factor Analysis
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Project No. 60634468-1
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Figure 4-1 Johnstown Airport 5-Year (2009 -2013) Wind Rose
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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Table 4-1 Keystone Generating Station –Unit 1 and Unit 2 Actual Annual Operation and Emissions
Time
Period Unit
Annual
Operating
Hours(a)
Power
Output (a)
Capacity
Factor
based
on MW (b)
Annual
Fuel Use (a)SO2 Emissions (a)NOx Emissions (a)
NOx
Emissions
when flue
gas
temperature
at SCR inlet
≥ 600°F (c)
(hr/yr)(MW)%(MMBtu/yr)(ton/yr)(lb/MMBtu)(ton/yr)(lb/MMBtu)(lb/MMBtu)
2006
through
2008
1 8,101 6,993,291 88%62,799,882 89,735 2.86 7,137 0.227 Not
applicable
2 8,023 6,823,606 86%60,103,001 85,408 2.84 6,466 0.215 Not
applicable
Average 8,062 6,908,448 87%61,451,441 87,571 2.85 6,801 0.221 Not
applicable
Total 175,143 --13,603 ----
2019
1 8,185 6,498,402 82%61,842,784 11,868 0.384 3,937 0.127 0.104
2 6,884 5,377,298 67%50,498,750 7,939 0.314 3,203 0.127 0.103
Average 7,534 5,937,850 74%56,170,767 9,903 0.353 3,570 0.127 0.104
Total 19,806 --7,140 ----
Emission Reduction 89%--48%----
(a) USEPA Air Markets Program Data (https://ampd.epa.gov.ampd/).
(b) Rated capacity for each unit is 910 MW, gross.
(c) Per PA DEP RACT II Rule, presumptive NOx emission limits for a coal-fired EGU boiler with SCR is 0.12 lb/MMBtu when flue gas temperature at
SCR inlet ≥ 600°F, 0.35 lb/MMBtu when flue gas temperature at SCR inlet is < 600°F (rolling 30-boiler operating day averaging period)1
1 25 Pa. Code §129.97(g)(1)(viii)and 25 Pa. Code §§129.97(g)(1)(vi)(B)
Four Factor Analysis
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5.Existing Emission Controls
EPA’s regional haze guidance2 includes several criteria that, if applicable, would indicate that a
source already has effective controls in place as result of a previous regional haze decision or
other Clean Air Act (CAA) requirements and as such, it may be reasonable for the state to not
select that source for further analysis.3 In addition, EPA guidance for effectively controlled
sources suggests that a full four-factor analysis would likely result in a conclusion that no
additional controls are necessary.
5.1 SO2 Control Measures
In addition to the certified CEMs noted in Section 2,Keystone Station operates and maintains
diagnostic SO2 and CO2 CEMs at the inlets to the FGD absorbers. Data from these diagnostic
CEMs are not reported to the agencies, but are rather used by Station Operations to gauge
performance of the FGD and other systems.The inlet diagnostic CEMS are calibrated
periodically, so the data are reliable.Using 2019 hourly-averaged data from the diagnostic
(inlet)and certified (i.e., actual stack emissions) CEMs yields SO2 control efficiencies of 90.7%
and 92.7% for Units 1 and 2, respectively.
5.2 NOx Control Measures
The Keystone Station Units 1 and 2 use low-NOx burners and SCR systems to control NOx
emissions. NOx emissions from Units 1 and 2 prior to the installation of the low-NOx burners
(1995) were approximately 0.7 lb/MMBtu (see RACT 1993-1995 proposals submitted to the PA
DEP). When operating conditions are sufficient to allow aqueous ammonia injection in the SCR
(close to the threshold specified in the PA DEP RACT II Rule, see Table 4-1), average NOx
emissions from Units 1 and 2 were 0.104 and 0.103 lb/MMBtu, respectively, in 2019, which
equates to an overall NOx control efficiency of 85%achieved by the low NOx burners and
SCRs. Therefore, based on the current actual NOx emission rate and control efficiency, the
existing NOx controls are highly effective.
6.Emissions Control Options
This section presents an evaluation of potential emissions reduction options applicable to SO2
and NOx emissions from Units 1 and 2.The evaluation starts with listing potential control
options and determining if the option is technically infeasible. For those options considered
technically feasible, an analysis will be conducted considering the four statutory factors:(1)
costs of compliance; (2) the time necessary for compliance; (3) the energy and non-air quality
environmental impacts of compliance;and (4) the remaining useful life of the emission unit.
Following that evaluation are conclusions related to the feasibility and reasonability of
implementing the remaining approaches.
6.1 Identification of Potentially Available SO2 Emissions Reduction Options
There are multiple options for controlling the emissions of SO2 from coal-fired EGUs. These
options fall in three general categories:
─Wet Flue Gas Desulfurization (wet FGD),
2 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019.
3 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019 (Page 23).
Four Factor Analysis
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Project No. 60634468-1
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─“Dry” FGD (e.g.; spray dryer absorber (SDA), circulating dry scrubbers (CDS), or novel
integrated desulfurization (NID)), or
─Dry Sorbent Injection (DSI).
Among these, the most effective at controlling SO2 emissions from coal-fired boilers is a wet
FGD system.Units 1 and 2 at the Keystone Station already have wet limestone FGD,which is
the top level of control in terms of overall efficiency.
The use of dibasic acid, an organic acid buffer,to increase SO2 control was considered. A
buffer increases SO2 control by decreasing the drop in pH at the gas-liquid interface which
occurs as SO2 is absorbed.However, this option was rejected because it can inhibit mercury
control.Increasing the limestone stoichiometric ratio (LSR,moles of Ca per moles of SO2
absorbed) may provide a marginal improvement in SO2 removal. However, the FGD system
already operates at the preferred LSR needed for scrubber operation.
At the Keystone Station, the wet FGD system (spray towers) has five recycle pumps that can
provide five spray levels of limestone slurry injection.Currently, the Station typically operates
three spray levels with the remaining two reserved for backup or occasional use in order to
maintain target emission rates of SO2 and other pollutants (e.g., Hg). Operating a fourth recycle
pump/spray level increases the liquid to gas ratio, thus resulting in a small improvement in SO2
control efficiency.
6.1.1 Costs of Compliance (Factor 1)
At the Station, SO2 emissions are controlled by wet limestone FGD, and as such, SO2
emissions are already well controlled (> 90 percent removal).Therefore, the potentially
available control options to further reduce SO2 emissions are limited to process improvements
and regular operation of a fourth FGD spray pump/level. Keystone Station has already
implemented several process improvements designed to increase the efficacy of the wet FGD
system during the past eleven years, which overlap with the first and second decadal review
periods of the RHR. The process improvements included the following:
Ø Optimized the performance of the slurry recycle pumps for the FGD absorber to allow
for consistent feed of limestone slurry to the spray banks;
Ø Optimized the performance of the limestone ball mill to allow for a finer grade of
pulverized limestone, which in turn allows for a more consistent limestone slurry;
Ø Configured the distributed control system to automatically adjust process variables to
ensure that absorber pH and limestone slurry density are maintained within the
specified tolerances; and,
Ø Implemented a preventative maintenance plan to proactively address potential
equipment issues related to FGD performance.
The regulatory drivers for the process improvements included the following:
Ø EPA’s MATS Rule -compliance with this rule began in April 2015. FGD efficacy
improvements were implemented during the years 2014 through 2020 to ensure
compliance with the MATS mercury emissions limits. These improvements also
resulted in co-beneficial reductions in SO2 emissions as demonstrated in the
summary table below. (The exhaust gas flues for Units 1 and 2 are in a single
chimney, the flue gas streams merge upon discharge to the atmosphere.)
Ø EPA’s 2010 SO2 NAAQS compliance demonstration –A dispersion model analysis
was performed to determine the Units 1 and 2 SO2 emission limit required to
demonstrate compliance with the 1-hour SO2 NAAQS. For Keystone Station, the
Four Factor Analysis
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Project No. 60634468-1
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modeling exercise showed that the new SO2 emission limit, which became applicable
in October 2018 (during the second decadal review period for the RHR) is
approximately 50 percent of the previous emission limit that was applicable when the
FGD systems began operations in late 2009.
Ø Keystone Station also utilizes a dry sorbent (hydrated lime, calcium hydroxide)
injection system at Units 1 and 2 to reduce sulfur trioxide / sulfuric acid mist emissions
as necessary in order to maintain compliance with PA DEP exhaust gas opacity limits.
Keystone Station believes that the alkaline sorbent (injected before the FGD system)
also provides for co-beneficial reductions in SO2 emissions.In 2019, Keystone
Station changed from using a standard hydrated lime product to an “enhanced”
(higher porosity) hydrated lime product, which improved oxidized sulfur removal.
To highlight the downward trend, annual SO2 emissions (tons/year, lb/MMbtu and lb/MWh) for
the past eleven years are shown in Table 6-1 below.
Table 6-1 Annual SO2 Emissions from Keystone Station Units 1 and 2
Unit IDs Year Gross Load
(MW-h)
Heat Input
(MMBtu)
SO2
(tons)
SO2
(lb/MMBtu)
SO2
(lb/MWh)
1 & 2
Combined 2010 14,574,271 130,161,394 39,113 0.60 5.4
1 & 2
Combined 2011 11,998,124 110,717,647 46,441 0.84 7.7
1 & 2
Combined 2012 10,222,266 95,680,332 29,420 0.61 5.8
1 & 2
Combined 2013 13,285,780 120,607,139 26,397 0.44 4.0
1 & 2
Combined 2014 12,317,305 112,359,466 28,138 0.50 4.6
1 & 2
Combined 2015 10,255,389 97,146,022 24,447 0.50 4.8
1 & 2
Combined 2016 11,019,360 105,560,720 22,403 0.42 4.1
1 & 2
Combined 2017 12,672,885 118,766,848 23,250 0.39 3.7
1 & 2
Combined 2018 13,338,898 123,507,053 23,951 0.39 3.6
1 & 2
Combined 2019 11,875,700 112,341,534 19,806 0.35 3.3
1 & 2
Combined 2020*7,931,484 77,364,300 13,011 0.34 3.3
* Preliminary data
Keystone Station believes that the FGD efficacy improvements implemented during the past
eleven years are sufficient to satisfy the PA DEP’s reasonable progress goals for visibility
improvement during the second decadal review period, and that this outcome is consistent with
EPA’s guidance that “reasoned decision-making is a core component of the regional haze
program, and thus of states’ regional haze SIP submissions.”4
However, in order to be complete and thorough, we present the following discussion regarding
the annual cost of regular operation of a fourth level of pumps at the existing wet FGD systems.
4 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019 (Page 1).
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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During 2020, total SO2 emissions for Units 1 and 2 were 13,011 tons/yr. A summary of hourly
inlet and outlet SO2 emission rates for Unit 1 for the period December 22, 2020 through January
6, 2021, based on continuous monitoring, demonstrates that the average SO2 emission rate with
three pumps in service is 0.365 lb/MMBtu and that with four pumps in service is 0.334
lb/MMBtu.In 2020,Unit 1 had an annual heat input of 38,621,586 MMBtu/year.
Operation of a fourth recycle is expected to increase SO2 control efficiency to about 94.2%as
opposed to the 93.6% with three pumps. An increase in SO2 control efficiency to 94.2% will
reduce annual emissions by 600 tons/year for Unit 1 (38,621,586 MMBtu/year x 0.365 lb/MMBtu
-38,621,586 MMBtu/year x 0.335 lb/MMBtu).
The following are the operating costs associated with regularly operating a fourth recycle pump:
·limestone cost;
·solid waste handling and disposal cost;
·Variable O&M costs; and,
·electricity to power the additional pump.
The increase in annual limestone cost would be about $21,710/yr based on an approximate
limestone usage rate of 1.59 tons limestone per ton of SO2 removed and a cost of $22.77 per
ton limestone. Annual electricity costs for a fourth recycle pump would be about $198,072/yr
based on the 2020 annual capacity factor of about 49% and an electricity cost of $26.7/MWh.
The incremental variable operating and maintenance cost is $22,400. Including the modest
savings in CSAPR allowance fee, the incremental annual cost for operating the fourth level of
pumps on a regular basis would be about $247,300/yr and the cost effectiveness would be
about $413 per ton of SO2 controlled for Unit 1.Since Units 1 and 2 are identical, the same
discussion is applicable to Unit 2 as well.
It should be noted that actual SO2 emissions reduction (tons) with a fourth recycle pump in
operation will vary depending upon operating loads, inlet SO2 (coal sulfur content) and other
factors.
6.1.2 Time Necessary for Compliance (Factor 2)
Wet limestone FGD, which is already used at the Station and has been optimized throughout its
service life, is the top level of SO2 control; therefore, no additional SO2 emissions controls are
being evaluated for this four-factor analysis.If determined to be required by the EPA-approved
SIP,Keystone Station can begin operation of the FGD systems with four spray pumps/levels in
regular service within six months of final SIP approval.
6.1.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)
Since a wet limestone FGD system already exists on Units 1 and 2 at the Station, the energy
and non-air quality environmental impacts have already been taken into account.
6.1.4 Remaining Useful Life (Factor 4)
Units 1 and 2 were commissioned in 1967 and 1968, respectively.Although the units have
achieved over 50 years of service,no specific retirement date has been set. Therefore,for
Station planning purposes,the remaining useful life of these units is assumed to be at least 20
years.
6.2 Identification of Potentially Available NOX Emissions Reduction Options
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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Several NOX control options were considered as additions to the current SCR controls for
application to the Keystone Generating Station including Selective Noncatalytic Reduction
(SNCR),Powerspan ECO® system, rich reagent injection, natural gas reburn, coal reburn,
NOxStar, water injection, LoTOX, PerNOxide, ROFA, and ROTAMIX. These technologies were
evaluated for technical feasibility (availability and applicability to Units 1 and 2) based on a
review of possible performance, engineering principals, and an assessment of commercial
availability.The findings are listed in Table 6-2.
Table 6-2 NOx Control Technologies
NOx Control
Option
Description
Rich reagent
injection Similar to SNCR. Only available for cyclone fired boilers.(1)
Natural gas
reburn
Performance is affected by baseline NOx concentration; reburn zone
temperature, residence time,and stoichiometry; overfire burnout zone
temperature and residence time; and mixing of the reburn fuel with the bulk flue
gas. Extensive testing required to make a meaningful prediction of performance.(1)
Based on very limited, if any, applications, natural gas reburn is not expected to
offer a significant emission reduction relative to other options such as an SNCR
and SCR.
Coal reburn Similar to natural gas reburn.
NOxStar
Uses an ammonia-based reagent and small amounts of hydrocarbon injected to
the flue gas at the convective pass of the boiler to reduce NOx. Only one full
scale demonstration project. An emerging technology that would require
extensive design engineering and a long-term full scale demonstration to evaluate
technical feasibility, cost,and performance.(1)
Water injection To date, only bench scale testing on coal firing. Extensive design engineering and
testing would be needed to determine scale-up potential, cost and performance.(1)
LoTOX
A low temperature oxidation system that uses ozone to convert NO and NO2 to
N2O5 for eventual removal by a wet scrubber. No known full-scale, coal-fired
EGU applications.
PerNOxide
Uses hydrogen peroxide injected into the duct ahead of the air preheater. Has
only been tested on a pilot scale. Extensive design engineering and testing would
be needed to determine scale-up potential, cost and performance.(1)
ROFA Rotating opposed overfire air. CFD modelling required to determine performance
but expected to be inferior to an SNCR or an SCR.
ROTAMIX Similar to an SNCR (Proprietary SNCR technology)
(1)Coyote Station Unit 1, North Dakota Regional Haze Second Planning Period Four-Factor Analysis.
Sargent & Lundy, May 8, 2019.
All the above options were rejected for one or more of the following reasons:
1.No commercial availability,
2.Emission control performance of these options is inferior to an SCR,which is already
being used on Units 1 and 2.EPA’s top-down approach suggests that if the top level of
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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control is chosen or as in this case, already installed on the units, no further analysis is
required.
We are, however, presenting costs of tuning/upgrading the existing low-NOx burners to achieve
a small NOx emissions reduction, as discussed in the subsequent sections.
6.2.1 Costs of Compliance (Factor 1)
For both Units 1 and 2, NOx emissions are controlled by low-NOx burners and SCR. The
controlling NOx emission limits are those specified in the PA DEP RACT II Rule, which are as
follows:
Presumptive NOx emission limits for a coal-fired EGU boiler with SCR is 0.12 lb/MMBtu
when flue gas temperature at SCR inlet ≥ 600 deg. F, 0.35 lb/MMBtu when flue gas
temperature at SCR inlet is < 600 deg. F (rolling 30-boiler operating day averaging
period).
In addition, the Keystone Generating Station received a letter from PA DEP on November 17,
2020 requesting submittal of a case-by-case NOx RACT analysis by April 1, 2021. A copy of
this letter is included as Appendix C of this report.The Station expects the proposed NOx
limits of this case-by-case analysis will be more stringent than the current NOx limits. The
revised NOx limits are expected to become effective by January 1, 2023.
Performance of the SCR systems is affected by recent operating modes for the Station. The
Station was originally designed for base load operation. However, due to a decrease in
electrical demand by the regional grid operator (PJM) and increase in supply from (i) newly-
constructed natural gas-fired EGUs (in response to abundant and low-cost natural gas that
became available following development of advanced drilling practices in Pennsylvania) and, to
a much lesser extent, (ii) renewable energy sources over the last few years, operations of Units
1 and 2 now typically cycle on a daily basis. This operation features higher or full load
conditions during daylight hours on the business weekdays with high regional electric demand
and often at loads in the 40% to 70%range or off-line at all other times. The performance of the
SCR system is adversely affected by the low flue gas temperatures that occur at low loads. At
loads below 70%, the flue gas temperature drops below 600°F. At 40% load, the flue gas
temperature drops below 540°F. Injection of aqueous ammonia at these lower flue gas
temperatures results in ammonium bisulfate formation, which deposits on the downstream air
pre-heater and ESP, thus fouling these devices. This issue is the underlying basis for the
bifurcated NOx emission limit scheme in the PA DEP RACT II Rule.Optimization of the existing
SCR systems will be addressed as part of the forthcoming case-by-case NOx RACT analysis.
In order to present a complete and thorough four-factor analysis, the Station discussed with R-V
Industries, Inc., additional NOx reduction options specifically around improving performance of
low-NOx burners at the Conemaugh Station. Since the Conemaugh and Keystone Stations are
sister facilities, equipment retrofit costs for the Conemaugh Station are reasonably applicable to
the Keystone Station units as well.
R-V Industries stated that there is no available low-NOx tip that can be bolted onto the existing
burners. Therefore, R-V Industries’ approach, based on prior experience with tangentially-fired
boilers of a similar size and design, was to install venturis in the windbox ductwork to resize the
burner tips to help minimize excess air and NOx formation and optimize the overall air flow. The
budgetary cost information from R-V Industries is presented in Tables 6-3 and 6-4 and the cost-
effectiveness is presented in Table 6-5.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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The replacement burners can achieve a 17% NOx reduction (~ 0.22 lb/MMBtu NOx emission
rate) when the minimum continuous operating temperature is less than 611°F (i.e., temperature
below which ammonia injection into the SCR cannot commence).
Table 6-3 Low-NOx Burner Replacement/Tuning Capital Cost Estimate –Per
Boiler
Cost Item
Computation
Method Factor Cost Notes
Direct Costs
Purchased
Equipment (PE)
Vendor Quote x
factor 1.00 $1,901,250 Quote provided by R-V Industries,
Inc.
Taxes PE x factor 0 $0 PE exempt from 6% PA sales tax
Freight PE x factor 0.05 $95,063
Table 2.4 of EPA's OAQPS
Control Cost Manual, Sixth
Edition, January 2002.
Total Purchased
Equipment Costs
(PEC)
Sum ----$1,996,313 PE + Taxes + Freight
Direct Installation
Costs
Conemaugh
Station Estimate
(applicable to
Keystone
Station as well)
----$1,700,000
The budgetary estimate does not
consider that all existing dampers
on the current burners would
need to be replaced, which is an
extremely labor intensive effort
that is not accounted for in the
vendor quote. The listed cost
(based on a comparable project)
accounts for this omission.
Total Direct Costs
(TDC)
Sum PEC +
Installation
Costs
----$3,696,313
Installation Costs,
Indirect
Engineering /
supervision TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition,January 2002
Construction / field
expenses TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Construction fee TDC x factor 0.10 $369,631
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Start-up TDC x factor 0.01 $36,963
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Performance test TDC x factor 0.01 $36,963
OAQPS Control Cost Manual,
Sixth Edition, January 2002
Contingencies TDC x factor 0.20 $739,263
Due to the uncertainties
associated with the preliminary,
budgetary nature of the cost
information, a contingency of 20%
is warranted.
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Cost Item
Computation
Method Factor Cost Notes
Modeling and
Optimization Studies
Conemaugh
Station Estimate
(applicable to
Keystone
Station as well)
----$500,000
This budgetary estimate does not
consider a critical analysis of
potential changes in combustion
zone conditions such as lower
temperatures, decreased
combustion efficiency (related to
decreased oxygen availability and
resultant increase in carbon
monoxide) and increase in
corrosion potential around the
furnace walls. The listed cost
(based on a comparable project)
accounts for this omission.
Loss of Revenue
Associated with
Special Outage
Required to Install
Equipment
Lost generation
x factor 25.00 $10,710,000
Factor = Estimated generation
revenue price ($/MWh), 28 day
outage, 850 MW generation
capacity, 75% annual capacity
factor
Total Indirect Costs
(TIC)Sum ----$13,132,083
Total Capital
Investment (TCI)Sum TDC + TIC ----$16,828,395 TDC + TIC
Table 6-4 Low-NOx Burner Replacement/Tuning Annual Cost Estimate
Cost Item
Computation
Method Factor Cost Notes
Direct Operating Costs
Operating Labor -
Operator (OL)---------
No additional OL costs
expected
Operating Labor -
Supervision ---------
No additional Supervisory
Labor costs expected
Maintenance Labor
(ML)---------
No additional ML costs
expected
Maintenance Materials ---------
No additional Maintenance
Material costs expected
Total Direct Operating
Costs (DOC)Sum $0
Indirect Operating Costs
Overhead (OL + ML) x
factor 0.80 $0
No change from current
conditions; i.e., Overhead is
included in the current
overhead cost of the existing
burners
Property Taxes TCI x factor 0.01 $168,284 OAQPS Control Cost Manual,
Sixth Edition, January 2001
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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Cost Item
Computation
Method Factor Cost Notes
Insurance TCI x factor 0.01 $168,284 OAQPS Control Cost Manual,
Sixth Edition, January 2002
Administration TCI x factor 0.02 $336,568 OAQPS Control Cost Manual,
Sixth Edition, January 2002
Capital Recovery (1)TCI x factor 0.0944 $1,588,481
Factor per Equation 2.8a of
EPA's OAQPS Control Cost
Manual, Sixth Edition, 2002.
(20 year life and 7% interest
rate).
Total Indirect
Operating Costs (IOC)Sum ----$2,261,617
Total Annualized
Cost (TAC)
Sum DOC+
IOC ----$2,261,617 Per unit
(1)Based on information available from the Station, the firm-specific nominal interest rate for the
Keystone Station is at least 7%. A 7% interest rate has been set by the United States Office of
Management and Budget (OMB) and is described in the January 2002 EPA Air Pollution Control Cost
Manual. Over the years, 7% has been used as a consistent basis for evaluating emission control
options for BACT, RACT and BART analyses. As shown in Table 23 on Page 70 in PA DEP’s June
2018 Technical Support Document for General Operating Permit for Unconventional Natural Gas Well
Site Operations and Remote Pigging Stations (GP-5A) and the General Plan Approval and General
Operating Permit for Natural Gas Compression Stations, Processing Plants, and Transmission
Stations (GP-5), PA DEP also supports use of an interest rate of 7%.
Table 6-5 Low-NOx Burner Replacement/Tuning Cost-Effectiveness ($/ton NOx
Removed)
Unit
No.
NOx Before
Control (1)
(tons/yr)
NOx After
Control (2)
(tons/yr)
Total
Annualized
Cost (3)($/yr)
Cost
Effectiveness
($ / ton NOx
Removed)
1 3,937 3,780 $2,261,617 $14,405
2 3,203 3,079 $2,261,617 $18,239
Average $16,322
(1)Based on CY2019 actual annual emissions. See Table 4-1.
(2)Based on available emissions and operating data for CY2019, the LNB upgrades are
expected to reduce emissions by 157 tons/year for Unit 1 and 124 tons/year for Unit 2.
(3)See Table 6-4 for calculation of annual costs.
As shown in Table 6-5, the cost of installation of per ton of NOx removed is excessive at an
average of $16,300/ton of NOx removed.
6.2.2 Time Necessary for Compliance (Factor 2)
Considering the extent, cost and duration of the outage associated with the low-NOx burner
tune-up project, if determined to be required, the Station expects that this project would not be
able to be completed for at least five years following an approval to proceed (plans for major
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
AECOM
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capital projects and major outages at the Station are prepared with five-year forecasts).
Permitting can take up to nine months (to ensure that appropriate federally enforceable
operating limits and conditions are established in the Plan Approval / construction permit as
issued by the PA DEP) with an additional twelve months required for completion of the modeling
study, final design, purchase and implementation. As noted above, optimization of the existing
SCR systems will be addressed as part of the forthcoming case-by-case NOx RACT analysis,
and the revised NOx limits are expected to become effective by January 1, 2023 (within two
years).
6.2.3 Energy and Non-Air Quality Environmental Impacts (Factor 3)
There are no unacceptable energy or non-air quality environmental impacts associated with
operation of the existing or the upgraded low-NOx burners and SCR systems on Units 1 and 2
at the Keystone Generating Station.
6.2.4 Remaining Useful Life (Factor 4)
EPA’s 2019 regional haze guidance states that the remaining useful life is the number of years
that the “new control equipment” is expected to be in service. Therefore, for in-service dates in
the 2025 to 2028 range, a 20-year useful life means that the coal-fired EGU on which the control
is installed, is expected to be operating in the 2045 to 2048-time frame. A 30-year useful life
means that the EGU is expected to be in operation in the 2055 to 2058-time frame. Although
the projected life of a new control system may be 30 years, the remaining useful life of an
existing EGU may be less than 30 years due to its current age and the current economic
dispatch competition from other sources of electricity (nuclear, combined-cycle natural gas and
renewable energy).
During the first regional haze planning period, a 20-year useful life was accepted as a default by
the EPA. This has proven to be overly optimistic as approximately 30% of the coal-fired
generation capacity in the U.S. has been retired in the 10-year period since 2009. Additional
retirements have been announced and are expected to continue (e.g., see the following link:
https://www.genon.com/genon-news/genon-holdings-inc-announces-retirement-of-morgantown-
coal-units) due to competition from natural gas-fired EGUs, renewable energy and other
environmental and non-environmental factors.
Units 1 and 2 were commissioned in 1967 and 1968, respectively and as mentioned previously,
no specific retirement date has been set for either of them. Therefore,for Station planning
purposes,the remaining useful life of these units is assumed to be 20 years.
7.Additional 5th Factor Consideration -Visibility Impacts
The goal of the RHR is to improve the visibility in Class I areas. Accordingly, when evaluating
possible emissions reduction projects or programs, it is appropriate to consider the degree to
which individual control projects might contribute towards that goal. Although states have a
statutory requirement to consider the “4 factors” addressed in the earlier portion of this report,
EPA’s guidance5 also allows inclusion of a “5th factor” which involves consideration of visibility
impacts of candidate control options.This section addresses the visibility impacts of current
operations as well as the impact of the marginal SO2 control offered by operating a fourth level
of spray pumps.As explained below, because the visibility impacts attributable to the Keystone
5 US EPA;“Guidance on Regional Haze State Implementation Plans for the Second Implementation Period” in August 2019.Available at
https://www.epa.gov/sites/production/files/2019-08/documents/8-20-2019_-_regional_haze_guidance_final_guidance.pdf.
Four Factor Analysis
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Project No. 60634468-1
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16
Station are low, further controls and/or lower emission limits, even if technically and
economically feasible, would not yield material visibility benefits at any of the regional Class I
areas because the Station’s Units 1 and 2’s current emissions have a very low visibility impact.
7.1 EPA Guidance Regarding Considerations of Visibility Impacts
The EPA issued “Guidance on Regional Haze State Implementation Plans for the Second
Implementation Period” in August 2019. This guidance allows a state, as part of its
consideration of emission controls, to include a “5th factor” consideration of visibility impacts of
candidate control options.
On pages 36 and 37 of this guidance, the EPA notes that concerning the underlying regulation
for ascertaining reasonable further progress, the regulation:
“assumes that the state will consider visibility benefits as part of the analysis. Section
51.308(f)(2)(i) of the Regional Haze Rule requires consideration of the four factors listed
in CAA section 169A(g)(1) and does not mention visibility benefits. However, neither the
CAA nor the Rule suggest that only the listed factors may be considered.Because the
goal of the regional haze program is to improve visibility, it is reasonable for a state to
consider whether and by how much an emission control measure would help achieve
that goal.” . . .
“. . . EPA interprets the CAA and the Regional Haze Rule to allow a state reasonable
discretion to consider the anticipated visibility benefits of an emission control measure
along with the other factors when determining whether a measure is necessary to make
reasonable progress.”
Consequently, an expectation of a very low impact to Class I visibility impairment from control of
certain facility pollutants is appropriate for consideration when evaluating the need for further
control of these emissions for Regional Haze Reasonable Progress.
EPA’s 2019 RHR guidance does not specifically state what would constitute an insignificant
visibility impact, but the preamble to the 1999 RHR (64 FR 35730)does specify a “no
degradation” visibility change if the impact is less than 0.1 deciview.In addition, MANE-VU
determined in the first decadal review that a visibility improvement less than 0.1 deciview
individual impact does not warrant consideration of additional controls6.This amount of visibility
change (for the worst 20% haze days)is on the order of 1%or less of the 2028 glidepath target,
so it constitutes a very low value.It should be noted that the 0.1 deciview benchmark is not in
and of itself an “off-ramp” for disqualifying the candidate control options being considered.
States need to review the already-installed emissions controls, the feasibility, effectiveness and
cost of an additional control option, as well as its visibility impact together in order to arrive at a
decision.
7.2 Class I Areas Near Keystone Generating Station
Class I areas in the eastern United States near Pennsylvania are shown in Figure 7-1. The
closest Class I areas are Dolly Sods and Otter Creek Wilderness Areas in West Virginia and
Shenandoah National Park in Virginia. Other Class I areas within 400 km include Brigantine
Wilderness Area (New Jersey) and James River Face Wilderness Area (Virginia).
6 77 FR 17367 (March 26, 2012).
Four Factor Analysis
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Figure 7-1 Class I Areas in the Vicinity of Keystone Generating Station
Four Factor Analysis
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7.3 MANE-VU CALPUFF Modeling
Pennsylvania is one of the states within the Mid-Atlantic/Northeast Visibility Union (MANE-VU)
Regional Planning Organization. In 2016, MANE-VU conducted visibility modeling using 2015
Electrical Generating Unit (EGU) to determine visibility impacts of em ission sources at Class I
areas within MANE-VU. This modeling was conducted with the CALPUFF model, which was
used for visibility modeling for the first decadal review.
Specific aspects of the MANE-VU modeling that are worth noting are as follows:
·2011 and 2015 emissions were considered (emission reductions since 2011 and 2015
are not accounted for, making this analysis significantly dated and questionable for
accuracy)
·95th percentile emission rates were assumed to occur continuously (this approach can
significantly overstate actual emissions, even for the outdated inventory used)
·CALPUFF was applied for distances from sources to Class I areas far exceeding the
Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 advisory7 that use of
CALPUFF for distances beyond 200 km could introduce significant overprediction biases
in the results.
·CALPUFF is a screening model that has been delisted as an EPA-preferred long-range
transport model (Appendix W updates in 2017, as proposed in 2015). It is puzzling why
MANE-VU relied upon this screening model for determining sources that are asked to
conduct four-factor analyses; no other Regional Planning Organizations have used
CALPUFF modeling for the Second Decadal Review.
·CALPUFF evaluations8 indicate large overpredictions of nitrate haze, especially in
winter, due the dated formulation used in the model. The default MESOPUFF-II
formulation has limitations for winter applications, where it results in overpredictions
approaching a factor range of 4-6 in the evaluations noted in the reference.
·The statistic reported from the CALPUFF modeling was the highest day’s impact, which
is a significant departure from the 8th highest day for the first decadal review and the
average of the 20% most impaired days for the second decadal review.
Due to widespread use of photochemical grid models such as CAMx by every other Regional
Planning Organization in the country, the next sub-section discusses available CAMx modeling
for some Pennsylvania EGUs (including the Keystone Generating Station)conducted by the
southeastern states Regional Planning Organization, VISTAS / SESARM.
7.4 VISTAS CAMx Modeling Analysis
The impact to Class I area visibility of current Station emissions and hypothetical reductions to
SO2 and NOx emissions can be determined by analyzing the results of visibility modeling
conducted by the VISTAS / SESARM9 Regional Planning Organization that included emissions
for some Pennsylvania power plants including the Keystone Generating Station. The VISTAS
modeling was conducted by Alpine Geophysics and utilized advanced CAMx modeling including
modeling particulate matter simulations and source apportionment studies.Determinations of
the haze contributions of specified large sources was accomplished by “tagging” the selected
sources for determining their contribution to impairment at each Class I area of interest.The
tagged sources included the Keystone Generating Station.The results of VISTAS modeling
7 IWAQM Phase 2 report, Appendix D. Available at http://www.epa.gov/scram001/7thconf/calpuff/phase2.pdf.
8 Joseph Scire presentation at the EPA 10th Modeling Conference, available at https://www3.epa.gov/scram001/10thmodconf/presentations/3-5-
CALPUFF_Improvements_Final.pdf.
9 “VISTAS” is an acronym for Visibility Improvement -State and Tribal Association of the Southeast and “SESARM” stands for Southeastern
States Air Resource Managers, Inc.Their web site for Regional Haze Rule modeling results is https://www.metro4-sesarm.org/content/vistas-
regional-haze-program.
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analysis of Keystone Station’s total emissions can be used, with emissions scaling, to estimate
the visibility impacts of Keystone Station Units 1 and 2’s current (2019) actual emissions.
Visibility impairment is commonly expressed using two parameters to characterize the visibility
impairment:
·Light Extinction (bext)is the reduction in light due to scattering and absorption as it
passes through the atmosphere. Light extinction is directly proportional to pollutant
particulate and aerosol concentrations in the air and is expressed in units of inverse
megameters or Mm-1.
·Deciview (DV)is a unitless metric of haze which is proportional to the logarithm of the
light extinction. Deciview correlates to a person’s perception of a visibility change, with a
change of 1 deciview being barely perceptible. The “no degradation” value of 0.1 DV
stated in the 1999 Regional Haze Rule is only 10% of this perceptibility threshold.
Both metrics are helpful in understanding changes to visibility impairment, but while the
deciview is the best parameter to relate the significance of a perceived visibility change,
modeling produces results in the form of light extinction using the new IMPROVE equation that
converts particulate concentrations to visibility impairment. A chart shown in Figure 7-2 is taken
from the VISTAS Regional Haze modeling project update (webinar)updated on September 10,
2020 (after being originally presented on May 20, 2020). It shows, in units of deciview, the
actual visibility measurements and projected modeling results of visibility for most impaired days
at the Shenandoah National Park.
Figure 7-2 shows that actual visibility measurements (the diamonds) confirm a strong trend of
improved visibility in the past 10 years from about 27 DV to about 16 DV. This rate of actual
improvement is much faster than the RHR target to maintain a “uniform rate of progress” or
“glide path” (the pink line), which could be revised to a less-steep revised glide path to account
for internationally-caused haze. However, VISTAS believes that since the Class I areas in this
region are so far ahead of projections, that refinement is not necessary at this time.
Additionally, VISTAS modeling of the expected emissions reductions in the coming years (on-
the-books / on-the-way controls) projects (the blue line) that visibility should continue to
significantly improve, reaching approximately 14.47 DV by the next RHR milestone year of
2028. This chart shows that visibility in this Class I area is currently running at least 20 years
ahead of the RHR targets and is expected to continue to do so. VISTAS modeling of other
regional Class I areas shows very similar trends and are all far ahead of their glide path targets.
Therefore, no additional emissions reductions at any regional facilities, beyond those already
planned, are needed to continue to meet the RHR interim goals.
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Figure 7-2 Visibility Trends at Shenandoah National Park
7.5 Visibility Impact of Keystone Station’s Units 1 and 2 SO2 and NOx Emissions
The VISTAS modeling used 2011 annual emissions for the tagged stations to develop the units’
projected 2028 emissions, and these values can be scaled to current representative emissions
for the Keystone Generating Station. PA DEP has stipulated that 2019 emissions should be
considered as representative for this analysis.The adjusted 2028 emissions modeled for
Keystone were 21,066 tons of SO2 and 5,086 tons of NOx.The representative current
emissions (2019) for the Keystone Generating Station were 19,806 ton of SO2 and 7,140 tons of
NOx.Keystone Station’s current best estimate is that Unit 1 and 2’s 2019 actual emissions are
a reasonable projection of their 2028 emissions.With linear scaling, this results in a modeled
impact at the Shenandoah National Park and other nearby Class I areas based upon the
VISTAS modeling as shown in Table 7-1.
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Table 7-1 Haze Impact from Keystone Generating Station’s Total 2019
Emissions of SO2 and NOx at Class I Areas Within 400 km
Class I Areas Nearest to the
Keystone Generating Station
Total Haze Impact from
2019 SO2 Emissions from
the Keystone Generating
Station
Total Haze Impact
from 2019 NOx
Emissions from the
Keystone Generating
Station
Mm-1 DV *Mm-1 DV *
Shenandoah National Park 0.696 0.083 0.013 0.002
Brigantine Wilderness Area 0.342 0.041 0.055 0.007
Dolly Sods Wilderness Area 0.232 0.028 0.001 0.000
Otter Creek Wilderness Area 0.179 0.021 0.001 0.000
James River Face Wilderness Area 0.204 0.025 0.008 0.001
* Potential Improvement in DV is listed for the 20% most impaired days for each Class I
area. Conversion between deciviews and extinction is based upon the 2028 glidepath goal
extinction as a reference point.
The VISTAS CAMx modeling results for tagged individual source visibility impacts are expressed as light extinction, in
units of inverse megameters. Another visibility metric is deciviews, which can be determined from extinction through a
logarithmic relationship, as noted in an EPA 2003 reference10 for tracking progress under the Regional Haze Rule. That
reference indicates (in Section 3.9) that a change of 1 deciview is equivalent to about a 10% change in extinction
coefficient, and Internet tools such as that available at http://vista.cira.colostate.edu/Improve/haze-metrics-converter/
can easily do the conversion. Recent guidance from EPA, issued in 2018, is “Technical Guidance on Tracking Visibility
Progress for the Second Implementation Period of the Regional Haze Program”11. This guidance indicates that the total
anthropogenic impairment:
“is the difference (the ‘delta deciviews’) between the total deciview value that exists (or is projected to exist) and the
deciview value that would have existed if there were only natural sources causing reduced visibility.This is the metric
that EPA recommends be used. We recommend that states use Equation 2 to calculate anthropogenic visibility
impairment:
∆ dv (anthropogenic visibility impairment) = dv (total)–dv (natural) (Eqn. 2),
where dv (total) is the overall deciview value for a day, and dv (natural) is the natural portion of the deciview value for a
day.
We are considering the question: What is the difference in anthropogenic visibility impairment due to a proposed
emission control? To determine this, one would use above equation twice to take the difference of two ∆dv
(anthropogenic visibility impairment) values. In so doing, the term dv (natural) cancels out. To determine the difference
caused by a proposed control action, we conservatively use the 2028 extinction goal to determine the conversion of
extinction to deciviews. With a 2028 extinction goal of approximately 80 Mm-1, the conversion between a difference of 1
Mm-1 (relative to the 2028 goal of 80 Mm-1) would be about 0.12 delta-dv.
Table 7-1 shows that total actual 2019 emissions of SO2 from the Keystone Generating Station
contributed only 0.696 Mm-1 light extinction at the Shenandoah National Park Class I area,
based upon 2019 actual emissions of 19,806 tons. This equates to a deciview value of 0.083
DV, which is a 0.58%contribution to total impairment –an insignificant portion of the 2028
projected ~14.47 DV visibility at the Shenandoah National Park. As indicated previously, EPA
has indicated that a DV change of less than 0.1 DV can be considered “no-degradation.”
Therefore,current SO2 emissions from Units 1 and 2 do not significantly contribute to visibility
degradation at Shenandoah National Park.Likewise,the Station’s current NOx emissions’
visibility impact (0.007 DV at Brigantine Wilderness)is well below the no degradation threshold
of 0.1 DV and less than 0.04% of the 2028 projected visibility at the Brigantine Wilderness Area
10 https://www3.epa.gov/ttnamti1/files/ambient/visible/tracking.pdf.
11 Available at https://www.epa.gov/sites/production/files/2018-12/documents/technical_guidance_tracking_visibility_progress.pdf.
Four Factor Analysis
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(18.4 DV). Therefore, any projects that reduce NOx emissions at the Station would have a
potential visibility improvement far less than the no-degradation threshold.
8.Conclusion
Emissions of SO2 and NOx from Units 1 and 2 at the Station are already well controlled by wet
FGD and SCR.Substantial SO2 and NOx emission reductions have already been achieved with
the existing emission controls.Since the 2006-2008 period, annual SO2 emissions have been
reduced by 89% and NOx emissions have been reduced by 48%.Improvements in visibility at
the nearest Class I areas are well ahead of the uniform rate of progress glide path.
The existing wet FGD and SCR are the best available emission control options and no other
technically feasible, more efficient controls have been identified.The combination of the FGD
and SCR also provides for effective emissions control for the MATS Rule pollutants (acid gases,
mercury and other non-mercury metals) and particulate matter.Regular operation of a fourth
level of pumps in the existing FGD systems had a cost effectiveness of $413/ton SO2 removed.
Replacement/tuning of the existing low-NOx burners was also evaluated and the cost
effectiveness of this control measure is excessive at $16,300/ton NOx removed. Additionally,
recent VISTAS visibility modeling conducted using advanced photochemical grid modeling
suggests that visibility impacts of the Station’s 2019 NOx emissions are less than one-tenth of
the threshold designated as a “no degradation” visibility change. Lastly, the Station will be
submitting a case-by-case NOx RACT analysis to the PA DEP by April 21, 2021 which is
expected to result in more stringent NOx limits.
Therefore, for Keystone Generating Station’s Units 1 and 2, no additional controls are needed in
order for PA DEP to meet their reasonable progress goal for the Second Decadal Review.
Four Factor Analysis
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Appendix A
PA DEP Four-Factor Analysis Request Letter
Four Factor Analysis
Keystone Generating Station Units 1 and 2
Project No. 60634468-1
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Appendix B
Summary of VISTAS Visibility Modeling Results
SO2 (tpy):21,066 SO2 (tpy):19,806
NOX (tpy):5,086 NOX (tpy):7,140
Extinction for 20% Worst Haze Days
Class I Area
Total
Modeled
Sulfate
Extinction
Mm-1
Total
Modeled
Nitrate
Extinction
Mm-1
Scaled
Modeled
Impacts
Results:
Sulfate
Extinction
Mm-1
Scaled
Modeled
Impacts
Results:
Nitrate
Extinction
Mm-1
Shenandoah NP 0.7400 0.0093 0.6957 0.0130
Brigantine WA 0.3637 0.0394 0.3419 0.0554
Dolly Sods WA 0.2464 0.0008 0.2317 0.0011
Otter Creek WA 0.1902 0.0008 0.1788 0.0011
James River Face
WA 0.2172 0.0054 0.2042 0.0076
Data from ATTACHMENT_A_PSAT_TAG_RESULTS_adjusted_08-11-2020.xlsx.
Projected 2028 Visibility at Current Emissions Levels
Mm-1 DV Mm-1 DV
0.696 0.083 0.013 0.002
0.342 0.041 0.055 0.007
0.232 0.028 0.001 0.000
0.179 0.021 0.001 0.000
0.204 0.025 0.008 0.001
0.12 DV per Mm-1 (See explanation in report)
Table B-1 Estimated Haze based on Current Emissions from Units 1 and 2 at the Keystone
Station
Keystone Adjusted 2028
Emissions Modeled 2019 Keystone Emissions
Class I Areas Nearest to Keystone
Generating Station
Total Haze Impact from 2019
SO2 Emissions
Total Haze Impact from 2019
NOx Emissions
Shenandoah National Park
Brigantine Wilderness Area
Dolly Sods Wilderness Area
Otter Creek Wilderness Area
James River Face Wilderness Area
Keystone Station
Four Factor Analysis Table B-1 (Haze Calcs)January 2021
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Appendix C
PA DEP Request for a Case-by-Case RACT Analysis

November 25, 2020

Via Email Delivery – [e-mail]
Mr. Eric A. Gustafson
Regional Air Quality Program Manager
Pennsylvania Department of Environmental Protection
Northwest Regional Office
230 Chestnut Street
Meadville, PA 16335

Re: Keystone Generating Station – Title V Operating Permit No. 03-00027
Acknowledgement of Department’s Request for Case-by-Case RACT Analysis for
Two Existing Coal-Fired Combustion Units Equipped with Selective Catalytic
Reduction (SCR) System

Dear Mr. Gustafson:
Keystone Station is in receipt of the attached letter, which includes the following request:

Please confirm in writing, within 10 days of receipt of this correspondence, that your
facility will submit complete case-by-case RACT II determinations for existing coal-fired
combustion units which are equipped with SCR to DEP, along with a significant operating
permit modification application, on or before April 1, 2021.

Keystone Station is planning to submit the above-mentioned determination and application on or
before April 1, 2021. It is our understanding that once the determination is approved, the
applicable requirements will be captured in an updated Title V operating permit and will both
supersede the existing RACT II Rule requirements and satisfy the Department’s forthcoming
RACT III Rule requirements.

If you have questions or concerns regarding this letter, then please contact me at [phone]
or [e-mail].

Very truly yours,
Nathan J. Rozic
Environmental Specialist – Keystone Generating Station

Cc: Joseph Kushner, Strategy & Compliance Manager – Keystone and Conemaugh Stations
Keystone Generating Station
313 Keystone Drive
Shelocta, PA 15774

November 17, 2020

Nathan J. Rozic – Environmental Specialist mailto:[e-mail]
Keystone Conemaugh Project LLC
175 Cornell RD STE 1
Blairsville, PA 15717

Re: RACT II regulation Implementation, §§ 129.96 to 129.100
Keystone Station
Title V Permit No: 03-00027
Plumcreek Township, Armstrong County

Dear Mr. Nathan J. Rozic:

On August 27, 2020, the U.S. Third Circuit Court of Appeals issued an opinion in Sierra Club v.
EPA, 3d. Cir. No. 19-2562 (“Sierra Club”) vacating and remanding three aspects of the U.S.
Environmental Protection Agency’s (EPA) May 19, 2019 approval of DEP’s 2016 reasonably
available control technology (RACT II) Rule to reduce ozone pollution from coal-fired power
plants (84 FR 20274). Sierra Club challenged EPA’s approval of the RACT II Rule’s oxides of
nitrogen emission limit for coal-fired power plants with selective catalytic reduction (SCR)
pollution controls; the inlet operating temperature threshold for power plants to operate SCR
pollution controls; and operating temperature data recordkeeping and reporting requirements.
The Court found EPA’s approval of these three provisions of the RACT II Rule to be arbitrary
and capricious, because they were not supported by the administrative record. As a result, the
Court vacated EPA’s approval of these three provisions and remanded them back to the agency
for further action. The vacated portion of the RACT II Rule affects your facility.

As a result of the Court’s decision in Sierra Club, DEP is required to address RACT II
requirements for existing coal-fired combustion units with SCR systems. DEP has determined
that the best method to do this is through requiring the owner or operator of each unit affected by
the Court’s decision to submit case-by-case RACT II determinations that satisfy 25 Pa. Code §
129.99 (relating to alternative RACT proposal and petition for alternative compliance schedule)
requirements. Case-by-case RACT determinations must be developed in accordance with the
procedures in §129.92(a)(1)—(5) and (b), which includes a top-down analysis. DEP will review
the proposed case-by-case determinations and incorporate the final determinations and associated
conditions into your facility’s Title V operating permit in accordance with 25 Pa. Code §
127.542 (relating to revising an operating permit for cause). The RACT determinations
incorporated into the Title V operating permit will then be submitted to EPA as a state
implementation plan revision.

Please confirm in writing, within 10 days of receipt of this correspondence, that your facility will
submit complete case-by-case RACT II determinations for existing coal-fired combustion units
Nathan J. Rozic Keystone Station November 17, 2020
which are equipped with SCR to DEP, along with a significant operating permit modification
application, on or before April 1, 2021. If you are planning to modify any existing equipment or
install a control device as a result of your RACT II determination, please contact us regarding the
need to submit a plan approval application. Please note that DEP is waiving permit fees for
review of the significant operating permit modification application.

If you have any questions, please contact me at 814-656-1346 or [e-mail].

Sincerely,

Eric A. Gustafson

Eric A. Gustafson
Program Manager
Northwest Region Air Quality Program

cc: Mark Hammond, Bureau Director
Hbg. – Permits
File

VISTAS Consultation with PA Bureau of Air Quality
Homer City Gen LP/Center TWP (42063-3005211)

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Correspondence Record
Date From To Description
June 22,
2020
VISTAS PA Bureau of
Air Quality
Request for Regional Haze Reasonable
Progress Analyses for Pennsylvania
Sources Impacting VISTAS Class I Areas
October
30, 2020
Homer City
Generation/
PA Bureau of
Air Quality
VISTAS Four Factor Analysis for Regional Haze, Homer
City Generating Station, Units 1, 2 and 3

- 1 -

Visibility Improvement State and Tribal Association of the Southeast

June 22, 2020

Virendra Trivedi, Acting Director
Pennsylvania Bureau of Air Quality
PO Box 8468
Harrisburg, Pennsylvania 17105-8468

RE: Request for Regional Haze Reasonable
Progress Analyses for Pennsylvania
Sources Impacting VISTAS Class I Areas

Dear Mr. Trivedi:

The Regional Haze Regulation 40 CFR § 51.308(d) requires each state to “address regional haze
in each mandatory Class I Federal area located within the State and in each mandatory Class I
Federal area located outside the State which may be affected by emissions from within the
State.” 40 CFR § 51.308(f) requires states to submit a regional haze implementation plan
revision by July 31, 2021. As part of the plan revision, states must establish a reasonable
progress goal that provides for reasonable progress towards achieving natural visibility
conditions for each mandatory Class I Federal area (Class I area) within their state . 40 CFR §
51.308(d)(1) requires that reasonable progress goals “must provide for an improvement in
visibility for the most impaired days over the period of the implementation plan and ensure no
degradation in visibility for the least impaired days over the same period.”

In establishing reasonable progress goals, states must consider the four factors specified in §
169A of the Federal Clean Air Act and in 40 CFR § 51.308(f)(2)(i). The four factors are: 1) the
cost of compliance, 2) the time necessary for compliance, 3) the energy and non-air quality
environmental impacts of compliance, and 4) the remaining useful life of any potentially
affected sources. Consideration of these four factors is frequently referenced as the “four-
factor analysis.”

To assist its member states, the Visibility Improvement State and Tribal Association of the
Southeast1 (VISTAS) and its contractors conducted technical analyses to help states identify

1 The VISTAS states are Alabama, Florida, Georgia, Kentucky, Mississippi, North Carolina, South Carolina,
Tennessee, Virginia, and West Virginia.

- 2 -

sources that significantly impact visibility impairment for Class I areas within and outside of the
VISTAS region. VISTAS initially used an Area of Influence (AoI) analysis to identify the areas and
sources most likely contributing to poor visibility in Class I areas. This AoI analysis involved
running the HYSPLIT Trajectory Model to determine the origin of the air parcels affecting
visibility within each Class I area. This information was then spatially combined with emissions
data to determine the pollutants, sectors, and individual sources that are most likely
contributing to the visibility impairment at each Class I area. This information indicated that the
pollutants and sector with the largest impact on visibility impairment were sulfur dioxide (SO2)
and nitrogen oxides (NOx) from point sources. Next, VISTAS states used the results of the AoI
analysis to identify sources to “tag” for PM (Particulate Matter) Source Apportionment
Technology (PSAT) modeling. PSAT modeling uses “reactive tracers” to apportion particulate
matter among different sources, source categories, and regions. PSAT was implemented with
the Comprehensive Air Quality Model with extensions photochemical model (CAMx Model) to
determine visibility impairment due to individual sources. PSAT results showed that in 2028 the
majority of visibility impairment at VISTAS Class I areas will continue to be from point source
SO2 and NOx emissions. Using the PSAT data, VISTAS states identified, for reasonable progress
analysis, sources shown to have a sulfate or nitrate impact on one or more Class I areas greater
than or equal to 1.00 percent of the total sulfate plus nitrate point source visibility impairment
on the 20 percent most impaired days for each Class I area. This analysis has identified the
following sources in Pennsylvania that meet this criterion:

• NRG Wholesale Gen/Seward Gen Sta (42063-3005111)
• Homer City Gen LP/Center TWP (42063-3005211)
• Genon NE Mgmt Co/Keystone Sta (42005-3866111)

Information regarding projected 2028 SO2 and NOx emissions and visibility impacts on VISTAS
Class I areas is shown in the tables attached to this letter (Attachment 1).

As required in 40 CFR § 51.308(d)(1)(i)(A), VISTAS, on behalf of Georgia, North Caroli na, South
Carolina, Tennessee, Virginia, and West Virginia, requests that Pennsylvania conduct, or require
that the sources in question initiate, and share when completed, the results of a reasonable
progress analysis for each noted source with VISTAS. This will be helpful to the VISTAS states as
they begin the formal Federal Land Manager consultation process for their individual draft
Regional Haze Plans in early 2021. So that the VISTAS states can include the results of your
state's reasonable progress analyses in developing the long-term strategies for Class I areas in
their states, we request that you submit this information to VISTAS no later than October 30,
2020. If any reasonable progress analyses cannot be completed by this date, please provide, no
later than this date, notice of an attainable date for completion of the analysis. If you
determine that a four-factor analysis is not warranted for one or more of the identified sources,
please provide the rationale for this determination by the requested date.

In developing projected 2028 emissions for these sources, VISTAS utilized ERTAC_16.0
emissions projections and sought additional input from Pennsylvania in February 2020. Please

- 3 -

review these projections to verify that they are reasonable. Should you be aware of significantly
different emission projections for 2028 for any of the sources or pollutants, please provide
revised estimates within thirty (30) days of the date of this letter. The applicable VISTAS states
will review any revised emission estimates, determine if reasonable progress analyses are not
needed to meet their regional haze obligations, and notify you accordingly.

Updated 2028 emission projections, if necessary, the results of your state’s reasonable pr ogress
analyses for the requested sources, and any necessary ongoing communications should be sent
via email to [e-mail].

Should you have any questions concerning this request, please contact me through September
30, 2020, at 404-361-4000 or [e-mail].

Sincerely,

John E. Hornback
Executive Director
Metro 4/SESARM/VISTAS

Attachment

Copies: Karen Hays, Georgia Air Protection Branch
Mike Abraczinskas, North Carolina Division of Air Quality
Rhonda Thompson, South Carolina Bureau of Air Quality
Michelle Walker Owenby, Tennessee Division of Air Pollution Control
Mike Dowd, Virginia Air and Renewable Energy Division
Laura Crowder, West Virginia Division of Air Quality
Marc Cone, Mid-Atlantic Regional Air Management Association
Paul Miller, Northeast States for Coordinated Air Use Management

- 4 -

Attachment 1: Projected 2028 SO2 and NOx Emissions and VISTAS Class I Area Impacts

Table 1. NRG Wholesale Gen/Seward Gen Sta (42063-3005111)
Modeled SO2 = 6,813.9 tpy, Modeled NOx = 1,632.9 tpy

Table 2. Homer City Gen LP/Center TWP (42063-3005211)
Modeled SO2 = 9,274.9 tpy, Modeled NOx = 4,962.3 tpy

Table 3. Genon NE Mgmt Co/Keystone Sta (42005-3866111)
Modeled SO2 = 21,066.4 tpy, Modeled NOx = 5,086.3 tpy

Impacted VISTAS Class I Area
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.172 0.003 15.375 1.12% 0.02%

Impacted VISTAS Class I Areas
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.274 0.010 15.375 1.78% 0.06%
Swanquarter Wilderness Area 0.151 0.008 10.894 1.38% 0.07%

Impacted VISTAS Class I Areas
Sulfate
PSAT
(Mm-1)
Nitrate
PSAT
(Mm-1)
Total EGU & non-
EGU Sulfate +
Nitrate (Mm-1)
Sulfate
PSAT %
Impact
Nitrate
PSAT %
Impact
Shenandoah NP 0.740 0.009 15.375 4.81% 0.06%
Swanquarter Wilderness Area 0.375 0.009 10.894 3.44% 0.09%
Cape Romain Wilderness 0.320 0.002 14.028 2.28% 0.01%
Linville Gorge Wilderness Area 0.235 0.000 12.884 1.82% 0.00%
James River Face Wilderness 0.217 0.005 14.404 1.51% 0.04%
Dolly Sods Wilderness 0.246 0.001 19.349 1.27% 0.00%
Shining Rock Wilderness Area 0.151 0.000 12.313 1.23% 0.00%
Great Smoky Mountains NP 0.166 0.001 13.916 1.19% 0.01%
Wolf Island Wilderness 0.149 0.002 12.957 1.15% 0.01%
Joyce Kilmer-Slickrock Wilderness 0.154 0.000 13.694 1.12% 0.00%
Cohutta Wilderness Area 0.137 0.002 13.229 1.04% 0.01%
Okefenokee Wilderness Area 0.137 0.002 13.400 1.02% 0.01%
Otter Creek Wilderness 0.190 0.001 19.077 1.00% 0.00%

10/30/2020 
Four Factor Analysis for Regional Haze

Homer City Generating Station
Units 1, 2 and 3

Homer City Generation L.P.
Center Township
Indiana County
Pennsylvania

Title V Operating Permit Number: 32-00055

October 30, 2020

i

TABLE OF CONTENTS

1. Introduction ........................................................................................................................................... 1
2. Background ........................................................................................................................................... 1
3. History of NOx Emission Control Installations at Homer City ............................................................. 4
3.1 Homer City Units 1 and 2 ............................................................................................................. 4
3.2 Homer City Unit 3 ........................................................................................................................ 5
4. History of SO2 Emission Control Installations at Homer City .............................................................. 5
4.1 Homer City Units 1 and 2 ............................................................................................................. 5
4.2 Homer City Unit 3 ........................................................................................................................ 6
5. Four Factor Analysis Criteria ................................................................................................................ 6
5.1 Cost of Compliance ....................................................................................................................... 6
5.2 Time Necessary for Compliance ................................................................................................... 7
5.3 Energy and Non-Air Quality Environmental Impacts of Compliance .......................................... 7
5.4 Remaining Useful Life of Any Potentially Affected Sources ....................................................... 7
6. NOx Control Options ............................................................................................................................. 7
6.1 Combustion Controls .................................................................................................................... 8
6.1.1 Low NOx Burners .................................................................................................................. 8
6.1.2 Overfire Air Systems ............................................................................................................ 8
6.1.3 Combustion Optimization ..................................................................................................... 8
6.2 Post-combustion Controls ............................................................................................................. 8
6.2.1 Selective Non-Catalytic Reduction (SNCR) ......................................................................... 8
6.2.2 Selective Catalytic Reduction ............................................................................................... 9
6.2.3 Nonselective Catalytic Reduction (NSCR) ........................................................................... 9
6.3 NOx Emission Reduction Options ............................................................................................... 10
7. Enhanced NOx Control Options .......................................................................................................... 10
7.1 LNB/OFA Replacement .............................................................................................................. 10
7.2 Changes/Upgrades to SCR Systems ........................................................................................... 11
7.3 Replacement of SCR Systems ..................................................................................................... 12
8. SO2 Control Options ........................................................................................................................... 12
8.1 Switching to Lower Sulfur Coal ................................................................................................. 12
8.2 Flue Gas Desulfurization (FGD) ................................................................................................. 13
9. Enhanced SO2 Control Measures ........................................................................................................ 13
9.1 Switching to Lower Sulfur Fuel .................................................................................................. 13

ii

9.1.1 Lower Sulfur Coal ............................................................................................................... 13
9.1.2 Conversion to Natural Gas .................................................................................................. 14
9.2 Upgrading the Existing Units 1 and 2 NID Systems ................................................................... 14
9.3 Replacing the Unit 3 Wet FGD System ...................................................................................... 15
10. Four Factor Analysis ........................................................................................................................... 15
10.1 Cost of Compliance ..................................................................................................................... 15
10.1.1 Enhanced NOx Control Measures ....................................................................................... 15
10.1.1.1 LNB/OFA Replacement .............................................................................................. 19
10.1.1.2 Upgrades to SCR System ............................................................................................ 19
10.1.1.3 Replacement of the SCR Systems ............................................................................... 19
10.1.2 Enhanced SO2 Control Measures ........................................................................................ 20
10.1.2.1 Switching to Lower Sulfur Coal ................................................................................. 23
10.1.2.2 Upgrading the Existing Units 1 and 2 NIDS ............................................................... 23
10.1.2.3 Replacing the Unit 3 Wet FGD System ...................................................................... 23
10.1.2.4 Conversion to Natural Gas .......................................................................................... 24
10.2 Time Necessary for Compliance ................................................................................................. 24
10.3 Energy and Non-Air Quality Environmental Impacts of Compliance ........................................ 24
10.3.1 Energy ................................................................................................................................. 24
10.3.1.1 LNB/SOFA ................................................................................................................. 25
10.3.1.2 Changes/Upgrades to SCR System ............................................................................. 25
10.3.1.3 Switching to Lower Sulfur Coal ................................................................................. 25
10.3.1.4 Upgrading the Existing Units 1 and 2 NIDS ............................................................... 25
10.3.2 Waste Transport/Disposal ................................................................................................... 25
10.4 Remaining Useful Life of Any Potentially Affected Sources ..................................................... 26
11. Conclusion .......................................................................................................................................... 26

iii

APPENDICES

APPENDIX TITLE

A Coal Analysis Reports – Units 1/2; and Unit 3

B RACT / BACT / LAER Clearinghouse: NOx Controls

C Cost Analysis – NOx Controls: SCR Replacement Units 1, 2, and 3

D RACT / BACT / LAER Clearinghouse: SO2 Controls

E Cost Analysis SO2 Controls: Units 1 and 2 Dry Scrubber (NIDS)

F Cost Analysis SO2 Controls: Unit 3 Dry Scrubber (NIDS)

G Table 2.8, Appendix K, New Hampshire Regional Haze Plan
Periodic Comprehensive Revision” (DRAFT 10/31/2019)

iv

LIST OF ACRONYMS

AIG ............................................................................................................ Ammonia Injection Grid
BART ....................................................................................... Best Available Retrofit Technology
BOFA .......................................................................................................... Boosted Over-Fired Air
CAA ............................................................................................................................ Clean Air Act
CAMD………………………………………………………………...Clean Air Markets Division
CO ........................................................................................................................ Carbon Monoxide
CO2 ........................................................................................................................... Carbon Dioxide
CPI ................................................................................................................. Consumer Price Index
Department ................................................. Pennsylvania Department of Environmental Protection
EGU ........................................................................................................... Electric Generating Unit
EPA ............................................................................................. Environmental Protection Agency
ESP ............................................................................................................. Electrostatic Precipitator
FGD........................................................................................................... Flue Gas Desulfurization
GHG ........................................................................................................................ Greenhouse Gas
GMW ..................................................................................................................... Gross Megawatts
HCl ...................................................................................................................... Hydrogen Chloride
HF ....................................................................................................................... Hydrogen Fluoride
LNB...................................................................................................................... Low NOx Burners
MANE-VU ........................................................................ Mid-Atlantic Northeast-Visibility Union
MMBtu .............................................................................................. Million British Thermal Units
MW ....................................................................................................................................Megawatt
N2 ....................................................................................................................... Molecular Nitrogen
NH3 ....................................................................................................................................Ammonia
NIDS .............................................................................. Novel Integrated Desulfurization Systems
NOx ......................................................................................................................... Nitrogen Oxides
NPS ................................................................................................................ National Park Service

v

NSCR ......................................................................................... Non-Selective Catalytic Reduction
OFA........................................................................................................................... Over-Fired Air
PADEP ....................................................... Pennsylvania Department of Environmental Protection
PM ......................................................................................................................... Particulate Matter
RACT II ........................................................................ Reasonably Available Control Technology
RBLC ...................................................................................... RACT/BACT/LAER Clearinghouse
RFP ......................................................................................................Reasonable Further Progress
ROFA ...................................................................................................... Rotating Opposed Fire Air
SIP ........................................................................................................... State Implementation Plan
SCR .................................................................................................... Selective Catalytic Reduction
SNCR ......................................................................................... Selective Non-Catalytic Reduction
SOFA ........................................................................................................ Separated Over-Fired Air
SO2 ............................................................................................................................. Sulfur Dioxide
TPY……………………………………………………………………………….…Tons per Year
VISTAS............................... Visibility Improvement State and Tribal Association of the Southeast

1

1. Introduction
The Clean Air Act’s visibility protection program (“Regional Haze Program”) helps to
protect clear views in national parks, such as Grand Canyon National Park, and wilderness areas,
such as the Okefenokee National Wildlife Refuge (federal “Class I” areas). States are required to
submit periodic plans demonstrating how they have and will continue to make progress towards
achieving their visibility improvement goals. The first state plans were due in 2007 and covered
the 2008-2018 planning period. States are required to submit SIPS for the second implementation
period, 2018-2028 by July 31, 2021.
The PADEP is in the process of developing a Regional Haze SIP revision to address
requirements for the second Regional Haze implementation period. PADEP has determined that
the Homer City Generating Station (“Homer City”) is a major source and that the emissions from
Homer City may impact visibility in Class I Areas. This determination is based on three separate
analyses performed by the MANE-VU1, the NPS2, and the VISTAS.3
PADEP has requested Homer City to evaluate control measures for SO2 and NOx using the
four factors set forth in the Clean Air Act,4 and Regional Haze Rule.5 These four factors are:
 Cost of compliance;
 Time necessary for compliance;
 Energy and non-air quality environmental impacts of compliance; and
 Remaining useful life of the source.
Calendar year 2019 emissions for EGUs are to be used as a baseline to evaluate cost and feasibility
of additional control measures for Homer City Units 1, 2, and 3. The analysis is to identify
available control measures that are technically feasible for SO2 and NOx using a top-down
approach to analyze multiple control options, and to identify the most effective and reasonable
control measures in light of the costs of compliance (in 2019 $/ton).
This report presents Homer City’s analysis.
2. Background
The Homer City Generating Station is located 45 miles northeast of Pittsburgh in Indiana
County, PA. The Station includes three coal-fired units with a nominal total 2,090 MW of gross

1 https://otcair.org/MANEVU/Upload/Publication/Formal%20Actions/MANE-VU%20Intra-
Regional%20Ask%20Final%208-25-2017.pdf

2 http://files.dep.state.pa.us/Air/AirQuality/AQPortalFiles/Pollutants/Haze/NPS%20Q%20over%20d%20analysis%20-
%20PA%20facilities%202020.pdf

3 Visibility Improvement State and Tribal Association of the Southeast (VISTAS) Letter dated June 22, 2020 to Mr.
Virendra Trivedi, PADEP

4 42 USC § 7491(g)(1)

5 40 CFR § 51.308(f)(2)(i)

2 

generation capacity. Units 1, 2, and 3 have gross generating capacities of 690 MW, 690 MW, and
710 MW, respectively.
The boiler nameplate rated capacities are stated in terms of pounds of steam per hour
4,613,000 lb/hr, 4,613,000 lb/hr, and 4,750,000 lb/hr for units 1, 2, and 3, respectively. The
maximum heat input has been determined based on fuel heating value and burner firing
capabilities.
Units 1 and 2 are Foster Wheeler wall-fired, dry bottom boilers constructed in 1969.
Number 2 distillate oil is the fuel used for start-ups. Each of the units has a nominal rated heat
input capacity of 6,792 MMBtu/hr. Units 1 and 2 are each equipped with a 40 CFR Part 75 CEMS
for NOx, SO2, and CO2 and a COMS for opacity. PM emissions are measured periodically based
on 40 CFR Part 60 stack testing and in accordance with procedures in 25 Pa. Code Chapter 139
(source testing requirements).
Units 1 and 2 utilize medium to high sulfur Pennsylvania bituminous coal (“steam coal”)
with a maximum sulfur content of 2.25 weight percent. A recent coal analysis report is shown in
Appendix A. Units 1 and 2 are equipped with LNB/SOFA and SCR for NOx, ESP for particulate
control, and were retrofitted in 2014 and 2015 with NIDS. The NIDS is a dry sulfur oxide (SO2)
removal system integrated with fabric filter controls. The ESPs remain in service and are located
between the SCR system and the NIDS.
Unit No. 3 is a Babcock & Wilcox, wall-fired boiler constructed in 1977. Number 2
distillate oil is the fuel used for start-ups. The unit has a rated heat input capacity output of 7,260
MMBtu/hr. Units 3 is equipped with a 40 CFR Part 75 CEMS for NOx, SO2, and CO2. PM
emissions are measured periodically based on 40 CFR Part 60 stack testing and in accordance with
procedures in 25 Pa. Code Chapter 139 (source testing requirements).
Unit 3 utilizes Pennsylvania steam coal with a maximum sulfur content of 3.25 weight
percent. A recent coal analysis report is shown in Appendix A. Unit 3 is equipped with
LNB/SOFA and SCR for NOx control and ESPs for particulate control. A wet limestone FGD
system is used for SO2 control.
The coal supply for Units 1 and 2 and the coal supply for Unit 3 are segregated.
2.1 Emissions
Actual emissions for Homer City Units 1, 2, and 3 are summarized in Table 1. At the Homer
City Generating Station, the Units 1, 2, and 3 actual emissions (TPY) of SO2 have been reduced
between 2006-2008 (baseline emissions before implementation of the first phase of the regional
haze program) and 2019 by approximately 97.7% and emissions (TPY) of NOx have been reduced
by approximately 91.3%. The emission reductions are indicative of the reductions achieved since
commencement of the regional haze program and are primarily attributable to the installation of
state of the art SO2 and NOx controls. For purposes of this analysis cost calculations have been
based on operation at 100 percent capacity.

3

Table 1. Homer City Emissions
Operating Output Capacity Heat Input SO2 SO2 NOx NOx
YEAR UNIT (hr) (GMW) (GMW pct) (MMbtu) (ton) (lb/MMbtu) (ton) (lb/MMbtu)

1 8,350 4,753,576 79.2 42,138,453 53,168 2.523 4,929 0.242
2006 2 7,971 4,452,801 74.2 40,354,389 51,006 2.518 5,558 0.281
3 6,143 3,882,967 61.6 34,172,587 2,598 0.133 4,532 0.287
HCS AVE 7,488 4,363,115 71.7 38,888,476 35,591 1.887 5,006 0.274
HCS TOTAL 13,089,344 116,665,428 106,772 15,019

1 8,202 4,836,563 80.6 44,709,617 63,112 2.805 6,304 0.288
2007 2 7,321 4,340,022 72.3 38,920,483 54,066 2.783 3,228 0.180
3 8,350 5,346,270 84.8 48,688,691 3,589 0.140 7,910 0.323
HCS AVE 7,958 4,840,952 79.2 44,106,264 40,256 1.806 5,814 0.270
HCS TOTAL 14,522,855 132,318,791 120,768 17,442

1 6,482 3,485,801 58.1 31,688,086 44,411 2.712 5,080 0.320
2008 2 8,083 4,231,975 70.5 39,571,744 55,230 2.784 5,758 0.290
3 8,013 4,394,033 69.7 40,562,901 2,844 0.133 7,048 0.340
HCS AVE 7,526 4,037,269 66.1 37,274,244 34,161 1.818 5,962 0.317
HCS TOTAL 12,111,808 111,822,731 102,484 17,886

2006-08 AVERAGE 7,657 4,413,779 72.3 40,089,661 36,669 1.837 5,594 0.287
2006-08 TOTAL 110,008 16,782

1 6,629 2,487,618 41.8 24,627,892 2,277 0.177 1,451 0.120
2019 2 5,035 1,914,841 32.1 19,338,077 1,827 0.178 1,511 0.158
3 6,833 3,143,128 50.5 30,720,108 3,613 0.205 1,412 0.091
HCS AVE 6,166 2,515,196 41.5 24,895,359 2,572 0.187 1,458 0.117
HCS TOTAL 7,545,587 74,686,077 7,717 4,374

Emissions
Reduction
(pct) 93.0 89.8 73.9 59.3

4

3. History of NOx Emission Control Installations at Homer City
Since the beginning of the Regional Haze Phase I initiative (December 2007), Homer City
has made significant capital expenditures to reduce NOx emissions. As late as 2015, NOx
emissions from Homer City Station were approximately 18,400 tons per year. Through the
installation and operation of the NOx controls discussed below, NOx emissions were reduced to
approximately 4,375 tons per year in 2019--an approximate 75% reduction from 2015 NOx
emission levels.
3.1 Homer City Units 1 and 2
Homer City Units 1 and 2 are each equipped with LNB/SOFA systems which were
installed in 1995, and SCR NOx controls which were installed in 2001. Through the use of the
LNB/SOFA system, Homer City maintains NOx emissions from the boiler combustion zones at
approximately 0.55 lb/MMBtu heat input. The initial capital cost for the Units 1 and 2 SCR
systems was approximately $75 million (2001$) for each system. Upgrades were completed on
the Units 1 and 2 SCR systems in 2009 and in 2018.
The 2009 upgrades included winterization of the SCR systems, including replacement of
solenoids, relocation of the ammonia storage facility and upgrades required to operate the systems
year-round to comply with the Clean Air Interstate Rule (CAIR).
The 2018 SCR system upgrades were to reduce emissions to comply with the Pennsylvania
RACT II requirements established in 25 Pa. Code Section 129.97 (i.e., 4.0 lbs NOx/MMBtu when
the SCR inlet is below 600o F and a 30-day rolling average of 0.12 lbs NOx/MMBtu when the SCR
is at or above 600o F) and included installation of a new AIGs and static mixers in the exhausts
upstream of the catalyst beds to provide better mixing of the ammonia in the exhaust stream. These
upgrades were completed at a cost of approximately $6.1 million and $5.5 million for Units 1 and
2, respectively.
The emission reductions achieved as a result of the upgrades in 2009 and 2018 are in excess
of those required to meet BART.
Through the use of the LNB/SOFA systems and the recently upgraded SCR systems,
Homer City maintains NOx emissions from Units 1 and 2 at or below 0.12 lb/MMBtu on a 30-day
rolling basis when the SCR inlet temperature is equal to or greater than 600o F.
Units 1 and 3 operated at equal to or less than 0.12 lb NOx/MMBtu on a 30-day rolling
basis in 2019. Unit 2 achieved RACT 2 emission limits on July 1, 2019. Prior to that time, Unit
2 was authorized to emit at greater than 0.12 lb NOx/MMBtu under a RACT 2 compliance
extension.
The LNB/SOFA systems are in operation all the time the unit is in operation. The SCR
systems operate at all times when the SCR inlet temperature is equal to or greater than 600o F.

5 

3.2 Homer City Unit 3
Homer City Unit 3 is equipped with LNB which were installed in 1977 and SOFA which
was installed in 1995. SCR NOx controls were installed in 2003. The Unit 3 SCR system reduces
emissions to comply with the Pennsylvania RACT II requirements established in 25 Pa. Code
Section 129.97.
Through the use of the LNB/SOFA systems and the SCR system, Homer City maintains
NOx emissions from Unit 3 at or below 0.12 lb/MMBtu on a 30-day rolling basis when the SCR
inlet temperature is equal to or greater than 600o F. The LNB/SOFA systems are in operation all
the time the unit is in operation. The SCR system operates at all times when the SCR inlet
temperature is equal to or greater than 600o F.
4. History of SO2 Emission Control Installations at Homer City
Since the beginning of the Regional Haze initiative Phase I (December 2007), Homer City
has made significant capital expenditures to reduce SO2 emissions. As late as 2015, SO2 emissions
from Homer City Station were approximately 100,000 tons per year. Through the installation and
operation of the SO2 controls discussed below, emissions were reduced to approximately 7,700
tons per year in 2019--an approximate 93% reduction from 2015 SO2 emission levels. Average
gross station capacity over this period was 40%. Gross station capacity in 2015 was 54%, and in
2019 was 42%. As a merchant generator, Homer City’s operations are dictated by electrical
demand. Therefore, it is not possible to predict unit operations and unit emissions.
4.1 Homer City Units 1 and 2
Homer City Units 1 and 2 are each equipped with a NIDS system installed in 2015 and
2016 at a cost of approximately $450 million for each NIDS. Each NIDS is a dry SO2 scrubber
made up of an integrated lime hydrator/mixer, a J-duct reactor, and a fabric filter. Hydrated lime
is used as a reagent to react with gaseous pollutants including SO2, HCl, and HF. The scrubbers
achieve approximately 95% control of SO2.
The control efficiency was calculated using the following formula:
(4.0 inlet lb SO2/MMbtu - 0.2 outlet lb SO2/MMbtu)/(4.0 inlet lb SO2/MMbtu)*100 = 95%
Reduction
Through the use of the Units 1 and 2 NIDS dry scrubbers, Homer City maintains SO2
emissions from Units 1 and 2 at a rate equal to or less than 0.2 lb/MMBtu heat input on a per boiler
basis.

6 

4.2 Homer City Unit 3
Homer City Unit 3 is equipped with a wet limestone scrubber for control of SO2. The wet
limestone scrubber was installed in 2001 at a cost of approximately $95 million (2001$). The
scrubber achieves approximately 90% control of SO2 emissions.
The control efficiency was calculated using the following formula:
(4.5 inlet lb SO2/MMbtu - 0.4 outlet lb SO2/MMbtu)/(4.0 inlet lb SO2/MMbtu)*100 =
90% Reduction
Through the use of the Unit 3 wet limestone scrubber, Homer City maintains SO2 emissions from
Unit 3 at a rate equal to or less than 0.4 lb/MMBtu heat input.
5. Four Factor Analysis Criteria
The CAA and the Regional Haze Program rules establish certain requirements for regional
haze programs. 40 CFR § 51.308(d) establishes requirements for regional haze SIPs including
requirements for establishment of RFP goals for any mandatory Class I Federal area within the
state. 40 CFR 51.308(d)(1). In establishing a reasonable progress goal for any mandatory Class I
Federal area within the State, the State must:
Consider the costs of compliance, the time necessary for compliance, the energy and non-
air quality environmental impacts of compliance, and the remaining useful life of any
potentially affected sources, and include a demonstration showing how these factors were
taken into consideration in selecting the goal. 40 CFR § 51.308(f)
Prior to the first step in the four-factor analysis, technically feasible control measures
should be identified. Once selected, the four factors can be characterized for each measure. In
general, available emission reduction measures can include:
 Improved work practices.
 Retrofits for sources with no existing controls.
 Upgrades or replacements for existing, less effective controls.
 Year-round operation of existing controls.
 Fuel mix with inherently lower emissions.
5.1 Cost of Compliance
For purposes of the second implementation period, EPA recommends that states follow the
source type-relevant recommendations in the EPA Air Pollution Control Cost Manual that are
stated in the manual as applying to cost estimates in a permitting context.6 In addition to the Cost
Control Manual, Homer City prepared certain control cost estimates using the EPA’s CAMD
Retrofit Cost Analyzer Tool7 and on information in Appendix K of the “New Hampshire Regional

6 Guidance on Regional Haze State Implementation Plans for the Second Implementation Period, August 20, 2019,
p. 31.
7 https://www.epa.gov/airmarkets/retrofit-cost-analyzer 

7 

Haze Plan Periodic Comprehensive Revision” (DRAFT 10/31/2019)8. Costs determined using
these tools were adjusted to 2019$.
5.2 Time Necessary for Compliance
The second statutory factor – the time necessary for compliance – involves estimating the
time needed for a source to implement a potential control measure. States should consider source-
specific factors.
5.3 Energy and Non-Air Quality Environmental Impacts of Compliance
Characterizing information about the third statutory factor, including the energy and non-
air environmental impacts, involves assessing the impacts of a control measure on the energy
consumed by a source. Non-air environmental impacts can include the generation of wastes for
disposal and impacts on other environmental media, such as nearby water bodies.
5.4 Remaining Useful Life of Any Potentially Affected Sources
Generally, this factor considers the useful life of the control system rather than the source.
Typically, the remaining useful life of the source itself will be longer than the useful life of the
emission control system under consideration unless there is an enforceable requirement for the
source to cease operation sooner. The presumption is that after the end of the useful life of the
emission control system, it will be replaced by a like system. Thus, annualized compliance costs
are typically based on the useful life of the control equipment rather than the life of the source.
6. NOx Control Options
Homer City has reviewed information reported to the RBLC9 and other publicly available
information concerning NOx control technologies for coal-fired utility boilers. (See Appendix B)
Based on information available on the RBLC website, NOx emissions controls installed on coal-
fired utility boilers include LNB, OFA, and SCR either singly or in combination. All three Homer
City Units already are equipped with LNB/SOFA combustion controls and SCR post-combustion
controls.
Other potential NOx controls include oxy-combustion, NSCR and SNCR. Oxy-combustion
has not been evaluated. The Homer City units are not designed and cannot be retrofitted to use
pure oxygen in the combustion process. Further, Homer City’s analysis did not determine the
existence of any oxy-combustion systems in operation on full sized commercial coal-fired EGUs,
either existing or new units.
Further discussion of each of the technologies identified in the RBLC review and
discussion of combustion optimization, and of NSCR and SNCR follows.

8 https://www.des.nh.gov/organization/divisions/air/do/asab/rhp/index.htm
9 https://www.epa.gov/catc/ractbactlaer-clearinghouse-rblc-basic-information

8 

6.1 Combustion Controls
6.1.1 Low NOx Burners
With LNB the initial fuel combustion occurs in a fuel-rich, oxygen deficient zone. This is
followed by a reducing atmosphere, where hydrocarbons created during coal combustion react
with already formed NOx to turn it into N2. Downstream of the primary combustion zone, the air
required to complete combustion of coal is added. The staging results in lower flame temperatures,
which results in lower NOx formation. LNB can reduce NOx formation by approximately 30 to
50%.
6.1.2 Overfire Air Systems
OFA controls are designed to reduce the available oxygen near the burner area, resulting
in minimized formation of fuel NOx. As little as 70 per cent of the required total combustion air
is provided near the burners, creating an oxygen-deficient, fuel-rich zone, resulting in partial
combustion of fuel. The remaining combustion air is injected above the burner elevation, through
the OFA nozzles into the furnace. Because the combustion temperature in the secondary zone is
relatively low, thermal NOx production is limited.
Variations of OFA systems include two-stage overfire air systems or SOFA, BOFA
systems, ROFA, and bypass over fire air systems. These promote improved mixing of the overfire
air and the furnace gases. In some cases, these systems can result in slightly higher NOx reductions
when compared to a conventional OFA system.
Typically, LNB and OFA systems, combined, result in potential NOx emission reductions
of approximately 45% to 75%.
6.1.3 Combustion Optimization
One method of combustion modification to control NOx from boilers is combustion
optimization or “tuning.” In combustion tuning, the air to fuel ratio for combustion is analyzed
and adjusted to lower NOx emissions. For properly instrumented and maintained and operated
boilers, the benefits of a combustion optimization program beyond current facility practices are
extremely limited.
Combustion tuning to minimize NOx emissions can also have detrimental effects, including
increased CO emissions and reduced boiler efficiency. In addition, the tuning can result in
increased unburned carbon in the fly ash, rendering is unsuitable for sale (for beneficial use) and
increasing waste disposal costs.
6.2 Post-combustion Controls
6.2.1 Selective Non-Catalytic Reduction (SNCR)
SNCR involves injection of ammonia or urea into a boiler in a zone where the flue gas
temperature is between 1650° F and 2200° F to reduce NOx to N2. SNCR can achieve NOx

9 

reductions ranging from 25–60 per cent for urea-based systems, while reductions for ammonia-
based SNCR systems range from 61 to 65 percent.
SNCR systems do not require a catalyst. The NOx control effectiveness of SNCR is
dependent on achieving adequate mixing of the ammonia/urea in the exhaust and maintaining
sufficient reaction time within a narrow flue gas temperature band. If the injection zone
temperature is too high, the ammonia/urea will decompose forming additional NOx. If the
temperature is too low, the reaction will not occur. The ammonia “slip” will react with sulfur from
the fuel to form ammonium sulfate and ammonium bisulfate. When these compounds condense
on cooler surfaces of the air heater, significant loss of efficiency and mechanical damage can occur.
Typically, SNCR systems on pulverized coal-fired boilers achieve efficiencies in the range
of 30% to 50%.
6.2.2 Selective Catalytic Reduction
SCR is the most effective and well-established NOx emission reduction technology in use.
SCR has been installed as a single NOx control technology, but it is generally used in conjunction
with other technologies, such as LNB and OFA. SCR operates on a principal similar to SNCR by
using a reagent such as ammonia to reduce NOx to nitrogen and water. In an SCR system the
reaction is carried out in the presence of a catalyst which promotes the reduction reaction.
Two advantages of SCR over SNCR are:
1. By using a catalyst, SCR systems can achieve a higher NOx removal than SNCR
systems.
2. The NOx reduction reaction takes place at a lower temperature and over a wider
temperature band. SCR systems typically operate in a temperature range of 600° F
to 750° F. However, SCR systems have higher capital costs and additional costs
are experienced for replacement of catalyst and disposal of the deteriorated catalyst
elements.
Theoretically, SCR systems can be designed for NOx removal efficiencies approaching
100 percent. In practice, commercial coal-, oil-, and natural gas–fired SCR systems are often
designed to meet control targets of over 90 percent. However, the reduction may be less than 90
percent when SCR follows other NOx controls such as LNB, LNB/SOFA, or FGR that achieve
relatively low emissions on their own.
Based on Homer City’s experience, NOx removal efficiencies for well-designed and well-
operated SCR systems associated with LNB/SOFA are in the range of 85 to 90%.
6.2.3 Nonselective Catalytic Reduction (NSCR)
In NSCR systems, CO, NOx and hydrocarbons are converted into CO2 and N2 via a catalyst.
This technique does not need additional reagents to be injected because the unburned hydrocarbons
are used as a reductant; though gases must not contain more than 0.5% oxygen. For this reason,
the oxygen concentration in flue gases must be kept below 0.5%. Because of the exhaust

10 

characteristics of coal-fired utility boilers, NSCR systems are not feasible for coal-fired utility
boilers.
6.3 NOx Emission Reduction Options
Homer City Units 1, 2, and 3 are currently equipped with LNB and OFA combustion
systems and post-combustion NOx control is further reduced through the use of SCR systems on
each boiler. The NOx emissions control technologies installed on Homer City Units 1, 2, and 3
are consistent with the technologies installed to meet emission limitations required of similar
sources as reflected in the RCLB. The combination of LNB/OFA/SCR controls, coupled with
combustion optimization, represents BACT for NOx emissions for Homer City Units 1, 2, and 3.
For optimal efficiency, the NOx controls are installed between the boilers and the SO2
controls. Changing the sequence of treatment is technically infeasible considering the volume of
exhausts being handled and the temperatures at which these controls operate. For example, it is
impractical to treat NOx with SCRs after SO2 wet scrubbing. The amount of energy needed to
reheat the gas stream from the 125o F exit temperature from the wet FGD unit to 600o F inlet
temperature required for SCR operation would be enormous. It would be practically impossible
to reheat the approximately 2.8 million cubic feet per minute of exhaust in a reasonable time.
Further, the use of fuel to reheat the exhaust would be at counter purposes to the Affordable Clean
Energy (ACE) program requirements and would result in significant GHG emissions increases
from the facility.
Nevertheless, Homer City has investigated the potential costs and NOx reduction benefits
of upgrades/replacements to the existing LNB/OFA systems and the SCR systems.
7. Enhanced NOx Control Options
Based on Homer City’s analysis of available, feasible options for achieving further NOx emission
reductions from Homer City Units 1, 2, and 3, Homer City determined that the only technically
feasible options available are replacement of the existing LNB/SOFA systems with new
LNB/SOFA systems and replacement/additional upgrades to the SCR systems. These potential
measures are discussed below.
7.1 LNB/OFA Replacement
During development of a compliance strategy for the Pennsylvania RACT II program in
2015/2016, Homer City investigated the cost, emission reduction benefits and delivery times for
LNB replacements and OFA upgrades for Units 1 and 2. Currently both units operate LNB/OFA
systems with combustion zone emissions of 0.55 lb/MMBtu. The vendor estimates to replace the
existing LNB/OFA system in each of Units 1 and 2 was $25 million (2016$). Cost estimates for
Unit 3 are approximately $30 million, based on prorating the Units 1 and 2 estimates. Vendor
estimates for the new LNB/SOFA systems for Units 1 and 2 were that boiler combustion zone NOx
would not exceed 0.47 lb/MMBtu (versus 0.55 lb /MMBtu for the currently installed LNB/SOFA
systems). Vendor estimates for the new LNB/SOFA system for Unit 3 were that boiler combustion
zone NOx would not exceed 0.35 lb/MMBtu (versus 0.38 lb /MMBtu for the currently installed

11 

LNB/SOFA systems).Replacement of the existing burners would result in NOx emission reduction
from the boiler combustion zone of approximately 476, 476, and 191 tons per year, respectively,
for Units 1, 2, and 3.
In addition to the cost information developed by Homer City during the RACT II
compliance analysis, Homer City developed cost information for the installation of new
LNB/SOFA systems for the boilers based on cost data developed by MANE-VU consistent with
EPA guidance. These comparative capital cost and operating cost estimates are summarized in
Table 1. Costs for replacement of the LNB/SOFA systems based on the MANE-VU/EPA
approach are approximately a factor of 2 higher than the vendor estimates provided to Homer City.
As is shown in Table 2, below, the cost of NOx emissions control for replacement of the
existing burners, based on the vendor estimates provided during the Homer City RACT II analysis,
is approximately (2019$): $8,170/ton, $8,170/ton, and $23,929/ton for Units 1, 2, and 3,
respectively. These cost estimates assume the replacement burners will require the same level of
maintenance effort as the existing burners. The 2016 costs have been adjusted based on the U.S.
Bureau of Labor Statistics CPI.10 Table 2 further shows control costs, based on the MANE-VU
costing methodology, of approximately: (2019$): $17,305/ton, $17,305/ton, and $43,883/ton for
Units 1, 2, and 3, respectively.
7.2 Changes/Upgrades to SCR Systems
In 2018 and in 2019, Homer City made modifications to the SCRs on Units 1 and 2 to
ensure that the units could operate in compliance with Pennsylvania’s RACT II requirements.
These modifications required a capital investment of approximately $6.1 million and $5.5 million
for Units 1 and 2, respectively. Capital costs and operating costs of the 2018/2019 SCR system
upgrades, the resulting emission reductions and the cost per ton of NOx reduced are shown in
Tables 1 and 2.
Any additional performance improvement on these SCRs would require significant capital
expenditures beyond those incurred during the recent upgrade and would impose additional
operating costs. Among the measures that would be necessary for significant performance upgrade
would be:
 Replacement of ammonia pumps with higher capacity pumps;
 Replacement of the ammonia vaporizers to provide for increased ammonia injection
into the exhaust stream; and,
 Installation of additional catalyst elements and more frequent catalyst replacement.
Projected emission reductions related to the SCR system upgrades are estimated to be
approximately 818, 818 and 604 tons per year respectively for Units 1, 2, and 3. Costs related to
the SCR upgrades are summarized in Table 1, below. As is shown in Table 1, the cost of NOx
emissions control for the upgrade of the SCR systems is approximately (2019$): $ 9,599/ton,
9,599/ton, and $10,112/ton for Units 1, 2, and 3, respectively.

10 https://www.bls.gov/data/inflation_calculator.htm

12 

7.3 Replacement of SCR Systems
Homer City has evaluated the cost for replacing the SCR systems for Units 1, 2, and 3.
The cost estimates for replacing the SCR systems were determined in accordance with Air
Markets Retrofit Cost Analyzer. Estimated additional NOx emission reductions that could result
from the replacement of the SCR systems are approximately 977, 977, and 695 tons per year,
respectively. Capital costs for the replacement of the SCR systems determined in accordance
with Air Markets Retrofit Cost Analyzer are estimated to be: $204,703,000, $ 204,703,000 and
$209,514,000 for Units 1, 2, and 3, respectively. (See Appendix C) Additionally, projected
operating costs are estimated to be: $4,834,000 , $4,834,000 and $4,717,000 for Units 1, 2, and
3, respectively. Costs of the emission reductions are estimated to be are estimated to be:
$14,830, $14,830 and $ 21,151/ton for Units 1, 2, and 3, respectively. These costs are shown in
Tables 1 and 2.
8. SO2 Control Options
Homer City has reviewed information reported to the RBLC and other publicly available
information concerning SO2 control technologies for coal-fired utility boilers. Based on
information available on the RBLC site and other sources, SO2 emissions control measures
implemented for coal-fired utility boilers include: switching to lower sulfur coal; and installing
flue gas desulfurization systems (FGD). (See Appendix D) Further discussion of each of these
measures follows.
8.1 Switching to Lower Sulfur Coal
Switching to lower sulfur content coal is a pre-combustion SO2 emission control technique.
Homer City Units 1, 2, and 3 currently burn medium sulfur content western Pennsylvania
bituminous coal. The coal sulfur content is approximately 2.3 to 3.0 weight percent sulfur, as
burned.
Coal with lower sulfur content than the coal currently burned at Homer City could be used
as fuel, but typically is used to produce metallurgical coke and for other uses in the metal industry.
However, there is a significant cost difference between “steam” coal and “met” coal. The U.S.
Energy Information Administration (EIA) reported September 18, 2020 spot coal prices for Central
Appalachia (1.2% S) and Northern Appalachia (<3% S) coals as $59.50 and $42.45 per ton,
respectively. (https://www.eia.gov/coal/). The extent of emission reductions achievable from
burning lower sulfur coal depends on the relative fuel sulfur contents of the current fuel and the
replacement fuel.
Cost analyses were conducted for each unit individually. Converting all units to a single
coal would make fuel management simpler and would assure maximum SO2 emission reductions.
The cost analysis was based on the relative costs of low sulfur “met” and high sulfur eastern
bituminous “steam” coal. No additional capital expense was associated with a conversion to low
sulfur “met” coal.

13 

8.2 Flue Gas Desulfurization (FGD)
Flue gas desulfurization (FGD) is a post combustion SO2 control method. There are two
basic types of FGD, wet and dry. Wet scrubbers are the most prevalent, accounting for in excess
of 80% of post-combustion SO2 control systems worldwide.
In a “wet” FGD a mixture of limestone and water is sprayed over the flue gas. This mixture
reacts with the SO2 to form gypsum (calcium sulfate), which is removed from the water and
disposed.
There are variations on dry FGD. Lime is typically the sorbent used. A slurry of slaked
lime is sprayed into the exhaust ductwork to remove SO2. Reaction products, primarily calcium
sulfate, and fly ash are captured downstream in the particulate removal device, typically a fabric
filter. A variation is dry sorbent injection (in-duct dry injection) in which hydrated lime or other
sorbent is injected into the flue gas. Duct spray drying is also used as post-combustion SO2
removal method.
Flue gas desulfurization systems typically achieve control efficiencies in excess of 95%.
9. Enhanced SO2 Control Measures
Homer City considered several measures that might be implemented to further reduce SO2
emissions from Units 1, 2, and 3. These measures include:
 Switching to lower sulfur fuel;
 Upgrading the existing NID systems installed on Units 1 and 2; and
 Replacing the wet FGD installed on Unit 3 with a NID system.
9.1 Switching to Lower Sulfur Fuel
Homer City has evaluated two lower sulfur fuel options for the facility, lower sulfur coal
and natural gas co-firing options. These options are discussed below.
9.1.1 Lower Sulfur Coal
Homer City evaluated the availability and cost of lower sulfur coal for use as fuel at the
facility. Basically, Pennsylvania coal is divided into two classes — “steam coal” and
“metallurgical” or “met” coal. Steam coal is that portion of the coal with a sulfur content greater
than 1.5 % by weight and met coal has a sulfur content less than 1.0 % by weight. Homer City
Units 1, 2, and 3 were designed to burn Pennsylvania (Appalachian Basin) bituminous coal with
specified heating values and other characteristics. Although other coals, such as Powder River
Basin coal, may be available at a lower cost, there are significant obstacles to their use at a facility
such as Homer City. These include: significantly lower heating value per ton; ash fusion
temperature issues; degradation of the coal in transport; and high transportation costs.

14 

The U.S. Energy Information publishes coal prices and a primary determinant of coal price
is the sulfur content.11 Comparison of high and low sulfur eastern bituminous coal prices on the
EIA website indicate September 18, 2020 prices of $42.45/ton for higher sulfur coal vs $59.50 /ton
low sulfur coal. (https://www.eia.gov/coal/) It should be noted that spot coal prices vary on a day-
to-day basis. Based on its evaluation, Homer City has determined that the additional cost for the
purchase of lower sulfur coal would increase the fuel costs by approximately $29,617,635,
$29,617,635, and $41,389,146 for Units 1, 2, and 3, respectively. These additional fuel costs
would be recurring annual expenses.
9.1.2 Conversion to Natural Gas
Homer City has evaluated the potential for conversion of the facility to natural gas firing.
Based on the analysis conducted in 2014, it was concluded that full conversion of the facility to
natural gas firing was not economically feasible for three reasons. First, the quantity of natural
gas was not readily available. Second, full conversion to natural gas firing would result in a
significant de-rating of the facility. The de-rating of the facility would result in the loss of capacity
payments and loss of generating revenue when the plant was in operation. Both of these
consequences would have significant adverse impacts on the facility. Finally, the interruptible
nature of the gas supply as opposed to on-site storage of coal could jeopardize operations.
Attempting to replace the total coal heat input of any of the Homer City units with natural
gas would result in derating of the unit simply because the combustion chambers are not large
enough to accommodate the volume of natural gas and combustion air required to maintain the
same heat input as achieved with coal. The derating would be a result of the simple physics of
combustion, not directly a natural gas supply issue. Replacing 1 ton of coal with natural gas would
require approximately 25,000 cubic feet of natural gas. At full load, Homer City Station would
require approximately 20,000,000 cubic feet of natural gas per hour.
Conversion of the facility to 50% natural gas firing was determined to be practical from
the standpoint of potentially available natural gas supplies and would not de-rate the facility.
However, cost of natural gas and the possibility of interruption of gas supply continue to be
significant concerns.
9.2 Upgrading the Existing Units 1 and 2 NID Systems
Homer City completed the installation of NID (dry SO2 scrubbers) systems on Units 1 and
2 in 2015 and 2016, respectively. These systems were designed to reduce SO2 emissions from the
Units to 0.2 lb/MMBtu. Increasing the SO2 removal efficiency of the NID systems could be
accomplished by injecting additional lime in the J-duct dry reactors. However, the injection of
additional lime would create additional byproduct, which would overload the existing dry scrubber
by-product handling system. Projected cost for the replacement of the by-product handling
systems with larger capacity systems is approximately $5 million for each system. In addition,
increased material costs would be experienced for the additional lime to be injected and increased
disposal costs would be incurred for the additional waste solids disposal. The increased lime

11 https://www.eia.gov/coal/markets/

15 

purchase and increased waste disposal costs associated with the use of additional lime are
estimated to be approximately $10.5 million per year for each unit. The additional lime and waste
disposal requirements will result in additional hauling that will result in increased mobile source
emissions and the additional disposal requirements will shorten the life of the waste disposal site.
Replacing these newly installed dry SO2 controls with wet scrubbers after only a few years
of operation would be cost prohibitive. (See Appendix E) Installation and operation of additional
wet scrubbers at the facility would require significant capital investment for the scrubbers as well
as advanced wastewater treatment to meet discharge limits for FGD wastewater.
9.3 Replacing the Unit 3 Wet FGD System
Homer City Unit 3 is currently equipped with a wet SO2 scrubber. Additional reductions
of SO2 emissions could be achieved by replacing the existing Unit 3 wet FGD system with a NIDS
dry SO2 removal system. Homer City has projected costs of a NIDS for Unit 3 based on scaling
of the recently installed Units 1 and 2 NIDS and on the methodology in the Air Markets Retrofit
Cost Analyzer. (See Appendix F)
10. Four Factor Analysis
Homer City has evaluated emission reduction technologies and techniques which might be
applied to reduce SO2 and NOx emissions from Homer City Units 1, 2, and 3 with respect to the
four factors specified in the Regional Haze regulations. Discussion of each factor with respect to
each pollutant (SO2 and NOx) follows.
10.1 Cost of Compliance
Homer City evaluated the cost of each available emission reduction technique/technology
for each pollutant using a 100 percent capacity factor as the emissions baseline. Costs for each
measure were developed using several methods. First, where available, Homer City uses cost
proposals obtained from vendors for other purposes (e.g., compliance with MATS or RACT II).
Second, for certain control options, costs were estimated in accordance with the source type-
relevant recommendations in the EPA Air Pollution Control Cost Manual as applying to cost
estimates in a permitting context. Third, for certain control options, costs were evaluated using
EPA’s CAMD Retrofit Cost Analyzer Tool. In each case, costs are adjusted to 2019 dollars for
comparison. Each of the potential emission reductions for the individual pollutants is discussed
more fully below. In its cost calculations, Homer City used an interest cost of 7.0 percent for
capital to finance the projects and a 20-year life of the equipment. The use of a 7 percent interest
charge is conservative given the reluctance of investors generally to provide funding for fossil-
fired generating projects.
10.1.1 Enhanced NOx Control Measures
As is discussed earlier, Homer City completed upgrades of the Units 1 and 2 SCR systems
in 2018 and 2019, respectively. These upgraded SCR controls complement the existing
LNB/SOFA systems on the Units to comply with PADEP’s RACT II requirements of 0.12

16 

lb/MMBtu. The upgrades were completed at a capital cost of approximately $6.5 million for Unit
1 and $5.5 million for Unit 2, respectively. Homer City Unit 3 is equipped with LNB/SOFA and
SCR NOx emission controls and did not require modification to comply with PADEP’s RACT II
requirements.
A summary of the projected NOx emission reductions, costs, and time to implement for the
available additional NOx emissions strategies for Units 1, 2, and 3 is shown in Table 2. The cost
data for the “Homer City Cost Estimates” are based on preliminary vendor quotations and the
“Costs Based on MANE-VU/EPA Data” are based on information contained in Appendix K of the
“New Hampshire Regional Haze Plan Periodic Comprehensive Revision” (DRAFT 10/31/2019)
and on EPA’s Air Markets Retrofit Cost Analyzer. Table 3 shows annualized cost for the potential
NOx control options on a cost per ton of pollutant and annualized costs based on the capital costs
and annual operating expenses shown in Table 2. Additional discussion is provided below for
each of the NOx control strategies.

17 

Table 2. NOx Strategies, Estimated Costs and Time to Implement
Homer City Cost Estimates Estimated Costs Based on MANE-
VU/EPA Data / EPA’s CAMD
Retrofit Cost Analyzer Tool

Strategy Emission
Reductions
(TPY)
Capital Cost
(2019$)
Annual
Operating
Cost
(2019$)
Emission
Reductions
(TPY)
Capital Cost
(2019$)
Annual
Operating
Cost (2019$)
Time to
Implement
(Years) (1)
New LNB/SOFA
Unit 1 476 27,093,900 300,000 476 52,290,800
(2)
1,036,487 (2) 3 – 6
Unit 2 476 27,093,900 300,000 476 52,290,800
(2)
1,036,487 (2) 3 – 6
Unit 3 191 32,512,700 300,000 191 53,806,500
(2)
987,631 (2) 3 – 6
New SCR
Unit 1 1,629 204,703,000
(3)
4,834,000 (3) 3 - 6
Unit 2 1,629
204,703,000
(3)
4,834,000
(3)
3 - 6
Unit 3 1,158 209,514,000
(3)
4,717,000 (3) 3 - 6
New NH3 Vaporizers
Unit 1 818 1,625,630 4,779,513 3 - 6
Unit 2 818 1,625,630 4,779,513 3 – 6
Unit 3 604 1,625,630 3,689,374 3 – 6
2018 SCR Upgrades
Unit 1 11,007 6,131,910 6,506,910 Complete
Unit 2 11,007 5,461,310 5,461,685 Complete

(1) Schedule assumes 2 - 3 years for permitting, design, fabrication and delivery, and installation over
a 3-year period during scheduled outages.
(2) Costs based on Tables 2.10 thru 2.13, Appendix K, New Hampshire Regional Haze Plan Periodic
Comprehensive Revision” (DRAFT 10/31/2019).
(3) Costs based on CAMD Air Markets Retrofit Cost Analyzer Tool.

18 

Table 3. NOx Strategies, Estimated Annualized Costs, and Cost per Ton Reduced
Homer City Cost Estimates Estimated Costs Based on MANE-
VU/EPA Data / EPA’s CAMD
Retrofit Cost Analyzer Tool
Strategy Emission
Reduction
(TPY)
Annualized
Cost
(2019$)
Cost
(2019$
per ton)
Emission
Reduction
(TPY)
Annualized
Cost
(2019$)
Cost
(2019 $
per ton)
New LNB/SOFA
Unit 1 476 3,888,684 8,170 476 8,237,084
(1)
17,305
(1)
Unit 2 476 3,888,684 8,170 476 8,237,085
(1)
17,305
(1)
Unit 3 191 4,570,422 23,929 191 8,381,605
(1)
43,883
(1)
New SCR
Unit 1 1,629 24,158,000
(2)
14,830(2)
Unit 2 1,629 24,158,000
(2)
14,830(2)
Unit 3 1,158 19,778,000
(2)
21,151(2)
New NH3 Vaporizers
Unit 1 818 7,851,741 9,599
Unit 2 818 7,851,741 9,599
Unit 3 604 6,107,518 10,112
2018 SCR Upgrades
Unit 1 11,007 8,156,415 741
Unit 2 11,000 8,066,286 733

(1) Costs based on Tables 2.10 thru 2.13, Appendix K, New Hampshire Regional Haze Plan Periodic
Comprehensive Revision” (DRAFT 10/31/2019).
(2) Costs based on CAMD Air Markets Retrofit Cost Analyzer Tool.

19 

10.1.1.1 LNB/OFA Replacement
In 2016 and 2017, Homer City evaluated compliance options for Units 1 and 2 for
PADEP’s RACT II program. As part of the evaluation, Homer City obtained quotations for
replacement of the LNBs in Units 1 and 2. Cost estimates and performance guarantees submitted
by the vendor during that analysis were used to determine costs per ton of NOx removed for Units
1 and 2 if the new LNB/SOFA system were installed.
NOx emissions from the Units 1 and 2 combustion zones with the existing burners are
approximately 0.55 lb/MMBtu. The vendor for the burners evaluated for RACT II estimated a
combustion zone NOx emission not to exceed a NOx emission rate of 0.47 lb/MMBtu. Assuming
8,760 hours of operation at full load, installation of the new LNB/SOFA system would result in
NOx emission reductions of approximately 476 tons per year each for Units 1 and 2.
NOx emissions from the Unit 3 combustion zone with the existing burners are
approximately 0.38 lb/MMBtu. Installation and operation of a new LNB/SOFA system could
reduce the combustion zone NOx emissions to approximately 0.35 lb/MMBtu. Assuming 8,760
hours of operation at full load, installation of the new LNB/SOFA system would result in NOx
emission reductions of approximately 191 tons per year for Unit 3.
10.1.1.2 Upgrades to SCR System
During 2018 and 2019, the SCR systems for Units 1 and 2 were upgraded at a cost of $6.1
and $5.5, respectively. These upgrades included replacement of the AIG and installation of static
mixers between the AIG and the catalyst to assure uniform distribution of the ammonia across the
catalyst. Additional upgrades to the Units 1 and 2 SCR systems would require capital investment
for installation of new AIGs with increased ammonia injection capacity, replacement of existing
ammonia pumps and addition of catalyst beds. Increased operating costs would be as a result of
increased ammonia use and catalyst replacement costs.
Upgrading the SCR system for Unit 3 would involve similar capital effort, i.e., replacing
the AIG and installation of additional catalysts, along with associated annual operating costs due
to increased ammonia use and need for additional catalyst bed replacements.
Assuming 8,760 hours of operation at full load, upgrades of the SCR systems would result
in NOx emission reductions of approximately 818, 818, and 604 tons per year each for Units 1, 2
and 3, respectively.
10.1.1.3 Replacement of the SCR Systems
Homer City has investigated the costs and emission reduction potential of replacement of
the existing SCR systems with new SCR systems. Costs were evaluated using the EPA CAMD
Retrofit Cost Analyzer Tool. Assuming 8,760 hours of operation at full load, upgrades of the
SCR systems would result in NOx emission reductions of approximately 1,629, 1,629, and 1,158
tons per year each for Units 1, 2 and 3, respectively.

20 

10.1.2 Enhanced SO2 Control Measures
As is discussed above, Homer City completed installation of NIDS SO2 removal systems
on Units 1 and 2 at a total cost of approximately $900 million (2014$). The allowable SO2 rate
was decreased from 3.7 lb/MMBtu to 0.20 lb/MMBtu (95% reduction in SO2 rate), and a 95%
reduction in tons emitted per hour. As a merchant generator, Homer City’s operations are dictated
by PJM, the grid operator based on electrical demand. Therefore, it is not possible to predict unit
utilization and corresponding emissions.
A summary of the projected SO2 emission reductions, costs, and time to implement for the
available SO2 emissions strategies for Units 1, 2, and 3 is shown in Table 4. Table 5 shows
annualized cost for the potential SO2 control options on a cost per ton of pollutant and annualized
costs based on the capitol costs and annual operating expenses shown in Table 4. Additional
discussion is provided below for each of the SO2 control strategies.

21 

Table 4. SO2 Strategies, Estimated Costs and Time to Implement
Homer City Cost Estimates Estimated Costs Based on MANE-
VU/EPA Data / EPA’s CAMD
Retrofit Cost Analyzer Tool/MANE-
VU/EPA Data

Strategy Emission
Reduction
(TPY)
Capital Cost
(2019$)
Annual
Operating
Cost (2019$)
Emission
Reduction
(TPY)
Capital Cost
(2019$)
Annual
Operating
Cost (2019$)
Time to
Implement
(Years) (8)
Low Sulfur Coal (1)
Unit 1 4,462 0 29,617,635

3 - 6
Unit 2 4,462 0
29,617,635
3 – 6
Unit 3 4,477 0 41,389,146

3 – 6
NIDS Upgrade
Unit 1 1,487 5,000,000 10,648,210 3 – 6
Unit 2 1,487 5,000,000 10,648,210 3 - 6
New NIDS
Unit 3 6,360 524,521,000
(7)
23,687,770
(7)
6,095 $348790,000
(4)

11,7132,000(
4)
3 - 6
Partial NG Conversion (2)
Unit 1, 2,
and 3
17,616

90,556,500 155,867,893 17,616 211,877,500
(5)
171,088,000
(5)
6 - 10 (3)
2015/2016 NIDS Install
Unit 1 104,121 493,945,000
(6)
20,061,688
(6)
112,547
$345,442,000
377,345,000
(4)
49,151,600
(4)
Completed
Unit 2 104,121 493,945,000
(6)
20,061,688
(6)
112,547
$345,442,000
377,345,000
(4)
49,151,600
(4)
Completed

(1) Costs based on current coal market costs
(2) Conversion would replace only approximately 50% of the coal firing with natural gas.
(3) Estimated schedule includes siting and construction of natural gas pipeline.
(4) Costs based on CAMD Air Markets Retrofit Cost Analyzer Tool for a dry lime scrubber.
(5) Costs based on Tables 2.10 thru 2.13, Appendix K, New Hampshire Regional Haze Plan Periodic
Comprehensive Revision (DRAFT 10/31/2019) 12
(6) Adjusted actual capital expenditure and operating costs based on Units 1 and 2, and adjusted to
2019$.
(7) Projected capital and operating costs are scaled from actual costs for Unit 1 and 2, and adjusted to
2019$.
(8) Schedule assumes 2 - 3 years for permitting, design, fabrication and delivery, and installation
over a 3-year period during scheduled outages.

12 https://www.des.nh.gov/organization/divisions/air/do/asab/rhp/documents/r-ard-19-01.pdf

22 

Table 5. SO2 Strategies, Estimated Annualized Costs, and Cost per Ton Reduced
Homer City Cost Estimates Estimated Costs Based on MANE-
VU/EPA Data / EPA’s CAMD
Retrofit Cost Analyzer Tool/MANE-
VU/EPA Data
Strategy Emission
Reduction
(TPY)
Annualized
Cost
(2019$)
Cost
(2019$
per ton)
Emission
Reduction
(TPY)
Annualized
Cost
(2019$)
Cost
(2019$
per ton)
Low Sulfur Coal
Unit 1 4,462 47,388,216 10,607
Unit 2 4,462 47,388,216 10,607
Unit 3 4,477 41,389,146 14,792
NIDS Upgrade
Unit 1 1,487 19,211,356 12,920
Unit 2 1,487 19,211,356 12,920
New NIDS
Unit 3 6,360 103,890,419 16,335 6,095 33,063,200
(2)
7,245 (2)
Partial NG Conversion (1)
Units 1, 2,
and 3
17,616 260,781,542

14,804 17,616 274,463,996
(3)
15,580
(3)
2015/2016 NIDS Install
Unit 1 104,121 83,468,980
(4)
802
(4)
112,547

35,341,300(2) 751(2)
Unit 2 104,121 83,468,980
(4)
802
(4)
112,547

35,341,300 (2) 751(2)

(1) Conversion would replace only approximately 50% of the coal firing with natural gas.
(2) Costs based on CAMD Air Markets Retrofit Cost Analyzer Tool.
(3) Costs based on Tables 2.10 thru 2.13, Appendix K, New Hampshire Regional Haze Plan Periodic
Comprehensive Revision (DRAFT 10/31/2019).
(4) Costs based on actual capital expenditure and operating costs adjusted to 2019$.

23 

10.1.2.1 Switching to Lower Sulfur Coal
Homer City investigated the availability and quality of lower sulfur coal for use in Units 1,
2, and 3. Homer City was designed for, and currently burns western Pennsylvania bituminous
coal, typically containing a sulfur content of approximately 3.5%, and greater. Lower sulfur
western Pennsylvania bituminous coal, typically metallurgical (met) coal is available. Securing
contracts and obtaining long term contracts for met coal in the quantities required for Homer City
would be a lengthy process. The length of the process is a function of the duration of the contract
of the existing contract. For example, negotiations to renew a 2-year contract will not start until
several months before the end of that contract.
Costs incurred would be the recurring cost differential between steam coal and met coal.
Comparison of high and low sulfur bituminous coal prices on the EIA website indicate September
18, 2020 prices of $42.45/ton for higher sulfur coal vs $59.50 /ton low sulfur coal.
(https://www.eia.gov/coal/) It should be noted that spot coal prices vary on a day-to-day basis.
Projected SO2 emission reductions and costs for conversion to lower sulfur met coal for
Units 1, 2, and 3 and projected times for installation are shown in Table 4.
10.1.2.2 Upgrading the Existing Units 1 and 2 NIDS
As discussed earlier, Homer City recently completed the installation of NIDS (dry FGD)
to reduce SO2 emissions from Units 1 and 2. These NIDS were installed in 2015 and 2016 at a
cost of $450 million (2014$) each for Units 1 and 2. Homer City evaluated measures necessary to
improve the SO2 removal efficiency of the NIDS. Enhancing the SO2 removal efficiency can be
accomplished through the injection of additional lime into the NIDS J-ducts. However, injection
of additional lime would result in overload of the NIDS by-product handling system. In order for
Homer City to upgrade the NIDS performance by injection of additional lime, it would be
necessary to replace the by-product handling system with a higher capacity system. Capital cost
estimates for replacement of the by-product handling systems are approximately $5 million each
for Units 1 and 2. Additional annual operating costs of approximately $10.5 million would be
experienced because of the cost of purchase of additional lime required, increased electrical costs
for motors, and in increased waste transport and disposal and shortened life of the waste disposal
site.
Projected SO2 emission reductions and costs for NIDS by-product handling system
replacement/upgrades for Units 1 and 2 and projected times for installation are shown in Table 4.
10.1.2.3 Replacing the Unit 3 Wet FGD System
Homer City has investigated measures necessary to improve the SO2 emission reduction
efficiency of the Unit 3 wet FGD. Significant upgrades to the existing scrubber would negatively
impact the water balance at the facility and would likely require significant investment in new
wastewater capability in addition to requiring significant additional fan capacity and resulting loss
in plant efficiency.

24 

Therefore, Homer City has evaluated the installation of a dry scrubber-type system similar
to the NIDS installed on Units 1 and 2. Homer City has developed control cost estimates for a dry
scrubber system based on the scaling of the costs experienced for the recent installation of the
Units 1 and 2 NIDS and adjusting the 2014($) to 2019($) and by using the calculation
methodologies in EPA’s Air Markets Retrofit Cost Analyzer. (See Appendix F) The projected
costs for procurement and operation of a new dry scrubber for Unit 3 are shown in Tables 4 and 5.
10.1.2.4 Conversion to Natural Gas
Homer City has investigated conversion of the facility to firing of natural gas. Because of
the quantity of natural gas fuel that would be required for full conversion of the facility it was
determined that full conversion was not practical. The evaluation indicated that replacement of
approximately 50% of the heat input with natural gas was feasible. Conversion of the facility to
partial firing of natural gas would require the construction of a major natural gas pipeline and
related natural gas handling facilities with associated air quality and non-air quality environmental
impacts, as well as boiler burner replacements. In addition, there is a projected significant increase
in fuel costs associated with a partial conversion to of the facility to natural gas firing. The fuel
cost differential was calculated using Homer City’s current coal cost and Henry Hub Natural Gas
Futures Quotes.13 Other costs related to partial conversion to natural gas, including estimated
pipeline construction costs and burners, were developed based on information in Appendix K,
New Hampshire Regional Haze Plan Periodic Comprehensive Revision (DRAFT 10/31/2019.
(See Appendix G)
Projected SO2 emission reductions and costs for the partial conversion to natural gas for
Units 1, 2, and 3 and projected times for installation are shown in Table 4.
10.2 Time Necessary for Compliance
The second statutory factor – the time necessary for compliance – involves estimating the
time needed for a source to implement a potential control measure. Each of these control options
would require permitting, engineering design, procurement and installation coordinated with
scheduled outages. Homer City has provided estimates for implementation of each of the potential
emissions measures in Tables 2 and 4.
10.3 Energy and Non-Air Quality Environmental Impacts of Compliance
The third statutory factor requires characterizing information about energy and non-air
quality environmental impacts. There are a number of associated environmental and energy issues
associated with the available NOx and SO2 emission reduction measures. These are discussed
more fully below.
10.3.1 Energy
Each of the available measures for reducing emissions of NOx or SO2 at the facility has
some increased energy consumption component. Increased material transport, increased size of

13 https://www.cmegroup.com/trading/energy/natural-gas/natural-gas.html

25 

motors, as well as related activities will result in increased emissions of criteria pollutants as well
as GHGs. Increased parasitic energy use will have a negative impact on the facility’s ability to
produce power for the grid and will negatively impact efforts to reduce GHG emissions as required
under the Affordable Clean Energy (ACE) rule.
10.3.1.1 LNB/SOFA
LNB/SOFA systems typically result in less than complete combustion of the fuel. This is
manifest in increased levels of unburned carbon in the fly ash. Tuning of burners to lower NOx
emissions also results in increased emissions of CO. These products of incomplete combustion
are indicative of increased energy inputs required over those for a non-LNB/SOFA system. This
incomplete combustion may have impacts on other factors including additional waste disposal and
additional fuel use resulting in associated increased mobile source emissions.
10.3.1.2 Changes/Upgrades to SCR System
Upgrades to the SCR systems will require additional energy to power the ammonia pumps
which supply ammonia to the AIG.
10.3.1.3 Switching to Lower Sulfur Coal
Lower sulfur “met” coal has a lower heating value per ton that the “steam” coal currently
burned at the facility. Therefore, replacing the “steam” coal with “met” coal will result in increased
emissions from transport of the additional tonnage of coal required to make up for the difference
in energy content. Since the energy content of the “met” coal is approximately 96 to 97% that of
steam coal, it is anticipated that transportation emissions required for transport of “met” coal to
the site would increase by approximately 3-4% with associated GHG emissions.
10.3.1.4 Upgrading the Existing Units 1 and 2 NIDS
Upgrading of the NIDS systems would result in additional energy consumption to transport
the additional lime to the facility, inject the lime into the J-duct scrubbers, and to transport the
additional waste for disposal. Additionally, transport of the additional lime required will increase
emissions of criteria pollutants and GHGs.
10.3.2 Waste Transport/Disposal
All of the available strategies have additional waste issues/costs associated with them.
Most of these are energy and disposal capacity issues on site. Generation of increased quantities
of SO2 scrubber by-product materials and the transport of the materials will result in increased
emissions and shorten the on-site disposal site life, ultimately requiring expenditure to find a new
site or a way to increase capacity at the site. In addition, the transport of the additional waste will
result in increased emissions of criteria pollutants and GHGs.

26 

10.4 Remaining Useful Life of Any Potentially Affected Sources
Homer City Units 1 and 2 were installed in 1969 and Homer City Unit 3 was installed in
1977. Although Units 1 and 2 the units are more than 50 years old and Unit 3 is 43 years old, no
specific retirement dates have been set. Therefore, the remaining useful lives of the Units may be
assumed to be at least 20 years.
11. Conclusion
Homer City has installed and operates BACT level controls for SO2, NOx and PM. The four-
factor analysis considers the potential and costs of upgrading these controls for SO2 and NOx.
These controls already meet LEE emission limits under the MATS Rule.
Homer City has identified a number of additional controls that are technically feasible for reducing
emissions of NOx and SO2. However, the projected costs of the emission reductions are not
reasonable, even assuming a 100% capacity factor for the facility. Costs per ton of emissions
reduction range from $8,170 to $43,883 for NOx; and from $7,245 to $15,580 for SO2. Moreover,
any of these options would take several years to implement and would result in increased energy
consumption, increased emissions of GHGs and other pollutants, increased consumption of
consumables (e.g., ammonia, lime, coal), and/or increased wastes to be disposed.

APPENDIX A
Coal Analysis Report

APPENDIX B
RACT / BACT / LAER Clearinghouse
NOx Controls
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Previous Page
COMPREHENSIVE REPORT
Report Date:08/17/2020
Facility Information
RBLC ID:AZ-0055 (final) Date Determination
Last Updated:01/08/2014
Corporate/Company Name:SALT RIVER PROJECT AGRICULTURAL AND POWER DISTRICT Permit Number:AZ 08-01
Facility Name:NAVAJO GENERATING STATION Permit Date:02/06/2012 (actual)
Facility Contact:KARA MONTALVO FRS Number:110028287725
Facility Description:2,250 MW COAL FIRED POWER PLANT SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221112
Permit URL:http://www.epa.gov/region9/air/permit/r9-permits-issued.html
EPA Region:9 COUNTRY:USA
Facility County:COCONINO
Facility State:AZ
Facility ZIP Code:86040
Permit Issued By:EPA REGION IX (Agency Name)
MR. GERARDO RIOS(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:GERARDO RIOS, EPA REGION IX, 415-972-3974, [e-mail]
Permit Notes:PERMIT ISSUED ON 11/20/2008 AND ADMINISTRATIVELY AMENDED ON 2/6/2012. AFFECTED CLASS I AREAS CAN BE
FOUND IN BART REGULATORY DOCKET AT http://www.regulations.gov/fdmspublic/component/main?
main=DocketDetail&d=EPA-R09-OAR-2008-0454
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 UT Arches NP 100km - 50km
CLASS1 UT Bryce Canyon NP < 100 km
CLASS1 UT Canyonlands NP 100km - 50km
CLASS1 UT Capitol Reef NP < 100 km
CLASS1 AZ Grand Canyon NP < 100 km
CLASS1 AZ Mazatzal > 250 km
CLASS1 CO Mesa Verde NP 100km - 50km
CLASS1 AZ Petrified Forest NP 100km - 50km
CLASS1 AZ Pine Mountain > 250 km
CLASS1 AZ Sycamore Canyon 100km - 50km
CLASS1 UT Zion NP 100km - 50km

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 2/58

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
8/17/2020 Format RBLC Report
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Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 4/58
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:TX-0601 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:TEXAS MUNICIPAL POWER AGENCY Permit Number:5699 AND PSDTX18M2
Facility Name:GIBBONS CREEK STEAM ELECTRIC STATION Permit Date:10/28/2011 (actual)
Facility Contact:KEN BABB [phone] FRS Number:110008138078
Facility Description:one 5,060 MMBtu/h boiler burning natural gas, lignite, coal, and a blend of lignite
or coal with petroleum coke
SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221122
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:GRIMES
Facility State:TX
Facility ZIP Code:77830
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 5/58
Other Agency Contact Info:Kate Stinchcomb, [phone], [e-mail]
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 TX Big Bend NP > 250 km

Process/Pollutant Information
PROCESS
NAME:
Boiler
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Coal
Throughput: 5060.00 MMBtu/h
Process Notes:
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1200 LB/MMBTU 30-DAY ROLLING AVERAGE
Emission Limit 2:2428.0000 LB/H
Standard Emission:2365.0000 T/YR
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:1.2000 LB/MMBTU
Emission Limit 2:1771.0000 LB/H
Standard Emission:6052.0000 T/YR
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Wet Flue Gas Desulfurization
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:CA-1206 (final) Date Determination
Last Updated:01/14/2014
Corporate/Company Name:APMC STOCKTON COGEN Permit Number:SJ 85-04
Facility Name:STOCKTON COGEN COMPANY Permit Date:09/16/2011 (actual)
Facility Contact:GLENN SIZEMORE FRS Number:110000484930
8/17/2020 Format RBLC Report
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Facility Description:49.9 MW COGENERATION POWER PLANT OWNED BY AIR PRODUCTS
MANUFACTURING CORPORATION (APMC) STOCKTON COGEN AND
LOCATED IN STOCKTON, CALIFORNIA
SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221112
Permit URL:http://www.epa.gov/region09/air/permit/r9-permits-issued.html
EPA Region:9 COUNTRY:USA
Facility County:SAN JOAQUIN COUNTY
Facility State:CA
Facility ZIP Code:95206
Permit Issued By:EPA REGION IX (Agency Name)
MR. GERARDO RIOS(Agency Contact) [phone] [e-mail]
Permit Notes:PSD permit amended to allow increased operation of facility's natural gas-fired auxiliary boiler and reduced operation of its coal-fired
circulating fluidized bed boiler. Facilitywide emission increases less than the PSD significant thresholds.
Facility-wide Emissions:Pollutant Name:Facility-wide Emissions Increase:
Carbon Monoxide 28.8000 (Tons/Year)
Nitrogen Oxides (NOx)6.6200 (Tons/Year)
Particulate Matter (PM)9.9300 (Tons/Year)
Sulfur Oxides (SOx)2.2600 (Tons/Year)
Volatile Organic Compounds (VOC)0.9900 (Tons/Year)

Process/Pollutant Information
PROCESS
NAME:
CIRCULATING FLUIDIZED BED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 730.00 MMBTU/H
Process Notes:
POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:59.0000 LB/H 8-HR AVG
Emission Limit 2:100.0000 LB/H 3-HR AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LIMESTONE INJECTION W/ A MINIMUM REMOVAL EFFICIENCY OF 70% (3-HR AVG) TO BE
MAINTAINED AT ALL TIMES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:50.0000 PPM @3% O2, 3-HR AVG
Emission Limit 2:42.0000 LB/H 3-HR AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(B) LOW BED TEMPERATUR STAGED COMBUSTION; SELECTIVE NON-CATALYTIC REDUCTION
(SNCR)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
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Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:OTHER LIMITS: AUX BOILER AND CIRCULATING FLUIDIZED BED BOILER MAY ONLY BE
OPERATED SIMULTANEOUSLY FOR UP TO 250 HRS PER YEAR, DURING CIRCULATING FLUIDIZED
BED BOILER STARTUP AND SHUTDOWN PERIODS, AND PERIODS OF LESS THAN 10 HRS
DURATION TO CONDUCT EMISSIONS TESTING

Process/Pollutant Information
PROCESS
NAME:
AUXILIARY BOILER
Process Type: 12.310 (Natural Gas (includes propane and liquefied petroleum gas))
Primary Fuel: NATURAL GAS
Throughput: 178.00 MMBTU/H
Process Notes:
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:7.0000 PPMVD @3% O2
Emission Limit 2:0.0085 LB/MMBTU
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:OTHER LIMITS: AUX BOILER AND CIRCULATING FLUIDIZED BED BOILER MAY ONLY BE
OPERATED SIMULTANEOUSLY FOR UP TO 250 HRS PER YEAR, DURING CIRCULATING FLUIDIZED
BED BOILER STARTUP AND SHUTDOWN PERIODS, AND PERIODS OF LESS THAN 10 HRS
DURATION TO CONDUCT EMISSIONS TESTING

Previous Page
Facility Information
RBLC ID:MI-0400 (final) Date Determination
Last Updated:04/14/2016
Corporate/Company Name:WOLVERINE POWER SUPPLY COOPERATIVE, INC. Permit Number:317-07
Facility Name:WOLVERINE POWER Permit Date:06/29/2011 (actual)
Facility Contact:BRIAN WARNER 2317755700 X 3336 [e-mail] FRS Number:26-14105823
Facility Description:Coal-fired power plant. SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:5 COUNTRY:USA
Facility County:PRESQUE ISLE
Facility State:MI
Facility ZIP Code:49779
Permit Issued By:MICHIGAN DEPT OF ENVIRONMENTAL QUALITY (Agency Name)
MS. CINDY SMITH(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Please contact permit engineer Melissa Byrnes at 517-373-7065 with questions regarding this permit. Thank you.
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 MI Seney 100km - 50km
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 8/58

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2)
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H EACH
Process Notes: 3,030 MMBTU/H each boiler
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , MACT , SIP
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Limit of 0.010 LB/MMBTU is for EACH boiler. Test Protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0260 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:78.8000 LB/H EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulset jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The limits specified above apply to EACH boiler.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0240 LB/MMBTU EACH; TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 9/58
Pollutant/Compliance Notes:NOTE: The PM2.5 limit above applies to EACH boiler.

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:1.0000 LB/MW-H GROSS OUTPUT; EACH; 30 D ROLL. AVG; NSPS
Emission Limit 2:281.1000 LB/H EACH; 24H ROLL.AVG.; BACT
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SNCR (Selective Non-Catalytic Reduction)
Est. % Efficiency:63.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The limits above apply to EACH boiler.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:
Emission Limit 2:744.0000 LB/H EACH; 24H ROLL. AVG.; BACT&SIP
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission Limit of 744 LB/H is for each boiler and is based on a 24-hr rolling average determined each
hour the boiler operates. This limit is set per BACT & SIP.

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:303.0000 LB/H EACH; 24-H ROLL.AVG.; BACT & SIP
Emission Limit 2:1.4000 LB/MW-H GROSS OUTPUT; EACH; 30D ROLL.AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limits above apply to EACH boiler. Emission Limit 2 above of 1.4 LB/MW-H gross ouput is
for each boiler and is based on a 30-day rolling average and is set per the NSPS.

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 10/58
Emission Limit 1:17.8000 LB/H EACH; TEST PROTOCOL; BACT,MACT,SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The emission limit above is for EACH boiler.

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0030 LB/MMBTU EACH; TEST PROTOCOL; BACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:14.0000 E-5 LB/MMBTU EACH; TEST PROTOCOL; MACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber and pulse jet fabric filter
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limit is 0.00014 LB/MMBTU for each boiler. Test Protocol will specify averaging time.

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:0.0077 LB/GW-H EACH; 12-MO ROLLING; MACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber, sorbent injection (e.ge. activated carbon), and a fabric filter.
8/17/2020 Format RBLC Report
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Est. % Efficiency:93.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Dioxide Equivalent (CO2e)
CAS Number:CO2e
Test Method:Unspecified
Pollutant Group(s):( Greenhouse Gasses (GHG) )
Emission Limit 1:2.1000 LB/KW-H EACH; 12-MO ROLL.AVG.; BACT
Emission Limit 2:6024107.0000 T/YR EACH; 12-MO ROLL.AVG.; BACT
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Use of biomass and energy efficiencies.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0011 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber and pulse jet fabric filter
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Auxiliary Boiler
Process Type: 13.220 (Distillate Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
Throughput: 72.40 MMBTU/H
Process Notes: Maximum operation was based on 4,000 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1100 LB/H TEST PROTOCOL; BACT/SIP/MACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 12/58
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.1700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.1700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:1.6700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Low NOx burner
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 13/58
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:6.1100 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(P) Good combustion control
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.3000 LB/H TEST PROTOCOL; BACT/SIP/MACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0500 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Emergency generator
Process Type: 17.110 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
Throughput: 4000.00 HP
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 14/58
Process Notes: Maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1500 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:1.7600 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:1.7600 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Fire Pump
Process Type: 17.210 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 15/58
Throughput: 420.00 HP
Process Notes: Maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1500 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1400 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1400 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:3.0000 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
8/17/2020 Format RBLC Report
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Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limit is expresssed as NMHC+NOx = 3.0 G/HP-H.

Process/Pollutant Information
PROCESS
NAME:
Turbine generator (EUBLACKSTART)
Process Type: 15.190 (Liquid Fuel & Liquid Fuel Mixtures)
Primary Fuel: Diesel
Throughput: 540.00 MMBTU/H
Process Notes: This is a turbine generator identified in the permit as EUBLACKSTART. It has a throughput capacity of 540MMBTU/HR which equates to 102 MW.
The maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0300 LB/MMBTU TEST PROTOCOL
Emission Limit 2:16.2000 LB/H TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:16.2000 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 17/58
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.1600 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0450 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0110 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Cooling Tower (EUCOOLINGTWR)
Process Type: 99.009 (Industrial Process Cooling Towers)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 18/58
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0005 %
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Drift eliminators
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE)
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Limestone handling activities
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0002 GR/DSCF LIMESTONE PROCESS. EQUIP.;TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM limit for limestone handling (EULIMESTONE) is 0.00016 gr/dscf and is established per BACT. This
limit applies to the limestone processing equipment within this emission unit.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:This PM10 limit is for the limestone processing equipment within EULIMESTONE portion of the permit.

8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 19/58
POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:This PM2.5 limit is for the limestone processing equipment portion of EULIMESTONE in the permit.

Process/Pollutant Information
PROCESS
NAME:
Limestone preparation (EULIMESTONEPREP)
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: This is the limestone preparation activities within this permit and is identified as EULIMESTONEPREP in the permit.
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See Pollutant Notes field below.
Pollutant Group(s):
Emission Limit 1:7.0000 % OPACITY TRANSFER PTS.
Emission Limit 2: % OPACITY BLDG. HOUSING CRUSHER
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Test method used varies per emission point. See below: The 7% opacity limit applies to the transfer points
portion of EULIMESTONEPREP. Method 9 is to be used if emissions are detected. The 0% opacity limit applies
to the building housing crusher. If emissions are detected, then Method 22 is to be used. A 7% opacity limit
ALSO applies to the dust collectors. If emissions are detected, then Method 9 is to be used.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:18.0000 E-7 GR/DSCF LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 20/58
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM limit of 0.0000018 grains/dscf applies to the limestone prep train portion of EULIMESTONEPREP.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/H LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP , NSPS
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM10 limit of 0.0006 LB/H applies to the limestone prep. train portion of EULIMESTONEPREP.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/H LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM2.5 limit of 0.0006 LB/H applies to the limestone prep train portion of EULIMESTONEPREP.

Process/Pollutant Information
PROCESS
NAME:
CFB Bed Ash Removal (EUBEDASH)
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:If emissions are detected, then Method 9 to be used.
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY TRANSFER POINTS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 21/58
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:5% Opacity at transfer points. Method 9 to be used if emissions are detected.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:11.0000 E-6 GR/DSCF BEDASH COLLECTION & REMOVAL EQUIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.000011 GR/DSCF for bedash collection & removal equipment. Averaging time is determined from test
protocol.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H BEDASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.0012 LB/H for bedash collection & removal equipment. The averaging time is determined from the
test protocol.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H BEDASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.0012 LB/H for bedash collection & removal equipment. Averaging time is determined from test
protocol.
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 22/58

Process/Pollutant Information
PROCESS
NAME:
Ash Removal Economizer & Fabric filter hoppers
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes: Ash removal economizer & fabric filter hoppers (EUFLYASH)
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % TRANSFER PTS.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:VE = 5% opacity at transfer points. Method 9 is to be used if emissions are detected.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:32.0000 E-6 GR/DSCF FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.000032 GR/DSCF for flyash collection & removal equipment. The averaging time is determined from
the test protocol.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 23/58
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.0012 LB/H for flyash collection & removal equipment. Test protocol will determine the averaging
time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.0012 LB/H for flyash collection & removal equipment. Test protocol will determine averaging time.

Process/Pollutant Information
PROCESS
NAME:
Solid fuel handling system (EUSOLIDFUELHANDLING)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See Pollutant Notes for details.
Pollutant Group(s):
Emission Limit 1:10.0000 % OPACITY DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % OPACITY BLDG. HOUSING CRUSHER
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity at drop & transfer points. If emissions are detected, Method 9 is to be used. The applicable reqts. for
this limit is PSD-BACT, SIP, & NSPS. 5% opacity for the building housing crusher. If emissions are detected,
Method 9 is to be used. The applicable reqts. for this limit is PSD-BACT, & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:18.4000 E-4 GR/DSCF TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 24/58
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00184 GR/DSCF for the transfer tower. Test protocol will determine averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.2360 LB/H TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.236 LB/H for the transfer tower. Test protocol will determine the averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.2360 LB/H TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.236 LB/H for the transfer tower. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
Coal crushers (EUFUELCRUSHER)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See pollutant notes below.
Pollutant Group(s):
Emission Limit 1:10.0000 % OPACITY DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % OPACITY DUST COLLECTOR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 25/58
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Fabric filter dust collector.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity for the drop and transfer points. If emissions are detected, Method 9 is to be used. The applicable
reqts. for this limit are PSD-BACT, SIP & NSPS. 5% opacity for the dust collector. If emissions are detected,
Method 9 is to be used. The applicable reqts. for this limit are PSD-BACT & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.0000 E-5 GR/DSCF FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Fabric filter dust collector.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00002 GR/DSCF for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.00276 LB/H for the fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 26/58
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
Coal fuel storage silos (EUFUELSILO)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:10.0000 % DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % DUST COLLECTOR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity at drop & transfer points. If emissions are detected, Method 9 is to be used. The applicable reqts. for
this limit is PSD-BACT, NSPS, & SIP. 5% opacity for the dust collector. If emissions are detected, Method 9 is to
be used. The applicable reqts. for this limit is PSD-BACT & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:25.0000 E-5 GR/DSCF FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00025 GR/DSCF for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 27/58
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2) - EXCLUDING Startup & Shutdown
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H each
Process Notes: Each boiler is rated at 3,030 MMBTU/H. NOTE -The emission limits included under this process name specifically EXCLUDE startup & shutdown.
The other CFB1 & CFB2 boiler section are the emission limits for the boiler that INCLUDE the startup & shutdown emissions. This has been
changed per discussion with RBLC Administrator.
POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU EACH; 30D ROLL.AVG.; BACT&SIP; EXC. SS
Emission Limit 2:0.0500 LB/MMBTU EACH;12-MO ROLL.AVG.; BACT&SIP; EXC.SS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: These SO2 limits apply to EACH boiler and EXCLUDE startup & shutdown emissions.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:72.7000 LB/H EACH; TEST PROTOCOL; BACT&SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulse jet Fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The 72.7 LB/H limit is for EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0700 LB/MMBTU EACH, 30 D ROLLING AVG; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) SNCR (Selective Non-Catalytic Reduction)
Est. % Efficiency:63.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Note: This limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1500 LB/MMBTU EACH; 30 D ROLLING AVG; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NOTE: This limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0030 LB/MMBTU EACH; LIMIT PER BACT, MACT, & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NOTE: This VOC limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.
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Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - Transfer Points
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "" Process untill broken out by RBLC Admin. Original Notes: Limestone handling (EULIMESTONE)
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:EPA/OAR Mthd 9
Pollutant Group(s):
Emission Limit 1:7.0000 % OPACITY TRANSFER PTS.,
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector. Test Method varies depending on process within this emission unit; i.e. transfer pts., truck
traffic, etc.)
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ------
Original Note ------ "7% opacity is limit for the transfer points within EULIMESTONE. If emissions are
detected, Method 9 is to be used."

Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - BLDG. HOUSING CRUSHER
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "" Process untill broken out by RBLC Admin. Limestone handling activities - This portion is for the building housing crusher.
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:EPA/OAR Mthd 22
Pollutant Group(s):
Emission Limit 1: % OPACITY BLDG. HOUSING CRUSHER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector. This portion is for the building housing crusher.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ---------
Original Notes --------- 0% opacity is the limit for the building housing crusher portion of the emission unit. If
emissions are detected, Method 22 is to be used.

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Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - WHEEL LOADERS & TRUCK TRAFFIC EACH
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "Limestone handling (EULIMESTONE) " Process until broken out by RBLC Admin. Limestone handling activities
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:Method 9D, if emissions detected
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY WHEEL LOADERS & TRUCK TRAFFIC EACH
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) This portion of the emission unit is wheel loaders and truck traffic.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ------------
original note -------------- 5% is the opacity limit for the wheel loaders and truck traffic portion of the limestone
handling emission unit EULIMESTONE. If emissions are detected, Method 9D is to be used.

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2)--Startup & Shutdown ONLY
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H EACH
Process Notes: This section is for emissions associated with startup & shutdown ONLY.
POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:54.5000 LB/H EACH; BACT & SIP; SS ONLY
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: This limit (PM2.5 = 54.5 LB/HR) applies ONLY during startup & shutdown of the boilers. There are no
other specific pollutant limits for either boiler during startup & shutdown.

Previous Page
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Facility Information
RBLC ID:TX-0585 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:TENASKA TRAILBLAZER PARTNERS LLC Permit Number:PSDTX1123 AND
HAP13, 84167
Facility Name:TENASKA TRAILBLAZER ENERGY CENTER Permit Date:12/30/2010 (actual)
Facility Contact:LARRY CARLSON 402-938-1661 FRS Number:UNKNOWN
Facility Description:Coal-fired electric generating facility SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:NOLAN
Facility State:TX
Facility ZIP Code:
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Mr. Richard Hughes
512-239-1554
[e-mail]
Permit Notes:HAP13, 84167
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 OK Wichita Mountains > 250 km

Process/Pollutant Information
PROCESS
NAME:
Coal-fired Boiler
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Sub-bituminous coal
Throughput: 8307.00 MMBTU/H
Process Notes: Fuel is PRB coal. Output is 900MW gross and 700 MW net. this boiler will have an amine scrubber to remove approximately 85% of the CO2 to be
used for enhanced recovery in nearby oil fields and gas wells; this is not required by the permit but is voluntary.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:EPA/OAR Mthd 7E
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0500 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:0.0600 LB/MMBTU 30-DAY ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Selective Catalytic Reduction
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:Other limits: 0.070 lb/MMBtu 24-hour avg 498 lb/hr 30-day avg 1661 lb/hr startup/shutdown

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.0600 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Wet limestone scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:498 lb/hr 30-day rolling

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1000 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.1000 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:830lb/hr 30-day rolling avg

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0120 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:99.6800 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Fabric Filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0250 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:207.6800 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter and wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:
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POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0036 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:29.9100 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practice
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0037 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:5.2000 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0005 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:4.1500 LB/H 1-H
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Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Lead (Pb) / Lead Compounds
CAS Number:7439-92-1
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1: LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Ammonia (NH3)
CAS Number:7664-41-7
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPMVD 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1: LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:NSPS
Control Method:(A) Sorbent injection and fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
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Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:TX-0593 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:SUMMIT TEXAS CLEAN ENERGY Permit Number:PSDTX1218 & 92350
Facility Name:TEXAS CLEAN ENERGY PROJECT Permit Date:12/28/2010 (actual)
Facility Contact:KARL MATTES [phone] FRS Number:UNKNOWN
Facility Description:Integrated Gasification Combined Cycle SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:EXTOR
Facility State:TX
Facility ZIP Code:
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Erik Hendrickson
[phone]
[e-mail]
Permit Notes:State permit number 92350
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 NM Carlsbad Caverns NP 100km - 50km

Process/Pollutant Information
PROCESS
NAME:
Integrated Gasification Combined Cycle
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: PRB coal
Throughput: 400.00 MW
Process Notes: This facility is an integrated gasification combined cycle power plant. It will produce a nominal 400 MW of electricity and it will produce
ammonia/urea and recover sulphuric acid as commercial products.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:3.5000 PPM ON SYNGAS
Emission Limit 2:2.5000 PPM ON NATURAL GAS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SCR
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
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CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:10.0000 PPM SULFUR CONTENT OF SYNGAS
Emission Limit 2:2.0000 GR/100 DSCF SULFUR CONTENT OF NATURAL GAS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) gasification of coal and sulfur recovery in syngas before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0070 LB/MWH
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasification of coal and sulfur recovery in syngas before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:Sulfur content of syngas is limited to 10 ppm. Sulfur content of natural gas is limited to 2 gr/100 dscf

POLLUTANT NAME:Particulate matter, total (TPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) gasification of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(including natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPM
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) good combustion controls
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201A and 202
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasificaiton of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasification of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:1.0000 PPM
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) good combustion controls
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
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Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0001 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:RACT
Other Applicable Requirements:
Control Method:(P) sungas clean-up before combustio in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1: LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) syngas clean-up before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:MI-0399 (final) Date Determination
Last Updated:04/14/2016
Corporate/Company Name:DETROIT EDISON Permit Number:93-09A
Facility Name:DETROIT EDISON--MONROE Permit Date:12/21/2010 (actual)
Facility Contact:LILLIAN WOOLLEY 313-235-5611 [e-mail] FRS Number:26-11500020
Facility Description:Utility--Coal fired power plant SIC Code:4911
Permit Type:D: Both B (Add new process to existing facility) &C (Modify process at existing
facility)
NAICS Code:221112
Permit URL:
EPA Region:5 COUNTRY:USA
Facility County:MONROE
Facility State:MI
Facility ZIP Code:48161-1970
Permit Issued By:MICHIGAN DEPT OF ENVIRONMENTAL QUALITY (Agency Name)
MS. CINDY SMITH(Agency Contact) [phone] [e-mail]
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Other Agency Contact Info:Please contact permit engineer Julie Brunner at 517-373-7088 with questions related to the permit. Thank you.
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
INTL BORDER US/Canada Border < 100 km

Process/Pollutant Information
PROCESS
NAME:
Boiler Units 1, 2, 3 and 4
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Coal
Throughput: 7624.00 MMBTU/H
Process Notes: 7,624 MMBTU/HR (Each unit). Pulverized coal-fired boilers, adding petroleum coke and increasing usage of subbituminous coal.
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1500 LB/MMBTU EACH, 30D ROLL. AVG. EXCL. STRTUP&SHTDWN
Emission Limit 2:27446.4000 LB/D EACH, 30D ROLLING AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Under 'Basis Information' and 'Other Applicable Requirements'--Other--NAAQS (above on page). Top Ranking
Option

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0800 LB/MMBTU EACH, 12-MONTH ROLLING AVG.
Emission Limit 2:222.6000 T/MO EACH, 12-MONTH ROLLING AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Staged combustion, low-NOx burners, overfire air, and SCR.
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. Under 'Basis Information' and 'Other Applicable Requirements--Other--NAAQS' (above on
page).

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0110 LB/MMBTU EACH, TEST/ OR 24H ROLL.AVG. IF PM CEMS
Emission Limit 2:10.0000 OPAC EACH, 6 MIN AVG TEST /OR COMS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
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Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:168 $/ton
Incremental Cost Effectiveness:18299 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:3rd ranking option

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.1070 LB/MMBTU EACH, 24-H ROLL. AVG.
Emission Limit 2:815.8000 LB/H EACH, 24-H ROLL. AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Wet flue gas desulfurization.
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. 'Other--NAAQS' (above)

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0034 LB/MMBTU EACH, TEST PROTOCOL
Emission Limit 2:25.9000 LB/H EACH, TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. 'Other--State'

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0240 LB/MMBTU EACH, TEST
Emission Limit 2:183.0000 LB/H EACH, TEST
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:167 $/ton
Incremental Cost Effectiveness:13093 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:3rd ranking option.

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POLLUTANT NAME:Lead (Pb) / Lead Compounds
CAS Number:7439-92-1
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1: LB/MMBTU EACH, TEST
Emission Limit 2:0.1300 LB/H EACH, TEST
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:168 $/ton
Incremental Cost Effectiveness:18299 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:3rd ranking option (cost based on surrogate of PM) 'Other -- NAAQS'

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0050 LB/MMBTU EACH, TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:89.000
Cost Effectiveness:126565 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Incremental Cost Effectiveness ($/ton)=NA 4th ranking option Note: Estimated Control Efficiency is 42% - 89%.
Only one value allowed to be entered on this page above.

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0002 LB/MMBTU EACH, TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:94.000
Cost Effectiveness:122779 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:3rd ranking option. Incremental Cost Effectivenss ($/ton) = NA

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:0.0200 LB/GW-H EACH, 12MO. ROLL. AVG.-CEMS
Emission Limit 2:143.1000 LB/YR UNITS 1&4, 12MO.ROLL.-CEMS
Standard Emission:
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Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) Co-benefit reduction due to SCRs, ESPs, and wet flue gas desulfurization.
Est. % Efficiency:90.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Units 2 & 3 have a limit of 144.2 LB/YR based on a 12-month rolling time period--using CEMS. NOTE: Under
'Control Efficiency' above, it is a range from 75% to 90% depending on the fuel type. Since only one limit may
be included above, 90% was used.

POLLUTANT NAME:Arsenic / Arsenic Compounds
CAS Number:7440-38-2
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:6.3000 E-6 LB/MMBTU EACH, TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Other Case by Case basis is T-BACT which is State Rule 336.1224.

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0024 LB/MMBTU LIMIT IS FOR EACH BOILER; TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization
Est. % Efficiency:97.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Limit is 0.0024 LB/MMBTU for each boiler. Test method will specify averaging time. The limit(s) were
established per Rule 336.1224, state rule, known as T-BACT (Best Available Control Technology for toxics).

Process/Pollutant Information
PROCESS
NAME:
4 Diesel-fired quench pumps
Process Type: 17.210 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel fuel
Throughput: 252.00 HP
Process Notes: Each pump engine is 252 HP. They are limited to emergency use and subject to NSPS Subpart IIII.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
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Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2 EACH, TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4 EACH, TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. Note: QP1 = Quench pump#1; QP2= Quench pump#2; QP3=Quench pump#3; QP4 =
Quench pump#4.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2, EACH; TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4, EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option Note: QP1=Quench pump #1; QP2=Quench pump#2; QP3=Quench pump#3; QP4=Quench
pump#4.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2 EACH; TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4 EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. 'Other Case-by-Case' is PM2.5 non-attainment, hybrid applicability

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:20.0000 % OPACITY 20% OPAC, 6 MIN. AVG; EACH PUMP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
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Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. 20% opacity on a 6-minute average for each pump QP1, QP2, QP3, QP4.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:2.6000 G/HP-H EACH PUMP; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:7.8000 G/HP-H QP1&QP2 EACH; TEST PROTOCOL
Emission Limit 2:3.0000 G/HP-H QP3&QP4 EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Limits are as NMHC+NOx based upon NSPS Subpart IIII.

Process/Pollutant Information
PROCESS
NAME:
Fuel handling activities
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel: Coal
Throughput: 19.20 MTons/yr
Process Notes: Coal = 19.2 Mtons/yr PetCoke = 1.1 Mtons/yr New and existing fuel handling for bituminous coal, subbituminous coal and petroleum coke.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input;
99% was chosen.

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY TEST PROTOCOL; BACT
Emission Limit 2:10.0000 % OPACITY TEST PROTOCOL; EXISTING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input
into the table.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Fabric filters; fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.
PM10 LB/H rate varies based upon the 0.004 GR/DSCF

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Fabric filters; fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
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Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. 'Other' = PM2.5 nonattainment, hybrid applicability PM2.5 emission rate varies based upon
0.004 GR/DSCF. Estimated efficiency is 70%-99%; however only one value is allowed to be input into the table.

Process/Pollutant Information
PROCESS
NAME:
Limestone, gypsum, hydrated lime handling activities
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel: Gypsum
Throughput: 360000.00 T/YR
Process Notes: Process is limestone, gypsum, hydrated lime handling acitivities. Limestone throughput capacity = 240,000 T/YR; Gypsum throughput capacity =
360,000 T/YR. New material handling for limestone, gypsum, hydrated lime; limestone & gypsum subject to NSPS Subpart OOO.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY FABRIC FILTERS; TEST PROTOCOL
Emission Limit 2:10.0000 % OPACITY DROP POINTS; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
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Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value allowed to be input. The
PM10 emission rate varies and is based upon 0.004 GR/DSCF.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. 'Other' = PM2.5 nonattainment, hybrid applicability. Estimated control efficiency is
70%-99%; however only one value allowed to be input. PM2.5 rate varies and is based upon 0.004 GR/DSCF.

Previous Page
Facility Information
RBLC ID:TX-0554 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:COLETO CREEK Permit Number:PSDTX1118 AND 83778
Facility Name:COLETO CREEK UNIT 2 Permit Date:05/03/2010 (actual)
Facility Contact:ROSS CRYSUP FRS Number:110000599692
Facility Description:Coal-fired boiler SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:GOLIAD
Facility State:TX
Facility ZIP Code:77960
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Sean O'Brien
512-239-1137
[e-mail]
Permit Notes:83778 HAP18

Process/Pollutant Information
PROCESS
NAME:
Coal-fired Boiler Unit 2
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: PRB coal
Throughput: 6670.00 MMBTU/H
Process Notes: IPA Coleto Creek, L.L.C. (IPA) has proposed to install a new solid fuel-fired utility boiler, Unit 2 (CC2), at their existing Coleto Creek Power Station
8/17/2020 Format RBLC Report
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(CC) which has one existing solid fuel fired boiler. CC2 will be a nominal 650 MW net (750 MW gross) boiler firing sub-bituminous coal and/or
bituminous coal with a maximum heat input rate of 6,670 MMBtu/hr based on a 30 day average of the heat input. The boiler will operate burning sub-
bituminous coal or a blend of that and up to 40% bituminous coal.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0600 LB/MMBTU ROLLING 30 DAY AVG
Emission Limit 2:0.0500 LB/MMBTU ROLLING 12 MONTH AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) low-NOx burners with OFA, Selective Catalytic Reduction
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.0600 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Spray Dry Adsorber/Fabric Filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1200 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.1200 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
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Emission Limit 1:0.0120 LB/GW-H 12-MONTH ROLLING / MIXED FUEL
Emission Limit 2:0.0150 LB/GW-H 12-MONTH ROLLING/ PRB ONLY
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Fabric filter with sorbent injection
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:The mercury standard is based on this formula: % sub-bituminous coal x 0.015 lb Hg/GW-hr + % bituminous
coal x 0.0075 lb Hg/GW-hr

POLLUTANT NAME:Ammonia (NH3)
CAS Number:7664-41-7
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPMVD 3-HOUR ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0120 LB/MMBTU ANNUAL / BASED ON STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total (TPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0250 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) fabric filter, spray dry adsorber for acid gases
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Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0034 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0040 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0008 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/ fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
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CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0005 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:KY-0100 (final) Date Determination
Last Updated:03/15/2011
Corporate/Company Name:EAST KENTUCKY POWER COOPERATIVE, INC Permit Number:V-05-070 R3
Facility Name:J.K. SMITH GENERATING STATION Permit Date:04/09/2010 (actual)
Facility Contact: 859.744.4812 JERRY PURVIS [[e-mail]] FRS Number:110017429521
Facility Description:NEW CFB EGU BECAUSE OF A LEGAL CHALLENGE OUTSIDE OF THE
TITLE V PROCEDURES, PERMITTEE AGREED TO TERMINATE
CONSTRUCTION AUTHORITY FOR PROJECT. R4 TO THIS PERMIT
REMOVES CONSTRUCTION AURTHORITY, AND THE PERMIT MAY NOT
BE AVAILABLE FROM KENTUCKY'S WEBSITE.
SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:4 COUNTRY:USA
Facility County:
Facility State:KY
Facility ZIP Code:
Permit Issued By:KENTUCKY DEP, DIV FOR AIR QUALITY (Agency Name)
MR. RICK SHEWEKAH, MGR(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:TOM ADAMS OR BEN MARKIN
Permit Notes:BECAUSE OF A LEGAL CHALLENGE OUTSIDE OF THE TITLE V PROCEDURES, PERMITTEE AGREED TO TERMINATE
CONSTRUCTION AUTHORITY FOR PROJECT. R4 TO THIS PERMIT REMOVES CONSTRUCTION AURTHORITY, AND THE
PERMIT MAY NOT BE AVAILABLE FROM KENTUCKY'S WEBSITE.

Process/Pollutant Information
PROCESS
NAME:
CIRCULATING FLUIDIZED BED BOILER CFB1 AND CFB2
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 3000.00 MMBTU/H
Process Notes: COAL AND WASTE COAL WITH NATURAL GAS FOR STARTUP THRUPUT IS PER UNIT.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0900 LB/MMBTU 30 DAY AVERAGE
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Emission Limit 2:210.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) BAGHOUSE
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM CEMS FOR COMPLIANCE

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0900 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) BAGHOUSE
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:METHOD 201 AND 202 FOR TOTAL PM10/2.5

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Other
Other Test Method:
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1000 LB/MMBTU 30 DAY
Emission Limit 2:300.0000 LB/H 8 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N) GOOD COMBUSTION CONTROLS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:CO CEMS

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0750 LB/MMBTU 30 DAY AVERAGE
Emission Limit 2:225.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
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Control Method:(A) LIMESTONE INJECTION (CFB)AND A FLASH DRYER ABSORBER WITH FRESH LIME INJECTION
Est. % Efficiency:99.100
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:LB/MMBTU LIMIT EXCLUDES STARTUP/SHUTDOWN. LBS/DAY LIMIT INCLUDES STARTUP AND
SHUTDOWN

POLLUTANT NAME:Nitrogen Dioxide (NO2)
CAS Number:10102-44-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) )
Emission Limit 1:0.0700 LB/MMBTU 30 DAY AVERAGE
Emission Limit 2:210.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SNCR
Est. % Efficiency:53.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:LBS/MMBTU EXCLUDES STARTUP.SHUTDOWN; LBS/HR INCLUDES S&S

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0200 LB/MMBTU 3-HOUR
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N) GOOD COMBUSTION CONTROL
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:6.0000 E-6 LB/MWH BIT COAL ON ANNUAL AVERAG
Emission Limit 2:6.0000 E-6 LB/MWH WASTE COAL ON ANNUAL AVE
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) FABRIC FILTER, SNCR
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:40 CFR 72.2 OR MERCURY CEMS. LIMIT SET TO MEET COMPLIANCE WITH STATE REGULATION.
Limits are 0.000006 LB/MWH.
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POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0050 LB/MMBTU 3-HR
Emission Limit 2:15.0000 LB/H 3 HR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) SAME AS CONTROLS FOR PARTICULATES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:LB/MMBTU EXCLUDES SSM LB/HR INCLUDES SSM

Process/Pollutant Information
PROCESS
NAME:
ASH HANDLING
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes: CFB1 FLY ASH SILO 73 TON/HR CFB1 BED ASH SILO 37 TONS/HR CFB2 FLY ASH SILO 73 TONS/HR CFB2 BED ASH SILO 37
TONS/HR
POLLUTANT NAME:Particulate matter, filterable < 2.5 µ (FPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 G/DSCF 24 BLOCK
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:0.005 GR/DSCF

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
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Compliance Verified:Unknown
Pollutant/Compliance Notes:FOUR STACKS FOR FLY AND BED ASH

Process/Pollutant Information
PROCESS
NAME:
COAL CRUSHING AND SILO STORAGE
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
COAL STOCKPILE
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 3000.00 T/H
Process Notes: STORAGE PILES, RAILCAR UNLOADING, EGRESS TO UNDERGROUND CONVEYOR
POLLUTANT NAME:Particulate Matter (PM)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:10.0000 OPACITY 3 MINUTE
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) WET SUPPRESSION, DUST SUPPRESSENT LOWERING WELL AND COMPACTION.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:LIMIT FOR PM/PM10/PM2.5

Process/Pollutant Information
PROCESS
NAME:
LIME SILO STORAGES
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Process Type: 90.019 (Lime/Limestone Handling/Kilns/Storage/Manufacturing)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) FABRIC FILTERS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:BACT FOR PM10 AND 2.5. THREE DIFFERENT TYPES OF SILOS WITH DIFFERENT PROCESS RATES.
0.30 LBS/HOUR FROM EACH FRESH LIME SILO 0.17 LBS/HOUR EACH RECYCLED LIME SILO . 0.02
LBS/HOUR FROM EACH SCRUBBER SLAKER

Process/Pollutant Information
PROCESS
NAME:
LIMESTONE UNLOADING
Process Type: 99.190 (Other Fugitive Dust Sources)
Primary Fuel:
Throughput: 44.00 T/H
Process Notes: LIMESTONE STORAGE PILE FUGITIVE EMISSIONS FROM UNLOADING/HANDLING
POLLUTANT NAME:Particulate matter, fugitive
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) WET SUPPRESSION OR DUST SUPPRESSANT
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:SUBJECT TO STATE FUGITIVE REGULATION

Process/Pollutant Information
PROCESS
NAME:
COALING TOWERS
Process Type: 99.999 (Other Miscellaneous Sources)
Primary Fuel:
Throughput: 0
Process Notes:
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POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:N/A
Control Method:(P) 0.0005% DRIFT ELIMINATORS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:COOLING TECHNOLOGY INSTITUTE (CTI) ACCEPTANCE TEST CODE (ATC) #140 TO VERIFY DRIFT
PERCENT ACHIEVED BY THE DRIFT ELIMINATOR

POLLUTANT NAME:Particulate matter, filterable < 2.5 µ (FPM2.5)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) BACT FOR PM/PM10/PM2.5 IS 0.0005% DRIFT ELIMINATORS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:COOLING TECHNOLOGY INSTITUTE (CTI) ACCEPTANCE TEST CODE (ATC) #140 TO VERIFY DRIFT
PERCENT ACHIEVED BY THE DRIFT ELIMINATOR

Process/Pollutant Information
PROCESS
NAME:
HAUL ROADS
Process Type: 99.140 (Paved Roads)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, fugitive
CAS Number:PM
Test Method:EPA/OAR Mthd 22
Pollutant Group(s):
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) PAVED ROADWAYS, CLEANING OR PROMPT REMOVAL OF MATERIAL, AND THE
APPLICATION OF WET SUPPRESSION, AS APPLICABLE.
Est. % Efficiency:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 58/58
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:BACT REQUIRES PAVED ROADS ONLY SUBJECT TO STATE FUGITIVE REGULATION

Process/Pollutant Information
PROCESS
NAME:
LIMESTONE STORAGE SILOS
Process Type: 90.019 (Lime/Limestone Handling/Kilns/Storage/Manufacturing)
Primary Fuel:
Throughput: 40.00 T/H
Process Notes: 2 SILOS, 40 TONS PER HOUR EACH.
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF 24 HR
Emission Limit 2:0.5100 LB/H (EACH) 24 HR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:ALSO LISTED AS PM2.5 LIMIT.

Previous Page

APPENDIX C
Cost Analysis – NOx Controls
SCR Replacement Units 1, 2, and 3

Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.
Variable Designation Units Value Calculation
EPC Project?TRUE
Unit Size A (MW)690 <--- User Input
Retrofit Factor B 1.00 <--- User Input (An "average" retrofit has a factor = 1.0)
Heat Rate C (Btu/kWh)9800 <--- User Input
NOx Rate D (lb/MMBtu)0.11 <--- User Input
SO2 Rate E (lb/MMBtu)0.2 <--- User Input
Type of Coal F 3 <--- User Input
Coal Factor G 1 Bit = 1.0, PRB = 1.05, Lig = 1.07
Heat Rate Factor H 0.98 C/10000
Heat Input I (Btu/hr) 6.76E+09 A*C*1000
Capacity Factor J (%)100 <--- User Input
NOx Removal Efficiency K (%)50 <--- User Input
NOx Removal Factor L 0.6250 K/80
NOx Removed M (lb/hr) 372 D*I/10^6*K/100
Urea Rate (100%) N (lb/hr) 260 M*0.525*60/46*1.01/0.99
Steam Required O (lb/hr) 294 N*1.1315
P (%) 0.56 0.56*(G*H)^0.43
Makeup Water Rate Q (1000 gph) 0
Urea Cost (50% wt solution) R ($/ton)350 <--- User Input
Catalyst Cost S ($/m3)8000 <--- User Input
Aux Power Cost T ($/kWh)0.06 <--- User Input (includes removal and disposal of existing catalyst and installation of new catalyst)
Steam Cost U ($/klb)4 <--- User Input
Operating Labor Rate V ($/hr)60 <--- User Input (Labor cost including all benefits)
Costs are all based on 2016 dollars
Capital Cost Calcuation Example Comments
Includes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) = 310000*(B)*(L)^0.2*(A*G*H)^0.92 113,294,000$ SCR (ductwork modifications and strengthening, reactor, bypass) island cost
BMF ($) = 564000*(M)^0.25 2,477,000$ Base reagent preparation cost
BMA ($) = IF E>= 3 and F = Bituminous, THEN 69000*(B)*(A*G*H)^0.78, ELSE 0 -$ Air heater modifications /SO3 control (Bituminous only and >= 3 lb/MMBtu)
BMB ($) = 529000*(B)*(A*G*H)^0.42 8,167,000$ ID or booster fans and auxiliary power modification costs
BM ($) = BMR + BMF + BMA + BMB 123,938,000$ Total base module cost including retrofit factor
BM ($/kW) = 180 Base cost per kW
Total Project Cost
A1 = 10% of BM 12,394,000$ Engineering and Construction Management costs
A2= 10% of BM 12,394,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…
A3 = 10% of BM 12,394,000$ Contractor profit and fees
CECC ($) = BM + A1 + A2 + A3 161,120,000$ Capital, engineering and construction cost subtotal
CECC ($/kW) = 234 Capital, engineering and construction cost subtotal per kW
B1 = 5% of CECC 8,056,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)
TPC' ($) - Includes Owner's Costs = CECC + B1 169,176,000$ Total project cost without AFUDC
TPC' ($/kW) - Includes Owner's Costs 245 Total project cost per kW without AFUDC
B2 = 6% of (CECC + B1) 10,151,000$ AFUDC (Based on a 2 year engineering and construction cycle)
C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 25,376,000$ EPC fees of 15%
TPC ($) = CECC + B1 + B2 + C1 204,703,000$ Total project cost
TPC ($/kW) = 297 Total project cost per kW
Aux Power
Include in VOM?
Fixed O&M Cost
FOMO ($/kW yr) = 1/2 operator time assumed)*2080*V/(A*1000) 0.09$ Fixed O&M additional operating labor costs
FOMM ($/kW yr) =(IF A < 300 then 0.005*BM ELSE 0.003*BM)/(B*A*1000) 0.54$ Fixed O&M additional maintenance material and labor costs
FOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.01$ Fixed O&M additional administrative labor costs
FOM ($/kW yr) = FOMO +FOMM+FOMA 0.64$ Total Fixed O&M costs
Variable O&M Cost
VOMR ($/MWh) = N*R/(A*1000) 0.13$ Variable O&M costs for Urea
VOMW ($/MWh) = (0.4*(G^2.9)*(L^0.71)*S)/(8760) 0.26$ Variable O&M costs for catalyst: replacement & disposal
VOMP ($/MWh) = P*T*10 0.33$ Variable O&M costs for additional auxiliary power required including additional fan power
VOMM ($/MWh) = O*U/A/1000 0.00$ Variable O&M costs for steam
VOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 0.73$ Total Variable O&M costs
Annual Capacity Factor = 100%
Annual MWhs = 6,044,400
Annual Heat Input MMBtu = 59,235,120
Annual Tons NOx Created = 3,258 current NOx Emission
Annual Tons NOx Removed = 1,629 at removal efficiency = 50%
Annual Tons NOx Emission = 1,629
Annual Avg NOx Emission Rate, lb/MMBtu = 0.055 Value is BELOW a 0.07 floor rate
Annual Capital Recovery Factor = 0.094 SCR
Annual Capital Cost (Including AFUDC), $ = 19,324,000
Annual FOM Cost, $ = 441,000
Annual VOM Cost, $ = 4,393,000 4,834,000
Total Annual SCR Cost, $ = 24,158,000
Capital Cost, $/MWh = 3.20
FOM Cost, $/MWh = 0.07
VOM Cost, $/MWh = 0.73
Total SCR Cost, $/MWh = 4.00
Capital Cost, $/ton = 11,863
FOM Cost, $/ton = 271
VOM Cost, $/ton = 2,697
Total SCR Cost, $/ton = 14,830
Lookup Table 0.07
Coal Coal FactorNOx Floor Limit
1 PRB 1.05 0.05
2 Lignite 1.07 0.05
3 Bituminous 1 0.07
Aux Power
TRUE
Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.
Variable Designation Units Value Calculation
EPC Project?TRUE
Unit Size A (MW)690 <--- User Input
Retrofit Factor B 1.00 <--- User Input (An "average" retrofit has a factor = 1.0)
Heat Rate C (Btu/kWh)9800 <--- User Input
NOx Rate D (lb/MMBtu)0.11 <--- User Input
SO2 Rate E (lb/MMBtu)0.2 <--- User Input
Type of Coal F 3 <--- User Input
Coal Factor G 1 Bit = 1.0, PRB = 1.05, Lig = 1.07
Heat Rate Factor H 0.98 C/10000
Heat Input I (Btu/hr) 6.76E+09 A*C*1000
Capacity Factor J (%)100 <--- User Input
NOx Removal Efficiency K (%)50 <--- User Input
NOx Removal Factor L 0.6250 K/80
NOx Removed M (lb/hr) 372 D*I/10^6*K/100
Urea Rate (100%) N (lb/hr) 260 M*0.525*60/46*1.01/0.99
Steam Required O (lb/hr) 294 N*1.1315
P (%) 0.56 0.56*(G*H)^0.43
Makeup Water Rate Q (1000 gph) 0
Urea Cost (50% wt solution) R ($/ton)350 <--- User Input
Catalyst Cost S ($/m3)8000 <--- User Input
Aux Power Cost T ($/kWh)0.06 <--- User Input (includes removal and disposal of existing catalyst and installation of new catalyst)
Steam Cost U ($/klb)4 <--- User Input
Operating Labor Rate V ($/hr)60 <--- User Input (Labor cost including all benefits)
Costs are all based on 2016 dollars
Capital Cost Calcuation Example Comments
Includes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) = 310000*(B)*(L)^0.2*(A*G*H)^0.92 113,294,000$ SCR (ductwork modifications and strengthening, reactor, bypass) island cost
BMF ($) = 564000*(M)^0.25 2,477,000$ Base reagent preparation cost
BMA ($) = IF E>= 3 and F = Bituminous, THEN 69000*(B)*(A*G*H)^0.78, ELSE 0 -$ Air heater modifications /SO3 control (Bituminous only and >= 3 lb/MMBtu)
BMB ($) = 529000*(B)*(A*G*H)^0.42 8,167,000$ ID or booster fans and auxiliary power modification costs
BM ($) = BMR + BMF + BMA + BMB 123,938,000$ Total base module cost including retrofit factor
BM ($/kW) = 180 Base cost per kW
Total Project Cost
A1 = 10% of BM 12,394,000$ Engineering and Construction Management costs
A2= 10% of BM 12,394,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…
A3 = 10% of BM 12,394,000$ Contractor profit and fees
CECC ($) = BM + A1 + A2 + A3 161,120,000$ Capital, engineering and construction cost subtotal
CECC ($/kW) = 234 Capital, engineering and construction cost subtotal per kW
B1 = 5% of CECC 8,056,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)
TPC' ($) - Includes Owner's Costs = CECC + B1 169,176,000$ Total project cost without AFUDC
TPC' ($/kW) - Includes Owner's Costs 245 Total project cost per kW without AFUDC
B2 = 6% of (CECC + B1) 10,151,000$ AFUDC (Based on a 2 year engineering and construction cycle)
C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 25,376,000$ EPC fees of 15%
TPC ($) = CECC + B1 + B2 + C1 204,703,000$ Total project cost
TPC ($/kW) = 297 Total project cost per kW
Aux Power
Include in VOM?
Fixed O&M Cost
FOMO ($/kW yr) = 1/2 operator time assumed)*2080*V/(A*1000) 0.09$ Fixed O&M additional operating labor costs
FOMM ($/kW yr) =(IF A < 300 then 0.005*BM ELSE 0.003*BM)/(B*A*1000) 0.54$ Fixed O&M additional maintenance material and labor costs
FOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.01$ Fixed O&M additional administrative labor costs
FOM ($/kW yr) = FOMO +FOMM+FOMA 0.64$ Total Fixed O&M costs
Variable O&M Cost
VOMR ($/MWh) = N*R/(A*1000) 0.13$ Variable O&M costs for Urea
VOMW ($/MWh) = (0.4*(G^2.9)*(L^0.71)*S)/(8760) 0.26$ Variable O&M costs for catalyst: replacement & disposal
VOMP ($/MWh) = P*T*10 0.33$ Variable O&M costs for additional auxiliary power required including additional fan power
VOMM ($/MWh) = O*U/A/1000 0.00$ Variable O&M costs for steam
VOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 0.73$ Total Variable O&M costs
Annual Capacity Factor = 100%
Annual MWhs = 6,044,400
Annual Heat Input MMBtu = 59,235,120
Annual Tons NOx Created = 3,258 current NOx Emission
Annual Tons NOx Removed = 1,629 at removal efficiency = 50%
Annual Tons NOx Emission = 1,629
Annual Avg NOx Emission Rate, lb/MMBtu = 0.055 Value is BELOW a 0.07 floor rate
Annual Capital Recovery Factor = 0.094 SCR
Annual Capital Cost (Including AFUDC), $ = 19,324,000
Annual FOM Cost, $ = 441,000
Annual VOM Cost, $ = 4,393,000 4,834,000
Total Annual SCR Cost, $ = 24,158,000
Capital Cost, $/MWh = 3.20
FOM Cost, $/MWh = 0.07
VOM Cost, $/MWh = 0.73
Total SCR Cost, $/MWh = 4.00
Capital Cost, $/ton = 11,863
FOM Cost, $/ton = 271
VOM Cost, $/ton = 2,697
Total SCR Cost, $/ton = 14,830
Lookup Table 0.07
Coal Coal FactorNOx Floor Limit
1 PRB 1.05 0.05
2 Lignite 1.07 0.05
3 Bituminous 1 0.07
Aux Power
TRUE
Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.
Variable Designation Units Value Calculation
EPC Project?TRUE
Unit Size A (MW)710 <--- User Input
Retrofit Factor B 1.00 <--- User Input (An "average" retrofit has a factor = 1.0)
Heat Rate C (Btu/kWh)9800 <--- User Input
NOx Rate D (lb/MMBtu)0.076 <--- User Input
SO2 Rate E (lb/MMBtu)0.4 <--- User Input
Type of Coal F 3 <--- User Input
Coal Factor G 1 Bit = 1.0, PRB = 1.05, Lig = 1.07
Heat Rate Factor H 0.98 C/10000
Heat Input I (Btu/hr) 6.96E+09 A*C*1000
Capacity Factor J (%)100 <--- User Input
NOx Removal Efficiency K (%)50 <--- User Input
NOx Removal Factor L 0.6250 K/80
NOx Removed M (lb/hr) 264 D*I/10^6*K/100
Urea Rate (100%) N (lb/hr) 185 M*0.525*60/46*1.01/0.99
Steam Required O (lb/hr) 209 N*1.1315
P (%) 0.56 0.56*(G*H)^0.43
Makeup Water Rate Q (1000 gph) 0
Urea Cost (50% wt solution) R ($/ton)350 <--- User Input
Catalyst Cost S ($/m3)8000 <--- User Input
Aux Power Cost T ($/kWh)0.06 <--- User Input (includes removal and disposal of existing catalyst and installation of new catalyst)
Steam Cost U ($/klb)4 <--- User Input
Operating Labor Rate V ($/hr)60 <--- User Input (Labor cost including all benefits)
Costs are all based on 2016 dollars
Capital Cost Calcuation Example Comments
Includes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) = 310000*(B)*(L)^0.2*(A*G*H)^0.92 116,312,000$ SCR (ductwork modifications and strengthening, reactor, bypass) island cost
BMF ($) = 564000*(M)^0.25 2,274,000$ Base reagent preparation cost
BMA ($) = IF E>= 3 and F = Bituminous, THEN 69000*(B)*(A*G*H)^0.78, ELSE 0 -$ Air heater modifications /SO3 control (Bituminous only and >= 3 lb/MMBtu)
BMB ($) = 529000*(B)*(A*G*H)^0.42 8,266,000$ ID or booster fans and auxiliary power modification costs
BM ($) = BMR + BMF + BMA + BMB 126,852,000$ Total base module cost including retrofit factor
BM ($/kW) = 179 Base cost per kW
Total Project Cost
A1 = 10% of BM 12,685,000$ Engineering and Construction Management costs
A2= 10% of BM 12,685,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…
A3 = 10% of BM 12,685,000$ Contractor profit and fees
CECC ($) = BM + A1 + A2 + A3 164,907,000$ Capital, engineering and construction cost subtotal
CECC ($/kW) = 232 Capital, engineering and construction cost subtotal per kW
B1 = 5% of CECC 8,245,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)
TPC' ($) - Includes Owner's Costs = CECC + B1 173,152,000$ Total project cost without AFUDC
TPC' ($/kW) - Includes Owner's Costs 244 Total project cost per kW without AFUDC
B2 = 6% of (CECC + B1) 10,389,000$ AFUDC (Based on a 2 year engineering and construction cycle)
C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 25,973,000$ EPC fees of 15%
TPC ($) = CECC + B1 + B2 + C1 209,514,000$ Total project cost
TPC ($/kW) = 295 Total project cost per kW
Aux Power
Include in VOM?
Fixed O&M Cost
FOMO ($/kW yr) = 1/2 operator time assumed)*2080*V/(A*1000) 0.09$ Fixed O&M additional operating labor costs
FOMM ($/kW yr) =(IF A < 300 then 0.005*BM ELSE 0.003*BM)/(B*A*1000) 0.54$ Fixed O&M additional maintenance material and labor costs
FOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.01$ Fixed O&M additional administrative labor costs
FOM ($/kW yr) = FOMO +FOMM+FOMA 0.64$ Total Fixed O&M costs
Variable O&M Cost
VOMR ($/MWh) = N*R/(A*1000) 0.09$ Variable O&M costs for Urea
VOMW ($/MWh) = (0.4*(G^2.9)*(L^0.71)*S)/(8760) 0.26$ Variable O&M costs for catalyst: replacement & disposal
VOMP ($/MWh) = P*T*10 0.33$ Variable O&M costs for additional auxiliary power required including additional fan power
VOMM ($/MWh) = O*U/A/1000 0.00$ Variable O&M costs for steam
VOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 0.69$ Total Variable O&M costs
Annual Capacity Factor = 100%
Annual MWhs = 6,219,600
Annual Heat Input MMBtu = 60,952,080
Annual Tons NOx Created = 2,316 current NOx Emission
Annual Tons NOx Removed = 1,158 at removal efficiency = 50%
Annual Tons NOx Emission = 1,158
Annual Avg NOx Emission Rate, lb/MMBtu = 0.038 Value is BELOW a 0.07 floor rate
Annual Capital Recovery Factor = 0.094 SCR
Annual Capital Cost (Including AFUDC), $ = 19,778,000
Annual FOM Cost, $ = 452,000
Annual VOM Cost, $ = 4,265,000
Total Annual SCR Cost, $ = 24,495,000
Capital Cost, $/MWh = 3.18
FOM Cost, $/MWh = 0.07
VOM Cost, $/MWh = 0.69
Total SCR Cost, $/MWh = 3.94
Capital Cost, $/ton = 17,078
FOM Cost, $/ton = 390
VOM Cost, $/ton = 3,683
Total SCR Cost, $/ton = 21,151
Lookup Table 0.07
Coal Coal FactorNOx Floor Limit
1 PRB 1.05 0.05
2 Lignite 1.07 0.05
3 Bituminous 1 0.07
Aux Power
TRUE

APPENDIX D
RACT / BACT / LAER Clearinghouse
SO2 Controls
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 1/58
Previous Page
COMPREHENSIVE REPORT
Report Date:08/17/2020
Facility Information
RBLC ID:AZ-0055 (final) Date Determination
Last Updated:01/08/2014
Corporate/Company Name:SALT RIVER PROJECT AGRICULTURAL AND POWER DISTRICT Permit Number:AZ 08-01
Facility Name:NAVAJO GENERATING STATION Permit Date:02/06/2012 (actual)
Facility Contact:KARA MONTALVO FRS Number:110028287725
Facility Description:2,250 MW COAL FIRED POWER PLANT SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221112
Permit URL:http://www.epa.gov/region9/air/permit/r9-permits-issued.html
EPA Region:9 COUNTRY:USA
Facility County:COCONINO
Facility State:AZ
Facility ZIP Code:86040
Permit Issued By:EPA REGION IX (Agency Name)
MR. GERARDO RIOS(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:GERARDO RIOS, EPA REGION IX, 415-972-3974, [e-mail]
Permit Notes:PERMIT ISSUED ON 11/20/2008 AND ADMINISTRATIVELY AMENDED ON 2/6/2012. AFFECTED CLASS I AREAS CAN BE
FOUND IN BART REGULATORY DOCKET AT http://www.regulations.gov/fdmspublic/component/main?
main=DocketDetail&d=EPA-R09-OAR-2008-0454
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 UT Arches NP 100km - 50km
CLASS1 UT Bryce Canyon NP < 100 km
CLASS1 UT Canyonlands NP 100km - 50km
CLASS1 UT Capitol Reef NP < 100 km
CLASS1 AZ Grand Canyon NP < 100 km
CLASS1 AZ Mazatzal > 250 km
CLASS1 CO Mesa Verde NP 100km - 50km
CLASS1 AZ Petrified Forest NP 100km - 50km
CLASS1 AZ Pine Mountain > 250 km
CLASS1 AZ Sycamore Canyon 100km - 50km
CLASS1 UT Zion NP 100km - 50km

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 2/58

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 3/58
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

Process/Pollutant Information
PROCESS
NAME:
PULVERIZED COAL FIRED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 7725.00 MMBTU/H
Process Notes: BOILER ALLOWED TO USE NO. 2 FUEL OIL FOR IGNITION FUEL
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.2400 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LOW NOX BURNER (LNB), SEPARATED OVERFIRE AIR (SOFA) SYSTEM,
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 4/58
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BART
Other Applicable Requirements:
Control Method:(A) FLUE GAS DESULFURIZATION (FGD), SCRUBBER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NO EMISSION LIMITS

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.2300 LB/MMBTU 30-DAY ROLLING AVG
Emission Limit 2:0.1500 LB/MMBTU 12-MONTH ROLLING AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) GOOD COMBUSTION PRACTICES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:TX-0601 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:TEXAS MUNICIPAL POWER AGENCY Permit Number:5699 AND PSDTX18M2
Facility Name:GIBBONS CREEK STEAM ELECTRIC STATION Permit Date:10/28/2011 (actual)
Facility Contact:KEN BABB [phone] FRS Number:110008138078
Facility Description:one 5,060 MMBtu/h boiler burning natural gas, lignite, coal, and a blend of lignite
or coal with petroleum coke
SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221122
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:GRIMES
Facility State:TX
Facility ZIP Code:77830
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 5/58
Other Agency Contact Info:Kate Stinchcomb, [phone], [e-mail]
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 TX Big Bend NP > 250 km

Process/Pollutant Information
PROCESS
NAME:
Boiler
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Coal
Throughput: 5060.00 MMBtu/h
Process Notes:
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1200 LB/MMBTU 30-DAY ROLLING AVERAGE
Emission Limit 2:2428.0000 LB/H
Standard Emission:2365.0000 T/YR
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:1.2000 LB/MMBTU
Emission Limit 2:1771.0000 LB/H
Standard Emission:6052.0000 T/YR
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Wet Flue Gas Desulfurization
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:CA-1206 (final) Date Determination
Last Updated:01/14/2014
Corporate/Company Name:APMC STOCKTON COGEN Permit Number:SJ 85-04
Facility Name:STOCKTON COGEN COMPANY Permit Date:09/16/2011 (actual)
Facility Contact:GLENN SIZEMORE FRS Number:110000484930
8/17/2020 Format RBLC Report
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Facility Description:49.9 MW COGENERATION POWER PLANT OWNED BY AIR PRODUCTS
MANUFACTURING CORPORATION (APMC) STOCKTON COGEN AND
LOCATED IN STOCKTON, CALIFORNIA
SIC Code:4911
Permit Type:C: Modify process at existing facility NAICS Code:221112
Permit URL:http://www.epa.gov/region09/air/permit/r9-permits-issued.html
EPA Region:9 COUNTRY:USA
Facility County:SAN JOAQUIN COUNTY
Facility State:CA
Facility ZIP Code:95206
Permit Issued By:EPA REGION IX (Agency Name)
MR. GERARDO RIOS(Agency Contact) [phone] [e-mail]
Permit Notes:PSD permit amended to allow increased operation of facility's natural gas-fired auxiliary boiler and reduced operation of its coal-fired
circulating fluidized bed boiler. Facilitywide emission increases less than the PSD significant thresholds.
Facility-wide Emissions:Pollutant Name:Facility-wide Emissions Increase:
Carbon Monoxide 28.8000 (Tons/Year)
Nitrogen Oxides (NOx)6.6200 (Tons/Year)
Particulate Matter (PM)9.9300 (Tons/Year)
Sulfur Oxides (SOx)2.2600 (Tons/Year)
Volatile Organic Compounds (VOC)0.9900 (Tons/Year)

Process/Pollutant Information
PROCESS
NAME:
CIRCULATING FLUIDIZED BED BOILER
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 730.00 MMBTU/H
Process Notes:
POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:59.0000 LB/H 8-HR AVG
Emission Limit 2:100.0000 LB/H 3-HR AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) LIMESTONE INJECTION W/ A MINIMUM REMOVAL EFFICIENCY OF 70% (3-HR AVG) TO BE
MAINTAINED AT ALL TIMES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:50.0000 PPM @3% O2, 3-HR AVG
Emission Limit 2:42.0000 LB/H 3-HR AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(B) LOW BED TEMPERATUR STAGED COMBUSTION; SELECTIVE NON-CATALYTIC REDUCTION
(SNCR)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 7/58
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:OTHER LIMITS: AUX BOILER AND CIRCULATING FLUIDIZED BED BOILER MAY ONLY BE
OPERATED SIMULTANEOUSLY FOR UP TO 250 HRS PER YEAR, DURING CIRCULATING FLUIDIZED
BED BOILER STARTUP AND SHUTDOWN PERIODS, AND PERIODS OF LESS THAN 10 HRS
DURATION TO CONDUCT EMISSIONS TESTING

Process/Pollutant Information
PROCESS
NAME:
AUXILIARY BOILER
Process Type: 12.310 (Natural Gas (includes propane and liquefied petroleum gas))
Primary Fuel: NATURAL GAS
Throughput: 178.00 MMBTU/H
Process Notes:
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:7.0000 PPMVD @3% O2
Emission Limit 2:0.0085 LB/MMBTU
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:OTHER LIMITS: AUX BOILER AND CIRCULATING FLUIDIZED BED BOILER MAY ONLY BE
OPERATED SIMULTANEOUSLY FOR UP TO 250 HRS PER YEAR, DURING CIRCULATING FLUIDIZED
BED BOILER STARTUP AND SHUTDOWN PERIODS, AND PERIODS OF LESS THAN 10 HRS
DURATION TO CONDUCT EMISSIONS TESTING

Previous Page
Facility Information
RBLC ID:MI-0400 (final) Date Determination
Last Updated:04/14/2016
Corporate/Company Name:WOLVERINE POWER SUPPLY COOPERATIVE, INC. Permit Number:317-07
Facility Name:WOLVERINE POWER Permit Date:06/29/2011 (actual)
Facility Contact:BRIAN WARNER 2317755700 X 3336 [e-mail] FRS Number:26-14105823
Facility Description:Coal-fired power plant. SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:5 COUNTRY:USA
Facility County:PRESQUE ISLE
Facility State:MI
Facility ZIP Code:49779
Permit Issued By:MICHIGAN DEPT OF ENVIRONMENTAL QUALITY (Agency Name)
MS. CINDY SMITH(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Please contact permit engineer Melissa Byrnes at 517-373-7065 with questions regarding this permit. Thank you.
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 MI Seney 100km - 50km
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 8/58

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2)
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H EACH
Process Notes: 3,030 MMBTU/H each boiler
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , MACT , SIP
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Limit of 0.010 LB/MMBTU is for EACH boiler. Test Protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0260 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:78.8000 LB/H EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulset jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The limits specified above apply to EACH boiler.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0240 LB/MMBTU EACH; TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 9/58
Pollutant/Compliance Notes:NOTE: The PM2.5 limit above applies to EACH boiler.

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:1.0000 LB/MW-H GROSS OUTPUT; EACH; 30 D ROLL. AVG; NSPS
Emission Limit 2:281.1000 LB/H EACH; 24H ROLL.AVG.; BACT
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SNCR (Selective Non-Catalytic Reduction)
Est. % Efficiency:63.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The limits above apply to EACH boiler.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:
Emission Limit 2:744.0000 LB/H EACH; 24H ROLL. AVG.; BACT&SIP
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission Limit of 744 LB/H is for each boiler and is based on a 24-hr rolling average determined each
hour the boiler operates. This limit is set per BACT & SIP.

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:303.0000 LB/H EACH; 24-H ROLL.AVG.; BACT & SIP
Emission Limit 2:1.4000 LB/MW-H GROSS OUTPUT; EACH; 30D ROLL.AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limits above apply to EACH boiler. Emission Limit 2 above of 1.4 LB/MW-H gross ouput is
for each boiler and is based on a 30-day rolling average and is set per the NSPS.

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
8/17/2020 Format RBLC Report
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Emission Limit 1:17.8000 LB/H EACH; TEST PROTOCOL; BACT,MACT,SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The emission limit above is for EACH boiler.

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0030 LB/MMBTU EACH; TEST PROTOCOL; BACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:14.0000 E-5 LB/MMBTU EACH; TEST PROTOCOL; MACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber and pulse jet fabric filter
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limit is 0.00014 LB/MMBTU for each boiler. Test Protocol will specify averaging time.

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:0.0077 LB/GW-H EACH; 12-MO ROLLING; MACT & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber, sorbent injection (e.ge. activated carbon), and a fabric filter.
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 11/58
Est. % Efficiency:93.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Dioxide Equivalent (CO2e)
CAS Number:CO2e
Test Method:Unspecified
Pollutant Group(s):( Greenhouse Gasses (GHG) )
Emission Limit 1:2.1000 LB/KW-H EACH; 12-MO ROLL.AVG.; BACT
Emission Limit 2:6024107.0000 T/YR EACH; 12-MO ROLL.AVG.; BACT
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Use of biomass and energy efficiencies.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0011 LB/MMBTU EACH; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT , SIP
Control Method:(A) Polishing scrubber and pulse jet fabric filter
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Auxiliary Boiler
Process Type: 13.220 (Distillate Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
Throughput: 72.40 MMBTU/H
Process Notes: Maximum operation was based on 4,000 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1100 LB/H TEST PROTOCOL; BACT/SIP/MACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 12/58
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.1700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.1700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:1.6700 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Low NOx burner
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 13/58
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:6.1100 LB/H TEST PROTOCOL; BACT/SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(P) Good combustion control
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.3000 LB/H TEST PROTOCOL; BACT/SIP/MACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0500 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:MACT
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Emergency generator
Process Type: 17.110 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
Throughput: 4000.00 HP
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 14/58
Process Notes: Maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1500 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:1.7600 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:1.7600 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Fire Pump
Process Type: 17.210 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 15/58
Throughput: 420.00 HP
Process Notes: Maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1500 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1400 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.1400 LB/H TEST PROTOCOL; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:3.0000 G/HP-H TEST PROTOCOL; BACT/SIP/NSPS
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 16/58
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: Emission limit is expresssed as NMHC+NOx = 3.0 G/HP-H.

Process/Pollutant Information
PROCESS
NAME:
Turbine generator (EUBLACKSTART)
Process Type: 15.190 (Liquid Fuel & Liquid Fuel Mixtures)
Primary Fuel: Diesel
Throughput: 540.00 MMBTU/H
Process Notes: This is a turbine generator identified in the permit as EUBLACKSTART. It has a throughput capacity of 540MMBTU/HR which equates to 102 MW.
The maximum operation was based on 500 hours per year.
POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0300 LB/MMBTU TEST PROTOCOL
Emission Limit 2:16.2000 LB/H TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:16.2000 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 17/58
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.1600 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0450 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0110 LB/MMBTU TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Cooling Tower (EUCOOLINGTWR)
Process Type: 99.009 (Industrial Process Cooling Towers)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 18/58
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0005 %
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Drift eliminators
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE)
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Limestone handling activities
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0002 GR/DSCF LIMESTONE PROCESS. EQUIP.;TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM limit for limestone handling (EULIMESTONE) is 0.00016 gr/dscf and is established per BACT. This
limit applies to the limestone processing equipment within this emission unit.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:This PM10 limit is for the limestone processing equipment within EULIMESTONE portion of the permit.

8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 19/58
POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0100 LB/H TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:This PM2.5 limit is for the limestone processing equipment portion of EULIMESTONE in the permit.

Process/Pollutant Information
PROCESS
NAME:
Limestone preparation (EULIMESTONEPREP)
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: This is the limestone preparation activities within this permit and is identified as EULIMESTONEPREP in the permit.
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See Pollutant Notes field below.
Pollutant Group(s):
Emission Limit 1:7.0000 % OPACITY TRANSFER PTS.
Emission Limit 2: % OPACITY BLDG. HOUSING CRUSHER
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Test method used varies per emission point. See below: The 7% opacity limit applies to the transfer points
portion of EULIMESTONEPREP. Method 9 is to be used if emissions are detected. The 0% opacity limit applies
to the building housing crusher. If emissions are detected, then Method 22 is to be used. A 7% opacity limit
ALSO applies to the dust collectors. If emissions are detected, then Method 9 is to be used.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:18.0000 E-7 GR/DSCF LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 20/58
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM limit of 0.0000018 grains/dscf applies to the limestone prep train portion of EULIMESTONEPREP.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/H LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP , NSPS
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM10 limit of 0.0006 LB/H applies to the limestone prep. train portion of EULIMESTONEPREP.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/H LIMESTONE PREP TRAIN; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:The PM2.5 limit of 0.0006 LB/H applies to the limestone prep train portion of EULIMESTONEPREP.

Process/Pollutant Information
PROCESS
NAME:
CFB Bed Ash Removal (EUBEDASH)
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:If emissions are detected, then Method 9 to be used.
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY TRANSFER POINTS
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 21/58
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:5% Opacity at transfer points. Method 9 to be used if emissions are detected.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:11.0000 E-6 GR/DSCF BEDASH COLLECTION & REMOVAL EQUIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.000011 GR/DSCF for bedash collection & removal equipment. Averaging time is determined from test
protocol.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H BEDASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.0012 LB/H for bedash collection & removal equipment. The averaging time is determined from the
test protocol.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H BEDASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.0012 LB/H for bedash collection & removal equipment. Averaging time is determined from test
protocol.
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 22/58

Process/Pollutant Information
PROCESS
NAME:
Ash Removal Economizer & Fabric filter hoppers
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes: Ash removal economizer & fabric filter hoppers (EUFLYASH)
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % TRANSFER PTS.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:VE = 5% opacity at transfer points. Method 9 is to be used if emissions are detected.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:32.0000 E-6 GR/DSCF FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.000032 GR/DSCF for flyash collection & removal equipment. The averaging time is determined from
the test protocol.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 23/58
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.0012 LB/H for flyash collection & removal equipment. Test protocol will determine the averaging
time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0012 LB/H FLYASH COLLECTION & REMOVAL EQUIP.
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.0012 LB/H for flyash collection & removal equipment. Test protocol will determine averaging time.

Process/Pollutant Information
PROCESS
NAME:
Solid fuel handling system (EUSOLIDFUELHANDLING)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See Pollutant Notes for details.
Pollutant Group(s):
Emission Limit 1:10.0000 % OPACITY DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % OPACITY BLDG. HOUSING CRUSHER
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity at drop & transfer points. If emissions are detected, Method 9 is to be used. The applicable reqts. for
this limit is PSD-BACT, SIP, & NSPS. 5% opacity for the building housing crusher. If emissions are detected,
Method 9 is to be used. The applicable reqts. for this limit is PSD-BACT, & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:18.4000 E-4 GR/DSCF TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
8/17/2020 Format RBLC Report
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Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00184 GR/DSCF for the transfer tower. Test protocol will determine averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.2360 LB/H TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.236 LB/H for the transfer tower. Test protocol will determine the averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.2360 LB/H TRANSFER TOWER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Magnetic separators with either dust suppression or dust collectors.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.236 LB/H for the transfer tower. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
Coal crushers (EUFUELCRUSHER)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:See pollutant notes below.
Pollutant Group(s):
Emission Limit 1:10.0000 % OPACITY DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % OPACITY DUST COLLECTOR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Fabric filter dust collector.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity for the drop and transfer points. If emissions are detected, Method 9 is to be used. The applicable
reqts. for this limit are PSD-BACT, SIP & NSPS. 5% opacity for the dust collector. If emissions are detected,
Method 9 is to be used. The applicable reqts. for this limit are PSD-BACT & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:2.0000 E-5 GR/DSCF FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Fabric filter dust collector.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00002 GR/DSCF for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.00276 LB/H for the fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
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Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
Coal fuel storage silos (EUFUELSILO)
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:10.0000 % DROP & TRANSFER PTS.
Emission Limit 2:5.0000 % DUST COLLECTOR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , SIP
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:10% opacity at drop & transfer points. If emissions are detected, Method 9 is to be used. The applicable reqts. for
this limit is PSD-BACT, NSPS, & SIP. 5% opacity for the dust collector. If emissions are detected, Method 9 is to
be used. The applicable reqts. for this limit is PSD-BACT & SIP.

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:25.0000 E-5 GR/DSCF FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM = 0.00025 GR/DSCF for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
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Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM10 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:27.6000 E-4 LB/H FABRIC FILTER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter dust collector
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM2.5 = 0.00276 LB/H for fabric filter. Test protocol will specify averaging time.

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2) - EXCLUDING Startup & Shutdown
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H each
Process Notes: Each boiler is rated at 3,030 MMBTU/H. NOTE -The emission limits included under this process name specifically EXCLUDE startup & shutdown.
The other CFB1 & CFB2 boiler section are the emission limits for the boiler that INCLUDE the startup & shutdown emissions. This has been
changed per discussion with RBLC Administrator.
POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU EACH; 30D ROLL.AVG.; BACT&SIP; EXC. SS
Emission Limit 2:0.0500 LB/MMBTU EACH;12-MO ROLL.AVG.; BACT&SIP; EXC.SS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dry flue gas desulfurization (spray dry absorber or polishing scrubber).
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: These SO2 limits apply to EACH boiler and EXCLUDE startup & shutdown emissions.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:72.7000 LB/H EACH; TEST PROTOCOL; BACT&SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulse jet Fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: The 72.7 LB/H limit is for EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0700 LB/MMBTU EACH, 30 D ROLLING AVG; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) SNCR (Selective Non-Catalytic Reduction)
Est. % Efficiency:63.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Note: This limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1500 LB/MMBTU EACH; 30 D ROLLING AVG; BACT
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NOTE: This limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0030 LB/MMBTU EACH; LIMIT PER BACT, MACT, & SIP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:MACT , SIP
Control Method:(P) Good combustion
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:NOTE: This VOC limit applies to EACH boiler and EXCLUDES startup & shutdown emissions.
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Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - Transfer Points
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "" Process untill broken out by RBLC Admin. Original Notes: Limestone handling (EULIMESTONE)
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:EPA/OAR Mthd 9
Pollutant Group(s):
Emission Limit 1:7.0000 % OPACITY TRANSFER PTS.,
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector. Test Method varies depending on process within this emission unit; i.e. transfer pts., truck
traffic, etc.)
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ------
Original Note ------ "7% opacity is limit for the transfer points within EULIMESTONE. If emissions are
detected, Method 9 is to be used."

Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - BLDG. HOUSING CRUSHER
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "" Process untill broken out by RBLC Admin. Limestone handling activities - This portion is for the building housing crusher.
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:EPA/OAR Mthd 22
Pollutant Group(s):
Emission Limit 1: % OPACITY BLDG. HOUSING CRUSHER
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Dust collector. This portion is for the building housing crusher.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ---------
Original Notes --------- 0% opacity is the limit for the building housing crusher portion of the emission unit. If
emissions are detected, Method 22 is to be used.

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Process/Pollutant Information
PROCESS
NAME:
Limestone handling (EULIMESTONE) - WHEEL LOADERS & TRUCK TRAFFIC EACH
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel:
Throughput: 0
Process Notes: Was part of the "Limestone handling (EULIMESTONE) " Process until broken out by RBLC Admin. Limestone handling activities
POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Other
Other Test Method:Method 9D, if emissions detected
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY WHEEL LOADERS & TRUCK TRAFFIC EACH
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) This portion of the emission unit is wheel loaders and truck traffic.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:(RBLC Admin) Was under the process "Limestone handling (EULIMESTONE)", however, the same pollutant
was listed 3 times which is not allowed. Each of the 3 VE limits was broken out into it's own process. ------------
original note -------------- 5% is the opacity limit for the wheel loaders and truck traffic portion of the limestone
handling emission unit EULIMESTONE. If emissions are detected, Method 9D is to be used.

Process/Pollutant Information
PROCESS
NAME:
2 Circulating Fluidized Bed Boilers (CFB1 & CFB2)--Startup & Shutdown ONLY
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Petcoke/coal
Throughput: 3030.00 MMBTU/H EACH
Process Notes: This section is for emissions associated with startup & shutdown ONLY.
POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:54.5000 LB/H EACH; BACT & SIP; SS ONLY
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) Pulse jet fabric filter
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:NOTE: This limit (PM2.5 = 54.5 LB/HR) applies ONLY during startup & shutdown of the boilers. There are no
other specific pollutant limits for either boiler during startup & shutdown.

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Facility Information
RBLC ID:TX-0585 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:TENASKA TRAILBLAZER PARTNERS LLC Permit Number:PSDTX1123 AND
HAP13, 84167
Facility Name:TENASKA TRAILBLAZER ENERGY CENTER Permit Date:12/30/2010 (actual)
Facility Contact:LARRY CARLSON 402-938-1661 FRS Number:UNKNOWN
Facility Description:Coal-fired electric generating facility SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:NOLAN
Facility State:TX
Facility ZIP Code:
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Mr. Richard Hughes
512-239-1554
[e-mail]
Permit Notes:HAP13, 84167
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 OK Wichita Mountains > 250 km

Process/Pollutant Information
PROCESS
NAME:
Coal-fired Boiler
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Sub-bituminous coal
Throughput: 8307.00 MMBTU/H
Process Notes: Fuel is PRB coal. Output is 900MW gross and 700 MW net. this boiler will have an amine scrubber to remove approximately 85% of the CO2 to be
used for enhanced recovery in nearby oil fields and gas wells; this is not required by the permit but is voluntary.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:EPA/OAR Mthd 7E
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0500 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:0.0600 LB/MMBTU 30-DAY ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Selective Catalytic Reduction
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:Other limits: 0.070 lb/MMBtu 24-hour avg 498 lb/hr 30-day avg 1661 lb/hr startup/shutdown

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.0600 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
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Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Wet limestone scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:498 lb/hr 30-day rolling

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1000 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.1000 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:830lb/hr 30-day rolling avg

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0120 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:99.6800 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) Fabric Filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0250 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:207.6800 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter and wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:
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POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0036 LB/MMBTU 12-MONTH ROLLING AVG
Emission Limit 2:29.9100 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practice
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0037 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0006 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:5.2000 LB/H 1-H
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0005 LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:4.1500 LB/H 1-H
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 34/58
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Wet scrubber
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Lead (Pb) / Lead Compounds
CAS Number:7439-92-1
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1: LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Ammonia (NH3)
CAS Number:7664-41-7
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPMVD 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1: LB/MMBTU 12-MONTH ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:NSPS
Control Method:(A) Sorbent injection and fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 35/58
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:TX-0593 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:SUMMIT TEXAS CLEAN ENERGY Permit Number:PSDTX1218 & 92350
Facility Name:TEXAS CLEAN ENERGY PROJECT Permit Date:12/28/2010 (actual)
Facility Contact:KARL MATTES [phone] FRS Number:UNKNOWN
Facility Description:Integrated Gasification Combined Cycle SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:EXTOR
Facility State:TX
Facility ZIP Code:
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Erik Hendrickson
[phone]
[e-mail]
Permit Notes:State permit number 92350
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
CLASS1 NM Carlsbad Caverns NP 100km - 50km

Process/Pollutant Information
PROCESS
NAME:
Integrated Gasification Combined Cycle
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: PRB coal
Throughput: 400.00 MW
Process Notes: This facility is an integrated gasification combined cycle power plant. It will produce a nominal 400 MW of electricity and it will produce
ammonia/urea and recover sulphuric acid as commercial products.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:3.5000 PPM ON SYNGAS
Emission Limit 2:2.5000 PPM ON NATURAL GAS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SCR
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 36/58
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:10.0000 PPM SULFUR CONTENT OF SYNGAS
Emission Limit 2:2.0000 GR/100 DSCF SULFUR CONTENT OF NATURAL GAS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) gasification of coal and sulfur recovery in syngas before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0070 LB/MWH
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasification of coal and sulfur recovery in syngas before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:Sulfur content of syngas is limited to 10 ppm. Sulfur content of natural gas is limited to 2 gr/100 dscf

POLLUTANT NAME:Particulate matter, total (TPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) gasification of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(including natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPM
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 37/58
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) good combustion controls
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201A and 202
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasificaiton of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0090 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) gasification of coal and syngas clean-up before combustion in turbine and duct burners; burning low ash fuels
(natural gas)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:1.0000 PPM
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) good combustion controls
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 38/58
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0001 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:RACT
Other Applicable Requirements:
Control Method:(P) sungas clean-up before combustio in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1: LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) syngas clean-up before combustion in turbine and duct burners
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:MI-0399 (final) Date Determination
Last Updated:04/14/2016
Corporate/Company Name:DETROIT EDISON Permit Number:93-09A
Facility Name:DETROIT EDISON--MONROE Permit Date:12/21/2010 (actual)
Facility Contact:LILLIAN WOOLLEY 313-235-5611 [e-mail] FRS Number:26-11500020
Facility Description:Utility--Coal fired power plant SIC Code:4911
Permit Type:D: Both B (Add new process to existing facility) &C (Modify process at existing
facility)
NAICS Code:221112
Permit URL:
EPA Region:5 COUNTRY:USA
Facility County:MONROE
Facility State:MI
Facility ZIP Code:48161-1970
Permit Issued By:MICHIGAN DEPT OF ENVIRONMENTAL QUALITY (Agency Name)
MS. CINDY SMITH(Agency Contact) [phone] [e-mail]
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 39/58
Other Agency Contact Info:Please contact permit engineer Julie Brunner at 517-373-7088 with questions related to the permit. Thank you.
Permit Notes:
Affected Boundaries:Boundary Type:Class 1 Area State:Boundary:Distance:
INTL BORDER US/Canada Border < 100 km

Process/Pollutant Information
PROCESS
NAME:
Boiler Units 1, 2, 3 and 4
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: Coal
Throughput: 7624.00 MMBTU/H
Process Notes: 7,624 MMBTU/HR (Each unit). Pulverized coal-fired boilers, adding petroleum coke and increasing usage of subbituminous coal.
POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1500 LB/MMBTU EACH, 30D ROLL. AVG. EXCL. STRTUP&SHTDWN
Emission Limit 2:27446.4000 LB/D EACH, 30D ROLLING AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Under 'Basis Information' and 'Other Applicable Requirements'--Other--NAAQS (above on page). Top Ranking
Option

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0800 LB/MMBTU EACH, 12-MONTH ROLLING AVG.
Emission Limit 2:222.6000 T/MO EACH, 12-MONTH ROLLING AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Staged combustion, low-NOx burners, overfire air, and SCR.
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. Under 'Basis Information' and 'Other Applicable Requirements--Other--NAAQS' (above on
page).

POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0110 LB/MMBTU EACH, TEST/ OR 24H ROLL.AVG. IF PM CEMS
Emission Limit 2:10.0000 OPAC EACH, 6 MIN AVG TEST /OR COMS
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 40/58
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:168 $/ton
Incremental Cost Effectiveness:18299 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:3rd ranking option

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.1070 LB/MMBTU EACH, 24-H ROLL. AVG.
Emission Limit 2:815.8000 LB/H EACH, 24-H ROLL. AVG.
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Wet flue gas desulfurization.
Est. % Efficiency:95.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. 'Other--NAAQS' (above)

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0034 LB/MMBTU EACH, TEST PROTOCOL
Emission Limit 2:25.9000 LB/H EACH, TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:Top ranking option. 'Other--State'

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0240 LB/MMBTU EACH, TEST
Emission Limit 2:183.0000 LB/H EACH, TEST
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:167 $/ton
Incremental Cost Effectiveness:13093 $/ton
Compliance Verified:Yes
Pollutant/Compliance Notes:3rd ranking option.

8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 41/58
POLLUTANT NAME:Lead (Pb) / Lead Compounds
CAS Number:7439-92-1
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1: LB/MMBTU EACH, TEST
Emission Limit 2:0.1300 LB/H EACH, TEST
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:168 $/ton
Incremental Cost Effectiveness:18299 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:3rd ranking option (cost based on surrogate of PM) 'Other -- NAAQS'

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0050 LB/MMBTU EACH, TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:89.000
Cost Effectiveness:126565 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Incremental Cost Effectiveness ($/ton)=NA 4th ranking option Note: Estimated Control Efficiency is 42% - 89%.
Only one value allowed to be entered on this page above.

POLLUTANT NAME:Hydrogen Fluoride
CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0002 LB/MMBTU EACH, TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:94.000
Cost Effectiveness:122779 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:3rd ranking option. Incremental Cost Effectivenss ($/ton) = NA

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:0.0200 LB/GW-H EACH, 12MO. ROLL. AVG.-CEMS
Emission Limit 2:143.1000 LB/YR UNITS 1&4, 12MO.ROLL.-CEMS
Standard Emission:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 42/58
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) Co-benefit reduction due to SCRs, ESPs, and wet flue gas desulfurization.
Est. % Efficiency:90.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Units 2 & 3 have a limit of 144.2 LB/YR based on a 12-month rolling time period--using CEMS. NOTE: Under
'Control Efficiency' above, it is a range from 75% to 90% depending on the fuel type. Since only one limit may
be included above, 90% was used.

POLLUTANT NAME:Arsenic / Arsenic Compounds
CAS Number:7440-38-2
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:6.3000 E-6 LB/MMBTU EACH, TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Other Case by Case basis is T-BACT which is State Rule 336.1224.

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0024 LB/MMBTU LIMIT IS FOR EACH BOILER; TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) ESPs and wet flue gas desulfurization
Est. % Efficiency:97.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Limit is 0.0024 LB/MMBTU for each boiler. Test method will specify averaging time. The limit(s) were
established per Rule 336.1224, state rule, known as T-BACT (Best Available Control Technology for toxics).

Process/Pollutant Information
PROCESS
NAME:
4 Diesel-fired quench pumps
Process Type: 17.210 (Fuel Oil (ASTM # 1,2, includes kerosene, aviation, diesel fuel))
Primary Fuel: Diesel fuel
Throughput: 252.00 HP
Process Notes: Each pump engine is 252 HP. They are limited to emergency use and subject to NSPS Subpart IIII.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
8/17/2020 Format RBLC Report
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Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2 EACH, TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4 EACH, TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. Note: QP1 = Quench pump#1; QP2= Quench pump#2; QP3=Quench pump#3; QP4 =
Quench pump#4.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2, EACH; TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4, EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option Note: QP1=Quench pump #1; QP2=Quench pump#2; QP3=Quench pump#3; QP4=Quench
pump#4.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.4000 G/HP-H QP1&QP2 EACH; TEST PROTOCOL
Emission Limit 2:0.1500 G/HP-H QP3&QP4 EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. 'Other Case-by-Case' is PM2.5 non-attainment, hybrid applicability

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:20.0000 % OPACITY 20% OPAC, 6 MIN. AVG; EACH PUMP
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 44/58
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking option. 20% opacity on a 6-minute average for each pump QP1, QP2, QP3, QP4.

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:2.6000 G/HP-H EACH PUMP; TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:

POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:7.8000 G/HP-H QP1&QP2 EACH; TEST PROTOCOL
Emission Limit 2:3.0000 G/HP-H QP3&QP4 EACH; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) Good combustion practices.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Limits are as NMHC+NOx based upon NSPS Subpart IIII.

Process/Pollutant Information
PROCESS
NAME:
Fuel handling activities
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel: Coal
Throughput: 19.20 MTons/yr
Process Notes: Coal = 19.2 Mtons/yr PetCoke = 1.1 Mtons/yr New and existing fuel handling for bituminous coal, subbituminous coal and petroleum coke.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 45/58
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input;
99% was chosen.

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY TEST PROTOCOL; BACT
Emission Limit 2:10.0000 % OPACITY TEST PROTOCOL; EXISTING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input
into the table.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Fabric filters; fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.
PM10 LB/H rate varies based upon the 0.004 GR/DSCF

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) Fabric filters; fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 46/58
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. 'Other' = PM2.5 nonattainment, hybrid applicability PM2.5 emission rate varies based upon
0.004 GR/DSCF. Estimated efficiency is 70%-99%; however only one value is allowed to be input into the table.

Process/Pollutant Information
PROCESS
NAME:
Limestone, gypsum, hydrated lime handling activities
Process Type: 90.999 (Other Mineral Processing Sources)
Primary Fuel: Gypsum
Throughput: 360000.00 T/YR
Process Notes: Process is limestone, gypsum, hydrated lime handling acitivities. Limestone throughput capacity = 240,000 T/YR; Gypsum throughput capacity =
360,000 T/YR. New material handling for limestone, gypsum, hydrated lime; limestone & gypsum subject to NSPS Subpart OOO.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.

POLLUTANT NAME:Visible Emissions (VE)
CAS Number:VE
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:5.0000 % OPACITY FABRIC FILTERS; TEST PROTOCOL
Emission Limit 2:10.0000 % OPACITY DROP POINTS; TEST PROTOCOL
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value is allowed to be input.

POLLUTANT NAME:Particulate matter, total < 10 µ (TPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 47/58
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. Estimated control efficiency is 70%-99%; however only one value allowed to be input. The
PM10 emission rate varies and is based upon 0.004 GR/DSCF.

POLLUTANT NAME:Particulate matter, total < 2.5 µ (TPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0040 GR/DSCF TEST PROTOCOL
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
Control Method:(A) Fabric filters, fugitive dust control plan.
Est. % Efficiency:99.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:Top ranking options. 'Other' = PM2.5 nonattainment, hybrid applicability. Estimated control efficiency is
70%-99%; however only one value allowed to be input. PM2.5 rate varies and is based upon 0.004 GR/DSCF.

Previous Page
Facility Information
RBLC ID:TX-0554 (final) Date Determination
Last Updated:02/03/2020
Corporate/Company Name:COLETO CREEK Permit Number:PSDTX1118 AND 83778
Facility Name:COLETO CREEK UNIT 2 Permit Date:05/03/2010 (actual)
Facility Contact:ROSS CRYSUP FRS Number:110000599692
Facility Description:Coal-fired boiler SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:6 COUNTRY:USA
Facility County:GOLIAD
Facility State:TX
Facility ZIP Code:77960
Permit Issued By:TEXAS COMMISSION ON ENVIRONMENTAL QUALITY (TCEQ) (Agency Name)
MS. ANNE INMAN(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:Sean O'Brien
512-239-1137
[e-mail]
Permit Notes:83778 HAP18

Process/Pollutant Information
PROCESS
NAME:
Coal-fired Boiler Unit 2
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: PRB coal
Throughput: 6670.00 MMBTU/H
Process Notes: IPA Coleto Creek, L.L.C. (IPA) has proposed to install a new solid fuel-fired utility boiler, Unit 2 (CC2), at their existing Coleto Creek Power Station
8/17/2020 Format RBLC Report
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(CC) which has one existing solid fuel fired boiler. CC2 will be a nominal 650 MW net (750 MW gross) boiler firing sub-bituminous coal and/or
bituminous coal with a maximum heat input rate of 6,670 MMBtu/hr based on a 30 day average of the heat input. The boiler will operate burning sub-
bituminous coal or a blend of that and up to 40% bituminous coal.
POLLUTANT NAME:Nitrogen Oxides (NOx)
CAS Number:10102
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) , Particulate Matter (PM) )
Emission Limit 1:0.0600 LB/MMBTU ROLLING 30 DAY AVG
Emission Limit 2:0.0500 LB/MMBTU ROLLING 12 MONTH AVG
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) low-NOx burners with OFA, Selective Catalytic Reduction
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0600 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.0600 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) Spray Dry Adsorber/Fabric Filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1200 LB/MMBTU 30-DAY ROLLING
Emission Limit 2:0.1200 LB/MMBTU 12-MONTH ROLLING
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
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Emission Limit 1:0.0120 LB/GW-H 12-MONTH ROLLING / MIXED FUEL
Emission Limit 2:0.0150 LB/GW-H 12-MONTH ROLLING/ PRB ONLY
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) Fabric filter with sorbent injection
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:The mercury standard is based on this formula: % sub-bituminous coal x 0.015 lb Hg/GW-hr + % bituminous
coal x 0.0075 lb Hg/GW-hr

POLLUTANT NAME:Ammonia (NH3)
CAS Number:7664-41-7
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:10.0000 PPMVD 3-HOUR ROLLING
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N)
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0120 LB/MMBTU ANNUAL / BASED ON STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Particulate matter, total (TPM)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0250 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) fabric filter, spray dry adsorber for acid gases
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Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0034 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) Good combustion practices
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0040 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrochloric Acid
CAS Number:7647-01-0
Test Method:Unspecified
Pollutant Group(s):( Acid Gasses/Mist , Hazardous Air Pollutants (HAP) , InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0008 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/ fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Hydrogen Fluoride
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CAS Number:7664-39-3
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.0005 LB/MMBTU ANNUAL / STACK TEST
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: U
Case-by-Case Basis:MACT
Other Applicable Requirements:
Control Method:(A) spray dry adsorber/fabric filter
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Previous Page
Facility Information
RBLC ID:KY-0100 (final) Date Determination
Last Updated:03/15/2011
Corporate/Company Name:EAST KENTUCKY POWER COOPERATIVE, INC Permit Number:V-05-070 R3
Facility Name:J.K. SMITH GENERATING STATION Permit Date:04/09/2010 (actual)
Facility Contact: 859.744.4812 JERRY PURVIS [[e-mail]] FRS Number:110017429521
Facility Description:NEW CFB EGU BECAUSE OF A LEGAL CHALLENGE OUTSIDE OF THE
TITLE V PROCEDURES, PERMITTEE AGREED TO TERMINATE
CONSTRUCTION AUTHORITY FOR PROJECT. R4 TO THIS PERMIT
REMOVES CONSTRUCTION AURTHORITY, AND THE PERMIT MAY NOT
BE AVAILABLE FROM KENTUCKY'S WEBSITE.
SIC Code:4911
Permit Type:A: New/Greenfield Facility NAICS Code:221112
Permit URL:
EPA Region:4 COUNTRY:USA
Facility County:
Facility State:KY
Facility ZIP Code:
Permit Issued By:KENTUCKY DEP, DIV FOR AIR QUALITY (Agency Name)
MR. RICK SHEWEKAH, MGR(Agency Contact) [phone] [e-mail]
Other Agency Contact Info:TOM ADAMS OR BEN MARKIN
Permit Notes:BECAUSE OF A LEGAL CHALLENGE OUTSIDE OF THE TITLE V PROCEDURES, PERMITTEE AGREED TO TERMINATE
CONSTRUCTION AUTHORITY FOR PROJECT. R4 TO THIS PERMIT REMOVES CONSTRUCTION AURTHORITY, AND THE
PERMIT MAY NOT BE AVAILABLE FROM KENTUCKY'S WEBSITE.

Process/Pollutant Information
PROCESS
NAME:
CIRCULATING FLUIDIZED BED BOILER CFB1 AND CFB2
Process Type: 11.110 (Coal (includes bituminous, subbituminous, anthracite, and lignite))
Primary Fuel: COAL
Throughput: 3000.00 MMBTU/H
Process Notes: COAL AND WASTE COAL WITH NATURAL GAS FOR STARTUP THRUPUT IS PER UNIT.
POLLUTANT NAME:Particulate matter, filterable (FPM)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0900 LB/MMBTU 30 DAY AVERAGE
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Emission Limit 2:210.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) BAGHOUSE
Est. % Efficiency:99.900
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:PM CEMS FOR COMPLIANCE

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0900 LB/MMBTU
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) BAGHOUSE
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:METHOD 201 AND 202 FOR TOTAL PM10/2.5

POLLUTANT NAME:Carbon Monoxide
CAS Number:630-08-0
Test Method:Other
Other Test Method:
Pollutant Group(s):( InOrganic Compounds )
Emission Limit 1:0.1000 LB/MMBTU 30 DAY
Emission Limit 2:300.0000 LB/H 8 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N) GOOD COMBUSTION CONTROLS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:CO CEMS

POLLUTANT NAME:Sulfur Dioxide (SO2)
CAS Number:7446-09-5
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Sulfur (SOx) )
Emission Limit 1:0.0750 LB/MMBTU 30 DAY AVERAGE
Emission Limit 2:225.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS , OTHER
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Control Method:(A) LIMESTONE INJECTION (CFB)AND A FLASH DRYER ABSORBER WITH FRESH LIME INJECTION
Est. % Efficiency:99.100
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:LB/MMBTU LIMIT EXCLUDES STARTUP/SHUTDOWN. LBS/DAY LIMIT INCLUDES STARTUP AND
SHUTDOWN

POLLUTANT NAME:Nitrogen Dioxide (NO2)
CAS Number:10102-44-0
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Oxides of Nitrogen (NOx) )
Emission Limit 1:0.0700 LB/MMBTU 30 DAY AVERAGE
Emission Limit 2:210.0000 LB/H 24 HOUR BLOCK
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) SNCR
Est. % Efficiency:53.000
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:LBS/MMBTU EXCLUDES STARTUP.SHUTDOWN; LBS/HR INCLUDES S&S

POLLUTANT NAME:Volatile Organic Compounds (VOC)
CAS Number:VOC
Test Method:Unspecified
Pollutant Group(s):( Volatile Organic Compounds (VOC) )
Emission Limit 1:0.0200 LB/MMBTU 3-HOUR
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(N) GOOD COMBUSTION CONTROL
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

POLLUTANT NAME:Mercury
CAS Number:7439-97-6
Test Method:Unspecified
Pollutant Group(s):( Hazardous Air Pollutants (HAP) , Heavy Metals , InOrganic Compounds )
Emission Limit 1:6.0000 E-6 LB/MWH BIT COAL ON ANNUAL AVERAG
Emission Limit 2:6.0000 E-6 LB/MWH WASTE COAL ON ANNUAL AVE
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:OTHER CASE-BY-CASE
Other Applicable Requirements:OTHER
Control Method:(A) FABRIC FILTER, SNCR
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:40 CFR 72.2 OR MERCURY CEMS. LIMIT SET TO MEET COMPLIANCE WITH STATE REGULATION.
Limits are 0.000006 LB/MWH.
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 54/58

POLLUTANT NAME:Sulfuric Acid (mist, vapors, etc)
CAS Number:7664-93-9
Test Method:Unspecified
Pollutant Group(s):( InOrganic Compounds , Particulate Matter (PM) )
Emission Limit 1:0.0050 LB/MMBTU 3-HR
Emission Limit 2:15.0000 LB/H 3 HR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(A) SAME AS CONTROLS FOR PARTICULATES
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:LB/MMBTU EXCLUDES SSM LB/HR INCLUDES SSM

Process/Pollutant Information
PROCESS
NAME:
ASH HANDLING
Process Type: 99.120 (Ash Storage, Handling, Disposal)
Primary Fuel:
Throughput: 0
Process Notes: CFB1 FLY ASH SILO 73 TON/HR CFB1 BED ASH SILO 37 TONS/HR CFB2 FLY ASH SILO 73 TONS/HR CFB2 BED ASH SILO 37
TONS/HR
POLLUTANT NAME:Particulate matter, filterable < 2.5 µ (FPM2.5)
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 G/DSCF 24 BLOCK
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:0.005 GR/DSCF

POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 55/58
Compliance Verified:Unknown
Pollutant/Compliance Notes:FOUR STACKS FOR FLY AND BED ASH

Process/Pollutant Information
PROCESS
NAME:
COAL CRUSHING AND SILO STORAGE
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Unknown
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:SIP
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:

Process/Pollutant Information
PROCESS
NAME:
COAL STOCKPILE
Process Type: 90.011 (Coal Handling/Processing/Preparation/Cleaning)
Primary Fuel:
Throughput: 3000.00 T/H
Process Notes: STORAGE PILES, RAILCAR UNLOADING, EGRESS TO UNDERGROUND CONVEYOR
POLLUTANT NAME:Particulate Matter (PM)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:10.0000 OPACITY 3 MINUTE
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(P) WET SUPPRESSION, DUST SUPPRESSENT LOWERING WELL AND COMPACTION.
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:LIMIT FOR PM/PM10/PM2.5

Process/Pollutant Information
PROCESS
NAME:
LIME SILO STORAGES
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 56/58
Process Type: 90.019 (Lime/Limestone Handling/Kilns/Storage/Manufacturing)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) FABRIC FILTERS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:BACT FOR PM10 AND 2.5. THREE DIFFERENT TYPES OF SILOS WITH DIFFERENT PROCESS RATES.
0.30 LBS/HOUR FROM EACH FRESH LIME SILO 0.17 LBS/HOUR EACH RECYCLED LIME SILO . 0.02
LBS/HOUR FROM EACH SCRUBBER SLAKER

Process/Pollutant Information
PROCESS
NAME:
LIMESTONE UNLOADING
Process Type: 99.190 (Other Fugitive Dust Sources)
Primary Fuel:
Throughput: 44.00 T/H
Process Notes: LIMESTONE STORAGE PILE FUGITIVE EMISSIONS FROM UNLOADING/HANDLING
POLLUTANT NAME:Particulate matter, fugitive
CAS Number:PM
Test Method:Unspecified
Pollutant Group(s):
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) WET SUPPRESSION OR DUST SUPPRESSANT
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:No
Pollutant/Compliance Notes:SUBJECT TO STATE FUGITIVE REGULATION

Process/Pollutant Information
PROCESS
NAME:
COALING TOWERS
Process Type: 99.999 (Other Miscellaneous Sources)
Primary Fuel:
Throughput: 0
Process Notes:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 57/58
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:N/A
Control Method:(P) 0.0005% DRIFT ELIMINATORS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:COOLING TECHNOLOGY INSTITUTE (CTI) ACCEPTANCE TEST CODE (ATC) #140 TO VERIFY DRIFT
PERCENT ACHIEVED BY THE DRIFT ELIMINATOR

POLLUTANT NAME:Particulate matter, filterable < 2.5 µ (FPM2.5)
CAS Number:PM
Test Method:Other
Other Test Method:
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:
Control Method:(P) BACT FOR PM/PM10/PM2.5 IS 0.0005% DRIFT ELIMINATORS
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:COOLING TECHNOLOGY INSTITUTE (CTI) ACCEPTANCE TEST CODE (ATC) #140 TO VERIFY DRIFT
PERCENT ACHIEVED BY THE DRIFT ELIMINATOR

Process/Pollutant Information
PROCESS
NAME:
HAUL ROADS
Process Type: 99.140 (Paved Roads)
Primary Fuel:
Throughput: 0
Process Notes:
POLLUTANT NAME:Particulate matter, fugitive
CAS Number:PM
Test Method:EPA/OAR Mthd 22
Pollutant Group(s):
Emission Limit 1:
Emission Limit 2:
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: Y
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:OTHER
Control Method:(A) PAVED ROADWAYS, CLEANING OR PROMPT REMOVAL OF MATERIAL, AND THE
APPLICATION OF WET SUPPRESSION, AS APPLICABLE.
Est. % Efficiency:
8/17/2020 Format RBLC Report
https://cfpub.epa.gov/rblc/index.cfm?action=Reports.ReportComprehensiveReport&ReportFormat=txt 58/58
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:BACT REQUIRES PAVED ROADS ONLY SUBJECT TO STATE FUGITIVE REGULATION

Process/Pollutant Information
PROCESS
NAME:
LIMESTONE STORAGE SILOS
Process Type: 90.019 (Lime/Limestone Handling/Kilns/Storage/Manufacturing)
Primary Fuel:
Throughput: 40.00 T/H
Process Notes: 2 SILOS, 40 TONS PER HOUR EACH.
POLLUTANT NAME:Particulate matter, filterable < 10 µ (FPM10)
CAS Number:PM
Test Method:EPA/OAR Mthd 201
Pollutant Group(s):( Particulate Matter (PM) )
Emission Limit 1:0.0050 GR/DSCF 24 HR
Emission Limit 2:0.5100 LB/H (EACH) 24 HR
Standard Emission:
Did factors, other then air pollution technology considerations influence the BACT decisions: N
Case-by-Case Basis:BACT-PSD
Other Applicable Requirements:NSPS
Control Method:(A) FABRIC FILTER
Est. % Efficiency:
Cost Effectiveness:0 $/ton
Incremental Cost Effectiveness:0 $/ton
Compliance Verified:Unknown
Pollutant/Compliance Notes:ALSO LISTED AS PM2.5 LIMIT.

Previous Page

APPENDIX E
Cost Analysis SO2 Controls
Units 1 and 2 Dry Scrubber (NIDS)

Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.
Variable Designation Units Value Calculation
EPC Project?TRUE
Unit Size A (MW)690 <--- User Input (Greater than 50 MW)
Retrofit Factor B 1.00 <--- User Input (An "average" retrofit has a factor = 1.0)
Heat Rate C (Btu/kWh)9800 <--- User Input
SO2 Rate D (lb/MMBtu)4 <--- User Input (SDA FGD Estimation only valid up to 3 lb/MMBtu SO2 Rate)
Type of Coal E 3 <--- User Input
Coal Factor F 1 Bit = 1.0, PRB = 1.05, Lig = 1.07
Heat Rate Factor G 0.98 C/10000
Heat Input H (Btu/hr) 6.76E+09 A*C*1000
Capacity Factor I (%)100 <--- User Input
Operating SO2 Removal J (%)95 <--- User Input (Used to adjust actual operating costs)
Design Lime Rate K (ton/hr) 22 (0.6702*(D^2)+13.42*D)*A*G/2000 (Based on 95% SO2 removal)
Design Waste Rate L (ton/hr) 47 (0.8016*(D^2)+31.1917*D)*A*G/2000 (Based on 95% SO2 removal)
M (%) 1.31 (0.000547*D^2+0.00649*D+1.3)*F*G
Makeup Water Rate N (1000 gph) 39 (0.04898*D^2+0.5925*D+55.11)*A*F*G/1000
Lime Cost P ($/ton)125 <--- User Input
Waste Disposal Cost Q ($/ton)30 <--- User Input
Aux Power Cost R ($/kWh)0.06 <--- User Input
Makeup Water Cost S ($/kgal)1 <--- User Input
Operating Labor Rate T ($/hr)60 <--- User Input (Labor cost including all benefits)
Costs are all based on 2016 dollars
Capital Cost Calcuation Example Comments
Includes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) = if (A>600 then (A*98000) else 637000*(A^0.716))*B*(F*G)^0.6*(D/4)^0.01 66,805,000$ Base module absorber island cost
BMF ($) = if (A>600 then (A*52000) else 338000*(A^0.716))*B*(G*D)^0.2 47,153,000$ Base module reagent preparation and waste recycle/handling cost
BMB ($) = if (A>600 then (A*138000) else 899000*(A^0.716))*B*(G*F)^0.4 94,454,000$ Base balance of plant costs including: ID or booster fans, piping, ductwork modifications and strengthening, electrical, etc...
BM ($) = BMR + BMF + BMB 208,412,000$ Total base module cost including retrofit factor
BM ($/kW) = 302 Base cost per kW
Total Project Cost
A1 = 10% of BM 20,841,000$ Engineering and Construction Management costs
A2= 10% of BM 20,841,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…
A3 = 10% of BM 20,841,000$ Contractor profit and fees
CECC ($) = BM + A1 + A2 + A3 270,935,000$ Capital, engineering and construction cost subtotal
CECC ($/kW) = 393 Capital, engineering and construction cost subtotal per kW
B1 = 2% of CECC if EPC TRUE, else 5% of CECC 5,419,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)
TPC' ($) - Includes Owner's Costs = CECC + B1 276,354,000$ Total project cost without AFUDC
TPC' ($/kW) - Includes Owner's Costs 401 Total project cost per kW without AFUDC
B2 = 10% of (CECC + B1) 27,635,000$ AFUDC (Based on a 3 year engineering and construction cycle)
C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 41,453,000$ EPC fees of 15%
TPC ($) = Includes Owner's Costs and AFUDC = CECC + B1 + B2 + C1 345,442,000$ Total project cost
TPC ($/kW) = Includes Owner's Costs and AFUDC 501 Total project cost per kW
Fixed O&M Cost
FOMO ($/kW yr) = (8 operators)*2080*T/(A*1000) 1.45$ Fixed O&M additional operating labor costs
FOMM ($/kW yr) =(BM*0.015)/(B*A*1000) 4.53$ Fixed O&M additional maintenance material and labor costs
FOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.10$ Fixed O&M additional administrative labor costs
Aux Power
Include in VOM?
FOM ($/kW yr) = FOMO +FOMM+FOMA 6.08$ Total Fixed O&M costs
Variable O&M Cost
VOMR ($/MWh) = K*P/(A*J)/98 3.95$ Variable O&M costs for limestone reagent
VOMW ($/MWh) = L*Q/(A*J)/98 2.02$ Variable O&M costs for waste disposal
VOMP ($/MWh) = M*R*10 0.78$ Variable O&M costs for additional auxiliary power required including additional fan power (Refer to Aux Power % above)
VOMM ($/MWh) = N*S/A 0.06$ Variable O&M costs for makeup water
VOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 6.81$ Total Variable O&M costs
Annual Capacity Factor = 100%
Annual MWhs = 6,044,400
Annual Heat Input MMBtu = 59,235,120
Annual Tons SO2 Created = 118,470 at 100% S conversion
Annual Tons SO2 Removed = 112,547 at removal efficiency = 95%
Annual Tons SO2 Emission = 5,924
Annual Avg SO2 Emission Rate, lb/MMBtu = 0.200 Value is AT or ABOVE a 0.06 floor rate
Annual Capital Recovery Factor = 0.094 Wet FGD
Annual Capital Cost (Including AFUDC), $ = 32,610,000
Annual FOM Cost, $ = 4,192,000 45,353,000
Annual VOM Cost, $ = 41,161,000
Total Annual SCR Cost, $ = 77,963,000
Capital Cost, $/MWh = 5.40
FOM Cost, $/MWh = 0.69
VOM Cost, $/MWh = 6.81
Total SCR Cost, $/MWh = 12.90
Capital Cost, $/ton = 290
FOM Cost, $/ton = 37
VOM Cost, $/ton = 366
Total SCR Cost, $/ton = 693
Lookup Table
Coal Coal Factor
1 PRB 1.05
2 Lignite 1.07
3 Bituminous 1
Aux Power
TRUE
Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.
Variable Designation Units Value Calculation
EPC Project?TRUE
Unit Size A (MW)690 <--- User Input (Greater than 50 MW)
Retrofit Factor B 1.00 <--- User Input (An "average" retrofit has a factor = 1.0)
Heat Rate C (Btu/kWh)9800 <--- User Input
SO2 Rate D (lb/MMBtu)4 <--- User Input (SDA FGD Estimation only valid up to 3 lb/MMBtu SO2 Rate)
Type of Coal E 3 <--- User Input
Coal Factor F 1 Bit = 1.0, PRB = 1.05, Lig = 1.07
Heat Rate Factor G 0.98 C/10000
Heat Input H (Btu/hr) 6.76E+09 A*C*1000
Capacity Factor I (%)100 <--- User Input
Operating SO2 Removal J (%)95 <--- User Input (Used to adjust actual operating costs)
Design Lime Rate K (ton/hr) 22 (0.6702*(D^2)+13.42*D)*A*G/2000 (Based on 95% SO2 removal)
Design Waste Rate L (ton/hr) 47 (0.8016*(D^2)+31.1917*D)*A*G/2000 (Based on 95% SO2 removal)
M (%) 1.31 (0.000547*D^2+0.00649*D+1.3)*F*G
Makeup Water Rate N (1000 gph) 39 (0.04898*D^2+0.5925*D+55.11)*A*F*G/1000
Lime Cost P ($/ton)125 <--- User Input
Waste Disposal Cost Q ($/ton)30 <--- User Input
Aux Power Cost R ($/kWh)0.06 <--- User Input
Makeup Water Cost S ($/kgal)1 <--- User Input
Operating Labor Rate T ($/hr)60 <--- User Input (Labor cost including all benefits)
Costs are all based on 2016 dollars
Capital Cost Calcuation Example Comments
Includes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.
BMR ($) = if (A>600 then (A*98000) else 637000*(A^0.716))*B*(F*G)^0.6*(D/4)^0.01 66,805,000$ Base module absorber island cost
BMF ($) = if (A>600 then (A*52000) else 338000*(A^0.716))*B*(G*D)^0.2 47,153,000$ Base module reagent preparation and waste recycle/handling cost
BMB ($) = if (A>600 then (A*138000) else 899000*(A^0.716))*B*(G*F)^0.4 94,454,000$ Base balance of plant costs including: ID or booster fans, piping, ductwork modifications and strengthening, electrical, etc...
BM ($) = BMR + BMF + BMB 208,412,000$ Total base module cost including retrofit factor
BM ($/kW) = 302 Base cost per kW
Total Project Cost
A1 = 10% of BM 20,841,000$ Engineering and Construction Management costs
A2= 10% of BM 20,841,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…
A3 = 10% of BM 20,841,000$ Contractor profit and fees
CECC ($) = BM + A1 + A2 + A3 270,935,000$ Capital, engineering and construction cost subtotal
CECC ($/kW) = 393 Capital, engineering and construction cost subtotal per kW
B1 = 2% of CECC if EPC TRUE, else 5% of CECC 5,419,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)
TPC' ($) - Includes Owner's Costs = CECC + B1 276,354,000$ Total project cost without AFUDC
TPC' ($/kW) - Includes Owner's Costs 401 Total project cost per kW without AFUDC
B2 = 10% of (CECC + B1) 27,635,000$ AFUDC (Based on a 3 year engineering and construction cycle)
C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 41,453,000$ EPC fees of 15%
TPC ($) = Includes Owner's Costs and AFUDC = CECC + B1 + B2 + C1 345,442,000$ Total project cost
TPC ($/kW) = Includes Owner's Costs and AFUDC 501 Total project cost per kW
Fixed O&M Cost
FOMO ($/kW yr) = (8 operators)*2080*T/(A*1000) 1.45$ Fixed O&M additional operating labor costs
FOMM ($/kW yr) =(BM*0.015)/(B*A*1000) 4.53$ Fixed O&M additional maintenance material and labor costs
FOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.10$ Fixed O&M additional administrative labor costs
Aux Power
Include in VOM?
FOM ($/kW yr) = FOMO +FOMM+FOMA 6.08$ Total Fixed O&M costs
Variable O&M Cost
VOMR ($/MWh) = K*P/(A*J)/98 3.95$ Variable O&M costs for limestone reagent
VOMW ($/MWh) = L*Q/(A*J)/98 2.02$ Variable O&M costs for waste disposal
VOMP ($/MWh) = M*R*10 0.78$ Variable O&M costs for additional auxiliary power required including additional fan power (Refer to Aux Power % above)
VOMM ($/MWh) = N*S/A 0.06$ Variable O&M costs for makeup water
VOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 6.81$ Total Variable O&M costs
Annual Capacity Factor = 100%
Annual MWhs = 6,044,400
Annual Heat Input MMBtu = 59,235,120
Annual Tons SO2 Created = 118,470 at 100% S conversion
Annual Tons SO2 Removed = 112,547 at removal efficiency = 95%
Annual Tons SO2 Emission = 5,924
Annual Avg SO2 Emission Rate, lb/MMBtu = 0.200 Value is AT or ABOVE a 0.06 floor rate
Annual Capital Recovery Factor = 0.094 Wet FGD
Annual Capital Cost (Including AFUDC), $ = 32,610,000
Annual FOM Cost, $ = 4,192,000 45,353,000
Annual VOM Cost, $ = 41,161,000
Total Annual SCR Cost, $ = 77,963,000
Capital Cost, $/MWh = 5.40
FOM Cost, $/MWh = 0.69
VOM Cost, $/MWh = 6.81
Total SCR Cost, $/MWh = 12.90
Capital Cost, $/ton = 290
FOM Cost, $/ton = 37
VOM Cost, $/ton = 366
Total SCR Cost, $/ton = 693
Lookup Table
Coal Coal Factor
1 PRB 1.05
2 Lignite 1.07
3 Bituminous 1
Aux Power
TRUE

APPENDIX F
Cost Analysis SO2 Controls
Unit 3 Dry Scrubber (NIDS)

Fill in the yellow cells with the known data inputs. The resulting costs are tabulated below. Variable names are defined as outlined in the table.Variable Designation Units Value CalculationEPC Project?TRUEUnit Size A (MW)710<--- User Input (Greater than 50 MW)Retrofit Factor B1.00<--- User Input (An "average" retrofit has a factor = 1.0)Heat Rate C (Btu/kWh)9800<--- User InputSO2 Rate D (lb/MMBtu)0.4<--- User Input (SDA FGD Estimation only valid up to 3 lb/MMBtu SO2 Rate)Type of Coal E3<--- User InputCoal Factor F 1 Bit = 1.0, PRB = 1.05, Lig = 1.07Heat Rate Factor G 0.98 C/10000Heat Input H (Btu/hr) 6.96E+09 A*C*1000Capacity Factor I (%)100<--- User InputOperating SO2 Removal J (%)50<--- User Input (Used to adjust actual operating costs)Design Lime Rate K (ton/hr) 2 (0.6702*(D^2)+13.42*D)*A*G/2000 (Based on 95% SO2 removal)Design Waste Rate L (ton/hr) 4 (0.8016*(D^2)+31.1917*D)*A*G/2000 (Based on 95% SO2 removal)M (%) 1.28 (0.000547*D^2+0.00649*D+1.3)*F*GMakeup Water Rate N (1000 gph) 39 (0.04898*D^2+0.5925*D+55.11)*A*F*G/1000Lime Cost P ($/ton)125<--- User InputWaste Disposal Cost Q ($/ton)30<--- User InputAux Power Cost R ($/kWh)0.06<--- User InputMakeup Water Cost S ($/kgal)1<--- User InputOperating Labor Rate T ($/hr)60<--- User Input (Labor cost including all benefits)Costs are all based on 2016 dollarsCapital Cost CalcuationExample CommentsIncludes - Equipment, intallation, buildings, foundations, electrical, and retrofit difficulty.BMR ($) = if (A>600 then (A*98000) else 637000*(A^0.716))*B*(F*G)^0.6*(D/4)^0.01 67,177,000$ Base module absorber island costBMF ($) = if (A>600 then (A*52000) else 338000*(A^0.716))*B*(G*D)^0.2 30,614,000$ Base module reagent preparation and waste recycle/handling costBMB ($) = if (A>600 then (A*138000) else 899000*(A^0.716))*B*(G*F)^0.4 97,191,000$ Base balance of plant costs including: ID or booster fans, piping, ductwork modifications and strengthening, electrical, etc...BM ($) = BMR + BMF + BMB194,982,000$ Total base module cost including retrofit factorBM ($/kW) =275 Base cost per kWTotal Project CostA1 = 10% of BM19,498,000$ Engineering and Construction Management costsA2= 10% of BM19,498,000$ Labor adjustment for 6 x 10 hour shift premium, per diem, etc…A3 = 10% of BM19,498,000$ Contractor profit and feesCECC ($) = BM + A1 + A2 + A3253,476,000$ Capital, engineering and construction cost subtotalCECC ($/kW) = 357Capital, engineering and construction cost subtotal per kWB1 = 2% of CECC if EPC TRUE, else 5% of CECC 5,070,000$ Owners costs including all "home office" costs (owners engineering, management, and procuement activities)TPC' ($) - Includes Owner's Costs = CECC + B1 258,546,000$ Total project cost without AFUDCTPC' ($/kW) - Includes Owner's Costs364Total project cost per kW without AFUDCB2 = 10% of (CECC + B1)25,855,000$ AFUDC (Based on a 3 year engineering and construction cycle)C1 = if EPC = TRUE, 15% of (CECC+B1), else 0 38,782,000$ EPC fees of 15%TPC ($) = Includes Owner's Costs and AFUDC = CECC + B1 + B2 + C1 323,183,000$ Total project costTPC ($/kW) = Includes Owner's Costs and AFUDC 455Total project cost per kWFixed O&M CostFOMO ($/kW yr) = (8 operators)*2080*T/(A*1000) 1.41$ Fixed O&M additional operating labor costsFOMM ($/kW yr) =(BM*0.015)/(B*A*1000)4.12$ Fixed O&M additional maintenance material and labor costsFOMA ($/kW yr) = 0.03*(FOMO + 0.4*FOMM) 0.09$ Fixed O&M additional administrative labor costsFOM ($/kW yr) = FOMO +FOMM+FOMA5.62$ Total Fixed O&M costsAux PowerInclude in VOM?
Variable O&M CostVOMR ($/MWh) = K*P/(A*J)/980.18$ Variable O&M costs for limestone reagentVOMW ($/MWh) = L*Q/(A*J)/980.10$ Variable O&M costs for waste disposalVOMP ($/MWh) = M*R*100.77$ Variable O&M costs for additional auxiliary power required including additional fan power (Refer to Aux Power % above)VOMM ($/MWh) = N*S/A0.05$ Variable O&M costs for makeup waterVOM ($/MWh) = VOMR + VOMW + VOMP + VOMM 1.09$ Total Variable O&M costsAnnual Capacity Factor = 100%Annual MWhs = 6,219,600 Annual Heat Input MMBtu = 60,952,080 Annual Tons SO2 Created = 12,190 at 100% S conversionAnnual Tons SO2 Removed = 6,095 at removal efficiency = 50%Annual Tons SO2 Emission = 6,095 Annual Avg SO2 Emission Rate, lb/MMBtu = 0.200 Value is AT or ABOVE a 0.06 floor rateAnnual Capital Recovery Factor = 0.094Wet FGDAnnual Capital Cost (Including AFUDC), $ = 30,508,000 Annual FOM Cost, $ = 3,988,000 Annual VOM Cost, $ = 6,810,000 Total Annual SCR Cost, $ = 41,306,000 Capital Cost, $/MWh = 4.91FOM Cost, $/MWh = 0.64VOM Cost, $/MWh = 1.09Total SCR Cost, $/MWh = 6.64Capital Cost, $/ton = 5,005 FOM Cost, $/ton = 654 VOM Cost, $/ton = 1,117 Total SCR Cost, $/ton = 6,777 Lookup TableCoal Coal Factor1 PRB 1.052 Lignite 1.073 Bituminous1Aux PowerTRUE

APPENDIX G
Tables 2.10 thru 2.13, Appendix K
New Hampshire Regional Haze Plan Periodic
Comprehensive Revision
(DRAFT 10/31/2019)

2-14

Table 2.8 IPM v5.13 Cost and Performance Assumptions for Coal to Gas Conversions

Factor Assumption Description
Heat Rate Penalty +5% Lower stack temperature and higher moisture loss
reduces efficiency
Incremental Capital
Cost
PC Unit: $/kW = 267*(75/MW)^0.35
Cyclone Unit: : $/kW = 374*(75/MW)^0.35
New gas burners, piping, air heater upgrade, gas
recirculating fans, and control system
modifications.
Incremental Fixed
O&M
-33% of the FOM cost of the existing coal unit Reduced need for maintenance materials and
labor.
Incremental Variable
O&M
-25% of the VOM cost of the existing coal unit Reduced waste disposal and other miscellaneous
costs.
Table reference: Table 5-21, EPA, 2013.

EPA also developed estimates of the cost of extending pipeline laterals from each coal-fired
boiler to the interstate national gas pipeline system. Their analysis included a number of factors
including:

 Mainline pipeline flow capacity
 Required lateral capacity based on heat rate and boiler capacity
 Diameter of each lateral (calculated using the Weymouth equation)
 Cost per lateral ($90,000 per inch-mile based on recently completed projects)

Based on data for 1,208 coal-fired units EPA calculated an average cost per boiler of $341/kW of
capacity. The distribution of lateral costs is shown in Figure 2.2.

Figure 2.2 Lateral Pipeline Costs per kW of Boiler Capacity

Source: Figure 5-7; EPA, 2013.