Technical Support Document (TSD)
for the Final Federal Good Neighbor Plan for the 2015 Ozone National Ambient Air Quality
Standards
Docket ID No. EPA-HQ-OAR-2021-0668
EGU NOx Mitigation Strategies Final Rule TSD
U.S. Environmental Protection Agency
Office of Air and Radiation
March 2023
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A. Introduction: 2
B. Optimizing and Restarting Existing SCRs 3
1. Cost Estimates for Optimizing and Restarting Existing SCRs 3
2. NOx Emission Rate Estimates for Full Operation of Existing SCRs 9
C. Installing State-of-the-Art Combustion Controls 17
1. Cost Estimates for State-of-the-Art Combustion Control Upgrade 17
2. NOx Emission Rate Estimates for State-of-the-Art Combustion Control Upgrade 19
D. Cost Estimates for Optimizing and Restarting and Optimizing Idled Existing SNCR 21
E. Cost and Emission Rate Performance Estimates for Retrofitting with SNCR and Related Costs 25
F. Cost and Emission Rate Performance Estimates for Retrofitting with SCR and Related Costs 27
G. Feasibility Assessment: Implementation Timing for Each EGU NOx Control Strategy 30
H. Additional Mitigation Technologies Assessed but Not Included in this Action 37
1. Combustion Control and SCR Retrofits on Combined Cycle and Combustion Turbine Units 37
2. Mitigation Strategies at Small Units that Operate on High Electricity Demand Days (HEDD) 37
Appendix A: Historical Anhydrous Ammonia and Urea Costs and their Associated Cost per NOx ton
Removed in a SCR 44
Appendix B: Cost Sensitivity Analysis for SCR/SNCR Optimization and SCR Retrofit 45
A. Introduction:
The analysis presented in this document supports the EPA's final Federal Good Neighbor Plan for the
2015 Ozone National Ambient Air Quality Standards. In developing this final rule, the EPA considered
all NOx control strategies that are widely in use by EGUs, listed below. This Technical Support
Document (TSD) discusses costs, emission reduction potential, and feasibility related to these EGU NOx
emission control strategies. Specifically, this TSD explores three topics: (1) the appropriate representative
cost resulting from "widespread" implementation of a particular NOx emission control technology; (2) the
NOx emission rates widely achievable by "fully operating" emission control equipment; and (3) the time
required to implement these EGU NOx control strategies (e.g., installing and/or restoring an emission
control system to full operation). These analyses inform the EPA's evaluation of costs and emission
reductions in Step 3 of its four step interstate transport framework.
NOx control strategies that are widely available for EGUs include:
• Returning to full operation any existing SCRs that have operated at fractional design capability;
• Restarting inactive SCRs and returning them to full operation;
• Restarting inactive SNCRs and/or returning to full operation any SNCRs that have operated at
fractional design capability;
• Upgrading combustion controls with newer, more advanced technology (e.g., state-of-the-art low
NOx burners);
• Installing new SCR systems;
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• Installing new SNCR systems; and
• Shifting generation (i.e., changing dispatch) from high- to low-emitting or zero-emitting units.1
To evaluate the cost for some of these EGU NOx reduction strategies, the agency used the capital
expenses, fixed and variable operation and maintenance costs for installing and fully operating emission
controls based on the cost equations used within the Integrated Planning Model (IPM) that were
researched by Sargent & Lundy, a nationally recognized architect/engineering firm with EGU sector
expertise.2 From this research, EPA has created a publicly available Excel-based tool called the Retrofit
Cost Analyzer (Update 1-26-2022) that implements these cost equations.3 Application of the Retrofit Cost
Analyzer equations to the existing EGU fleet can be found in the docket.4
The costs presented in the TSD are in 2016 dollars, unless otherwise noted. For some cost estimates, EPA
provides multiple statistics to describe the cost. These include: the "emission weighted average," which is
the total cost of the mitigation strategy applied to the applicable units divided by the total tons of NOx
reduced; the "median," which is the cost of the mitigation strategy at the median, or 50th percentile, unit:
and the "90th percentile", which is the cost of the mitigation strategy at the 90th percentile unit.
B. Optimizing and Restarting Existing SCRs
1. Cost Estimates for Optimizing and Restarting Existing SCRs
Coal Steam:
EPA examined costs for full operation of SCR controls for units that already have this technology
installed. SCR systems are post-combustion controls that reduce NOx emissions by reacting the NOx with
a reagent (typically ammonia or urea). The SCR technology utilizes a catalyst to increase the conversion
efficiency and produces high conversion of NOx. Overtime with use, the catalyst will degrade and
require replacement. The ammonia or urea reagent is also consumed in the NOx conversion process. Fully
operating an SCR includes maintenance costs, labor, auxiliary power, catalyst, and reagent cost. The
1 For reasons explained in Section V.B.I.f of the preamble, the final rule does not incorporate emissions reductions
from generation shifting as a control strategy informing the Step 3 determination of "significant contribution," and
this strategy is not further analyzed in this document.
2 The underlying equations come from data and information in the following reports:
• "IPM Model - Updates to Cost and Performance for APC Technologies: SCR Cost Development
Methodology for Coal-fired Boilers" (February 2023) ("Coal-Fired SCR Cost Methodology" for short)
• "IPM Model - Updates to Cost and Performance for APC Technologies: SNCR Cost Development
Methodology for Coal-fired Boilers" (February 2023) ("Coal-Fired SNCR Cost Methodology" for short)
• "IPM Model - Updates to Cost and Performance for APC Technologies: SCR Cost Development
Methodology for Oil/Gas-fired Boilers" (February 2023) ("Gas-Fired SCR Cost Methodology" for short)
• "IPM Model - Updates to Cost and Performance for APC Technologies: SNCR Cost Development
Methodology for Oil/Gas-fired Boilers" (February 2023) (" Gas-Fired SNCR Cost Methodology" for short)
• "Combustion Turbine NOx Technology Memo" (January 2022) EPA-HQ-OAR-2021-0668-0085
• "Typical SCR and SNCR Schedule (Coal or Oil/Gas boilers)" (February 2023)
3 See https://www.epa.gov/airmarkets/retrofit-cost-analvzer for the "Retrofit Cost Analyzer (Update 1-26-2022)"
Excel tool. EPA-HQ-OAR-2021-0668-0118
4 See the file "Retrofit Cost Tool Fleetwide Final GNP" for detailed cost estimates using the Retrofit Cost Analyzer
for SCR and SNCR operation and installation. For consistency, EPA did not update the fleet included in this tool
from the version of the proposal, with the exception of correcting that the following three units do not have SNCR:
Sikeston 1 and Whitewater Valley 1 & 2.EPA did however conduct a sensitivity analysis (see appendix B) that
determined the small changes to the fleet would not have impacted any of the costs for SCR and SNCR operation
and installation. See Appendix B.
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chemical reagent (typically ammonia or urea) is a significant portion of the operating cost of these
controls. For a unit with an idled, bypassed, or mothballed SCR, all fixed operating and maintenance
(FOM) and variable operations and maintenance (VOM) costs such as auxiliary fan power, catalyst costs,
and additional administrative costs (labor) are realized upon resuming operation through full potential
capability.
EPA examined the costs to fully operate an SCR that was already being operated to some extent and the
costs to restart and fully operate an SCR that had been idled using the equations within the Retrofit Cost
Analyzer. There are VOM costs related to the consumption of reagent and degradation of the catalyst as
well as FOM costs related to maintaining and operating the equipment to be considered that pertain to
these two situations.
EPA examined three of the VOM costs illustrated in the Retrofit Cost Analyzer: reagent, catalyst, and
auxiliary power. Depending on circumstances, SCR operators may operate the system while achieving
less than "full" removal efficiency by using less reagent, and/or not replacing degraded catalyst which
allows the SCR to perform at lower reduction capabilities. For units where the SCR has been idled, there
would be no reagent or catalyst utilized. Consequently, the EPA finds it reasonable to include the costs of
both additional reagent and catalyst maintenance and replacement in representing the cost of optimizing
operating SCR systems and also to include these costs for restarting idled systems. In contrast, based on
the Retrofit Cost Analyzer equations, the auxiliary power component of VOM is largely indifferent to the
NOx removal. That is, auxiliary power is indifferent to reagent consumption, catalyst degradation, or NOx
removal rate. Therefore, for units where the SCR is operating, but may not be fully operating, the
auxiliary power VOM component has likely been incurred. For units where the SCR has been idled, this
cost component needs to be accounted for when assessing the cost to restart and fully optimize the SCR
control.
In addition, based on the Retrofit Cost Analyzer equations for FOM, units running their SCR systems
have incurred the complete set of FOM costs, regardless of reagent consumption, catalyst degradation, or
NOx removal rate. Thus, as was the case for the auxiliary power VOM cost component, the FOM cost
component is also not included in the cost estimate to achieve "full" operation for units that are already
operating. For units where the SCR has been idled, all the FOM costs would need to be accounted for
when assessing the cost to restart and fully optimize the SCR control. In conclusion, EPA finds that only
the VOM reagent and catalyst replacement costs should be included in cost estimates for optimization of
partially operating SCRs, while the full suite of VOM and FOM costs should be included when assessing
the cost to restart and fully optimize the SCR control. EPA assessed these costs using both representative
units as well as assessment of the existing fleet of EGUs with these controls.
In an SCR, the chemical reaction consumes approximately 0.57 tons of ammonia or 1 ton of urea reagent
for every ton of NOx removed. During development of the Clean Air Interstate Rule (CAIR) and the
original CSAPR, the agency identified a marginal cost of $500/ton of NOx removed (1999$) with
ammonia costing $190/ton of ammonia, which equated to $108/ton of NOx removed for the reagent
procurement portion of operations. The remaining balance reflected other operating costs. Over the years,
reagent commodity prices have changed, affecting the operational cost in relation to reagent procurement.
For data on the relationship between reagent price and its associated cost regarding NOx reduction, see
Appendix A: "Historical Anhydrous Ammonia and Urea Costs and their Associated Cost per NOx ton
Removed in a SCR." These commodities are created in large quantities for use in the agriculture sector.
Demand from the power sector for use in pollution controls is small relative to the magnitude used in
agriculture. Fluctuations in price are expected and are demonstrated in the pricing data presented in
Appendix A. Some of these prices reflect conditions where demand and commodity prices are high.
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Consequently, the reagent costs used by EPA in this final rule are representative. In the cost estimates
presented here, EPA uses the cost for urea, which is greater than ammonia costs, to arrive at a reasonable
estimate. In the CSAPR Update, EPA used the default cost of $310/ton for a 50% weight solution of urea
in the Retrofit Cost Analyzer. With the updates to the Retrofit Cost Analyzer, the default costs of the urea
reagent also increased to $350/ton for a 50% weight solution of urea. In this action, considering the most
recent updates to the Retrofit Cost Analyzer, EPA assumed the cost of $350/ton for a 50% weight
solution of urea. Using the Retrofit Cost Analyzer (multiplying the VOM $/ton cost by the ratio of the
VOM cost for urea $/MWh to the total VOM cost $/MWh) results in a cost of around $500/ton of NOx
removed for the reagent cost alone.
Urea prices in 2022 were elevated well above the historic norm because of a variety of factors including:
offline production capacity, relatively high natural gas prices (the key component for urea
manufacturing), and the war in Ukraine. EPA expects that the costs will revert to the historic mean trend
overtime because supply chain issues will be resolved, natural gas prices will decrease, and if necessary,
additional production capacity will be developed. In fact, the March 2023 EIA Short Term Energy
Outlook forecasted the average 2023 Henry Hub natural gas price to be $3.02/MMBtu and the average
Henry Hub price in January and February 2023 was $2.83/MMBtu.5 Therefore, it is reasonable to
continue to use $350/ton as the cost for urea, particularly for the purposes of long-term analysis.
Additionally, EPA performed a sensitivity analysis on the impact of urea price on the dollar-per-ton cost
of NOx removal for SCR/SNCR retrofit and optimization, which can be found in Appendix B "Cost
Sensitivity Analysis for SCR/SNCR Optimization and SCR Retrofit." The results of that sensitivity
analysis yield cost levels that EPA would still find cost-effective for the purposes of this rule."
EPA also estimated the cost of catalyst replacement and disposal in addition to the costs of reagent. EPA
identified the cost for returning a partially operating SCR to full operation applying the Retrofit Cost
Analyzer equations for all SCR-controlled coal-fired units that operated in 2021 in the United States on a
per ton of NOx removed basis. EPA updated the set of units based on the NEEDS database (October
2021). This assessment covered 226 units.6 EPA focused on a subset of 172 units that had minimum
"input" NOx emission rates of at least 0.14 lb/MMBtu).7 Here, EPA defines the term "input" NOx rate, or
"uncontrolled" NOx rate to be the emission rate of the unit following the combustion process including
the effects of all existing combustion controls, measured after it has left the boiler, and where it would
enter any post-combustion control equipment (if any). EPA used 0.14 lb/MMBtu because it found that, as
described in the combustion control evaluation of this document (Figure C.3), that depending on unit type
and fuel use, units emitting above that rate may have only state of the art combustion controls installed.
Input NOx rates below the 0.14 lb/MMBtu rate suggest that the SCR may have been operating to some
extent, thereby biasing the cost estimates. EPA was able to identify the costs of each of the individual
VOM and FOM cost components, including reagent, catalyst, and auxiliary fans and thereby, for each
unit, to estimate the costs to fully optimize an SCR assuming it is currently operating to some extent and
5 As of February 28th, 2023, Henry Hub natural gas prices was $2.50/MMBtu. In the first two months of 2023, the
ranged between $2.07/MMBtu and $3.78/MMBtu, with the average daily price being $2.83/MMBtu. Urea prices, as
reported in the February 23, 2023 Illinois Production Cost Report (See Appendix A) had dropped to $655/ton from
the July 2022 price of $895/ton (and a 2022 high of $1027/ton). Other metrics for urea prices have shown greater
declines. For example, the price for granular Urea FOB Gulf Coast futures for May 2023 (the start of the 2023 ozone
season) have dropped from a high of $692 to about $320 on February 28, 2023.
6 See the "Retrofit Cost Tool Fleetwide Final GNP"
7 A NOx emission rate at or above 0.2 lb/MMBtu, and possibly as low as 0.14 lb/MMBtu for some plant
configurations, may be indicative of emissions from units where the SCR is not operating at all (See the discussion
about state-of-the-art combustion controls).
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to restart and fully optimize an SCR assuming it currently has been idled. Some of these expenses, as
modeled by the Retrofit Cost Analyzer, vary depending on factors such as unit size, NOx generated from
the combustion process, and reagent utilized. The EPA performed multiple assessments with this tool's
parameters to investigate sensitivity relating to cost per ton of NOx removed. Additionally, the agency
modeled costs with urea, the higher-cost reagent for NOx mitigation (and the reagent included in the
Retrofit Cost Analyzer equations). The key input parameters in the cost equations are the size of the unit,
the "input" NOx rate, the NOx removal efficiency, the type of coal, and the capacity factor.
In the analysis, we assumed these units burned the coal identified for the given unit in the NEEDS
database at a 56% capacity factor.8 We assumed that the SCRs operate with the NOx removal efficiency
needed for them to achieve the lower of their 2021 ozone season NOx rate or the coal steam SCR
optimized ozone season rate starting from the highest monthly NOx rate for the time-period 2009-2021.
This was selected as the "controlled" rate because it represented consistent and efficient operation of the
unit's SCR. For the input NOx rate, to identify an emission rate when the unit's SCR was not operating,
we identified each unit's maximum monthly emission rate from the period 2009-2021.9
To estimate the cost to return a partially operating SCR to full operation, EPA examined only the sum of
the VOM reagent and catalyst cost components and for these units, EPA ranked the quantified VOM costs
for each unit and identified the cost at the 90th percentile level rank, which rounded to $900/ton of NOx
removed. EPA selected the $900/ton value because a substantial portion of units had combined reagent
and catalyst costs at or less than this value of NOx removed.
To estimate the cost to restart and fully optimize an idled SCR, EPA ranked the sum of the VOM and
FOM costs for each unit and identified the 90th percentile cost. When rounded, this was $l,700/ton of
NOx removed. EPA also identified the emission weighted average cost, which also rounded to $900/ton
of NOx removed.
To further evaluate the costs for returning a partially operating control to full operation and for restarting
a unit with an idled SCR, EPA applied the Retrofit Cost Analyzer equations for two "typical" units with
varying input NOx rates in a bounding analysis. The EPA used this to identify reasonable high and low
per-ton NOx control costs from reactivating an existing but idled SCR across a range of potential input
NOx rates.10 For a hypothetical 500 MW unit with a relatively high input NOx rate (e.g., 0.4 lb
NOx/MMBtu, 80% removal efficiency, 56% capacity factor, and 10,000 Btu/kWh heat rate), The urea
and catalyst costs were around $660/ton. The full VOM and FOM costs associated with restarting an idled
control were around $950/ton of NOx removed. Conversely, a unit with a lower input NOx rate (e.g., 0.14
lb NOx/MMBtu and 60% removal) experienced a higher cost range revealing a urea and catalyst cost of
$l,150/ton. The full VOM and FOM costs associated with restarting an idled control were around
$2,220/ton of NOx removed.
Considering the fleetwide assessment and the bounding analysis, for coal-steam units with SCR, EPA
concludes that $900/ton NOx removed represents a reasonable estimate of the cost for operating SCR
8 EPA evaluated costs of SCR operation at coal steam units utilizing the projected capacity factor in the 2030 run
year of the Air Quality Modeling Base Case for the final rule for all operating coal steam units in the fleet, excluding
circulating fluidized bed units, which would retrofit SNCR and not SCR.
9 For units where controls have always operated year-round, this method will likely underestimate the input NOx
rate.
10 For these hypothetical cases, the "uncontrolled" NOx rate includes the effects of existing combustion controls
present (e.g., low NOx burners).
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post-combustion controls on coal steam units that are already operating to some extent based on current
market prices and typical operation.
Considering the fleetwide assessment and the bounding analysis, for coal-steam units with SCR, and the
analysis conducted for the Revised CSAPR Update (RCU), the EPA concludes that a cost of $l,600/ton
of NOx removed is a representative cost for the point at which restarting and fully operating idled SCRs
becomes widely available to EGUs. EPA notes that most units identified as having SCR optimization
potential are already partially operating and best reflected by the $900/ton optimization cost for partially
operating units rather than this $l,600/ton cost for fully idled units.
Oil/Gas Steam:
For existing oil/gas steam units with existing SCR controls, EPA conducted a similar fleetwide
assessment to that done for coal-steam units using the Retrofit Cost Tool.11 We assumed these units
burned the fuel identified in the NEEDS database at a 26% capacity factor.12 We assumed that the SCRs
operate with the NOx removal efficiency needed for them to achieve the lower of their 2021 ozone season
NOx rate or the oil/gas steam SCR optimized ozone season rate starting from the highest monthly NOx
rate for the time-period 2009-2021. This was selected as the "controlled" rate because it represented
consistent and efficient operation of the unit's SCR. For the input NOx rate, to identify an emission rate
when the unit's SCR was not operating, we identified each unit's maximum monthly emission rate from
the period 2009-2021.13
To estimate the cost to return a partially operating SCR to full operation we examined only the sum of the
VOM reagent and catalyst cost components, while to assess the costs to restart and fully optimize an idled
SCR the full VOM and FOM costs were assessed. In this section, from the full set of existing oil/gas
steam unit, we focused on a subset of 16 units (of 20 existing oil/gas steam units with SCR) that had
minimum "input" NOx emission rates of at least 0.14 lb/MMBtu. EPA ranked the quantified VOM costs
for each unit and identified the cost at the 90th percentile level rank, which rounded to $500/ton of NOx
removed.
To estimate the cost to restart and fully optimize an idled SCR, EPA ranked the sum of the VOM and
FOM costs for each unit and identified the 90th percentile cost. When rounded, this was $l,000/ton of
NOx removed. We also identified an emission weighted average cost of $700/ton. EPA concludes that
$500/ton is a representative cost for units to optimize an SCR for an oil/gas steam unit that is currently
operating its control to some extent while $700/ton NOx removed is a representative cost to restart an
idled SCR on oil/gas steam units based on current market prices and typical operation.
Combined Cycle and Combustion Turbine:
Considering SCR controls for other types of units (i.e., combined cycle and combustion turbines), EPA
notes that these units would have similar operational costs to oil/gas steam units because most of the
additional cost would be for reagent, which is directly proportional to the number of tons removed.
11 See the "Retrofit Cost Tool Fleetwide Final GNP."
12 EPA evaluated costs of SCR operation at oil/gas steam units utilizing the same capacity factor of 26% as used in
the proposed rule for clarity and consistency. For the 2030 run year of the Air Quality Modeling Base Case, the
projected capacity factor for all operating O/G Steam units in the fleet was slightly lower at 25%. These costs of
optimizing existing SCR on O/G steam units do not change meaningfully if a capacity factor of 25% rather than
26% is used.
13 For units where controls have always operated year-round, this method will likely underestimate the input NOx
rate.
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Consequently, the costs to fully optimize an SCR that is already operating to some extent and the cost to
restart and fully optimize an idled SCR would be comparable to that for oil/gas steam.
Summary:
Thus, considering the cost estimates for coal, oil/gas steam, combined cycle, and combustion turbines,
EPA concludes that $900/ton NOx removed represents a reasonable estimate that encompasses the cost
for fully operating SCR controls that are current operating to some extent across all affected EGU types
based on the historical trend of market prices and typical operation. Similarly, for coal-steam, oil/gas
steam units, combined cycle units, and combustion turbines the costs to restart and fully operate existing
idled SCRs is typically less than $l,600/ton. Thus, EPA finds it reasonable to assume that all of these
technologies will fully operate at this cost level. Additionally, EPA conducted cost sensitivities
considering urea price, coal type, and fleet updates, which can be found in Appendix B.
In summary, EPA assumes that $900/ton of NOx removed is a broadly available cost point for units that
currently are partially operating SCRs to fully operate their NOx controls while $l,600/ton of NOx
removed is a broadly available cost point for units to restart and fully operate existing idled SCR.
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2. NOx Emission Rate Estimates for Full Operation of Existing SCRs
Coal Steam:
EPA examined the ozone season average NOx rates for 176 coal-fired units in the contiguous U.S. with
an installed SCR over the time-period 2009-2021, then identified each unit's lowest, second lowest, and
third-lowest ozone season average NOx rate.14 EPA updated the set of units based on the NEEDS
database (October 2021). EPA examined ozone season average NOx rates from 2009 onwards as this year
marks the point at which annual NOx programs, rather than just seasonal programs, became widespread in
the eastern US with the start of CAIR in 2009. EPA captured this dynamic with its baseline choice as this
regulatory development could affect SCR operation (specifically, annual use of SCR means more frequent
change of catalyst and relative difficulty with scheduling timing when the unit (or just the SCR) is not
operating to allow for catalyst replacement and SCR maintenance).
The CSAPR Update and Revised CSAPR Update focused on the third-lowest ozone season NOx rates
achieved since 2009, reasoning that these emission rates are characteristic of a well-run and well-
maintained system and achievable on a routine basis. At that time, 2019 represented the most recent year
of full ozone-season data available. In the Revised CSAPR Update, EPA found that, between 2009 and
2019, EGUs on average achieved a rate of 0.079 lb NOx/MMBtu for the third-lowest ozone season rate.
Furthermore, EPA verified that in years prior to 2019, more than 95% of these same coal-fired units with
identified optimization-based reduction potential in the Revised CSAPR Update had demonstrated and
achieved a NOx emission rate of 0.08 lb/MMBtu or less on a seasonal and/or monthly basis.15 In the
Revised CSAPR Update, EPA selected 0.08 lb NOx/MMBtu as a reasonable representation for full
operational capability of an SCR.
For this final rule, EPA utilizes the same rationale and methodology for identifying the rate that it did
with the Revised CSAPR Update. As in prior rules, EPA assigns this rate as a "ceiling" on those units
with SCR optimization potential, while generally assigning to SCR-equipped units emissions rates
commensurate with actual historical performance. In other words, if an SCR-equipped EGU demonstrated
achievement of an emission rate below 0.08 lb/MMBtu, that rate was assigned to the unit in the budget-
setting process. EPA maintains that the timeline should include most-recent operational data (i.e., up
through 2021) and continue to extend back to 2009. Considering the emissions data over the full time-
period of available data that includes expected annual operation of SCRs at coal steam units (i.e., 2009-
2021) results in an equal weighted unit-average third-best rate of 0.071 lb/MMBtu.16 EPA notes that half
of the EGUs achieved a rate of 0.064 lb NOx/MMBtu or less over their third-best entire ozone season (see
Figure B. 1). EPA verified that in years prior to 2021, the majority (over 90%) of these same coal-fired
units with identified optimization-based reduction potential in this rule had demonstrated and achieved a
NOx emission rate of 0.08 lb/MMBtu or less on a seasonal and/or monthly basis.17
After identifying this approach, the Agency examined each ozone season over the time period from 2009-
2021 and identified the lowest monthly average NOx emission rates for each year. Examining the third-
lowest historical monthly NOx rate, the EPA found that, on average EGUs achieved a rate of 0.062 lb
14 See "Historical NOx Seasonal Emission Rates for Units with SCR Final" for details.
15 See "Optimizing SCR Units with Best Historical NOx Rates Final" in the docket for this rulemaking. (EPA-HQ-
OAR-2021 -0668-0116)
16 See "Historical NOx Seasonal Emission Rates for Units with SCR Final" for details.
17 See "Optimizing Coal Steam SCR Units with Best Historical NOx Rates Updated to 2021 Final" in the docket for
this rulemaking
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NOx/MMBtu. The third-lowest historical monthly NOx rate analysis showed that a large proportion of
units displayed NOx rates below 0.08 lb/MMBtu (see Figure B.2).
EPA also considered if the analysis should be specific to coal rank, among other factors. The average for
bituminous coal units increased to 0.074 lb/MMBtu, while the average rate for subbituminous units
decreased to 0.068 lb/MMBtu. These rates are relatively similar and therefore coal type is not an
important factor when choosing a widely achievable NOx rate for an optimized SCR on coal steam units.
Figure B.l. "Frequency" distribution plots for coal-fired units with an SCR showing their seasonal
average NOx emission rates (lb/MMBtu) during ozone seasons from 2009-2021. For each unit, the
lowest, second lowest, and third lowest ozone season average NOx rates are illustrated.
Three Lowest Seasonal Average Ozone-Season NOx Rates (2009 -
2021, for coal steam units with SCR)
¦ lowest (0.060 Ibs/MMBtu avg)
¦ 2nd lowest (0.065 Ibs/MMBtu avg)
¦ 3rd lowest (0.071 Ibs/MMBtu avg)
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NOx Rate (Ibs/MMBtu
Figure B.2. "Frequency" distribution plots for coal-fired units with an SCR showing their monthly
average NOx emission rates (lb/MMBtu) during ozone seasons from 2009-2021. For each unit, the
lowest, second lowest, third lowest, fourth lowest, and fifth lowest monthly average NOx rates are
illustrated.
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Five Lowest Monthly Average Ozone-Season NOx Rates (2009 - 2021,
for coal steam units with SCR)
¦ lowest (0.048 Ibs/MMBtu avg)
¦ 2nd lowest (0.057 Ibs/MMBtu avg)
¦ 3rd lowest (0.062 Ibs/MMBtu avg)
¦ 4th lowest (0.066 Ibs/MMBtu avg)
¦ 5th lowest (0.071 Ibs/MMBtu avg)
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NOx Rate (Ibs/MMBtu)
Not only has the group of units with SCR optimization potential demonstrated they can perform at or
better than the 0.08 lb/MMBtu rate on average, but more than 90 percent of the individual units in this
group have met this rate on a seasonal and/or monthly basis based on their reported historical data. As an
example, Miami Fort Unit 7 was able to improve the performance of the SCR at its coal unit (consistent
with optimization assumptions) in the first year of CSAPR Update implementation (2017) and again in
the first period of the Revised CSAPR Update implementation (2021) when the updated budgets created
an incentive through higher allowance prices, (see Figure B.3)
Figure B.3. Example of Unit-level Emissions Rate Changes at a Given Capacity Factor Range.
Miami Fort Unit 7 Ozone Season Mid- to High-Load NOx Rates
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400
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300
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200
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100
o
0
capacity factor 60-(
=P
capacity factor 70-79%
i 4- ;
2017
2019
2021
2017
2019
2021
capacity factor 50-59%
capacity factor 60-69%
capacity factor 70-79%
2017
2019
2021
2017
2019
Year
2021
2017
2019
2021
EPA observed this pattern in other units identified in this rulemaking as having significant SCR
optimization emissions reduction potential. For instance, nearly 90% of the coal units identified as having
11
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reduction potential from its existing SCR in 2021 had operated at an emission rate lower than the 0.08
lb/MMBtu optimized rate in prior years. In the Emissions Data TSD for the supplemental notice that EPA
released in a proceeding to address a recommendation submitted to EPA by the Ozone Transport
Commission under CAA section 184(c), EPA noted, "In their years with the lowest average ozone season
NOx emissions rates in this analysis, these EGUs had relatively low NOx emissions rates at mid- and
high-operating levels; moreover, there was little variability in NOx emissions rates at these operating
levels. However, during the 2019 ozone season, these EGUs had higher NOx emissions rates and greater
variability in NOx emissions rates across operating levels than in the past, particularly at mid-operating
levels."18
Finally, some stakeholders have suggested that maintaining emissions rates characteristic of optimized
SCR performance is difficult in an environment where coal units are dispatching less, often citing that the
catalyst in SCRs needs to be at a minimum operating temperature to function. This can be addressed
through a variety of means such as adding supplemental heaters; removing less heat from the exhaust gas
for preheating combustion air or boiler feedwater; or using a catalyst designed for a lower minimum
operating temperature. Units can also adjust their cycling patterns to ensure the unit operates at the
minimum temperature needed for SCR use.
EPA's review of hourly data indicates that maintaining consistent SCR performance at lower capacity
factors is possible. For example, the unit-level performance data in Figure B.4 show the emissions rate at
a plant, Brandon Shores, staying relatively low (consistent with our optimization assumption of 0.08
lb/MMBtu) and stable across a wide range of capacity factors. The use of the fleetwide average rate
computed using each unit's third best year to derive the SCR optimization rates further accommodates
any heterogeneity in emissions rate that may stem from a unit's operational decisions such as capacity
factor or coal-rank choice. Moreover, Figure B.3 illustrates that historical data from Miami Fort Unit 7
that similarly demonstrates that variation in emission rate - illustrated in the sharp 2019 increase - is not
correlated with capacity factor.
A second example from 2022 illustrates that cycling units do have the ability to adjust cycling patterns in
a manner that enables them to maintain a lower emissions rate throughout the season while still achieving
a load cycling pattern at the unit. Conemaugh unit 2 raised its minimum overnight load from the 2021
ozone season to 2022, which allowed for operation of its SCR. This coincided with a period of higher
NOx allowance prices than previous years. The hourly unit-level gross load and NOx rate for Conemaugh
unit 2 for the 2021 and 2022 ozone seasons is shown in Figure B.5.19 In both ozone seasons, the unit often
cycled daily between its maximum load of approximately 900 MW during the daytime and a lower load
level overnight, and in both ozone seasons the unit's typical daytime emissions rate was between 0.05 and
0.07 lb/mmBtu. However, while in the 2021 ozone season, the unit cycled down to a load level of
approximately 440 MW overnight and did not operate its SCR, in the 2022 ozone season, when allowance
prices were considerably higher, the unit cycled down to a load level of approximately 540 MW overnight
and did operate its SCR. Despite the higher nighttime generation levels, the result was a decrease of
roughly 50% in the unit's seasonal average NOx emissions rate, from approximately 0.14 lb/mmBtu to
approximately 0.07 lb/mmBtu, and a comparable reduction in NOx mass emissions.
18 See "Analysis of Ozone Season NOx Emissions Data for Coal-Fired EGUs in Four Mid-Atlantic States" (Docket
#: EPA-HQ-OAR-2020-0351) available at https://www.regnlations.gov/docnment/EPA- '20-0351-0004
19 See "Conemaugh and Keystone unit 2021 to 2022 Hourly Ozone Season Data" in the docket.
12
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Figure B.4. Example of Consistently Low Unit-level Emissions Rate During Periods of Varying Capacity
Factor
Brandon Shores
14 7 101316192225283134374043464952555861646770
HOUR
-Average Capacity Factor
-Average IMOx Rate
Figure B.5. Example of Increased Minimum Overnight Load to Enable Overnight Use of SCR.
0.45
0.40
0.35
2 0.30
| 0.25
5 0.20
£ 0.15
0.10
0.05
0.00
1,000
800
600
400
200
0
Conemaugh 2: May-September 2021 Hourly NOx Rate
lfl
500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
Hour of Ozone Season
Conemaugh 2: May-September 2021 Hourly Gross Load
fill
1,500 2,000 2,500
Hour of Ozone Season
3,000 3,500 4,000
Conemaugh 2: May-September 2022 Hourly NOx Rate
0.45
0.40
035
B 0 30
| 0.25
5 0.20
=2 0.15
0.10
0.05
0.00
1,000
800
600
400
200
0
rwiljjtipU
500 1,000 1,500 2,000 2,500 3,000 3,500 4,000
Hour of Ozone Season
Conemaugh 2: May-September 2022 Hourly Gross Load
Ml
1500 2000 2500
Hour of Ozone Season
13
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Based on all of the factors above, including the seasonal and monthly findings in Figures B. 1 and B.2, the
agency concludes an emission rate of 0.08 lb NOx/MMBtu is widely achievable by the portion of the
coal-fired EGU fleet with SCR optimization potential identified.
Oil/Gas Steam:
EPA conducted a similar analysis for oil/gas steam units. EPA examined the ozone season average NOx
rates for 23 oil/gas steam units in the contiguous U.S. with an installed SCR over the time-period 2009-
2021 and calculated an equal weighted unit-average third-best rate of 0.03 lb/MMBtu.2" EPA notes that
half of these EGUs achieved a rate of 0.014 lb NOx/MMBtu or less over their third-best entire ozone
season (see Figure B.5). EPA verified that in years prior to 2021, the majority (approximately 60%) of
these same oil/gas steam units with identified optimization-based reduction potential in 2021 data had
demonstrated and achieved a NOx emission rate of 0.03 lb/MMBtu or less on a seasonal and/or monthly
basis; all such units had achieved a NOx emission rate of 0.05 lb/MMBtu or less on a seasonal and/or
monthly basis. Based on this analysis, the agency concludes an emission rate of 0.03 lb NOx/MMBtu is
widely achievable by the portion of oil/gas steam EGU fleet with SCR optimization potential identified.
Figure B.5. Frequency distribution plots for oil/gas steam units with an SCR showing their seasonal
average NOx emission rates (lb/MMBtu) during ozone seasons from 2009-2021. For each unit, the
lowest, second lowest, and third lowest ozone season average NOx rates are illustrated.
10
9
8
7
6
5
4
3
2
1
0
Three Lowest Seasonal Average Ozone-Season NOx Rates (2009 -
2021, for oil/gas steam units with SCR)
¦ lowest (0.020 Ibs/MMBtu avg)
¦ 2nd lowest (0.023 Ibs/MMBtu avg)
¦ 3rd lowest (0.026 Ibs/MMBtu avg)
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(approximately 50%) of these same combined cycle units with identified optimization-based reduction
potential in 2021 data had demonstrated and achieved a NOx emission rate of 0.012 lb/MMBtu or less on
a seasonal and/or monthly basis; all such units had achieved a NOx emission rate of 0.066 lb/MMBtu or
less on a seasonal and/or monthly basis. Based on this analysis, the agency concludes an emission rate of
0.012 lb NOx/MMBtu is widely achievable by the portion of combined cycle EGU fleet with SCR
optimization potential identified.
15
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Figure B.6. Frequency distribution plots for combined cycle units with an SCR showing their seasonal
average NOx emission rates (lb/MMBtu) during ozone seasons from 2009-2021. For each unit, the
lowest, second lowest, and third lowest ozone season average NOx rates are illustrated.
Three Lowest Seasonal Average Ozone-Season NOx Rates (2009 -
2021, for combined cycle units with SCR)
140
120
100
80
60
40
20
0
lowest (0.011 Ibs/MMBtu avg)
I 2nd lowest (0.011 Ibs/MMBtu avg)
I 3rd lowest (0.012 Ibs/MMBtu avg)
cO
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Figure B.7. Frequency distribution plots for combustion turbine units with an SCR showing their
seasonal average NOx emission rates (lb/MMBtu) during ozone seasons from 2009-2021. For each unit,
the lowest, second lowest, and third lowest ozone season average NOx rates are illustrated.
Three Lowest Seasonal Average Ozone-Season NOx Rates (2009 -
2021, for combustion turbine units with SCR)
¦ lowest (0.016 Ibs/MMBtu avg)
¦ 2nd lowest (0.018 Ibs/MMBtu avg)
¦ 3rd lowest (0.024 Ibs/MMBtu avg)
120
to
100
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3
80
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60
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40
2
20
0
C>- O- O-
NOx Rate (Ibs/MMBtu)
C. Installing State-of-the-Art Combustion Controls
1. Cost Estimates for State-of-the-Art Combustion Control Upgrade
Combustion control technology has existed for many decades. The technology generally limits NOx
formation during the combustion process by extending the combustion zone. Overtime, as the technology
has advanced, combustion controls have become more efficient at achieving lower NOx rates than those
installed years ago. Modern combustion control technologies routinely achieve rates of 0.20 - 0.25 lb
NOx/MMBtu and, for some units, depending on unit type and fuel combusted, can achieve rates below
0.16 lb NOx/MMBtu. Figure C.l shows average NOx rates from coal-fired units with various combustion
controls for different time periods.
17
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Figure C.l. Ozone Season NOx Rate (lb/MMBtu) Over Time for Coal-fired Units with Various
Combustion Controls*
NOx Control
For 2003 - 2008
For 2003 - 2008
For 2009-2020
For 209-2020
For 2021
For 2021
Technology
NOx Rate
Number of
NOx Rate
Number of
NOx Rate
Number of
(lb/MMBtu)
Unit-Years
(lb/MMBtu)
Unit-Years
(lb/MMBtu)
Unit-Years
Overfire Air
0.384
476
0.291
647
0.260
17
Low NOx Burner
Technology (Dry
Bottom only)
0.351
1,062
0.266
1,208
0.217
32
Low NOx Burner
Technology w/
Overfire Air
0.306
464
0.225
742
0.203
29
Low NOx Burner
Technology w/
Closed-coupled
OFA
0.266
341
0.219
361
0.162
14
Low NOx Burner
Technology w/
Separated OFA
0.222
451
0.187
635
0.151
24
Low NOx Burner
Technology w/
Closed-
0.207
460
0.166
886
0.138
52
coupled/Separated
OFA
Source: Clean Air Markets Program Data (CAMPD), campd.epa.gov, EPA, 2021
Current combustion control technology reduces NOx formation through a suite of technologies. Whereas
earlier generations of combustion controls focused primarily on either Low NOx Burners (LNB) or
Overfire Air (OFA), modern controls employ both, and sometimes include a second, separated overfire
air system. Further advancements in fine-tuning the burners and overfire air system(s) as a complete
assembly have enabled suppliers to obtain better results than tuning individual components. For this final
rule, the agency evaluated EGU NOx reduction potential based on upgrading units to modern combustion
controls. Combustion control upgrade paths are shown in Table 3-14 of the IPM version 6 Summer 2021
Reference Case documentation (see Chapters 3 and 5 of the IPM documentation for additional
information, and Table 2b below).24 The fully upgraded configuration for units with wall-fired boilers is
LNB with OFA. For units with tangential-fired boilers, the fully upgraded configuration is LNC3 (Low
NOx burners with Close-Coupled and Separated Overfire Air). For each unit, EPA's understanding of the
current NOx control configuration can be found in the "NOx Comb Control" column of the NEEDS v6
database file.25 EPA identified whether a unit has combustion control upgrade potential by comparing the
Mode 1 NOx Rate (lb/MMBtu) with the Mode 3 NOx Rate (lb/MMBtu) within NEEDS. If the Mode 3
value is lower than the Mode 1 value, then the unit's combustion control configuration does not match the
state-of-the-art configuration outlined in Figure C.2. For these units, EPA assumed a combustion control
24 See "Documentation for EPA's Power Sector Modeling Platform v6 using Updated Summer 2021 Reference
Case". EPA-HQ-OAR-2021-0668-0154. https://www.epa.gov/airmarkets/documentation-epas-power-sector-
modeling-platfonn-v6-summer-2021-reference-case: and
"Updated Summer 2021 Reference Case Incremental Documentation for the 2015 Ozone NAAQS
Actions."https://www.epa.gov/power-sector-modeling/supporting-documentation-2015-ozone-naaas-actions
25 See the NEEDS v.6 data file available in the docket and for download at https://www.epa.gov/airmarkets/national-
electric-energy-data-svstem-needs-v6
18
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upgrade is possible based on the technology configurations identified in the NOx post combustion control
column.
With the wide range of LNB configurations and furnace types present in the fleet, the EPA decided to
assess compliance costs based on an illustrative unit.26 The agency selected this illustrative unit because
its attributes (e.g., size, input NOx emission rate) are representative of the EGU fleet, and, thus, the cost
estimates are also representative of the EGU fleet. The EPA estimated costs for various combustion
control paths. The cost estimates utilized the equations found in Table 5-4 "Cost (2016$) of NOx
Combustion Controls for Coal Boilers (300 MW Size)" from Chapter 5 of the IPM 5.13 documentation.27
For these paths, EPA found that the cost ranges from $450 to $l,220/ton NOx removed ($2011). EPA
examined slightly lower capacity factors (i.e., 70%) and found the costs increased, to a range of $550 to
$l,460/ton. At lower capacity factors (i.e., 56%), costs increased to a maximum of $l,800/ton for one
type of installation. Examining the estimates for all the simulations, the agency finds that the costs of
combustion control upgrades for units operating in a baseload fashion are typically comparable to the
costs for returning a unit with an inactive SCR to full operation (i.e., $l,600/ton). Consequently, EPA
identifies $l,600/ton as the cost level where upgrades of combustion controls would be widely available.
2. NOx Emission Rate Estimates for State-of-the-Art Combustion Control Upgrade
EPA derived its performance rate assumptions for combustion control upgrade from an assessment of
historical data where EPA reviewed similar boiler configurations with fully upgraded combustion controls
and their resulting emission rates. Specifically, EPA examined two types of coal steam units: 1) dry-
bottom wall-fired boilers and 2) tangentially-fired boilers. EPA looked at the current rate of existing units
of each firing configuration and that already had state-of-the-art combustion controls (SOA CC). EPA
estimated the average 2021 ozone season NOx emission rates for all such units by firing type. EPA did
not include any units that had post-combustion controls installed as their historical rate would be
indicative of not just combustion control potential, but also post-combustion control potential. For dry
bottom wall-fired coal boilers with "Low NOx Burner" and "Overfire," there were 34 units averaging
0.204 lb/MMBtu.28 For tangentially-fired coal boilers with "Low NOx Burner" and "Closed-
coupled/Separated OFA," there were 48 units averaging 0.138 lb/MMBtu.
Next, EPA identified the current boiler type for each unit in the fleet. It then applied the information
shown below in Figure C.2 regarding state-of-the-art configurations compared to that unit's reported
combustion control figuration to determine whether the unit had combustion control upgrade potential.
Starting with dry-bottom wall-fired boilers, EPA verified that the average performance rate identified
26 For this analysis, EPA assumed a 500 MW unit with a heat rate of 10,000 Btu/kWh and an 85% annual capacity
factor. We assumed the unit was burning bituminous coal and had a NOx rate of 0.50 lb NOx / MMBtu initial rate
based on its existing NOx combustion controls and had a 42% NOx removal efficiency after the combustion control
upgrades. This 0.50 lb/MMBtu input NOx rate is comparable to the observed average rate of 0.48 lb/MMBtu for the
coal-fired wall-fired units from 2003-2008 that had not installed controls. There are very few remaining units that
lack combustion controls. One unit had a rate higher than 0.5 lb/MMBtu. Using 2019 data for wall-fired coal units
lacking combustion controls and comparing these rates against controlled units of the same type, EPA observes a
42% difference in rate. Similarly, EPA observes a 55% reduction for coal units with tangentially-fired boilers.
Despite the very small numbers of remaining units that lack combustion controls, EPA used the lower 42%
reduction from wall-fired coal units.
27 Costs were converted to 2016$ from the tables original $2011$ values. See: EPA-HQ-OAR-2021-0668-0088.
https://www.epa.gOv/sites/production/files/2015-07/documents/chapter_5_emission_control_technologies_0.pdf
28 In past rulemakings, EPA found the representative rate for state-of-the-art combustion controls to be 0.199
lb/MMBtu. Thus, this analysis re-affirms EPA's selection of 0.199 lb/MMBtu as the representative rate for state-of-
the-art combustion controls for most unit types.
19
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above for this boiler configuration with state-of-the-art combustion controls 1) resulted in reductions
consistent with the technology's assumed percent-reduction potential when applied to this subset of units,
and/or 2) had been demonstrated by both subbituminous and bituminous coal units with state-of-the-art
combustion controls in its 2019 dataset. EPA found an assumed emission rate of 0.199 lb/MMBtu to be
reasonable for dry-bottom, wall-fired boilers upgrading to state-of-the-art combustion controls.
EPA applied the same approach for tangentially-fired coal boilers. As shown in Figure C.3, this produced
a weighted average assumed emission rate of 0.147 lb/MMBtu. However, EPA observed that in 2019 no
bituminous burning units with this boiler type (and no post-combustion controls) had met the 0.147
lb/MMBtu average for this control configuration (which was heavily weighted by subbituminous units
with such combustion controls) (see Figure C.3). It also noted that the 0.147 rate lb/MMBtu would imply
a greater percent reduction for some bituminous units with upgrade potential than EPA identified as
representative for the technology. Therefore, given these two findings and the bituminous orientation of
the fleet with state-of-the-art combustion control upgrade potential covered in this action, EPA
determined that the 0.199 lb/MMBtu was also appropriate for tangentially-fired units in this action as that
rate satisfied both criteria.29
Figure C.2. State-of-the-Art Combustion Control Configurations by Boiler Type
Boiler Type
Existing NOx Combustion Control
Incremental Combustion Control
Necessary To Achieve "State-of-the-
Art"
Tangential Firing
Docs not include LNC1 and LNC2
LNC3
Tangential Firing
Includes LNC1, but not LNC2
Conversion from LNC2 to LNC3
Tangential Firing
Includes LNC2, but not LNC3
Conversion from LNC1 to LNC3
Tangential Firing
Includes LNC1 and LNC2 or LNC3
-
Wall Firing, Dry Bottom
Docs not Include LNB and OFA
LNB + OFA
Wall Firing, Dry Bottom
Includes LNB. but not OFA
OFA
Wall Firing, Dry Bottom
Includes OFA. but not LNB
LNB
Wall Firing, Dry Bottom Includes both LNB and OFA
Note: Low LNB =NOx Burner Technology, LNCl=Low NOx coal-and-air nozzles with close-coupled overfire air, LNC2= Low NOx Coal-and-
Air Nozzles with Separated Overfire Air, LNC3 = Low NOx Coal-and-Air Nozzles with Close-Coupled and Separated Overfire Air, OFA =
Overfire Air
Figure C.3. 2019 average NOX rate for units with state-of-the-art combustion controls for
tangentially-fired boilers (lb/MMBtu)
Coal Type
NOx Rate (lb/MMBtu)
Bituminous
0.199
Bituminous, Subbituminous
0.172
Subbituminous
0.134
Weighted Average
0.147
29 See the entry titled "State-of-the-art Combustion Control Data" in the docket for this rulemaking. EPA-HQ-OAR-
2021-0668-0120
20
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D. Cost Estimates for Optimizing and Restarting and Optimizing Idled Existing SNCR
Coal Steam:
EPA sought to examine costs for full operation of SNCR. SNCR are post-combustion controls that reduce
NOx emissions by reacting the NOx with either ammonia or urea, without catalyst. Because the reaction
occurs without catalyst and is thereby a less efficient reaction, several times more reagent must be
injected to achieve a given level of NOx removal with SNCR than would be required to achieve the same
level of NOx removal with SCR technology. Usually, an SNCR system does not achieve the level of
emission reductions that an SCR can achieve, even when using large amounts of reagent. For the SNCR
analysis, as with the SCR analyses described above, the agency used the Retrofit Cost Analyzer equations
to perform a bounding analysis for examining operating expenses associated with a "generic" coal steam
unit returning an SNCR to full operation. EPA examined the costs to fully operate an SNCR that was
already being operated to some extent and the costs to restart and fully operate an SNCR that had been
idled.
Comparable to the discussion about fully optimizing an SCR, the cost to fully optimize an SNCR that is
currently operating to some extent is the VOM costs for additional reagent (urea and steam). Reagent
consumption represents the largest portion of the VOM cost component of unit operation and is directly
related to NOx removal. The other VOM components (e.g., to auxiliary power) as well as the FOM
components are assumed to be largely indifferent to additional NOx removal. For units with an idled, or
mothballed, SNCR returning to full operation, the owner incurs the full suite of VOM and FOM costs.
For this bounding analysis, the agency examined two cases: first, a coal steam unit with a high input NOx
rate 0.40 lb/MMBtu; second, a coal steam unit with a lower input NOx rate 0.20 lb /MMBtu - both
assuming a 25% removal efficiency for NOx.30'31 For the high-rate unit case, VOM and FOM costs were
calculated as approximately $2,100/ton NOx with about $l,600/ton of that cost associated with urea use.
For the low-rate unit case, VOM and FOM costs approached $3,500/ton NOx with nearly $2,700/ton of
that cost associated with urea procurement. Despite equivalent reduction percentages for each unit, the
cost dichotomy results from differences in the input NOx rates for the units and the type of boiler,
resulting in a modeled step-change difference in urea rate (either a 15% or 25% reagent usage factor).
EPA also examined SNCR cost sensitivity by varying NOx removal efficiency while maintaining the
input NOx emission rate. In this analysis, SNCR NOx removal efficiency was assumed to be 40% for the
first cost estimate and 10% for the second cost estimate. For a high-rate unit (with an input rate of 0.40 lb
NOx/MMBtu), the associated costs were $2,000/ton and $2,450/ton. For a low-rate unit (i.e., an input rate
of 0.20 lb NOx/MMBtu), the associated costs were $3,370/ton and $4,180/ton. These analyses together
illustrate that SNCR costs on a dollar per ton basis are more sensitive to a unit's input NOx rate than the
potential NOx removal efficiency of the SNCR itself.
30 For both cases, we examined a 500 MW unit with a heat rate of 10,000 Btu/kWh operated at a 26% annual
capacity factor while burning bituminous coal. The capacity factor used was based on the IPM-estimated operation
of units with SNCR. Furthermore, in the cost assessment performed here, the agency assumes SNCR NOx removal
efficiency to be 25%, which is consistent with the range of documented removal efficiency in IPM and historic data.
See the Retrofit Cost Analyzer (Update 1-26-2022) tool and the "Coal-Fired SNCR Cost Methodology."
31 Steam; Its Generation and Use 41ed (2005) J B Kitto; S C Stultz; Babcock & Wilcox Company, lists 20-30%
conversion of NOx as typical, with up to 50% possible under certain circumstances.
21
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EPA conducted a fleetwide assessment of coal-fired units with existing SNCR (67 units total) using the
same set of assumptions used for the fleetwide assessment for units with SCR (i.e., the method for
determining input NOx rate, NOx removal efficiency, and capacity factor) using the Retrofit Cost Tool.32
In that tool, we can examine the VOM and FOM cost components associated with operation of the unit to
approximate costs of fully optimizing a currently operating control and to restart and fully optimize an
idled control. Of the full set of units, 47 met the size and operating criteria set forth for SCR units (i.e.,
100 MW in size or great, 0.14 lb/MMBtu input NOx rate or greater, and at least some emission
reduction). EPA found that the median cost to fully optimize a currently operating control is $l,600/ton
while the cost to restart and fully optimize an idled control has a median cost of $3,500/ton and an
emission weighted cost of $2,100/ton. Additionally, EPA conducted cost sensitivities considering urea
price and fleet updates, which can be found in Appendix B.
In the Revised CSAPR Update, EPA concluded that $l,800/ton was a representative cost for units that are
currently operating their SNCR controls to some extent to fully operate those controls and $3,900/ton was
a representative cost for units that had idled their SNCR controls. Based on the fleetwide analysis, the
bounding analysis, and the Revised CSAPR Update analysis, EPA concludes that $l,800/ton is a
representative cost to fully operate SNCR for units that are currently operating an SNCR to some extent
and that a $3,900/ton cost is representative to turn on and fully operate controls for units whose SNCR
control has been idled.
Finally, EPA assessed the existing fleet of units with SNCR technology to assess whether, or not, the
units were typically operating their controls to some extent or whether the controls had been fully idled to
assess whether the cost breakpoint level should be identified as $l,800/ton or $3,900/ton. EPA examined
the fleet of coal-steam and oil/gas steam units that have SNCR optimization potential within the
geography and assessed whether the units are currently partially operating but not necessarily optimizing
their SNCRs or whether the units have idled their controls. EPA assessed whether SNCRs were partially
operating or were idled doing a two-part analysis. First, EPA compared each unit's 2021 reported rate to
this rule's SNCR optimization emission rate for that unit. A difference less than 25% between reported
and optimized NOx rate for a given EGU is an indicator that its SNCR is already partially operating as of
2021 (as 25% NOx removal is a representative average of what SNCRs may achieve when going from no
operation to full operation).33 To identify the optimized value for each unit and compare that to 2021
baseline emission rates, EPA utilized the mode 2 rate from the NEEDS database (October 2021). As
described in EPA's power sector IPM Modeling Documentation (Chapter 3), these unit-specific NOx
mode rates are calculated from historical data and reflect operation of existing post-combustion controls.34
Four modes are identified for each unit to, among other things, identify their emission rates with and
without their post-combustion controls operating. Mode 2 for SNCR-controlled units is intended to reflect
the operation of that unit's post combustion control based on prior years when that unit operated its
control. The optimized SNCR emission rates assumed for each controlled unit are identifiable in the
NEEDS file "Mode 2 NOx rate (lb/MMBtu)" column.35 If a unit's 2021 emission rate was at or lower
than its "optimized" SNCR rate, than no additional reductions are expected from "optimizing" that unit's
post-combustion control.
32 See "Retrofit Cost Tool Fleetwide Final GNP."
33 "Coal-Fired SNCR Cost Methodology"
34 https://www.epa.gov/system/files/documents/2021-09/chapter-3-power-system-operation-assumptions.pdf
35 See the NEEDS v6 October 2022 data file available in the docket and for download at
https://www.epa.gov/airmarkets/national~electric~energv-data~svstem~needs~v6
22
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Comparing each unit's 2021 reported emissions rate to this rule's SNCR optimization emission rate (see
Figure D.l), the majority of affected EGUs with existing SNCR (39 of 43 units) have percent differences
less than 25%, suggesting that their SNCRs appeared to be partially operating at least to some extent
based on the first indicator alone. For the remaining 4 units, EPA compared the historical highest rate for
each unit (dating back to 2009) to its 2021 reported emission rate. For two of the units, the reported 2021
rate was substantially lower than the unit's historical highest rate, so EPA assumes that the SNCR at these
units were also operating to some extent in 2021. For the remaining units, either the SNCR has
consistently been fully operating throughout the life of the unit (i.e., the time period of this analysis) or
the control may have been idled. Between the two indicators, EPA determined that nearly all SNCRs with
optimization potential were at least partially operating their controls during 2021. Consequently, EPA
concludes that a VOM reagent-centric cost of $l,800/ton is a reasonable representative cost for emissions
reductions for fully operating SNCR for units with this existing control.
23
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Figure D.l. Ozone-season NOx Emission Rates (lb/MMBtu) for Units with SNCR Reduction Potential
Facility
State
ORIS
Boiler
2021 OS
SNCR
Percent
Historical
Percent
NOx Rate
(lb/MMBtu)
Optimization
OS Rate
(lb/MMBtu)
Change in
Rate (2021
vs
Optimized
Rate)
Max OS
NOx Rate
(2009-2021)
Change
Between 2021
and Historical
Max
Yorktown Power Station
Virginia
3809
3
0.13
0.02
86%
0.25
46%
Grant Town Power Plant
West Virginia
10151
IB
0.32
0.16
51%
0.35
7%
Grant Town Power Plant
West Virginia
10151
1A
0.33
0.16
50%
0.35
7%
Manitowoc
Wisconsin
4125
9
0.08
0.05
43%
0.09
10%
Brame Energy Center
Louisiana
6190
3-2
0.04
0.03
32%
0.07
38%
Seward
Pennsylvania
3130
2
0.12
0.09
24%
Powerton
Illinois
879
61
0.11
0.08
20%
Edge Moor
Delaware
593
4
0.05
0.04
20%
Marion
Illinois
976
123
0.10
0.08
20%
Brame Energy Center
Louisiana
6190
3-1
0.04
0.03
18%
Powerton
Illinois
879
62
0.10
0.08
17%
Sikeston
Missouri
6768
1
0.12
0.10
14%
Whitewater Valley
Indiana
1040
1
0.32
0.28
13%
Whitewater Valley
Indiana
1040
2
0.34
0.30
12%
Grayling Generating
Station
Michigan
10822
1
0.13
0.12
12%
Twin Oaks
Texas
7030
U1
0.10
0.09
12%
IPL - Harding Street
Indiana
990
60
0.04
0.04
10%
Station (EW Stout)
Limestone
Texas
298
LIM2
0.18
0.16
9%
Sioux
Missouri
2107
1
0.25
0.23
9%
Powerton
Illinois
879
51
0.11
0.10
9%
Spruance Genco, LLC
Virginia
54081
BLR04A
0.03
0.03
8%
Joliet 29
Illinois
384
82
0.10
0.09
8%
Spruance Genco, LLC
Virginia
54081
BLR03A
0.03
0.03
7%
Joliet 29
Illinois
384
81
0.10
0.09
7%
Joliet 29
Illinois
384
71
0.08
0.08
7%
Boswell Energy Center
Minnesota
1893
4
0.11
0.10
6%
Twin Oaks
Texas
7030
U2
0.10
0.09
6%
Spruance Genco, LLC
Virginia
54081
BLR04B
0.03
0.03
6%
Altavista Power Station
Virginia
10773
2
0.12
0.12
6%
Altavista Power Station
Virginia
10773
1
0.12
0.12
6%
Joliet 29
Illinois
384
72
0.08
0.08
5%
Southampton Power
Station
Virginia
10774
1
0.13
0.12
4%
Southampton Power
Station
Virginia
10774
2
0.13
0.12
4%
Barry
Alabama
3
4
0.27
0.26
4%
San Miguel
Texas
6183
SM-1
0.16
0.16
3%
Fort Martin Power
West Virginia
3943
1
0.29
0.28
3%
Station
Hopewell Power Station
Virginia
10771
1
0.12
0.12
3%
Hopewell Power Station
Virginia
10771
2
0.12
0.12
3%
AES Warrior Run
Maryland
10678
001
0.07
0.07
3%
24
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Oil/Gas Steam:
Using the Retrofit Cost Analyzer, the agency conducted a bounding analysis to assess the costs for
optimizing Oil/Gas steam units that are not fully operating their controls and/or restarting and optimizing
idled SNCR controls. Again, assuming a 25% reduction in emission rate and for a unit similar to that
examined above for coal steam units (500 MW, tangential boiler, input NOx rate of 0.2 lb NOx/MMBtu,
10,000 Btu/kWh heat rate, with a 25% NOx removal efficiency) using natural gas with a 26% capacity
factor, the VOM and FOM costs were calculated as approximately $3,500/ton NOx with about $2,700/ton
of that cost associated with urea use. These costs are not particularly sensitive to the capacity factor of the
unit, with the urea-use cost insensitive to unit usage. The costs were also largely indifferent to the
selection of gas compared with oil. For the same unit, but with a lower input NOx rate of 0.14 lb/MMBtu,
the VOM+FOM costs increased to $3,600/ton while the urea cost remained at $2,700/ton. For the same
unit, but with a higher input NOx rate of 0.4 lb/MMBtu, the VOM+FOM costs decreased to $2,000/ton
while the urea cost dropped to $l,600/ton.
EPA also conducted a similar fleetwide analysis for oil/gas steam units with existing SNCR, which
included 22 units, 21 of which met the size and operating criteria (i.e., 100 MW in size or great, 0.14
lb/MMBtu input NOx rate or greater, and at least some emission reduction).36 EPA found that the median
cost to fully optimize a currently operating control is $l,600/ton while the cost to restart and fully
optimize an idled control has a median cost of $l,900/ton and an emission weighted cost of $2,000/ton.
Additionally, EPA conducted cost sensitivities considering urea price and fleet updates, which can be
found in Appendix B.
Based on the fleetwide analysis and the bounding analysis, EPA estimates that $l,600/ton is a
representative cost to fully operate SNCR for oil/gas steam units that are currently operating an SNCR to
some extent and that a $3,500/ton cost is representative to turn on and fully operate SNCR for oil/gas
steam units whose control has been idled.
Summary:
EPA finds that $l,800/ton is a representative cost to fully operate SNCR for both coal and oil/gas steam
units that are currently operating an SNCR to some extent and that a $3,900/ton cost is representative to
turn on and fully operate controls for SNCR units whose controls have been idled.
E. Cost and Emission Rate Performance Estimates for Retrofitting with SNCR and
Related Costs
SNCR technology is an alternative method of NOx emission control that incurs a lower capital cost
compared with an SCR, albeit at the expense of greater operating costs and less NOx emission reduction.
Some units with anticipated shorter operational lives or with low utilization may benefit from this control
technology. The higher cost per ton of NOx removed reflects this technology's lower removal efficiency
which necessitates greater reagent consumption, thereby escalating VOM costs. The agency examined the
costs of retrofitting coal steam and oil/gas steam units with SNCR technology using the Retrofit Cost
Analyzer. The agency did not consider retrofitting SNCR on combustion turbine or combined cycle units
36 See the "Retrofit Cost Tool Fleetwide Final GNP.
25
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as, except for a single combustion turbine at the Delaware City Plant, there are no EGUs of these plant
types in NEEDS equipped with SNCR.
Coal Steam:
For SNCR retrofits on coal steam units, the agency set the NOx emission reduction rate at 25% - the
same assumption used in the Revised CSAPR Update Rule and in EPA's power sector modeling.37 For a
similar illustrative unit examined for combustion control upgrades (500 MW, tangential boiler, 10,000
Btu/kWh heat rate, bituminous fuel) and input emission rate of 0.2 lb NOx/MMBtu, with a capacity factor
of 56%, the cost is $6,200/ton.38 When the capacity factor is 26%, the costs increase to $9,700/ton. At a
higher capacity factor (i.e., 80%), the costs decrease, going to $5,300/ton, respectively. Next, EPA
examined the cost of SNCR installation at small units (25 MW and 100 MW in size). The costs at the
three capacity factors (26%, 56%, and 80%) for the 25 MW unit were $38,300/ton, $19,500/ton, and
$14,600/ton. The costs forthe 100 MW unit at the three capacity factors (26%, 56%, and 80%)39 were
$19,300/ton, $10,700/ton, and $8,400/ton.
Next, using a similar set of assumptions as in the previous paragraph (i.e., type of coal and capacity
factor),40 EPA examined the remaining coal-fired fleet that lack SNCR or other NOx post-combustion
control to estimate an emission weighted average and median cost of SNCR installation (on a $/ton basis)
using the Retrofit Cost Analyzer.41 In this case the input NOx rate was the 2023 baseline NOx rate
engineering analysis rate (see Section B in the Ozone Transport Policy Analysis Final Rule TSD for
details) and the "controlled" NOx rate was usually the input NOx rate reduced by 25% (circulating
fluidized bed boilers were assigned reductions of 50%). Costs were estimated for units that had a
minimum input NOx rate of at least 0.14 lb/MMBtu. In this instance, the emission weighted average cost
is $6,000/ton and the median value is $6,300/ton. EPA repeated these calculations for the subset of coal-
fired units less than 100 MW and found an emission weighted average cost of $6,800/ton and a median
value of $9,000/ton.42 Additionally, EPA conducted cost sensitivities considering urea price and fleet
updates, which can be found in Appendix B.
EPA also looked at the size of coal steam units that had a SNCR or SCR. Looking at the existing coal
fleet in NEEDS for the Summer 2021 Reference Case,43 there are 146 GW (315 units) with a NOx post-
combustion control: 25 GW (88 units) with SNCR and 121 GW (227 units) with SCR. There are
approximately 52 GW of coal units without a NOx post-combustion control. The average size of units
with SNCR or SCR is about 275 MW and 530 MW, respectively, indicating that not only is SCR a more
common NOx post-combustion control, covering about 60% of the coal fleet capacity, but also that it
tends to be installed on larger coal-fired units. Looking at the subset of units with post-combustion
controls that are less than 100 MW, EPA found that post-combustion controls favored SNCR. There are
37 "Coal-Fired SNCR Cost Methodology"
38 The input emission rate for a tangentially-fired unit with bituminous coal and state of the art combustion controls
is 0.2 (see Figure C.3).
39These capacity factors were chosen because they provide a wide range of capacity factors. Furthermore, 26% and
56% are the operating fleet-wide oil-gas steam and coal steam unit capacity factors in 2030 in the Summer 2021
IPM Reference Case, and therefore represent the projected average capacity factor for those plant types.
40 Units were assumed to use the coal identified in NEEDS, were assumed to operate the control throughout the year,
and were assumed to have a capacity factor of 56%.
41 See the Excel file Retrofit Cost Tool Fleetwide Final GNP for additional details.
42 See the Retrofit Cost Tool Fleetwide Final GNP for details.
43 With additional correction that the following 3 units do not have SNCR: Sikeston 1 and Whitewater Valley 1 & 2
26
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28 such units with SNCR and 4 with SCR, indicating that SNCR seems to be the overwhelming choice of
NOx post-combustion control for smaller units. Finally, EPA notes SNCR retrofits on coal steam units
have a decreasing removal efficiency as unit size increases, which further explains the observed
prevalence on smaller units.44
Oil/Gas Steam:
Using the Retrofit Cost Analyzer, the agency conducted a similar analysis for SNCR retrofit on Oil/Gas
Steam units, again assuming a 25% reduction in emission rate.45 For a unit similar to that examined above
for coal steam units (500 MW, tangential boiler, 0.2 lb NOx/MMBtu, 10,000 Btu/kWh heat rate, with a
25% NOx removal efficiency) using natural gas with a 26% capacity factor, the cost is $8,400/ton of NOx
removed. At a capacity factor of 56%, the cost is $5,600/ton. At higher capacity factors (i.e., 80%), the
costs decrease, going to $4,900/ton. The costs were largely indifferent to the selection of gas compared
with oil. For the same unit, but with a lower starting NOx rate of 0.14 lb/MMBtu, the costs at the three
capacity factors increased to $10,500, $6,600, and $5,600/ton. Next, EPA examined the cost of SNCR
installation at small units (25 MW and 100 MW in size with an input NOx rate of 0.2 lb/MMBtu). The
costs at the three capacity factors (26%, 56%, and 80%) for the 25 MW unit were $31,400/ton,
$16,200/ton, and $12,300/ton, respectively. The costs for the 100 MW unit were $16,100/ton, $9,200/ton,
and $7,400/ton, respectively.
Finally, using a similar method for determining an input NOx rate and a NOx removal efficiency
described above for coal steam units, EPA examined the remaining oil/gas steam fleet that lack SNCR or
other NOx post-combustion control to estimate an emission weighted average and median cost of SNCR
installation (on a $/ton basis) using the Retrofit Cost Tool.46 Costs were estimated for units that had a
minimum input NOx rate of at least 0.14 lb/MMBtu and had athree-year average (2019-2021) of at least
150 tons of ozone season NOx (i.e., approximately 1 ton per day during the ozone season). Units were
assumed to have a NOx removal rate of 25% and assumed to operate the control throughout the year and
had an assumed capacity factor of 26% (the fleet-wide oil/gas steam capacity factor from the Summer
2021 IPM reference case). In this instance, the emission weighted average cost is $8,600/ton and the
median value is $9,600/ton.
F. Cost and Emission Rate Performance Estimates for Retrofitting with SCR and Related
Costs
For coal-fired and oil/gas steam units, an SCR retrofit is the state-of-the-art technology used to achieve
the greatest reductions in NOx emissions. The agency examined the cost for newly retrofitting a unit with
SCR technology. Based on the updated Retrofit Cost Analyzer,47 EPA assumed a new state-of-the-art
SCR retrofit could achieve 0.05 lb/MMBtu emission rate48 performance on a coal steam unit (regardless
44 See Table 5-4 in the Documentation for EPA's IPM Summer 2021 Reference Case.
45 "Gas-Fired SNCR Cost Methodology"
46 See the Retrofit Cost Tool Fleetwide Final GNP for details
47 See the Retrofit Cost Analyzer (Update 1-26-2022) EPA-HQ-OAR-2021-0668-0118
48 In prior modeling used for CSAPR rulemakings, EPA had assumed new SCR retrofits could achieve a 0.07
lb/MMBtu NOx emission rate for bituminous coal and 0.05 lb/MMBtu for other coal rank (e.g., subbituminous).
27
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of type of coal used) and 0.03 lb/MMBtu for an oil-/gas steam unit. The same assumption was used in the
EPA's power sector modeling for this final rule. The EPA found that more than three quarters of coal-
fired units with SCR retrofits completed since 2007 have achieved a rate of 0.05 lb/MMBtu or better on a
monthly or seasonal basis, further supporting that new SCRs can achieve such an emission rate.
Additionally, most oil/gas steam units equipped with SCR have achieved NOx emission rates under 0.03
lb/MMBtu.
Coal Steam:
To understand the effect of input NOx rate on costs, using the Retrofit Cost Analyzer equations, the EPA
performed a bounding analysis to identify reasonable high and low per-ton NOx control costs for adding
SCR post-combustion controls across a range of potential input NOx rates.49 For a hypothetical unit 500
MW in size with a relatively low input NOx rate (e.g., 0.2 lb NOx/MMBtu, bituminous fuel, 2 lb
S02/MMBtu, 60% removal efficiency, 56% capacity factor, and 10,000 Btu/kWh heat rate), the capital
cost was about $151,000,000. For a similar unit with an input NOx rate of 0.4 lb/MMBtu and 80% NOx
removal efficiency, the total capital cost was $160,000,000. The cost on a per-ton basis varies with the
assumptions concerning the operation of the unit and the book life of the loan (or lifetime of the
equipment). Assuming an annual capital recovery factor of 0.143, NOx rate of 0.2 lb/MMBtu and removal
efficiency of 60% and annual operation, the cost per ton was $16,400/ton ($14,700/ton for the capital
cost, $300/ton for the FOM cost, and $l,400/ton for the VOM cost). For the unit with the NOx rate of 0.4
lb/MMBtu and removal efficiency of 80%, the costs were $6,800/ton ($5,800/ton for the capital cost,
$100/ton forthe FOM cost, and $850/ton for the VOM cost).
For this rule, EPA examined the remaining coal-fired fleet that lack SCR to estimate a median cost of
SCR installation (on a $/ton basis). In this case the "input" NOx rate was, generally, the 2023 baseline
NOx rate engineering analysis rate (see Section B in the Ozone Transport Policy Analysis Final Rule TSD
for details). For units with existing SNCR controls, for the "input" NOx rate, we identified each unit's
maximum monthly emission rate from the period 2009-2021. Costs were estimated for units that had
"input" NOx rates of at least 0.14 lb/MMBtu prior to installation of the post-combustion control. With the
control installed, the output NOx rate was reduced to a value of 0.05 lb/MMBtu. Furthermore, we
assumed annual operation of the control and assumed a capacity factor of 56% (the capacity factor for
coal units from the Summer 2021 IPM v.6 reference case). In this instance, these assumptions produce an
emission weighted average of $11,000/ton, a median value of $13,700/ton and a 90th percentile value of
$20,900/ton. EPA repeated these calculations for the subset of coal-fired units less than 100 MW and
found a median value of $ 15,500/ton and a weighted average of $ 12,700/ton.50 Additionally, EPA
conducted cost sensitivities considering several input factors, including urea price, interest rate, loan
repayment period, capital costs, coal type, fleet geography, and fleet updates, which can be found in
Appendix B.
EPA had previously highlighted the upper end of this range as a representative rate based on the achievable NOx
emission rate for units burning bituminous coal, though units burning subbituminous and lignite coal could achieve
lower emission rates. Improvement in the catalyst and additional experience constructing and operating SCRs has
resulted in higher confidence in guaranteeing lower emission rates, even for units burning bituminous coal. See
"Coal-Fired SCR Cost Methodology" and "Gas-Fired SCR Cost Methodology" for details.
49 For these hypothetical cases, the "input" NOx rate includes the effects of existing combustion controls (e.g., low
NOx burners).
50 See the Retrofit Cost Tool Fleetwide Final GNP for details of this calculation.
28
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In states linked in 2026, there are 15 non-CFB coal steam units at least 100 MW and that do not have
known retirements occurring before 2026 that are currently equipped with SNCRthat reported emissions.
In 2021, those units had a combined 13,000 tons of OS NOx emissions, with a weighted average NOx rate
of 0.19 lb/MMBtu. If those were to have a achieved a 0.05 lb/MMBtu emission rate, commensurate with
retrofitting a new SCR, they could reduce 9,600 tons of OS NOx emissions, with several units achieving
reductions of over 500 tons of OS NOx each. Because these units are already achieving some level of
NOx emission reduction with an SNCR, the dollar per ton cost would be greater for these units than
comparable units that lacked SNCRs. If an existing SNCR achieves 25% removal efficiency, upgrading to
an SCR with 90% removal efficiency would add an incremental 65% removal efficiency. Assuming the
SCR retrofit costs about the same for a unit whether it already has an SNCR, then the SCR retrofit cost
would properly be spread over only the incremental tons of reductions. This would lead to the per ton cost
increasing by 38%, not accounting for cost savings because SCRs have a lower per ton O&M cost than
SNCRs.
For a hypothetical unit 500 MW in size with a relatively low input NOx rate (e.g., 0.17 lb NOx/MMBtu,
bituminous fuel, 2 lb S02/MMBtu, 70% removal efficiency, 56% capacity factor, and 10,000 Btu/kWh
heat rate), the capital cost was about $155,000,000. Assuming an annual capital recovery factor of 0.143,
NOx rate of 0.17 lb/MMBtu and removal efficiency of 70% and annual operation, the cost per ton was
$17,000/ton ($15,200/ton for the capital cost, $300/ton for the FOM cost, and $l,500/ton forthe VOM
cost).Repeating the fleet-wide analysis of SCR retrofit cost, but limited to just units with SNCRthat could
be considered for SCR retrofit (at least 100 MW in size and not a circulating fluidized unit), results in an
emission weighted average of $13,400/ton, a median value of $14,100/ton and a 90th percentile value of
$19,000/ton. These costs are not simply 38% higher than the fleet-wide analysis for all units without SCR
because this subset of units has different characteristics than the wider fleet.
Oil/Gas Steam:
To understand the effect of input NOx rate on costs, using the Retrofit Cost Analyzer equations, the EPA
performed a bounding analysis to identify reasonable high and low per-ton NOx control costs for adding
SCR post-combustion controls across a range of potential input NOx rates.51 For a hypothetical unit 500
MW in size with an input NOx rate of 0.14 lb NOx/MMBtu, 79% removal efficiency, 26% capacity
factor, and 10,000 Btu/kWh heat rate using natural gas, the capital cost was about $60,000,000. For a
similar unit with an input NOx rate of 0.2 lb/MMBtu and 85% NOx removal efficiency, the total capital
cost was $61,000,000. The cost on a per-ton basis varies with the assumptions concerning the operation of
the unit and the book life of the loan (or lifetime of the equipment). Assuming an annual capital recovery
factor of 0.143, NOx rate of 0.14 lb/MMBtu and removal efficiency of 79% and annual operation, the cost
perton was $14,700/ton ($13,600/ton forthe capital cost, $300/ton forthe FOM cost, and 800/ton forthe
VOM cost). For the unit with the NOx rate of 0.2 and removal efficiency of 85%, the costs were
$9,900/ton ($9,000/ton forthe capital cost, $200/ton forthe FOM cost, and $700/ton forthe VOM cost).
For this rule, EPA examined the remaining oil/gas steam fleet that lack SCR to estimate a median cost of
SCR installation (on a $/ton basis). In this case the "input" NOx rate was, generally, the 2023 baseline
NOx rate engineering analysis rate (see Section B in the Ozone Transport Policy Analysis Final Rule TSD
for details). For units with existing SNCR controls, for the "input" NOx rate, we identified each unit's
51 For these hypothetical cases, the "input" NOx rate includes the effects of existing combustion controls (e.g., low
NOx burners).
29
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maximum monthly emission rate from the period 2009-2021. Costs were estimated for units that had
input NOx rates of at least 0.14 lb/MMBtu prior to installation of the post-combustion control and
decreasing to rates of 0.03 lb/MMBtu following control installation. EPA relied on the same methodology
for determining SCR optimization at these units to inform its estimate of emission rate performance for
SCR operation at new retrofits, which agreed with the emission rate achievable with an SCR retrofit
described in "Gas-Fired SCR Cost Methodology." Furthermore, we assumed annual operation of the
control and assumed a capacity factor of 26% (the capacity factor for coal units from the Summer 2021
IPM v.6 reference case). In this instance, these assumptions produce an emission weighted average of
$7,700/ton, a median value of $10,000/ton and a 90th percentile value of $15,300/ton.52 EPA repeated
these calculations for the subset of oil/gas steam units less than 150 tons per ozone season and found a
weighted average of $15,600/ton.53 Additionally, EPA conducted cost sensitivities considering several
input factors, including urea price, interest rate, loan repayment period, capital costs, fleet geography, and
fleet updates, which can be found in Appendix B.
G. Feasibility Assessment: Implementation Timing for Each EGU NOx Control Strategy
Restarting and Optimizing Existing Post-Combustion Controls
EPA evaluated the time it would take for EGUs to turn on idled SCRs and SNCRs. The EGU sector is
very familiar with restarting SCR and SNCR systems. Based on past practice and taking account of the
steps needed to restart the controls (e.g., re-stocking reagent, bringing the system out of protective lay-up,
performing inspections), returning these idled controls to operation is possible by 2023. In states
included in the NOx Budget Trading program, 2005 EGU NOx emission data suggest that 126 out of 156
coal-fired units with SCR operated the systems in the summer ozone season, likely for compliance with
the program, while idling these controls for the remaining seven non-ozone season months of the year.54
Similarly, in 2005, 20 of 72 coal-fired units with SNCR in the NOx Budget Trading program operated in
both the ozone season and non-ozone season and had ozone season NOx rates more than 25% below their
non ozone season NOX rates suggesting that the SNCR was operated during the ozone season and may
not have been operated during non-ozone season.55 To comply with the seasonal NOx limits, these SCR
and SNCR controls were regularly taken out of and then returned to service within seven months.
Therefore, EPA believes this SCR and SNCR optimization mitigation strategy is available for the 2023
ozone season.
EPA also found there are very few units that appear to have fully idled their SCRs. EPA assessed the
number of coal-fired units with SCR that operated in 2021 with ozone-season emission rates greater than
or equal to 0.2 lb/MMBtu suggesting that their units may not be operating their NOx post-combustion
control equipment. EPA finds that only 8 units in the contiguous United States (of which four are in states
52 See the "Retrofit Cost Tool Fleetwide Final GNP""
53 See the "Retrofit Cost Tool Fleetwide Final GNP"
54 Units with SCR were identified as those with 2005 ozone season average NOx rates that were less than 0.12 / lb
MMBtu and 2005 average non-ozone season NOx emission rates that exceeded 0.2 lb/MMBtu.
55 For this analysis, we identified units that had heat input greater than zero in both seasons and had non-ozone
season NOx rates above 0.20 lb/MMBtu.
30
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that are "linked" at or above 1% in this rule) fit this criterion.56,57 EPA's assumptions that this mitigation
technology is available for the 2023 ozone-season is further bolstered given that the previous rulemakings
(i.e., CSAPR Update and the Revised CSAPR Update) identified turning on and optimizing existing SCR
as a cost-effective control technology available by the next ozone season after those rules were
promulgated. Many sources successfully implemented that strategy in response to those rules, and it
appears that only a low number of units in the regions covered by these rules may have entirely ceased
operating these controls subsequently. Similarly, for SNCRs (as shown above where the cost of operating
an existing SNCR control is described), most units are currently operating these controls, meaning that
timing considerations need to focus on additional reagent acquisition.
Full operation of existing SCRs that are already operating to some extent involves increasing reagent (i.e.,
ammonia or urea) flow rate, and maintaining and replacing catalyst to sustain higher NOx removal rate
operations. As with restarting idled SCR systems, EGU data demonstrate that operators have the
capability to fully idle SCR systems during winter months and return these units to operation in the
summer to comply with ozone season NOx limits. The EPA believes that this widely demonstrated
behavior also supports our finding that fully operating existing SCR systems currently being operated,
which would necessitate fewer changes to SCR operation relative to restarting idled systems, is also
feasible for the 2023 ozone season. Regarding full operation activities, existing SCRs that are only
operating at partial capacity still provide functioning, maintained systems that may only require increased
chemical reagent feed rate up to their design potential and catalyst maintenance for mitigating NOx
emissions. Units must have adequate inventory of chemical reagent and catalyst deliveries to sustain
operations. Considering that units have procurement programs in place for operating SCR, this may only
require updating the frequency of deliveries. This may be accomplished within a few weeks. The vast
majority of existing units with SCRs covered in this action fall into this category. To the extent that there
are any existing units with fully idled SNCR systems, the same timing considerations and conclusions
apply. Moreover, since SNCR systems do not require catalyst, and may only need additional ammonia or
urea reagent, the timing may even be faster than that for SCR systems. EPA concludes that these SNCR
systems could be fully operational within a few weeks.
Moreover, hourly unit-level data, such as that shown in Figure B.3, clearly show that SCR performance
can improve within a 2-month time frame. Specifically, when controls are partially operating (as EPA has
demonstrated is the case in nearly all units with optimization potential), the data shows the hourly
emission rate varying significantly (reflective of SCR performance) over hours that occur well within two
months of one another. For instance, the size of the rectangle in Figure B.3 showing hourly NOx rates for
the unit when the control is partially operating in 2017 and 2018 reflect the 25th-75th percentile hours. The
top left graphic shows emission rates varying between approximately 0.22 b/MMBtu to 0.07 lb/MMBtu
in 2017 for instance. This variation, reflective of SCR performance, is occurring within a two- month time
span, indicating the ability for quick improvements in control performance even controlling for load
levels.58
56 See the "2021 NOx Rates for 234 SCR Coal Units" (EPA-HQ-OAR-2021-0668-0081) file in the docket for
details. Of the four units in states linked at or above 1%, three are in Missouri and one is in Pennsylvania.
57 The four units in "linked" states that had idled SCRs in 2021 appeared to have operated their SCRs in 2022 based
on emissions data reported to CAMPD.
58 Unit-level hourly emission rate data at campd.epa.gov. See also "Miami Fort Hourly Emission Rate at Capacity
Factor of 50%-80%" (EPA-HQ-OAR-2021-0668-0172) in the docket for this rulemaking. This file shows the
emission rate changes occuring withing two months of one another.
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Combustion Control Upgrades
Combustion controls, such as LNB and/or OFA, represent mature technologies requiring a short
installation time - typically, four weeks to install along with a scheduled outage (with order placement,
fabrication, and delivery occurring beforehand and taking a few months). Construction time for installing
combustion controls was examined by the EPA during the original CSAPR development and is discussed
in the TSD for that rulemaking entitled, "Installation Timing for Low NOx Burners (LNB)", Docket ID
No. EPA-HQ-OAR-2009-0491-0051.59 Industry has demonstrated retrofitting LNB technology controls
on a large unit (800 MW) in under six months (excluding permitting). This TSD is in the docket for the
CSAPR Update and for this rulemaking.
Retrofitting Post-Combustion Control Technologies
SNCR is a mature, post-combustion technology that requires about 12 months from award through
commissioning (not including permitting) at a single boiler. Conceptual design, permitting, financing, and
bid review require additional time. A month-by-month evaluation of SNCR installation is discussed in
EPA's "Engineering and Economic Factors Affecting the Installation of Control Technologies for
Multipollutant Strategies," located in the docket for this rulemaking.60,61 The analysis in this exhibit
estimates the installation period from contract award as within a 10-13-month timeframe. The exhibit
also indicates a 16-month timeframe from start to finish, inclusive of pre-contract award steps of the
engineering assessment of technologies and bid request development. EPA is therefore assuming SNCRs
can be retrofit in 16 months, consistent with the more complete timeframe estimated by the analysis in the
exhibit.
SCR is a mature, post-combustion technology, for which EPA makes a fleetwide retrofit timing
assumption of 36-48 months. Unit-specific installation timing depends on site-specific engineering
considerations and on the number of installations being considered. A month-by-month evaluation of
SCR installation is discussed in EPA's "Engineering and Economic Factors Affecting the Installation of
Control Technologies for Multipollutant Strategies," located in the docket for this rulemaking.62 A
detailed analysis for a single SCR system and a seven-SCR system can be found in Exhibits A-3 and A-4
of the report. For a single SCR, the analysis in this exhibit estimates the installation period from contract
award in a 16-month timeframe. The exhibit also indicates a 21-month timeframe from start to finish,
inclusive of pre-contract award steps of the engineering assessment of technologies and bid request
development, though there are instances of SCR retrofits taking as little as 9 months from contract award
to completion (about 13 months allowing for work prior to contract award).63 At a facility with multiple
59 http://www.epa.gov/airmarkets/airtransport/CSAPR/pdfs/TSD_Installation_timing_for_LNBs_07-6-10.pdf
60 "Final Report: Engineering and Economic Factors Affecting the Installation of Control Technologies for
Multipollutant Strategies" (EPA) (EPA-HO-OAR-202.1.4)6684)0891
http://nepis.epa.gov/Adobe/PDF/P1001G0Q.pdf
61 Exhibit A-5 in "Final Report: Engineering and Economic Factors Affecting the Installation of Control
Technologies for Multipollutant Strategies" (EP A-HO-O AR-202.1. -0668-0089') shows the timeline for retrofitting an
ACI system, which has an equivalent timeline to an SNCR.
62 "Final Report: Engineering and Economic Factors Affecting the Installation of Control Technologies for
Multipollutant Strategies" (EPA) (EP A-HO-O AR-202.1.4)6684)0891
http://nepis.epa.gov/Adobe/PDF/P1001G0Q.pdf
63 The AES Somerset station completed an SCR retrofit on a 675 MW boiler in 9 months from contract award. The
Keystone plant retrofit SCR on two 900 MW boilers are estimated to have taken just 17 to 19 months, even allowing
for a relatively long 6 to 8 months of preliminary engineering and contract negotiation. Two 600 MW units at New
Madrid were retrofit with SCR, with the first unit being retrofit in about 20 months from contract award.
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SCR units, the facility can stagger installation to minimize operation disruptions. For a seven-unit SCR
system, the analysis in this exhibit finds that seven SCR units could be installed at a single facility in 35
months, or roughly an incremental 2.5 months per additional retrofit. EPA notes that most of the SCR
retrofits that may be expected in response to this rule would happen at facilities where only one or two
boilers would need to be retrofit. EPA believes the timing estimates for SCR installation have not
changed significantly since the publication of this report.
In addition to these prior reports and installation schedules cited above and in prior CSAPR Rules, EPA
assessed the schedules again as it prepared this rule. In the summer of 2021, a third-party engineering and
consulting firm provided an assessment based on the latest data of SCR cost, performance, and timing
assumptions. This timing assessment is consistent with the timing schedules described in EPA's analysis.
In particular, the findings noted that a SCR project could go from capital investment to commercial
operation in 30-36 months, with faster schedules possible if motivated by a deadline or compliance date.64
Some commenters provided analysis by Sargent & Lundy with a retrofit timeline that matches the
"extended duration" scheduled that was the basis for the higher end retrofit estimate of 36 months.
Some commenters also provided estimates of SCR retrofit timelines between 3 and 5 years based on past
projects. The Midwest Ozone Group provided analysis that showed "the typical time required for a single
SCR reactor is 40 months, while retrofit of multiple reactors to one site requires 45 months."65 Some of
the units included in MOG's analysis completed retrofits in less than or close to 3 years. Furthermore, the
average retrofit time includes some notoriously difficult and time-consuming retrofits, including Sammis
units 6 and 7 which required building a platform over a highway for some of the equipment. Though this
data is not necessarily a representative sample, it also confirms that SCR retrofits can be completed within
3 or 4 years.
Some commenters noted there are ongoing supply chain issues related to the pandemic. Most of these
comments were about broad material availability, like steel and concrete, though some were a little more
specific listing wiring, electrical components including power transformers, conduits, and pipes as
components that are facing current supply chain issues and elevated prices. These comments did not
explain for how long these supply chain issues would persist. As described in the "NOx Emission Control
Technology Installation Timing for Non-EGU Sources" report, many supply chain issues have been
resolved since the summer of 2022 or are on track to be resolved in 2023, with order delays decreasing.
For example, while the Port of Los Angeles had over 100 cargo ships waiting to unload in February 2022,
that queue has almost entirely disappeared.66 Furthermore, many economic indicators and indices have
peaked or trended towards their pre-pandemic levels. For example, some commenters noted potential
shortages or high prices of steel. According to data from the Federal Reserve Economic Data (FRED), the
PPI for Cold Rolled Steel Sheet and Strip has experienced a drop of 50% from December 2021 to
December 2022; Steel Mill Products have dropped 30% from December 2021 to Dec 2022.67 The
American Iron and Steel Institute reported that for the week ending January 28, 2023 that domestic raw
steel production capability utilization rate had dropped to 73.1% from 79.8% a year previous68 and some
64 See "Typical SCR and SNCR Schedule (Coal or Oil/Gas boilers)" in the docket for this rulemaking.
65 Comment submitted by Midwest Ozone Group. EPA-HQ-OAR-2021-0668-0323
66 "Southern California's Notorious Container Ship Backup Ends." Paul Berger. Oct. 21, 2022
https://www.wsj.com/articles/southern-californias-notorious-container-ship-backup-ends-11666344603
67 https://fred.stlouisfed.org/series/WPU101707; https://fred.stlouisfed.org/series/WPU1017
68 "US Raw Steel Production Up 0.9 percent week-on-week." SteelOrbis. Jan 30, 2023.
https://www.steelorbis.com/steel-news/latest-news/ys-raw-steel-prodyction-yp-09-percent-week-on-week-
1276954.htm
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US steel producers have reported cutting back operations in the face of an over-production of steel.69
Finally, EPA notes that the changes and compliance flexibilities added to the final rule and the smaller
quantity of projected SCR retrofits on EGUs from the final rule, 8 GW70 vs 32 GW in the proposal,
further ameliorate the impact of any potential supply chain issues that would prevent units from
complying with the rule.
The ability of industry to provide enough catalyst for SCR retrofits was also a potential concern. Vendors
are currently able to produce sufficient catalyst for SCRs (and potentially have excess production capacity
as many EGUs with SCRs have retired over the past few years. Furthermore, EPA notes that 24 GW of
EGUs with SCR (18 GW of coal steam; 4 GW of O/G steam) have announced or committed retirements
between January 2021 and 2026, with another 27 GW of coal steam units retiring by 2030. This does not
include any EGUs that may retire but do not currently have announced or committed plans to retire by
2030. By comparison, EPA projects only 8 GW of coal steam units to retrofit SCR by 2030 (or 2.6 GW of
retrofits when provisions of the Inflation Reduction Act are included). Therefore, EPA finds that any
increased demand for catalyst for SCRs would be more than offset by decreased demand from units with
SCR retiring.
The availability of skilled labor - specifically, boilermakers - is an important consideration for, and
potential constraint to, the installation of a significant amount of emission controls. Significant analysis
on boilermaker labor was conducted by the EPA to verify that sufficient boilermaker labor would be
available to support the installation of pollution control retrofits required by Clean Air Interstate Rule
(CAIR), and can be found in the Boilermaker Labor Analysis for the Final Clean Air Interstate Rule
TSD.71 At the time of CAIR implementation, the US boilermaker population was estimated to be 28,000
boilermakers, based on International Brotherhood of Boilermakers (IBB) membership in 2003. EPA
analysis showed that the boilermaker population of 28,000 provided more than enough available
boilermaker labor to install the incremental 24 GW of SCR retrofits projected to be required by the rule in
a three-year time period, in addition to 49 GW of scrubbers over the same time period. As of September
28, 2021, the IBB reports its active membership at 47,615 members, a 70% increase in membership over
the past 18 years.72 In analyzing the labor availability necessary for the installation of 73 GW of SCR on
142 units and 123 GW of SNCR on 497 units that was projected under the NOx SIP Call, EPA found that
approximately 13,000 to 19,000 workers would be capable of completing all SCR and SNCR installations
over a two to three year period.73 Given that there are now more boilermakers available, and EPA is
projecting 8 GW (all coal steam units) of incremental SCR retrofits as part of this rule,74'75 EPA believes
69 "Steelmakers idle manufacturing as oversupply dampens prices." SupplyChainDive. Sarah Zimmerman. Sept 15,
2022. https://www.supplychaindive.com/news/steel-oversupply-prices-decline-nucor-cleveland-cliffs/631566/
70 The 8 GW of capacity that retrofits with SCR is for the policy case presented in the RIA. Additional modeling that
incorporates the Inflation Reduction Act (IRA) projected only 2.6 GW of capacity retrofitting with SCR.
71 "Boilermaker Labor Analysis for the Final Clean Air Interstate Rule TSD"
https://archive.epa.gov/airmarkets/programs/cair/web/pdf/finaltech05.pdf
72 "Boilermakers AFL-CIO FORM LM-2 LABOR ORGANIZATION ANNUAL REPORT 2020-2021"
https://olmsapps.dol.gov/query/orgReport.do?rptId=782863&rptForm=LM2Form
73 "Feasibility of Installing NOx Control Technologies by May 2003" https://www.regulations.gov/document/EPA-
HQ-OAR-2001 -0008-0125
74 See the Regulatory Impact Analysis for this rulemaking
75 EPA is also projecting 0.6 GW of SNCR being retrofit on units. As this is a very small amount and SNCR
construction is much simpler than SCR, it does not affect EPA's conclusion on there being sufficient labor
availability.
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the current number of boilermakers will provide sufficient labor availability to install all of the SCR
retrofits in this rule in the implementation timeline.
EPA can further strengthen this argument by providing an estimate of the boilermaker labor required to
complete the 8 GW of EGU SCR installations projected under the final rule. EPA estimates that 700
work-hours/MW of construction labor are needed for a typical coal-fired SCR retrofit, and 50% of those
hours, or 350 hours/MW, is attributed to boilermaker work-hours.76 This means that 2.8 million hours of
total boilermaker labor is required to complete the 8 GW of SCR installations projected to occur under
this rule.77 EPA estimates that the annual number of hours worked by a boilermaker is 2,000 hours.
Therefore, EPA's estimate of total number of boilermaker-years required to complete the projected EGU
SCR control installations is approximately 1,400 boilermaker-years. This would represent only 3% of
IBB's active membership in the year 2021 (47,615 members), indicating that there is more than enough
skilled labor available to complete the 8 GW of EGU SCR installation projections under this final rule.78
The air pollution control industry has demonstrated that they are able to install significant amounts of air
pollution control equipment in short periods of time. Based on EPA data and analysis, SCRs went online
for the first time on approximately 41.7 and 15.6 GW of coal-fired capacity in 2003 and 2002,
respectively, as a result of the NOx SIP Call.79 In addition to the large number of SCRs installed during
this time, boilermakers were also working on an unusually high number of natural-gas fired power plants
during the same period. In the three decades prior to 2000, an average of 5 GW of new natural gas
capacity was constructed in the United States per year. However, from 2000 to 2004 there was on average
41 GW of new natural gas-fired power plant builds, for a total of 205 GW. Furthermore, the peak year for
new gas power plant builds during this period, 60 GW in 2003, coincides with the peak year for SCR
start-ups for the NOx SIP call.80 EPA believes this demonstrates a robust maximum rate of SCR start-ups
after the NOx SIP Call of 41.7 GW, which is more than enough to support the capacity of SCR retrofits in
this rule.
While the rule does not require installation of controls on any particular source, instead leaving choice of
compliance strategy to facility owners and operators, EPA projects roughly 8GW of SCR retrofits to
occur,81 with other without SCR finding alternative methods of compliance, which could include shifting
76 "Boilermaker Labor Analysis for the Final Clean Air Interstate Rule TSD"
https://archive.epa.gov/airmarkets/programs/cair/web/pdf/finaltech05.pdf
77 The 8 GW of capacity that retrofits with SCR is for the policy case presented in the RIA. Additional modeling that
incorporates the Inflation Reduction Act (IRA) projected only 2.6 GW of capacity retrofitting with SCR.
78 In order to become an IBB union journeyman, the prospective worker will typically enroll in a 3.5 to 4 year
apprenticeship training program offered by the IBB. The apprenticeship program provides both classroom as well as
on-the-job training. See https://boilermakers.org/apprenticeship for more information.
79 "Boilermaker Labor Analysis for the Final Clean Air Interstate Rule TSD"
https://archive.epa.gov/airmarkets/programs/cair/web/pdf/finaltech05.pdf
80 "Typical Installation Timelines for NOx Emissions Control Technologies on Industrial Sources"
https://cdn.ymaws.com/www.icac.com/resource/resmgr/ICAC_NOx_Control_Installatio.pdf
81 The 8 GW of SCR retrofit occur in the 2030 run year of the model, coinciding with the imposition of the 0.14
lb/mmBtu backstop emission rate. This result suggests that if the need arises, large coal EGUs lacking SCR can
comply with the emission budgets of this rule beyond 2026-2027 by reducing their utilization, providing additional
time if ultimately necessary for SCR retrofits to occur.
Additionally, the 8 GW of capacity that retrofits with SCR is for the policy case presented in the RIA. Additional
modeling that incorporates the Inflation Reduction Act (IRA) projected only 2.6 GW of capacity retrofitting with
SCR.
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some generation to other units, converting to gas, or retiring. Accordingly, EPA considers it appropriate
to evaluate the feasibility of installation of the projected 8 GW of SCR retrofits on the rule's
implementation timeline. EPA believes that, given the timing estimates of 21 months for a single SCR
installation to 35 months for SCR retrofits on seven units at a single facility, a significant increase in
boilermaker labor since 2003, and historical analysis that shows a maximum rate of SCR retrofits after the
NOx SIP Call of 41.7 GW in a single year, despite exceptionally high new gas power plant builds
occurring in that same year, the SCR installation timeline in this rule is feasible and consistent with past
EPA analyses.
For all of these reasons, EPA believes it is feasible to have the majority of SCR retrofits in place within
36 months, but it does allow up to 48 months for full implementation of this measure in the final rule to
accommodate some of the volume-based and supply-side concerns raised by commenters. See preamble
sections V.B 1 e and VI.A.2.a for a full discussion of the changes that EPA is making in the final rule to
address some of the technical concerns about the implementation control technology timing that were
identified by commenters.
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H. Additional Mitigation Technologies Assessed but Not Included in this Action
I. Combustion Control and SCR Retrofits on Combined Cycle and Combustion Turbine Units
Combined Cycle:
While many newer and/or larger combined cycle units are equipped with SCRs, some smaller, older units
do not have a post-combustion control. Based on sample cost estimates, EPA's estimate of the cost of
retrofitting an SCR on a 90 MW natural gas combined cycle unit (operating at an 65% capacity factor and
a 0.05 lb/MMBtu NOx emissions rate) to have an overnight project cost of $5.5 million dollars with an
annual O&M cost of $265,000, or roughly $12,000/ton.82
Evaluating the fleet of combined cycle units in states linked in 2026, there are 46 units, or about 4 GW of
capacity, that do not have an SCR had a NOx emissions rate over 0.05 lb/MMBtu, and a capacity factor
above 10%. If those units were retrofit with SCR, they would have a reduction potential 3,100 tons, or
about 70 tons per unit.
Combustion Turbine:
Roughly 75% of Combustion Turbines use either water injection, Dry Low NOx Burners (DLN), or Ultra
Low NOx Burners (ULN). In some circumstances, these technologies can be difficult to retrofit, given
requirements for either access to sufficient water or space for upgraded combustors. It is estimated that
retrofitting DLN or ULD on a 50 MW combustion turbine that only operated in the summer at a 15%
capacity factor and NOx emission rate of 0.15 lb/MMBtu would have a project cost of roughly $2.2
million dollars with an annual O&M cost of $53,000. That translates to a cost of roughly $21,600/ton.83
Evaluating the fleet of combustion turbine units in states linked in 2023, there are 8 units, or about 450
MW of capacity, that: do not have combustion controls and could achieve a lower emission rate by
retrofitting them; and operated at a capacity factor greater than 10% on average for the 2019-2021 ozone
seasons. Those units have combined 2021 ozone season NOX emissions of 232 tons. If those units were
to retrofit with DLN/ULN, they would have a reduction potential of 97 tons, or about 12 tons per unit.84
While almost 20% of the combustion turbine fleet has an SCR, many units do not have SCRs and operate
at relatively low capacity factors and/or emission rates. EPA estimates the cost of retrofitting an SCR on a
50 MW combustion turbine unit (operating at a 15% capacity factor during the ozone season, and
negligibly the rest of the year, and a 0.15 lb/MMBtu NOx emissions rate) to have an overnight project
cost of $ 14 million dollars with an annual O&M cost of $62,000. The relatively low utilization of the unit
and high project cost imply a cost of roughly $102,000/ton.85
2. Mitigation Strategies at Small Units that Operate on High Electricity Demand Days (HEDD)
Within the universe of combustion turbine EGUs, EPA also examined the subset of units that typically
operate in a "peaking" fashion (i.e., those with low seasonal capacity factors and operating primarily on
82 See the Retrofit Cost Tool Fleetwide Final GNP and the report "Combustion Turbine NOx Technology Memo."
83 See the Retrofit Cost Tool Fleetwide Final GNP and the report "Combustion Turbine NOx Technology Memo."
84 Using a tons per season rather than a capacity factor cutoff, the fleet of combustion turbine units in states linked in
2023, there are 32 units, that: do not have combustion controls and could achieve a lower emission rate by
retrofitting them; and emitted 10 or more tons on average for the 2019-2021 ozone seasons. Those units have
combined 2021 ozone season NOx emissions of 995 tons.
85 See the Retrofit Cost Tool Fleetwide Final GNP and the report "Combustion Turbine NOx Technology Memo."
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days of peak electricity demand). EPA did not identify a broadly available mitigation strategy across this
class of units that was within the range of cost effectiveness values of other EGU strategies included in
the rule at step 3, or that had relatively favorable air quality benefit to cost ratios (as discussed in
preamble section V.D). 890 out of 1117 combustion turbines included in EPA's 2023 analysis for linked
states operated at a capacity factor of 15% or less across the 2021 ozone season (i.e., at levels suggesting
a peaking unit) and averaged less than 0.1 ton of NOx per day. The vast majority emitted less than 5 tons
for the season and did not have a day where they exceeded a single ton of emissions. This heavy
weighting towards low overall emissions and low emission-reduction opportunities from this subset of
units suggests a uniform mitigation strategy applied to all units would deliver relatively little reductions
relative to the amount of sources and relative to the average cost. However, EPA recognizes that within
the heterogenous universe of combustion turbine EGUs, there may be instances where mitigation
measures are cost effective for a given unit. In addition, these units generally operate as part of the
interconnected electricity grid with other EGUs. Therefore, EPA includes this class of units in its CSAPR
trading programs and uses the same approach in this rule. This creates an economic incentive for
emissions reductions to be realized from this class of units to the extent such opportunities exist.
Types of mitigation strategies that could be installed on peaking units range from combustion controls
such as water injection technology to post-combustion controls such as SCR retrofit. As discussed in
section H.l, using representative values characteristic of uniform control treatment, these costs could
range from $24,000/ton (combustion controls) to $115,000/ton (post-combustion control) on average
when applied to the combustion turbine fleet. A mitigation strategy of broadly assumed generation
shifting away from these sources is both limited by the fact that 1) many of these units operate at peak
demand times and may serve critical reliability purposes, and 2) the overall reduction potential is limited
in non-peak times as these units generally do not operate during those periods.
However, EPA's regulatory coverage and allowance holding requirements for these units will extract
emission reduction across this generator type at the limited units where it may be cost effective, even
when a mitigation strategy is not cost-effective across the fleet segment more broadly. The opportunity
cost of an allowance surrendered to cover emissions is anticipated to incentivize any mitigation behavior
where viable in this universe of units and cost-effective at the level of stringency of the overall EGU
control strategy (i.e., around $11,000/ton).
EPA also identifies two features of these units that make this segment well suited towards a market
incentive approach as opposed to assuming any uniform at-the-source mitigation strategies or unit-
specific rate limitations. These are: 1) reliability considerations and 2) existing and ongoing state
regulatory developments.
Peaking units play a unique role in ensuring grid reliability, and in certain areas, as a result of their
function, also may contribute relatively large emissions to ozone levels at nearby receptors. The days that
are conducive to ozone in the summer tend to have high temperatures, and as a result, are associated with
substantial additional electricity demand from air conditioning (among other reasons). To meet this
incremental demand, particularly in some areas where there are noted transmission constraints, small
units that have relatively high emission rates initiate operation. These units are often simple cycle
combustion turbines or oil-fired boilers. They are usually small and only operate a few hours out of the
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summer when they are critical to meeting demand. The generation they provide is likely critical to
ensuring grid stability and power system reliability during these high-demand times.
EPA recently evaluated unit-level operations on HEDD for the States in the Revised CSAPR Update. In
the 12 states affected by the CSAPR Update Revision, EPA identified a total of 1,096 units that operated
during the 2019 ozone season. Of these, 102 units exhibited capacity factors that fell below 10% for the
period. Most of these units (94 out of 102) were combustion turbine units—29 of which were fueled by
oil and 65 were fueled by natural gas. While the 102 identified units, called "peaker units" here (in
reference to their use during "peak" electricity demand), operated in relatively few hours during the 2019
ozone season, an average of 13% of gross generation from these units occurred in higher energy demand
hours, which we define as the top 1% of hours with the highest regional electric load. For 18 of these
units, electricity production in higher energy demand hours accounted for at least 20% of their total
generation for the 2019 ozone season.
With their relatively high emission rates, relatively small seasonal capacity factors, and tendency to
operate on HEDD, the emissions from these units could have substantial emissions and air quality
impacts on high ozone days. An assessment of emissions intensities for the units relative to the state and
regional average emission rate indicates that the emission rates of these units can be up to 118 times their
respective state averages. In the 12-state region, 50 units across 17 facilities had emission intensity values
substantially higher than the state average. Dividing the unit-level 2019 ozone season NOx rate by the
average 2019 ozone season NOx rate for the state indicated that the emission rates for these units were at
least 20 times that of their respective state averages for the 2019 ozone season.
In a separate analysis, EPA identified six states located in the northeastern US in which significant air
quality problems may persist on HEDD—Pennsylvania, New Jersey, New York, Delaware, Connecticut,
and Maryland. For a better understanding of the emissions impact of combustion turbine unit operations,
we compared the peak hour generation and emissions activities of natural gas and oil units located in these
states on sample HEDD and low energy demand days (LEDD). The sample days were chosen from a
selection of 15 days in the 2019 ozone season with the highest and lowest cumulative daily gross load for
all EGUs in CAMD's data sets in the six states. The sampled HEDD and LEDD days and peak hours used
in the analysis are July 30, 16:00, and May 18, 18:00, respectively.
When comparing gross generation between the two days, we observe that combustion turbine natural gas
and oil units generate more in days and hours of higher energy demand. On the sampled LEDD,
combustion turbine natural gas and oil units in the six northeastern states provided a total of 3,953 MWh
of electricity over the course of the day—673 MWh of which was produced in the peak hour (Figure H. 1),
contributing to 539 lbs, or 9% of the total peak hour NOx emissions in the six states (Figure H.2).
Comparatively, on the HEDD, gross generation from combustion turbine units amounted to 28,263 MWh
over the course of the day. Generation in the peak hour reached 2,207 MWh (Figure H. 1), and contributed
to 4,881 lbs, or 19% of total peak hour NOx emissions (Figure H.3).
For the sampled HEDD day, the largest shares of peak hour NOx emissions from combustion turbine
units originate in New York and Pennsylvania (Figure 1.3). A unit-level assessment of peakers in New
York state indicates that while these units are highly emissions-intensive, they provide relatively minimal
generation in peak hours. Specifically, combustion cycle natural gas and oil units in New York contribute
to 1,359 lbs, or 19%, of the state's total peak hour NOx emissions on the sample HEDD, while only
providing 1,186 MWh, or 8%, of generation. On this sample HEDD, the Glenwood and Holtsville
facilities, in particular, account for 4% of total peak hour oil generation in New York but contribute to
31% of the total peak hour NOx emissions from oil units (Figure 1.4). With peak hour NOx rates of 0.44
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lb/MMBtu and 0.58 lb/MMBtu, respectively, the Glenwood and Holtsville facilities are relatively
emissions intensive; however, these units only dispatch in hours and days with higher energy demand. In
2019, Glenwood operated a total of 31 hours, 19 of which fell in the ozone season, while Holtsville ran a
total of 403 hours. Of these, 222 hours fell in the ozone season.
These units have the highest emissions, and the most downwind impact, on particular HEDDs and at
particular receptors that are in relatively close proximity to the peaking units. As discussed above, they
otherwise do not have emissions levels, impacts, or cost-effective emission reduction opportunities that
would warrant imposition of additional control requirements (other than inclusion in the trading program)
at step 3 under the good neighbor provision for the 2015 ozone NAAQS. Moreover, in states with
relatively higher concentrations of peaker units that are in closer proximity to out of state receptors
identified in this rule, EPA observes that mitigation measures have often been implemented. These states,
New York and New Jersey, have already adopted regulations to reduce summertime NOx emissions from
peaking units, and in doing so have conducted thorough assessments of the degree of emissions reduction
that is achievable from these units, particularly in light of their critical function in ensuring grid
reliability.
The New York Department of Environmental Conservation (NY-DEC), for example, adopted a rule in
January 2020 to limit emissions from combustion turbines that operate as peaking units. This rule.
Subpart 227-3,86 entitled "Ozone Season NOx Emission Limits for Simple Cycle and Regenerative
Combustion Turbines." applies to simple cycle combustion turbines (SCCTs) with a nameplate capacity
of 15 MW or greater that supply electricity to the grid. The regulation, more commonly referred to as the
"Peaker Rule", contains two compliance dates with increasingly stringent NOx limits, as follow s: by May
1. 2023, all SCCTs subject to the rule must meet a NOx emission limit of 100 ppmvd,87 and by May 1.
2025, gas-fired SCCTs must meet a NOx emission limit of 25 ppmvd. and distillate or other liquid-fueled
units must a limit of 42 ppmvd. In lieu of meeting these limits directly. New York's rule offers two
alternative compliance options. The first compliance option allows owners and operators to elect an
operating permit condition that would prohibit the source from operating during the ozone season. The
second option allows owners and operators to adhere to an output-based NOx daily emission rate that
includes electric storage and renewable energy under common control with the SCCTs with which they
would be allowed to average.
New York performed comprehensive studies to assess the reliability implications of removing these units
from the system. The 2020 Reliability Needs Assessment Report, carried out by the NYISO in November
2020, found that the deactivation of all peaking units impacted by New York's Peaker Rule without
replacement solutions results in transmission and resource adequacy deficiencies that leave the bulk
power system unable to serve the forecasted load in New York City throughout the study period (up to
2030).88 While units can be retrofitted with new NOx controls to comply with the rule, many of the older
units in New York are not configured in a manner conducive to the retrofit pollution control technology.
These units are therefore likely to elect to retire rather than pay the high installation costs for new water
86 Subpart 227-3 is found within Chapter III. Air Resources, Part 227, of Title 6 of New York Codes. Rules and
Regulations (NYCRR).
87 Parts per million on a dry volume basis at 15% oxygen. Using a heat rate of 15,000 BTUs/KWh identified in New
York's background materials for the rule and the alternative 3 lbs NOx/MWh limit equating to 100 ppmvd, the
equivalent emission rate would be approximately 0.2 lb/MMBtu and significantly lower for the full implementation
of 25 ppmvd. See https://www.dec.try.gov/docs/air pdf/siprevision2273.pdf
88 "2020 Reliability Needs Assessment Report." New York ISO.
https://www.nyiso.com/documents/20142/2248793/2020-RNAReport-Nov2020.pdf
40
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injection systems. Units that elect to retire are required to submit a Generator Deactivation Notice to the
NYISO. If they do so, the NYISO will perform a Generator Deactivation Assessment to ensure that the
retirement of the respective unit does not create reliability issues for the system. Units identified by this
assessment as being necessary for grid reliability receive a two-year extension on their compliance
deadlines.
New Jersey addressed the issue of NOx emissions on peak energy demand days with a rule that defines
peak energy usage days, referred to as high electric demand days (HEDD), and sets operational
restrictions for HEDD units that operate on these days.89,9" New Jersey's HEDD Rules came into effect on
May 19, 2009, and imposed emissions control requirements for units with NOx rates exceeding 0.15
lb/MMBtu and lacking identified control technologies.91
Due to their relatively small size, large number of units, potentially high control costs, low emission
reduction potential, reliability considerations, and existing regulations, EPA does not identify any
uniform, cost-effective mitigation strategy for this class of units as a whole in its EGU NOx mitigation
strategy assessment for this rule. EPA recognizes heterogeneity in receptor impacts and emissions
reduction potential across these types of units, but in the one region where emissions reductions at such
units may be warranted due to uniquely large impacts at nearby out-of-state receptors (i.e., in the New
York City area), the immediate two upwind states have already adopted measures to reduce emissions
from these units. EPA does not have sufficient information on the current record that would warrant
assuming application of additional mitigation technologies beyond those already in place or otherwise
incentivized or required. Nonetheless, EPA does include these units, along with all other EGUs meeting
applicability criteria, in this rule as covered sources (as in prior CSAPR trading programs). Inclusion in
the trading program will create an economic incentive for these units to take advantage of economical
emission reduction opportunities wherever available.
Figure H.l. Hourly gross generation by combustion turbine natural gas and oil units in the six
northeastern states on sampled LEDD and HEDD
Hourly grosi generation by combustion turbine natural gas and «1 units in hjc northeastern states on LEDD.
89 N.J.A.C. § 7:27-19
911 HEDD units are EGUs greater or equal to 15MW that commenced operation prior to May 1, 2005, and that
operated less than or equal to an average of 50% of the time during the ozone seasons of 2005 and 2007.
91 CTs are required to have water injection or selective catalytic reduction (SCR) controls; steam units must have
either an SCR or noncatalytic reduction (SNCR)
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Figure H.2. Percentage share of peak hour NOx emissions by unit type across region and states on a
sampled LEDD
Peak hour NOx emissions by unit-type across states and region on LEDD1,
lb
¦ Combust ho Turbine ¦ Other
Region and States
CT share of
emissions.
1) M ay 13lh (18:00) is used as the exemplary LEDD dav and peak hour.
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Figure H.3. Percentage share of peak hour NOx emissions by unit type across region and states on an
sampled HEDD (Source: Clean Air Markets Program Data (CAMPD), campd.epa.gov, EPA, 2020)
Peak hour NOx emissions by unit-type across states and region on HEDD1,
lb
O 2HHH
a
s i™»
Z
*5
J 10000
¦ Contxjstinc Turtine ¦ Other
¦
MO
Regfciri arid States
4^^
CT share of
emissions.
1) Ji% 30"' (16:Q0f is used as the exemplary HEDD day and peak haur.
Figure H.4. Peak hour generation and emissions on HEDD by oil units in NY as a percentage (Source:
Clean Air Markets Program Data (CAMPD), campd.epa.gov, EPA, 2020)
Peak hour gross generation on a HEDD from oil units in NY state1-2. Peak hour NOx emissions on a HEDD from oil units in NY state,
MWh Pounds
19%
20%
33%
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Appendix A: Historical Anhydrous Ammonia and Urea Costs and their Associated Cost
per NOx ton Removed in a SCR
Minimum Cost to Operate Anhydrous NH3 & Urea costs ($/ton) [from USDA]
Year
NH3 (anh)
NH3 Cost
Urea cost
Urea Cost
Cost
/ ton NOx
/ ton NOx
2009
$ 562
$ 320
$425
$425
2010
$ 548
$ 312
$424
$424
2011
$ 801
$457
$ 543
$ 543
2012
$ 808
$461
$ 746
$ 746
2013
$ 866
$494
$ 508
$ 508
2014
$ 739
$421
$ 533
$ 533
2015
$ 729
$416
$472
$472
2016
$ 588
$ 335
$ 354
$ 354
2017
$ 501
$286
$ 328
$ 328
2018
$ 517
$295
$ 357
$ 357
2019
$ 612
$ 349
$433
$433
2020
$499
$284
$ 375
$ 375
2021
$727
$414
$543
$543
2022
$1,469
$837
$895
$895
Feb 23, 2023
$1,237
$705
$655
$655
Average price from the first reporting period in July of each year, except where otherwise noted.
Source: Illinois Production Cost Report (GX_GR210) USDA-IIL, Dept of Ag Market News Service,
Springfield, IL
www. ams.usda.gov/mnretx) rts/ gx g r210. txt
www .ams.usda. gov/LPSMarketN ew sPage
For February 23, 2023 report, see:
https://mvmarketnews.ams.usda.gov/filerepo/sites/default/files/3195/2023-02-
23/682504/an I080.pdf
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Appendix B: Cost Sensitivity Analysis for SCR/SNCR Optimization and SCR Retrofit
Using the retrofit cost tool, EPA conducted a series of sensitivity analyses, assessing how the costs for
SCR and SNCR optimization and retrofit responded to variation in a number of the input parameters.92
EPA assessed the sensitivity of cost to variation in:
1. Interest Rate and Debt Life (encapsulated in the Annual Capital Recovery Factor);
2. Coal Type; and
3. Material and Labor Costs
4. Urea Costs
5. Limiting Geography to Covered States
6. Fleet Updates since the proposed rule
These sensitivities show that for each of these parameters that, while there is some variation, the costs are
comparable enough to the representative values that we have identified in the earlier sections that they
would not change EPA's conclusions about the cost-effectiveness of the selected control stringency for
the purposes of this rule. Preamble section V.B.I discusses these sensitivities.
1. Interest Rate and Debt Life (Capital Recovery Factor)
EPA performed sensitivities that assessed the effects of interest rates and the time-period of the book life
(or loan term) on costs (on a dollar per ton basis) for new post-combustion controls. First, EPA examined
the effect of interest rates, while assuming a 15-year debt life, or the duration of the loan used to finance
the retrofit. The default value that EPA has used is 11.5% (resulting in an annual capital recovery factor
of 0.143).93 A simplified formula to transform the interest rate to the capital recovery factor is:
Capital Recovery Factor =I/(1-((1+I)A-T)) Equation B-l
Where the Capital Recovery Factor is a fraction, I is the interest rate (expressed as a decimal), and T is
the Debt Life (in years).
EPA assessed the effects of interest rates ranging from 7.5% up to 14.5% on the cost on a dollars per ton
basis for the controls. This varied the annual capital recovery factor from 0.113 up to 0.167. The costs,
then varied from $9,000/ton to $12,600/ton (Figure B-3).
92 Modified versions of the Retrofit Cost Tool for these sensitivities can be found in the docket.
1. Retrofit Cost Tool Fleetwide Final GNP Sensitivity CRF Debt Life and Interest Rate
2. Retrofit Cost Tool Fleetwide Final GNP Sensitivity Coal Type
3. Retrofit Cost Tool Fleetwide Final GNP Sensitivity Material and Labor Cost
4. Retrofit Cost Tool Fleetwide Final GNP Sensitivity Urea Cost
5. Retrofit Cost Tool Fleetwide Final GNP Sensitivity Geography
6. Retrofit Cost Tool Fleetwide Final GNP Sensitivity Updated Fleet
93 The 15-year debt life is the same as used in IPM and the 11.5% interest rate is a blend of the capital charge rates
for environmental retrofits for utility and merchant owned units. See chapter 10 of the "Documentation for
EPA's Power Sector Modeling Platform v6 Using the Integrated Planning Model." (Sept 2021).
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SCR Retrofit (Coal) Cost Weighted Avg $/ton
14,000
12,000
10,000
X
i 8,000
C
*2 6,000
-------
2. Coal Type
EPA performed a cost sensitivity that assessed the effect of coal-type (i.e., lignite, bituminous,
subbituminous) on costs (on a dollar per ton basis) for post-combustion controls for coal-fired units. We
examined both the costs to turn on and optimize existing controls and to install and operate new post-
combustion controls. We selected subsets of units that operated using various types of coals.94 As in the
retrofit cost tool, subbituminous coal type is referred to as PRB coal, since a source region for this coal
type that is widely used is the Powder River Basin. The results of this assessment can be found in Table
B-l. For turning on and optimizing existing SCRs, the weighted average costs varied from $800/tonto
$1000/ton, compared with the fleetwide average of $900/ton that accounts for all units, but does not
distinguish between units using one type of coal compared with another. For installing and operating new
SCR post-combustion controls, the weighted average costs varied from $8,100 to $12,100/ton for lignite
to PRB coal type. The fleetwide average was $11,000/ton.
Table B-l. Weighted average cost on a dollar per ton of Nox removed basis as a function of coal
type for turning on and optimizing SCR control and for installing and operating a new SCR
control.
Coal Type
SCR Optimization
SCR Retrofit
Bituminous
$ 800
$ 10,300
Lignite
$ 8,100
PRB
$ 1,000
$ 12,100
All
$900
$ 11,000
3. Material and Labor Costs
EPA conducted analysis to examine the effects of potential changes to material and labor costs on SCR
and SNCR installation. We expect that control installation and operation will be responsive to economy-
wide changes in cost, such as inflation. One particular focus of commenters was the recent increases in
SCR retrofit costs due to inflation. Since EPA continues to use 2016 dollars for this rulemaking, only
changes in retrofit prices in excess of the general inflation rate would affect the material or labor costs. To
determine any difference in inflation, EPA considered the change in CPI-U from January 2021 to July
2022 with the Handy-Whitman Steam Production Plant Index, since July 2022 is the most recent data
available for the Handy-Whitman Index. Over this time period, CPI-U increased 12.6% while the Handy-
Whitman Index increased 19.5%.95, or a difference of 6.9%. Therefore, the current costs for SCRs may be
slightly higher than the calculations presented in Sections E and F of this TSD. However, EPA notes that
since this summer, the prices of many materials have stopped increasing and, in many cases, decreased
significantly, as discussed in Section G of this TSD and the "NOx Emission Control Technology
Installation Timing for Non-EGU Sources" report.
94 For units that according to the NEEDS database utilize several types of coal, or that utilize blends of various coals,
we selected a single type of coal to apply. For details see the column Z on the SRChorz worksheet of the Retrofit
Cost Tool Fleetwide Final GNP in the docket for this rulemaking
95 CPI-U data accessed 2/3/2023: https://fred.stlonisfed.org/series/CPIAUCSL ;
For Handy-Whitman Index increase, see the "Coal-Fired SCR Cost Methodology" report.
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EPA examined the cost components within the Retrofit Cost Tool for SCR and SNCR retrofits, focusing
on the capital cost components that could have relatively higher or lower costs than "average" inflation
levels (as a result, for example, because of supply chain issues or other production issues).
We observed that the "retrofit factor" could provide a mechanism to adjust the relative costs for some of
the components (particularly those that are focused on capital expenditures). As described in the
documentation, the retrofit factor is used to account for the difficulty in construction of the control
system, with an average value of 1 being the default value for a "retrofit of average difficulty".96 We
performed a series of sensitivity analyses for SCR and SNCR retrofit costs, where we adjusted the retrofit
factor over a wide range of values, from 0.75 to 1.25, meaning that the relative costs of some of the
components could be 25% higher (or lower) than EPA's base assumptions. The relationship between the
cost on a dollar per ton basis can be seen in Figure B-5. The weighted average cost of NOX reductions for
retrofits scales nearly linearly with the retrofit factor, as shown in figure B-5. For the SCR retrofit for the
coal-fired SCR, the cost varied from $8,600/ton to $13,300/ton. For the SNCR retrofit, the cost was less
sensitive, varying from $6,200 to $9,300/ton. For the SCR retrofits, the response is more sensitive
because the capital costs of the controls are a larger proportion of the total cost compared to SNCR
retrofits.
Weighted Avg Cost NOx Reduction $/ton vs Retrofit Factor
di a nnn
$12,000
$10,000
X
| $8,000
C
£3 $6,000
$4,000
$2,000
$-
0.
—•—New S
25
75 0.8 0.85 0.9 0.95 1 1.05 1.1 1.15 1.2 1.
Retrofit Factor
:R: Coal —•—New SCR: O/G Steam -»-New SNCR: Coal < 100 MW
Figure B-5. SCR or SNCR retrofit cost on a dollar per ton basis as a function of the retrofit factor.
4. Urea Costs
EPA performed a sensitivity analysis that assessed the effects of reagent cost on costs (on a dollar per ton
basis) for operation as well as the installation operation of newly retrofitted post-combustion controls. In
the retrofit cost analyzer, one of the variables is for the cost of urea for a 50% weight solution. The default
value is $350/ton. Based on the equations in the tool, variations in the urea cost would affect the VOM
cost components. Consequently, the controls that have higher default reagent costs would be more
sensitive to changes in reagent cost (on a per ton of NOx removed basis). The sensitivity analyses
examined here confirm that assessment. They also complement the analyses described above in Section B
and Appendix A of this TSD. Here, we varied the reagent cost from $100/ton up to $l,000/ton, which
96 See "Coal-Fired SCR Cost Methodology" report. The retrofit factor is used to multiply the "SCR Island" and the
"Booster Fan and Auxiliary Power Modification" portions of the capital cost; and the "Additional Maintenance and
Material" portion of the fixed O&M cost. It does not affect variable O&M cost.
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brackets the historical values in Appendix A, and then observed the response in the cost of turning on and
operating existing SCR and SNCR controls for coal-steam units and for installing and operating new SCR
and SNCR controls for coal-fired and oil-gas steam unit (Figure B-6). As can be seen in the figure, and as
was expected, the weighted average dollar per ton cost was most sensitive for the SNCR units (with their
relatively high reagent VOM costs). The costs varied from $850/ton (at $100/ton urea) to $5,500/ton (at
$l,000/ton urea) for the coal-fired unit with an existing SNCR. The costs for SCR units were much less
sensitive, appearing to vary with the cost (i.e., as the reagent cost increased from $100 to $900, the cost
for operating the control increased in about the same amount) (Figure B-6).
Weighted Avg $/ton NOx Cost vs Urea Price
$15,000
x
O
$10,000
c
o
-co-
$5,000
$0
$100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000
Urea Price ($/ton)
SCR: Off to On (Coal) SCR: New (Coal)
SNCR: Off to on (Coal) SNCR: New (Coal Under 100 MW Only)
SCR: New (OG Steam)
Figure B-6. SCR or SNCR operation and retrofit cost on a dollar per ton basis as a function of the cost of
urea for a 50% weight solution.
5. Limiting Geography to Covered States
EPA performed a sensitivity analysis that assessed the costs of controls (on a dollar per ton of NOx
removed basis) when the fleet of units analyzed is limited to the units from states that are included in the
rule (rather than the comprehensive nationwide fleet). We examined the weighted average cost for
retrofitting coal-fired units with SCR, for turning on and optimizing SCR for coal-fired units with existing
SCR, for installing and/or turning on and optimizing SCR for oil-gas steam units, and for installing new
SNCR for coal-fired units under 100 MW. Generally, we observe very little difference in costs in each of
these categories (Table B-2), with some weighted average costs slightly lower with the analyzed fleet
limited to the covered geography.
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Table B-2. Weighted average cost on a dollar per ton of NOx removed basis for the nationwide fleet
of EGUs compared with a fleet that is limited to the geography of the rule.
Units in
All States
Only Units
in Covered
States
Coal Steam SCR
New SCR, with 0.05 lb/mmBtu rate:
$11,000
$11,000
Coal Steam SCR
Existing SCR off to on and optimized at
3rd best:
$900
$800
Coal Steam
SNCR
New SNCR Under 100 MW Only
$6,800
$5,700
O/G Steam SCR
New SCR, with 0.03 lb/mmBtu rate:
$7,700
$7,600
O/G Steam SCR
Existing SCR off to on and optimized at
3rd best:
$700
$700
6. Fleet Updates since the proposed rule
EPA performed a sensitivity analysis that assessed the weighted average costs of controls (on a dollar per
ton of NOx removed basis) when the fleet of units analyzed was adjusted to include currently operating
units from the nationwide fleet. In this assessment, we removed several units, namely Wansley 1 and 2;
Erickson 1, Coffeyville 4, Garden City S-2, West Springfield 3, Plant X 113B, Gadsden 1 and 2, and
Decker Creek 2 that are retiring before 2023 ozone season. We also added several units, namely Merom
1SG1; Merom 2SG1; Muscatine 8; Dan E Karn 1; Dan E Karn 2; Sherburne County 2; Morgantown
Energy Facility CFB1; and Edgewater (4050) 5. Making these fleet changes had no impact on Coal or
O/G Steam SCR optimization or retrofit costs.
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