Technical Support Document (TSD)
for the Proposed Revised CSAPR Update for the 2008 Ozone NAAQS
Docket ID No. EPA-HQ-OAR-2020-0272
EGU NOx Mitigation Strategies Proposed Rule TSD
U.S. Environmental Protection Agency
Office of Air and Radiation
October 2020
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Introduction:
The analysis presented in this document supports the EPA's proposed Revised CSAPR Update for the
2008 Ozone NAAQS. In developing the proposed Revised CSAPR Update, 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 or shifting generation to reduce NOx emissions). These analyses inform
the EPA's evaluation of costs and emission reductions in Step 3 of its four step interstate transport
framework. These mitigation technology assessments are also central to EPA's electricity system impact
estimates, compliance feasibility assessments, and emissions budget determinations for the proposed
Revised CSAPR Update Rule.
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;
• Installing new SNCR systems; and
• Shifting generation (i.e., changing dispatch) from high- to low-emitting or zero-emitting units.
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 researched by Sargent & Lundy, a nationally recognized architect/engineering firm with the EGU
sector expertise. From this research, EPA has created a publicly available Excel-based tool called the
Retrofit Cost Analyzer that implements the cost equations.1 Application of the Retrofit Cost Analyzer
equations to the existing coal-fired fleet can be found in the docket.2 EPA also used the Integrated
Planning Model (IPM) to analyze power sector response while accounting for electricity market dynamics
such as generation shifting.
Cost Estimate for Fully Operating Existing SCR that Already Operate to Some Extent
EPA sought to examine costs for full operation of SCR controls. 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
1 See https://www.epa.gov/airmarkets/retrofit-cost-analvzer for the location of the Excel tool and for the
documentation of the underlying equations in Attachment 5-3: SCR Cost Methodology (PDF) and Attachment 5-4:
SNCR Cost Methodology (PDF).
2 See the file "EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx" for detailed cost estimates using the
Retrofit Cost Analyzer for SCR and SNCR operation and installation.
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NOx. Over time 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 chemical reagent (typically ammonia or
urea) is a significant portion of the operating cost of these controls.
EPA examined the costs to fully operate an SCR that was already being operated to some extent using the
equations within the Retrofit Cost Analyzer. There are variable operations and maintenance (VOM) costs
related to the consumption of reagent and degredation of the catalyst as well as fixed operating and
maintenance (FOM) costs related to maintaining and operating the equipment to be considered.
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. Consequently, the EPA finds it reasonable to
consider the costs of both additional reagent and catalyst maintenance and replacement in representing the
cost of optimizing existing and operating SCR 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.
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 degredation, 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. 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.
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 $500 per ton of NOx removed (1999$) with
ammonia costing $ 190 per ton of ammonia, which equated to $ 108 per 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. Consequently, the reagent costs used by EPA in this 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
conservative estimate. In the CSAPR Update, EPA used the default cost of $310/ton for a 50% weight
solution in 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, EPA
conservatively 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.
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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 coal-fired units that operated in 2019 in the United States on a per ton of NOx
removed basis. This assessment covered 223 units.3 EPA was able to identify the costs of individual
VOM and FOM cost components, including reagent, catalyst, and auxiliary fans. 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 conservatively 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 uncontrolled, or "input", NOx rate, the NOx removal
efficiency, the type of coal, and the capacity factor.4
In the analysis, we assumed these units burned bituminous coal at a 47.6% capacity factor.5 We assumed
that the SCRs operate with the NOx removal efficiency needed for them to achieve their third-lowest
ozone season NOx rate over the time-period from 2009-2019.6 In this section, where we are assessing the
cost to return a partially operating SCR to full operation, we examined only the sum of the VOM reagent
and catalyst cost components (from the set of 153 units that had minimum "input" NOx emission rates of
at least 0.2 lb/mmBtu).7 EPA ranked the quantified VOM costs for each unit and identified the cost at the
90th percentile level rank, which rounded to $800 per ton of NOx removed. EPA also identified the
average cost which rounded to $700 per ton of NOx removed. EPA selected the 90th percentile value
because a substantial portion of units had combined reagent and catalyst costs at or less than this $800/ton
of NOx removed.
Thus, $800 per ton NOx removed represents a reasonable estimate of the cost for operating these post
combustion controls based on current market prices and typical operation. For purposes of the IPM
modeling, the agency assumes that $800 per ton of NOx removed is a broadly available cost point for
units that currently are partially operating SCRs to fully operate their NOx controls.
3 See the file "EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx" for detailed cost estimates using the
Retrofit Cost Analyzer for SCR and SNCR operation and installation.
4 For the input NOx rate, each unit's maximum average ozone season (or non-ozone season) emission rate was
examined from the period 2003-2019 (inclusively) for the purpose of identifying the unit's maximum emission rate
during time periods when the control was not operating. The long timeframe allowed examination prior to the onset
of annual NOx trading programs (e.g., CAIR and CSAPR). For units where controls have always operated year-
round, this method will underestimate the input NOx rate.
5 EPA evaluated costs of SCR operation utilizing a capacity factor value representing recent unit operation. EPA
identified the 2019 heat input weighted ozone season capacity factor of 47.6% for 193 coal units with SCR on-line
at the start of 2019 and which have nonzero 2019 heat input and are in the CSAPR Update region.
6 The NOx removal efficiency varies by unit and is based on the ozone season or non-ozone season with the highest
NOx rate for the time-period 2003-2019 and is based on the third-lowest ozone season rate from 2009-2019. The
third-lowest ozone season rate from 2009-2019 was selected as the "controlled" rate. This was selected because it
represented a time when the unit was most likely consistently and efficiently operating its SCR over a time period
when the unit would be expected to operate on an annual basis.
7 A NOx emission rate at or above 0.2 lb/mmBtu may be indicative of emissions from units where the SCR is not
operating. See the discussion about state-of-the-art combustion controls for details about why 0.2 lb/mmBtu is an
appropriate emission rate when only combustion controls are being utilized.
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Cost Estimates for Restarting Idled Existing SCR
For a unit with an idled, bypassed, or mothballed SCR, all FOM and VOM costs such as auxiliary fan
power, catalyst costs, and additional administrative costs (labor) are realized upon resuming operation
through full potential capability. To understand the costs, the agency applied the Retrofit Cost Analyzer
equations for two "typical" units with varying input NOx rates in a bounding analysis and then did a more
detailed analysis encompassing all coal-fired units with SCR that operated in 2019 in the contiguous
United States. For both analyses, the agency assumed the same input parameters used for the partially-
operating SCR analysis described above, but in keeping with this assessment's focus on restarting SCRs
that are not already operating, these analyses included the auxiliary fan power VOM component and all of
the FOM components along with the reagent and catalyst VOM components in the total cost estimate.
First, to better 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 from reactivating an existing but idled SCR across a range of potential uncontrolled NOx
rates.8 Similar to what was described at proposal, for a hypothetical 500 MW unit with a relatively high
uncontrolled NOx rate (e.g., 0.4 lb NOx/mmBtu, 80% removal efficiency, 47.6% capacity factor, and
10,000 Btu/kWh heat rate), VOM and FOM costs were around $l,050/ton of NOx removed. Conversely,
a unit with a low uncontrolled NOx rate (e.g., 0.2 lb NOx/mmBtu and 60% removal) experienced a higher
cost range revealing VOM and FOM costs about $l,840/ton of NOx removed.
Next, using the Retrofit Cost Analyzer cost equations and same input parameters described above for
unit-specific input NOx rate and third best controlled NOx rate, EPA evaluated all of the VOM and FOM
costs for the 153 coal-fired units with SCR in the contiguous United States that were operating in 2019
and had minimum "input" NOx emission rates of at least 0.2 lb/mmBtu.9 As before, EPA ranked the sum
of the VOM and FOM costs for each unit and identified the 90th percentile cost. When rounded, this was
$l,600/ton of NOx removed. EPA also identified the average cost, which rounded to $l,200/ton of NOx
removed. Specifically, this assessment found that 137 of the 153 units demonstrated VOM plus FOM
costs lowerthan $l,600/ton ofNOx removed.10
Examining the results, the EPA concludes that a cost of $l,600/ton ofNOx removed is reasonably
representative of the cost to restart and fully operate idled SCRs.
NOx Emission Rate Estimates for Full SCR Operation
EPA examined the ozone season average NOx rates for 250 coal-fired units in the contiguous US with an
installed SCR over the time-period 2009-2019, then identified each unit's lowest, second lowest, and
third-lowest ozone season average NOx rate.11 EPA examined ozone season average NOx rates over this
time period since annual NOx programs, rather than just seasonal programs, became widespread in the
eastern US with the start of CAIR in 2009, and this regulatory development could affect SCR operation
8 For these hypothetical cases, the "uncontrolled" NOx rate includes the effects of existing combustion controls
present (i.e., low NOx burners).
9 See the file "EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx" for detailed cost estimates using the
Retrofit Cost Analyzer for SCR and SNCR operation and installation.
10 Given the sensitivity of the cost to the input uncontrolled NOx rates, EPA examined the units with higher costs
and observed that some exhibited low, uncontrolled NOx rates suggesting that, perhaps, the SCR may have been
consistently operated year-round over the entire time-period. A low uncontrolled NOx rate would result in a low
number of tons ofNOx removed, and, thus, a high cost on a "per ton ofNOx removed" basis when modest fixed and
variable costs are divided by just a few tons of NOx removed.
11 See "SCR_Historical_OS_Rates_Revised_CSAPR_Update_Proposal.xlsx" for details.
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(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 final CSAPR Update focused on the third-lowest ozone season NOx rates,
reasoning that these emission rates may be characteristic of a well-run and well-maintained system and
achievable on a routine basis, while avoiding atypical times such as the start of a new regulatory program
when several catalyst layers may have been simultaneously refreshed or years when the operation of the
unit is not similar to recent or expected operational patterns. In the CSAPR Update, EPA focused on the
third lowest ozone season rate over the 2009-2015 time period to ensure that the rate represents efficient
but routine SCR operation (i.e., the performance of the SCR is not simply the result of being new, or
having a highly aggressive catalyst replacement schedule such as may be found at the onset of new
emission reduction programs, but is the result of being well-maintained and well-run). At that time, 2015
represented the most recent year of full ozone-season data available. In the CSAPR Update, EPA found
that, between 2009 and 2015, EGUs on average achieved a rate of 0.10 lbs NOx/mmBtu for the third-
lowest ozone season rate. In the CSAPR Update, EPA selected 0.10 lbs NOx/mmBtu as a reasonable
representation for full operational capability of an SCR. Here, EPA utilizes the same rationale and
methodology for identifying the rate. However, EPA updates the timeline to include most-recent
operational data (i.e., up through 2019). Considering the emissions data over the full time-period of
available data that includes expected annual operation of SCRs (i.e., 2009-2019) results in a third-best
rate of 0.080 lb/mmBtu. EPA notes that half of the EGUs achieved a rate of 0.68 lbs NOx/mmBtu or less
over their third-best entire ozone season (see Figure 1). EPA verified that in prior years, the majority
(over 90%) of these same coal-fired units had demonstrated and achieved a NOx emission rate of 0.08
lb/mmBtu or less on a seasonal and/or monthly basis.12
After identifying this approach, the Agency examined each ozone season over the time period from 2009-
2019 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 0.069 lbs
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 2).
Based on the ozone season emission rates, and supported by the monthly rates, the agency concludes an
emission rate of 0.08 lb NOx/mmBtu is widely achievable by the EGU fleet.13
Figure 1. "Frequency" distribution plots for coal-fired units with an SCR showing their seasonal average
NOx emission rates (lbs/mmBtu) during ozone seasons from 2009-2019. For each unit, the lowest,
second lowest, and third lowest ozone season average NOx rates are illustrated.
12 See "Optimizing SCR Units with Best Historical NOx Rates.xlsx" included in the Docket
13 EPA also reviewed historical hourly data and observed reduced capacity factor was not a primary driver of
emission rate performance at levels above 20% for SCR controlled coal units in 2019.
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Lowest Seasonal Average Ozone-Season NOx Rates
60
50
2 30
a;
-Q
E
= 20
10
lowest (0.068 avg)
2nd lowest (0.075 avg)
3rd lowest (0.080 avg)
O* qV & & q> N" Q>
Ov Ov 0V 0V 0V Ov 0V 0V 0V ° 0> C> O-* O Cr °
NOx Rate (Ibs/mmBtu)
Figure 2. "Frequency" distribution plots for coal-fired units with an SCR showing their monthly average
NOx emission rates (Ibs/mmBtu) during ozone seasons from 2009-2019. For each unit, the lowest,
second lowest, third lowest, fourth lowest, and fifth lowest monthly average NOx rates are illustrated.
Lowest Monthly Average Ozone-Season NOx Rates
lowest
2nd lowest
3rd lowest
4th lowest
5th lowest
Q* & Cy> cj* cS3 ^ & o> N* N1, '*y> '^ ''V3 '^ ^
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same level ofNOx 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"
unit returning an SNCR to full operation. For units with a mothballed SNCR returning to full operation,
the owner incurs the full suite of VOM and FOM costs. Reagent consumption represents the largest
portion of the VOM cost component. For this bounding analysis, the agency examined two cases: first, a
unit with a high input uncontrolled NOx rate 0.40 lb/mmBtu; second, a unit with a low input uncontrolled
NOx rate 0.20 lb /mmBtu - both assuming a 25% removal efficiency.14 For the high rate unit case, VOM
and FOM costs were calculated as approximately $2,300/ton NOx with about $l,820/ton of that cost
associated with urea procurement. For the low rate unit case, VOM and FOM costs approached
$3,890/ton NOx with nearly $3,040/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 uncontrolled NOx emission rate. In these studies, 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 uncontrolled rate of 0.40 lb NOx/mmBtu, the associated costs were $2,210/ton and
$2,600/ton. For a low rate unit with an uncontrolled rate of 0.20 lb NOx/mmBtu, the associated costs
were $3,730/ton and $4,4700/ton. This analysis illustrates that SNCR costs ($/ton) are more sensitive to a
unit's uncontrolled input NOx rate than the potential NOx removal efficiency of the SNCR itself.
Examining the results across all the simulations, but focusing on the 25% removal efficiency scenario for
the low input uncontrolled NOx rate, which is more representative of typical removal efficiency, EPA
finds that costs for fully operating idled SNCR are substantially higher than for SCR. We conclude that a
cost of $3,900/ton ofNOx removed is representative of the cost to restart and fully operate idled SNCRs.
NOx Emission Rate Estimates for Full SNCR Operation
As EPA notes above, both in the CSAPR Update Rule and in the agency's power sector modeling up to
25% removal potential for SNCR was assumed. In order to translate what this optimized value would be
for each unit, and compare that to 2019 baseline emission rates, EPA utilized the mode 2 rate from the
NEEDS database (June 2020). 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.15 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 coal units is intended to reflect the operation of that unit's post combustion control
based on prior years when that unit operated its control. As noted above, SNCRs are more sensitive to a
unit's uncontrolled input NOx rate than the potential NOx removal efficiency. Consequently, the
"optimized" SNCR emission rate identified through mode 2 has more variability than the optimized rate
14 For both cases, we examined a 500 MW unit with a heat rate of 10,000 Btu/kWh operated at a 27.3% annual
capacity factor while burning bituminous coal. The 2019 heat input weighted ozone season capacity factor for 44
coal units with SNCR on-line at the start of 2019 and which have nonzero 2019 heat input and are in the CSAPR
Update region was 27.3%. Furthermore, in the cost assessment performed here, the agency conservatively assumes
SNCR NOx removal efficiency to be 25%, noting that multiple installations have achieved better results in practice.
25% removal efficiency is the default NOx removal efficiency value from the IPM documentation. See
https://www.epa.gov/airmarkets/retrofit-cost-analvzer for the location of the Excel tool and for the documentation of
the underlying equations in Attachment 5-4: SNCR Cost Methodology (PDF).
15 https://www.epa.gov/sites/production/files/2019-03/documents/chapter_3_0.pdf
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assumed for SCR installations (which typically begin to approximate an emission rate floor due to the
90% reduction). The optimized SNCR emission rates assumed for each controlled unit are identifiable in
the NEEDS file "Mode 2 NOx rate (lb/mmBtu)" column.16 If a unit's 2019 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.
Cost Estimates for Installing Low NOx Burners and / or Over Fire Air
Combustion control technology has existed for many decades. The technology generally limits NOx
formation during the combustion process by extending the combustion zone. Over time, 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. Table 1 shows average NOx rates from coal-fired units with various
combustion controls for different time periods.
Table 1: Ozone Season NOx Rate (lb/mmBtu) Over Time for Coal-fired Units with Various
Combustion Controls*
Years
Years
Between 2003
Between 2009
Year =
2019
and 2008
and 2018
NOx Kntc
(Ihinmlitu)
Number
NOx Kntc
(Ihinmlitu)
Number
NOx Rate
(Ihinmlitu)
Number
NOx Control Technology
ot'linit-
Ycn i's
ot'linit-
Ycn i's
of linit-
Ycn i's
Overfire Air
0.384
476
0.294
603
0.221
30
Low NOx Burner Technology (Dry Bottom
only)
0.351
1,062
0.270
1,126
0.209
46
Low NOx Burner Technology w/ Overfire
Air
0.306
464
0.228
672
0.202
41
Low NOx Burner Technology w/ Closed-
coupled OFA
Low NOx Burner Technology w/Separated
OFA
0.266
0.222
341
451
0.223
0.191
326
584
0.187
0.159
20
33
Low NOx Burner Technology w/ Closed-
coupled/Separated OFA
0.207
460
0.169
773
0.147
59
* Source: Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2020
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
regulation, the agency evaluated EGU NOx reduction potential based on upgrading units to modern
combustion controls. Combustion control upgrade paths are shown in Table 3-11 of the IPM version 6
documentation (see Chapters 3 and 5 of the IPM documentation for additional information, and Table 2
below).17 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-
16 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
17 https://www.epa.gOv/sites/production/files/2018-08/documents/epa_platform_v6_documentation_-
_all_chapters_august_23_2018_updated_table_6 -2 .pdf
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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 National Electric Energy Data
System v6 (NEEDS) database file.18 EPA identified whether a unit has combustion control upgrade
potential by comparing the Mode 1 NOx Rate (lbs/mmBtu) with the Mode 3 NOx Rate (lbs/mmBtu)
within NEEDS. If the Mode 3 value is lower than the Mode 1 value, than the unit's combustion control
configuration does not match the state-of-the-art configuration outlined in Table 2. For these units, EPA
assumed a combustion control 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.19 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 (2011$) of NOx
Combustion Controls for Coal Boilers (300 MW Size)" from Chapter 5 of the IPM 5.13 documentation.20
For these paths, EPA found that the cost ranges from $420 to $ 1140 per ton NOx removed ($2011). EPA
examined slightly lower capacity factors (i.e., 70%) and found the costs increased from $510 to $1,370
per ton. At lower capacity factors (i.e., 47.6%), costs increased to a max of $1,970 per ton for one type
of installation.21 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
and cost-effective.
NOx Emission Rate Estimates for LNB upgrade
EPA first identified the current boiler type of a given unit, and then applied the information shown below
in Table 2 regarding state-of-the-art configurations compared to a unit's reported combustion control
figuration to determine whether the unit had combustion control upgrade potential. If so, then EPA
assumed the combustion control upgrade configuration would yield an emission rate of 0.1549 lb/mmBtu
for dry-bottom wall fired boilers that were upgrading their combustion controls. EPA assumed a rate of
0.1390 lb/mmBtu for tangentially-fired coal boilers that were upgrading their controls. These estimates
were derived 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 - dry bottom wall-fired boilers and tangentially fired boilers - with state-of-
18 See the NEEDS v.6 data file available in the docket and for download at https://www.epa.gov/airmarkets/national-
electric~energv-data~svstem~needs~v6
19 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 an input uncontrolled NOx rate of 0.50 lb NOx /
mmBtu initial rate and had a 42% NOx removal efficiency after the combustion control upgrades. This 0.50
lbs/mmBtu input NOx rate is comparable to the observed average rate of 0.48 lbs/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 uncontrolled wall-fired coal units 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 uncontrolled units, to be conservative, EPA used the 42% reduction from wall-fired coal units.
20 https://www.epa.gOv/sites/production/files/2015-07/documents/chapter_5_emission_control_technologies_0.pdf
21 When EPA analyzed low capacity factor/low emission rate scenarios down to capacity factors of 47% and
emission rates of 0.30 lb/mmBtu, the range of costs increased from $1,260 to $3,280.
Page 10 of 22
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the-art combustion controls (SOA CC). EPA estimated the average 2016 ozone season NOx emission
rates for all such units by firing type. For dry bottom wall-fired coal boilers with "Low NOx Burner" and
"Overfire", there were 148 units averaging 0.1549 lb/mmBtu. For tangentially-fired coal boilers with
"Low NOx Burner" and "Closed-coupled/Separated OFA", there were 105 units averaging 0.1390
lb/mmBtu.
Table 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
Does not Include LNC1 and LNC2
Includes LNC1, but not LNC2
Includes LNC2, but not LNC3
Includes LNC1 and LNC2 orLNC3
LNC3
CONVERSION FROM LNC1 TO LNC3
CONVERSION FROM LNC2 TO LNC3
Wall Firing, Dry Bottom
Does not Include LNB and OFA
Includes LNB, but not OFA
Includes OFA, but not LNB
Includes both LNB and OFA
LNB + OFA
OFA
LNB
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
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 a unit with SNCR technology using the Retrofit Cost Analyzer. The agency
conservatively set the NOx emission reduction rate at 25% - the same assumption used in the CSAPR
Update Rule and in EPA's power sector modeling. For the unit examined above (500 MW, 0.2 lbs
NOx/mmBtu) with a 47.6% capacity factor, the cost is $6,680/ton of NOx removed. When the capacity
factor is 27.3%, the costs increase to $9,000/ton. At higher capacity factors (e.g., 70% and 85%), the
costs decrease, going to $5,680 and $5,310/ton, respectively.
Next, EPA examined the remaining coal-fired fleet that lack SNCR or other NOx post-combustion control
to estimate a median cost of SNCR installation (on a $/ton basis). Costs were estimated for units that had
a minimum input NOx rate of at least 0.2 lb/mmBtu and an assumed NOx removal rate of 25%, assumed
to use bituminous coal, assumed annual operation of the control, and an assumed capacity factor of 59.3%
Page 11 of 22
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(the fleet-wide coal capacity factor from the January 2020 IPM reference case).22 In this instance, the
median value is $5,800/ton.23
Cost and Emission Rate Performance Estimates for Retrofitting with SCR and Related Costs
For coal-fired 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. EPA conservatively assumed 0.07 lb/mmBtu emission rate performance for a new state-of-
the-art SCR retrofit. The same assumption used in the CSAPR Update Rule and in EPA's power sector
modeling along with the Retrofit Cost Analyzer.24 Historically, reported unit-level emission rate data
further supports this assumption, as many of the recently installed SCRs achieve this emission rate or
lower on a yearly basis.
First, to better 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 uncontrolled NOx
rates.25 For a hypothetical unit 500 MW in size with a relatively low uncontrolled NOx rate (e.g., 0.2 lb
NOx/mmBtu, 60% removal efficiency, 47.6% capacity factor, and 10,000 Btu/kWh heat rate), the capital
cost was about $143,000,000. For a similar unit with an input NOx rate of 0.4 lb/mmBtu and 80% NOx
removal efficiency, the total capital cost was $152,000,000. 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 $18,210/ton ($16,373/ton for the
capital cost, $290/ton for the FOM cost, and $l,546/ton for the VOM cost). For the unit with the NOx
rate of 0.4 and removal efficiency of 80%, the costs were $7,562/ton ($6,515/ton for the capital cost,
$115/ton forthe FOM cost, and $932/ton for the VOM cost).
In CSAPR Update, using a higher capacity factor assumption, EPA used the Retrofit Cost Analyzer to
examine the costs of SCR retrofit for an illustrative unit, a 500 MW unit operating at an 85% capacity
factor with an uncontrolled rate of 0.35 lb NOx / mmBtu, retrofitted with an SCR to a lower emission rate
of 0.07 lb NOx / mmBtu, results in a compliance cost of $5,000 / ton of NOx removed. For this
illustrative unit, as annual capacity factor increased, costs per ton decreased (because the capital cost is
constant, but the number of tons of emissions decreases).
For this proposal, EPA examined the remaining coal-fired fleet that lack SCR to estimate a median cost of
SCR installation (on a $/ton basis). Costs were estimated for units that had uncontrolled NOx rates of at
least 0.2 lb/mmBtu prior to installation of the post-combustion control and decreasing to rates of 0.07
22 For the input NOx rate for units with SNCR NOx post-combustion controls that could presumably upgrade to
SCR post-combustion control technology, each unit's maximum average ozone season (or non-ozone season)
emission rate was examined from the period 2003-2019 (inclusively) for the purpose of identifying the unit's
maximum emission rate during time periods when the control was not operating. The long timeframe allowed
examination prior to the onset of annual NOx trading programs (e.g., CAIR and CSAPR). For units where controls
have always operated year-round, this method will underestimate the input NOx rate. For the input NOx rate for
units that lack SNCR post-combustion controls, we used the most recent available ozone-season average NOx rate
(i.e., 2019).
23 See the file "EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx" for detailed cost estimates using the
Retrofit Cost Analyzer for SCR and SNCR operation and installation.
24 https://www.epa.gov/sites/production/files/2019-03/documents/chapter_5.pdf
25 For these hypothetical cases, the "uncontrolled" NOx rate includes the effects of existing combustion controls
present (i.e., low NOx burners).
Page 12 of 22
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lb/mmBtu following control installation and were assumed to use bituminous coal.26 Furthermore, we
assumed annual operation of the control and assumed a capacity factor of 59.3% (the capacity factor for
coal units from the January 2020 IPM v.6 reference case). In this instance, we get a median value of
$9,600/ton and a 90th percentile value of $13,700/ton. For atypical baseload coal capacity factor of 80%,
the 90th percentile is less than the $9,600/ton value.227
Feasibility Assessment: Implementation Timing for Each EGU NOx Control Strategy
The agency evaluated the implementation time required for each compliance option to assess the
feasibility of achieving reductions during the 2021 ozone season.
EPA evaluated the feasibility of turning on idled SCRs for the 2021 ozone season. The EGU sector is
very familiar with restarting SCR systems. Based on past practice and the possible effort 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 within the compliance timeframe of this rule. This
timeframe is informed by many electric utilities' previous, long-standing practice of utilizing SCRs to
reduce EGU NOx emissions during the ozone season while putting the systems into protective lay-up
during non-ozone season months when the EGUs did not have NOx emission limits that warranted
operation of these controls. For example, this was the long-standing practice of many EGUs that used
SCR systems for compliance with the NOx Budget Trading Program. Based on the seasonality of EGU
NOx emission limits, it was typical for EGUs to turn off their SCRs following the September 30 end of
the ozone season control period. They would then lay-up the pollution control for seven months of non-
use. By May 1 of the following ozone season, the control would be returned to operation. In the 22 state
CSAPR Update region, 2005 EGU NOx emission data suggest that 112 EGUs operated SCR systems in
the summer ozone season, likely for compliance with the NOx Budget Trading program, while idling
these controls for the remaining seven non-ozone season months of the year.28 In order to comply with the
seasonal NOx limits, these SCR controls regularly were taken out of and put back into service within
seven months. Therefore, EPA believes this SCR optimization mitigation strategy is available for the
2021 ozone season.
EPA assessed the number of coal-fired units with SCR that are currently operating 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 14 units in the contiguous United States
(of which eight are in states that are "linked" at or above 1% in this Revised CSAPR Update Rule) fit this
26 For the input NOx rate for units with SNCR NOx post-combustion controls that could presumably upgrade to
SCR post-combustion control technology, each unit's maximum average ozone season (or non-ozone season)
emission rate was examined from the period 2003-2019 (inclusively) for the purpose of identifying the unit's
maximum emission rate during time periods when the control was not operating. The long timeframe allowed
examination prior to the onset of annual NOx trading programs (e.g., CAIR and CSAPR). For units where controls
have always operated year-round, this method will underestimate the input NOx rate. For the input NOx rate for
units that lack SNCR post-combustion controls, we used the most-recent available ozone-season average NOx rate
(i.e., 2019).
27 See the file "EGU_SCR_and_SNCR_costs_Revised_CSAPR_Proposal.xlsx" for detailed cost estimates using the
Retrofit Cost Analyzer for SCR and SNCR operation and installation.
28 Units with SCR were identified as those with 2005 ozone season average NOx rates that were less than 0.12
lbs/mmBtu and 2005 average non-ozone season NOx emission rates that exceeded 0.2 lb/mmBtu.
Page 13 of 22
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criterion.29 EPA's assumptions that this mitigation technology is available for the 2021 ozone-season is
further bolstered given that the previous rulemaking (i.e., CSAPR Update) identified turning on and
operating existing SCR as a cost-effective control technology, many sources successfully implemented
that technology requirement, and it appears that only a low number of units in the region may have turned
off these controls.
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.28 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 2021 ozone season. Increasing NOx removal by SCR controls that are already operating
can be implemented by procuring more reagent and catalyst. EGUs with SCR routinely procure reagent
and catalyst as part of ongoing operation and maintenance of the SCR system. In many cases, where the
EPA has identified EGUs that are operating their SCR at non-optimized NOx removal efficiencies, EGU
data indicate that these units historically have achieved more efficient NOx removal rates. Therefore, the
EPA finds that optimizing existing and SCR systems currently being operated could generally be done by
reverting to previous operation and maintenance plans. 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.
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-2009-0491-0051.30 Industry has demonstrated retrofitting LNB technology controls
on a large unit (800 MW) in under six months. This TSD is in the docket for the CSAPR Update and for
this rulemaking. EPA is providing until 2022 to implement these controls as the limited time available
between the estimated signature date of this rule and start of the 2021 ozone season would not be
sufficient to install LNBs on a regional level.
This rule does not consider retrofitting SCR or SNCR technology as a viable compliance option in the
2021 compliance timeframe. The time requirements for a single boiler SCR retrofit exceed 18 months
from contract award through commissioning (not including permitting). SNCR is similar to activated
29 See the "2019 NOx Rates for 258 Units.xlsx file" in the docket for details. Eight of the units are in states linked at
or above 1%. Three are in Ohio, two each are in Kentucky and New York, and one is in Indiana. Both units in New
York have since permanently retired; Somerset 1 last operated in March 2020 and Cayuga 1 last operated in August
2019. Both units in Kentucky have since permanently retired; Paradise 3 last operated in February 2020 and Elmer
Smith 1 last operated in June 2019.
30 http://www.epa.gov/airmarkets/airtransport/CSAPR/pdfs/TSD_Installation_timing_for_LNBs_07-6-10.pdf
Page 14 of 22
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carbon injection (ACI) and dry sorbent injection (DSI) installation and 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 detailed analysis for a single SCR system
can be found in Exhibit A-3 and an ACI system (equivalent timeline to a SNCR) in Exhibit A-5 in: "Final
Report: Engineering and Economic Factors Affecting the Installation of Control Technologies for
Multipollutant Strategies" located in the Docket for this Rulemaking.31 On a regional scale, the estimate
for installing SCR at multiple boilers on multiple plants is in excess of 39 months. EPA assumes these
technologies would not be available at regional scale prior to the start of the of the 2025 ozone season.
See preamble section VII.C for more discussion on post combustion control retrofit timing.
This proposed rule, like prior interstate transport rules, takes into account the potential for shifting
generation among electric power producers, depending on the price-signal of the allowances in a trading
program. Shifting generation to lower NOx-emitting or zero-emitting EGUs occurs in response to
economic factors, including the costs of pollution control. As the cost of emitting NOx increases,
combined with all other costs of generation, it becomes increasingly cost-effective for units with lower
NOx rates to increase generation, while units with higher NOx rates reduce generation. Because the cost
of generation is unit-specific, this generation shifting occurs incrementally on a continuum.
Consequently, there is more generation shifting at higher cost NOx levels. Because we have identified
discrete cost thresholds resulting from the full operation of particular types of emission controls, it is
reasonable to simultaneously quantify the reduction potential from generation shifting strategy associated
with operating controls at each cost level. Including these reductions is important, ensuring that cost-
effective full operation of controls can be expected to occur.
As described in the preamble, EPA modeled generation shifting to units with lower NOx emission rates
only within the same state as a proxy for estimating the amount of generation that could be shifted in the
near-term (i.e., 2021). We further assume that such generation shifting only occurs within and among
generators that are already in operation and connected to the grid in EPA's baseline. Under these
circumstances, shifting generation to lower NOx- or zero-emitting EGUs, similar to operating existing
post-combustion controls, uses investments that have already been made, and can significantly reduce
EGU NOx emissions relatively quickly. For example, natural gas combined cycle (NGCC) facilities can
achieve NOx emission rates of 0.0095 lb/mmBtu, compared to existing coal steam facilities, which
emitted at an average rate of 0.12 lb/mmBtu of NOx across the 22 states included in the CSAPR Update
in 2019. Similarly, generation could shift from uncontrolled coal units to SCR-controlled or SNCR
controlled coal units. Shifting generation to lower NOx-emitting EGUs would be a cost-effective, timely,
and readily available approach for EGUs to reduce NOx emissions, and EPA analyzed EGU NOx
reduction potential from this control strategy for the CSAPR Update. EPA considers that the amount of
generation shifting modeled to occur within each particular linked state in response to the selected control
strategy represented by $1600/ton reflects the generation shifting that can occur in the 2021 ozone season
and is thus incorporated into the emission budgets. Table 3 and Table 4 below illustrate the low amount of
generation assumed in EPA's analysis relative to historical levels.
Table 3: Regional Coal and Gas Summer Generation Changes Base to Cost Threshold Case
(2021, GWh)
31 http://nepis.epa.gov/Adobe/PDF/P1001G0O.pdf
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Region
Coal Adj.
Base
Case
Coal
($1600/ton)
Coal
Change
Coal
Percent
Change
Combined
Cycle Adj.
Base Case
Combined
Cycle
($1600/ton)
Combined
Cycle
Change
Combined
Cycle
Percent
Change
MISO
104,670
101,791
-2,879
-2.8%
82,672
85,044
2,372
2.9%
NY
7
7
0
0.0%
29,193
29,205
12
0.04%
PJM
72,435
71,393
-1,041
-1.4%
138,672
140,267
1,595
1.2%
SERC
62,963
62,797
-166
-0.3%
120,689
120,779
90
0.1%
Table 4: Historical Rate of Generation Change for Coal and Combined Cycle Units
Coal Generation (GWh)
Combined Cycle Generation (GWh)
2016
2017
2018
2019
Averag
e
annual
change
2016
2017
2018
2019
Averag
e
annual
change
Total for
12
linked
states
235,218
211,145
206,053
167,880
10.39%
132,404
131,081
149,124
179,518
-11.05%
Additional Mitigation Technologies Assessed but Not Proposed in this Action
Mitigation Strategies at Small Units that Operate on High Electricity Demand Days (HEDD).
In previous rules, stakeholders have commented that emissions on the days that are conducive to ozone
matter the most for attainment of the NAAQS. The seasonal trading programs have been highly effective,
ensuring that the large units install and operate efficient post-combustion controls. However, 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
summer. The generation they provide is likely critical to ensuring grid stability during these high-demand
times. Having sufficient generation available to meet demand is essential for health and safety. At the
same time, emissions from these sources can help cause or exacerbate exceedances of the NAAQS.
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. The majority 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, 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.
Page 16 of 22
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With their relatively high emission rates, relatively small seasonal capacity factors, and tendency to
operate on HEDD, the emissions 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 in the six states. The exemplary 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 exemplary 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 3),
contributing to 539 lbs, or 9% of the total peak hour NOx emissions in the six states (Figure 4).
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 3), and contributed to
4,881 lbs, or 19% of total peak hour NOx emissions (Figure 5).
For the example HEDD day, the largest shares of peak hour NOx emissions from combustion cycle units
originate in New York and Pennsylvania (Figure 5). 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 6). With peak hour NOx rates of 0.44 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.
Increasingly, states have focused on regulation of these sources, tightening emissions standards for them
(see NJ regs and NY regs). For example, in January of 2020 the New York Department of Environmental
Conservation (NY-DEC) adopted a rule to limit emissions from combustion turbines that operate as
peaking units. New York's adopted Subpart 227-332, entitled "Ozone Season NOx Emission Limits for
Simple Cycle and Regenerative Combustion Turbines." The regulation applies to simple cycle
32 Subpart 227-3 is found within Chapter III. Air Resources, Part 227, of Title 6 of New York Codes, Rules and
Regulations (NYCRR).
Page 17 of 22
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combustion turbines (SCCTs) with a nameplate capacity of 15 MW or greater that supply electricity to the
grid. The regulation contains two compliance dates with increasingly stringent NOx limits, as follows: by
May 1, 2023, all SCCTs subject to the rule must meet a NOx emission limit of 100 ppmvd33, 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.
The EPA previously promulgated NOx emission standards for combustion turbines, which are
found in New Source Performance Standards (NSPS) located at 40 CFR Part 60, Subparts GG and
KKKK. Subpart GG covers turbine engines that commenced constructed after October 3, 1977 and before
February 18, 2005. Subpart KKKK covers both the combustion turbine engine and any associated heat
recovery steam generator for units that commenced construction after February 18, 2005. SO; emission
limits are also contained within these requirements. Several states within the Ozone Transport Region
(OTR) have adopted NOx emission limits for combustion turbines.
33 Parts per million on a dry volume basis at 15% oxygen.
Page 18 of 22
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Houfty gross feneration bv combustion turbine natural pas and oil units in six northeastern states on LEE>D,
¦ ftKUJl Gj>i • Oil
5 JGOO
r moo
o t j i 4 i * ? a 9 u u u u u u u if ii a n u m u
Hou«ty £rojs ceneraiwn by combustion turbine natural £** and oil units in s« northeaste«n slates on KEOD.
aOEttirsi&K a ai
HOP
I-
¦
•g ISQQ
hi.. nl
Q »
0 1 1 1 I % t ? 1 t 39 U U 3) U 11 )i II 11 M M n n n
Hour <4 «*»
Figure 3. Hourly gross generation by combustion turbine natural gas and oil units in the six northeastern
states on an exemplary LEDD and HEDD
Peak hour NOx emissions by unit-type across states and region on LEDD1,
lb
¦ Cnmbu sthe Turbine ¦ Other
71300
1) May 13"' (IfloQQ) ii used at the exemplary LiDO day and peak hour.
Figure 4. Percentage share of peak hour NOx emissions by unit type across region and states on an
exemplary LEDD
I -
Page 19 of22
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Peak hour NOx emissions by unit-type across states and region on HEDD1,
lb
¦ GoniiuftfrieTtftine ¦ Other
2 20000
5
E
6 15m°
r
° 10000
¦ - ¦
Region and States
CT share of
emissionsr
1) Ju ty 30lh (16:00} n used as the exemplary HEDD day and peak hour.
Figure 5. Percentage share of peak hour NOx emissions by unit type across region and states on an
exemplary HEDD (Source: Air Markets Program Data (AMPD), ampd.epa.gov, EPA, 2020)
Peak hour gross generation on a HEDD from oil unit in NY state. Peak hour NOx emissions on a HEDD from oil unit in NY state,
MWh Pounds
7/
Figure 6. Peak hour generation and emissions on HEDD by oil units in NY as a percentage (Source: Air
Markets Program Data (AMPD), ampd.epa.gov, EPA, 2020)
Mitigation Strategies at Small Municipal Solid Waste (MSW) Units
EPA is also inviting comment on whether other EGUs not covered by the existing CSAPR programs
should be considered. Stakeholders have pointed out that grid-connected Municipal Solid Waste
combustors (MSW) are often located near problematic receptors and have high emission rates. Due to
their small size (less than 25 MW) and non-electric load driven operation decisions, EPA has not typically
considered these units to be viable sources for cost-effective reductions under the CSAPR framework
and therefore excluded them from its regional programs. However, EPA does include their emissions
estimates in its EGU inventory and invites comment in the preamble on their relevance and emission
reduction potential in an interstate transport rulemaking context going forward.
As additional background, data from EPA's 2017 National Emissions Inventory (NEI) database
reports NOx emissions of 15,758 tons from MWCs in the eleven states that EPA's modeling indicates
significantly contribute to ozone levels in the NY-NJ-CT nonattainment area. EPA regulates emissions of
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nine pollutants, including NOx, under Section 111 of the CAA for four types of solid waste incineration
units, including MSWs. These requirements are contained within new source performance standards
(NSPS) and emission guidelines promulgated by states pursuant to requirements codified within 40 CFR
Part 60. Additionally, some states have adopted more restrictive NOx emission limits, primarily through
requirements adopted to meet reasonably available control technology (RACT) requirements.
Information assembled by the Ozone Transport Commission (OTC) indicates that SNCR is a common
control equipment choice for MSW units, as all 9 of the OTC states with MSW units contain at least one
facility that controls NOx emissions using that technology.34 Connecticut and New Jersey have adopted
the following NOx emission limits, which are among the most restrictive NOx emission limits for MSWs
adopted via state requirements: Connecticut has adopted a NOx emission limit of 150 ppm for mass
burn waterwall units, and a limit of 146 ppm for processed-municipal solid waste combustors,35 and
New Jersey has adopted a NOx emission limit of 150 ppm applicable to MSW units of any size.36 Table 3
below illustrates the projected share of state-level ozone-season NOx EGU emissions expected to come
from MSW units in 2023.
Table 5: IPM Projected 2023 OS NOx Emissions (1000 tons)37
MSW
Emission
All EGU
MSW Share
Rate
MSW
Sources
of Emissions
(Ib/mmBtu)
California
0.26
2.37
11%
0.18
Connecticut
1.46
1.94
76%
0.34
Florida
5.05
17.14
29%
0.43
Indiana
0.01
17.82
0%
0.39
Maine
0.47
1.05
44%
0.40
Maryland
1.51
2.83
53%
0.54
Massachusetts
1.76
2.54
69%
0.26
Michigan
0.27
13.96
2%
0.30
Minnesota
0.64
7.97
8%
0.38
New Hampshire
0.12
0.30
42%
0.32
New Jersey
0.95
2.55
37%
0.22
New York
3.43
7.29
47%
0.49
Oregon
0.18
0.69
25%
0.50
Pennsylvania
2.45
13.61
18%
0.40
Virginia
1.01
4.31
24%
0.29
Washington
0.22
0.51
44%
0.38
34 See "White Paper on Control Technologies and OTC State Regulations for Nitrogen Oxide (NOx) Emissions from
Eight Source Categories", Final Draft, February 10, 2017.
35 See Table 38-2a within Section 22a-174-38, Municipal Waste Combustors, of the Regulations of Connecticut
State Agencies. Emission limits expressed as ppm are corrected to 7% oxygen, dry basis.
36 See Section 7:27-19.12, Municipal Solid Waste (MSW) Incinerators, of the New Jersey State Department of
Environmental Protection Administrative Code.
37 EPA January 2020 IPM Reference Case v6; 2023 Parsed File. Available at
https://www.epa.gov/airmarkets/results-using-epas-power-sector-modeling-platform-v6-january-2020-reference-
case
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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]
Cost / ton Cost / ton
year
NH3 (anh)
NOx
Urea cost
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
Average price from the first reporting period in July of each year.
Source: Illinois Production Cost Report (GX_GR210)USDA-IIL,
Dept of Ag Market News Service, Springfield, IL
www.ams.usda.gov/mnreports/gx_gr210.txt
www.ams.usda.gov/LPSMarketNewsPage
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