TECHNICAL MEMORANDUM
TO: Docket for Rulemaking, "Proposed Federal Implementation Plan Addressing Regional Ozone
Transport for the 2015 Ozone National Ambient Air Quality Standards" (EPA-HQ-OAR-2021-0668)
DATE: February 28, 2022
SUBJECT: Screening Assessment of Potential Emissions Reductions, Air Quality Impacts, and Costs from
Non-EGU Emissions Units for 2026
I. Introduction
The EPA developed an analytical framework to facilitate decisions about industries, emissions unit types, and cost
thresholds for including emissions units in the non-electric generating unit "sector" (non-EGUs) in a federal
implementation plan (FIP) proposal for the 2015 ozone national ambient air quality standards (NAAQS) transport
obligations. Using this analytical framework, we prepared a screening assessment for the year 2026.
This memorandum presents the analytical framework and summarizes the screening assessment the EPA
prepared to identify industries and emissions unit types to include in proposed rules to obtain NOx emissions
reductions from non-EGUs. Sections VILA.2. and VII.C. of the proposal preamble include discussions of the non-
EGU NOx emissions limits, compliance timing, and other related-rule requirements for the industries and
emissions unit types identified through the screening assessment.
The remainder of this memorandum includes the following sections:
II. Background on Analytical Framework
III. The Analytical Framework
o Step 1 - Identifying Potentially Impactful Industries in 2023
o Step 2a - Identifying a Cost Threshold to Evaluate Emissions Reductions in Potentially Impactful
Industries for 2023
o Step 2b - Assessing Non-EGU Emission Reduction Potential and Estimated Air Quality Impacts in
Potentially Impactful Industries in 2023
o Step 2c - Refining Tier 2 by Identifying Potentially Impactful Boilers in 2023
IV. Modifying the Analytical Framework for the Screening Assessment for 2026
V. Screening Assessment Results for 2026 - Estimated Total Emissions Reductions, Air Quality
Improvements, and Annual Total Costs for Emissions Units in Tier 1 Industries and Impactful Boilers in Tier
2 Industries
VI. Request for Comment and Additional Information
II. Background on Analytical Framework
The number of different industries and emissions unit categories and types, as well as the total number of
emissions units that comprise the non-EGU "sector"1 makes it challenging to define a single method to identify
impactful emissions reductions. We incorporated air quality information as a first step in the analytical framework
to help determine potentially impactful industries to focus on for further assessing emission reduction potential,
air quality improvements, and costs. Given the lengthy decision-making and analysis schedules for the FIP
proposal, we developed the analytical framework using inputs from the air quality modeling for the Revised
1 The non-EGU "sector" includes non-electric generating emissions units in various manufacturing industries and does not
include municipal waste combustors (MWC), cogeneration units, or <25 MW EGUs. For a discussion of MWCs, cogeneration
units, and EGUs <25 MW, see Section VI.B.3. of the proposed rule preamble.
1
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CSAPR Update (RCU) for 20232, as well as the projected 2023 annual emissions inventory from the 2016v2
emissions platform that was used for the air quality modeling for the proposed rule.
Using the RCU modeling for 2023, we identified upwind states linked to downwind nonattainment or
maintenance receptors using the 1% of the NAAQS threshold criterion, which is 0.7 ppb (1% of a 70 ppb NAAQS).
In 2023 there were 27 linked states for the 2015 NAAQS: AL, AR, CA, DE, IA, IL, IN, KY, LA, MD, Ml, MN, MO, MS,
NJ, NY, NV, OH, OK, PA, TN, TX, UT, VA, Wl, WV, and WY.
To analyze non-EGU emissions units, we aggregated the underlying projected 2023 emissions inventory data into
industries defined by 4-digit NAICS.3 Then for the linked states, we followed the 2-step process below:
1. Step 1 - We identified industries whose potentially controllable emissions are estimated, by applying
the analytical framework, to have the greatest ppb impact on downwind air quality, 4 and
2. Step 2 - We determined which of the most impactful industries and emissions units had the most
emissions reductions that would make meaningful air quality improvements at the downwind
receptors at a marginal cost threshold we determined using underlying control device efficiency and
cost information.
Additional details on these steps are presented in the Section III below.
Finally, the EPA concluded, based on the most recent information available from the CSAPR Update Non-EGU
TSD,5 that controls on all of the non-EGU emissions units cannot be installed by the 2023 ozone season.6 As such,
we modified the analytical framework slightly and applied it for a screening assessment estimating potential
emissions reductions, air quality improvements, and costs for the year 2026.
III. The Analytical Framework
Step 1 - Identifying Potentially Impactful Industries in 2023
The analytical framework starts with identifying industries whose potentially controllable emissions may
contribute to downwind receptors. To identify industries that have large, meaningful air quality impacts from
potentially controllable emissions, we estimated air quality contribution by 4-digit NAICS-based industry for 2023.
To estimate the contributions by 4-digit NAICS at each downwind receptor, we used the 2023 state-receptor
specific RCU ppb/ton values and the RCU calibration factors used in the air quality assessment tool (AQAT) for
control analyses in 2023.7
2 We used the RCU air quality modeling for this screening assessment because the air quality modeling for the proposed rule
was not completed in time to support this assessment.
3 North American Industry Classification System (https://www.census.gov/naics/).
4 To identify industries, we reviewed emissions units with >= lOOtpy emissions units in the 2023 inventory in those industries
in the upwind states.
5 Final Technical Support Document (TSD) for the Final Cross-State Air Pollution Rule for the 2008 Ozone NAAQS, Assessment
of Non-EGU NOx Emissions Controls, Cost of Controls, and Time for Compliance Final TSD ("CSAPR Update Non-EGU TSD"),
August 2016, available at https://www.epa.pov/csapr/assessment-non-epu-NOx-emission-controls-cost-controls-and-time-
compliance-final-tsd.
6 Note that information on control installation timing as detailed in the 2016 CSAPR Update Non-EGU TSD is not complete or
sufficient to serve as a foundation for timing estimates for this proposed FIP.
7 The calibration factors are receptor-specific factors. For the RCU, the calibration factors were generated using 2016 base
case and 2023 base case air quality model runs. These receptor-level ppb/ton factors are discussed in the Ozone Transport
Policy Analysis Final Rule TSD found here: https://www.epa.gov/sites/default/files/2021-
03/documents/ozone transport policy analysis final rule tsd O.pdf.
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We focused on assessing emissions units that emit >100 tpy of NOx.8 By limiting the focus to potentially
controllable emissions, well-controlled sources that still emit > 100 tpy are excluded from consideration. Instead,
the focus is on uncontrolled sources or sources that could be better controlled at a reasonable cost. As a result,
reductions from any industry identified by this process are more likely to be achievable and to lead to air quality
improvements.
Based on the industry contribution data, we prepared a summary of the estimated total, maximum, and average
contributions from each industry and the number of receptors with contributions >= 0.01 ppb from each industry.
We evaluated this information to identify breakpoints in the data, as described in detail in Appendix A. These
breakpoints were then used to identify the most impactful industries to focus on for the next steps in the
analysis.9
A review of the contribution data indicated that we should focus the assessment of NOx reduction potential and
cost primarily on four industries. These industries each (1) have a maximum contribution to any one receptor of
>0.10 ppb and (2) contribute >= 0.01 ppb to at least 10 receptors. We refer to these four industries identified
below as comprising "Tier 1".
• Pipeline Transportation of Natural Gas
• Cement and Concrete Product Manufacturing
• Iron and Steel Mills and Ferroalloy Manufacturing
• Glass and Glass Product Manufacturing
In addition, the contribution data suggests that we should include five additional industries as a second tier in the
assessment. These industries each either have (1) a maximum contribution to any one receptor >=0.10 ppb but
contribute >=0.01 ppb to fewer than 10 receptors, or (2) a maximum contribution <0.10 ppb but contribute
>=0.01 ppb to at least 10 receptors. We refer to these five industries identified below as comprising "Tier 2".
• Basic Chemical Manufacturing
• Petroleum and Coal Products Manufacturing
• Metal Ore Mining
• Lime and Gypsum Product Manufacturing
• Pulp, Paper, and Paperboard Mills
8 In the non-EGU emission reduction assessment prepared for the Revised Cross State Air Pollution Rule Update
(https://www.regulations.gov/document/EPA-HQ-OAR-2020-0272-0014), we reviewed emissions units with >150 tpy of NOx
emissions. In this screening assessment, we broadened the scope to include emissions units with >=100 tpy of NOx emissions.
We believe that emissions units that are smaller may already be controlled and reductions from these smaller units are likely
to be more costly.
9 The air quality contribution data and the R code that processed these data are available upon request.
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Step 2a - Identifying a Cost Threshold to Evaluate Emissions Reductions in Potentially Impactful Industries for
2023
To identify an annual cost threshold for evaluating potential emissions reductions in the Tier 1 and Tier 2
industries, the EPA used the Control Strategy Tool (CoST)10, the Control Measures Database (CMDB)11, and the
projected 2023 emissions inventory to prepare a listing of potential control measures, and costs, applied to non-
EGU emissions units in the projected 2023 emissions inventory. Using this data, we plotted curves for Tier 1
industries, Tier 2 industries, Tier 1 and 2 industries, and all industries at $500 per ton increments. Figure 1
indicates there is a "knee in the curve" at approximately $7,500 per ton.12 We used this marginal cost threshold to
further assess estimated emissions reductions, air quality improvements, and costs from the potentially impactful
industries. Note that controls and related emissions reductions are available at several estimated cost levels up to
the $7,500 per ton threshold. The costs do not include monitoring, recordkeeping, reporting, or testing costs.
Figure 1. Ozone Season NOx Reductions and Costs per Ton (CPT) for Tier 1, Tier 2 Industries,
and Other Industries
120,000-
100,000
c.
£
o
QL
c
O
O
3
~0
w
0£
x
O
C
o
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Step 2b - Assessing Non-EGU Emission Reduction Potential and Estimated Air Quality Impacts in Potentially
Impactful Industries in 2023
Next, using the marginal cost threshold of $7,500 per ton, to estimate emissions reductions and costs the EPA
processed the CoST run using the maximum emission reduction algorithm1314 with known controls.15 We
identified controls for non-EGU emissions units in the Tier 1 and Tier 2 industries that cost up to $7,500 per ton.
Note that $7,500 per ton represents a marginal cost, and controls and related emissions reductions are available
at several estimated costs up to the $7,500 per ton threshold. The costs do not include monitoring,
recordkeeping, reporting, or testing costs.
We then calculated air quality impacts associated with the estimated reductions for the 27 linked states in 2023
following the steps below.
1. We binned the estimated reductions by 4-digit NAICS code into the Tier 1 and Tier 2 industries.
2. We used the 2023 state-receptor specific RCU ppb/ton values and the RCU calibration factors used in the
AQAT for control analyses in 2023. We multiplied the estimated non-EGU reductions by the ppb/ton
values and by the receptor-specific calibration factor to estimate the ppb impacts from these emissions
reductions.16
Note that we did not include the impact of reductions in the "home state" even if the "home state" was linked to
receptor(s) in another state. That is, we only looked at the impact of NOx emissions reductions from upwind states.
Furthermore, for each receptor we included impacts from states that are upwind to any receptor, not just those
states that are upwind to that particular receptor.
Step 2c - Refining Tier 2 by Identifying Potentially Impactful Boilers in 2023
In 2023 because boilers represent the majority emissions unit in the Tier 2 industries for which there were
controls that cost up to $7,500 per ton (see Table 1 below), we targeted emissions reductions and air quality
improvements in Tier 2 industries by identifying potentially impactful industrial, commercial, and institutional (ICI)
boilers.
13 The maximum emission reduction algorithm assigns to each source the single measure (if a measure is available for the
source) that provides the maximum reduction to the target pollutant. For more information, see the CoST User's Guide
available at the following link: https://www.cmascenter.org/cost/documentation/3.7/CoST%20User's%20Guide/.
14 The maximum emission reduction CoST run results and CMDB are available upon request.
15 Known controls are well-demonstrated control devices and methods that are currently used in practice in many industries.
Known controls do not include cutting edge or emerging pollution control technologies.
16 The 2023 state-receptor specific RCU ppb/ton values, the RCU calibration factors used in AQAT for control analyses in 2023,
the R code that processed the CoST run results using the maximum emission reduction algorithm, and the summaries of the
air quality improvements are available upon request.
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Table 1. Number of Emissions Unit Types in Tier 2 Industries
Num
ber of Emissions Units by Type
Tier 2 Industries
Boiler
Internal
Combustion Engine
Industrial
Processes
Metal Ore Mining
-
1
15
Pulp, Paper, and Paperboard Mills
49
1
-
Petroleum and Coal Products
Manufacturing
37
4
48
Basic Chemical Manufacturing
46
8
13
Lime and Gypsum Product Manufacturing
-
-
1
Totals
132
14
77
To identify potentially impactful boilers, using the projected 2023 emissions inventory in the linked upwind states
we identified a universe of boilers with >100 tpy NOx emissions that had any contributions at downwind
receptors.17,18 We refined the universe of boilers to a subset of impactful boilers by sequentially applying the
three criteria below to each boiler. This approach is similar to the overall analytical framework and was tailored
for application to individual boilers.19,20
• Criterion 1 - Estimated maximum air quality contribution at an individual receptor of >=0.0025 ppb or
estimated total contribution across downwind receptors of >=0.01 ppb.
• Criterion 2 - Controls that cost up to $7,500 per ton.
• Criterion 3 - Estimated maximum air quality improvement at an individual receptor of >=0.001 ppb.
IV. Modifying the Analytical Framework for the Screening Assessment for 2026
EPA concluded, based on the most recent information available from the CSAPR Update Non-EGU TSD, that
controls on all of the non-EGU emissions units cannot be installed by the 2023 ozone season. As such, we
prepared a screening assessment for the year 2026 by generally applying the analytical framework detailed above.
Specifically, we
• Retained the impactful industries identified in Tier 1 and Tier 2, the $7,500 cost per ton threshold, and the
methodology for identifying impactful boilers,
• Modified the framework to address challenges associated with using the projected 2023 emissions
inventory by using the 2019 emissions inventory, and
• Updated the air quality modeling data by using data for 2026.
Using the projected 2023 emissions inventory introduced challenges associated with the application of new
source performance standards (NSPS).21 Some of the projected emissions inventory records reflected percent
17 We used the 2023fj non-EGU point source inventory files from the 2016v2 emissions platform.
18 MD, MO, NV, and WY did not have boilers with >100 tpy NOx emissions.
19 For the impactful boiler assessment, the estimated air quality contributions and improvements were not based on
modeling of individual emissions units or emissions source sectors. The air quality estimates were derived by using the 2023
state/receptor specific RCU ppb/ton values and the RCU calibration factors used in AQAT. The results are intended to provide
a general indication of the relative impact across sources.
20 For the impactful boiler assessment, the 2023 state-receptor specific RCU ppb/ton values, the RCU calibration factors used
in the AQAT for ozone for control analyses in 2023, and the R code that processed the CoST run results are available upon
request.
21 Using the projected inventory also introduced challenges associated with the growth of emissions at sources over time.
EPA determined that the 2019 inventory was appropriate because it provided a more accurate prediction of potential near-
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reductions associated with the application of current NSPS (e.g., Reciprocating Internal Combustion Engine,
Natural Gas Turbines, Process Heaters NSPS). Applying NSPSs during the emissions projections process includes
estimating the number of modifications/replacements that would trigger NSPS requirements. None of the existing
sources, as they currently exist, would install a control because of a NSPS. But some of those sources might
modify and become subject to the NSPS. Because we do not know which sources might become subject to an
NSPS by modifying, across-the-board percent reductions from unknown control measures are applied to all of the
sources.22 As a result, CoST replaced some of the unknown control measures with a control measure that it
concluded was more efficient. However, we do not know if a control would be applied to a particular source in
response to the NSPS rules and if so, what that control would be. Therefore, we do not know if CoST is correctly
replacing those unknown control measures. To address this challenge, we used a current, not projected,
emissions inventory along with the latest air quality modeling information for 2026. Specifically, we used the 2019
inventory for information on emissions, emissions units, and estimated emissions reductions in concert with the
emissions sector-specific (non-EGU-specific) ppb/ton factors for 2026 and 2026 AQAT calibration factors to
estimate the impacts on future air quality from reductions at emissions units as those units currently exist.23
V. Screening Assessment Results for 2026 -- Estimated Total Emissions Reductions. Air Quality Improvements,
and Annual Total Costs for Emissions Units in Tier 1 Industries and Impactful Boilers in Tier 2 Industries
This screening assessment is not intended to be, nor take the place of, a unit-specific detailed engineering analysis
that fully evaluates the feasibility of retrofits for the emissions units, potential controls, and related costs. We
used CoST to identify emissions units, emissions reductions, and costs to include in a proposed FIP; however, CoST
was designed to be used for illustrative control strategy analyses (e.g., NAAQS regulatory impact analyses) and not
for unit-specific, detailed engineering analyses. The estimates from CoST identify proxies for (1) non-EGU
emissions units that have emission reduction potential, (2) potential controls for and emissions reductions from
these emissions units, and (3) control costs from the potential controls on these emissions units.
See Sections VII.A.2. and VII.C. of the proposal preamble for discussions of the NOx emissions limits, compliance
timing, and other related rule requirements for the industries and emissions unit types identified through this
screening assessment.
To prepare the screening assessment for 2026, we applied the analytical framework detailed in the sections above
with the modifications discussed in the previous section. The assessment includes emissions units from the Tier 1
industries and impactful boilers from the Tier 2 industries. Using the latest air quality modeling for 2026, we
identified upwind states linked to downwind nonattainment or maintenance receptors using the 1% of the NAAQS
threshold criterion, or 0.7 ppb. In 2026 there are 23 linked states for the 2015 NAAQS: AR, CA, IL, IN, KY, LA, MD,
Ml, MN, MO, MS, NJ, NY, NV, OH, OK, PA, TX, UT, VA, Wl, WV, and WY.
We re-ran CoST with known controls, the CMDB, and the 2019 emissions inventory. We specified CoST to allow
replacing an existing control if a replacement control is estimated to be >10 percent more effective than the
term emissions reductions. For additional discussion of the 2019 inventory, please see the 2019 National Emissions Inventory
Technical Support Document: Point Data Category available in the docket. In switching to the 2019 inventory, however, we
did not account for any growth or decrease in emissions that might occur at individual units. Because the controls applied by
CoST have efficiencies, or percent reductions, this means we could be over- or under-estimating the emission reductions and
their ppb impacts.
22 For additional information on the 2016v2 inventory and the projected 2023 emissions inventory, please see the September
2021 Technical Support Document Preparation of Emissions Inventories for 2016v2 North American Emissions Modeling
Platform in the docket or available at the following link: https://www.epa.gov/svstem/files/documents/2021-
09/2016v2 emismod tsd september2021.pdf.
23 For this proposed FIP, the EPA used the ozone AQAT, which is described in detail in Ozone Policy Analysis Proposed Rule
TSD in the docket. The receptor-state specific calibration factors for 2026 were derived using the following air quality
modeling runs: 2026 base case and 2026 control case with 30 percent across-the-board NOx emissions cuts.
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existing control. We did not replace an existing control if the 2019 emissions inventory indicated the presence of
that control, even if the CMDB reflects a greater control efficiency for that control. Also, we removed six facilities
from consideration because they are subject to an existing consent decree, are shut down, or will shut down by
2026. See Appendix B for a summary of the facilities removed.
For the emissions units in the Tier 1 industries and the impactful boilers in the Tier 2 industries, the estimated
emissions reductions, air quality improvements, and costs are summarized below and in Tables 2 through 5 that
follow. The cost estimates do not include monitoring, recordkeeping, reporting, or testing costs.24 As shown in
Table 2, the total estimated ozone season emissions reductions are 47,186 tons, the estimated total ppb
improvement across all downwind receptors is 5.16 ppb, and the estimated total cost is $410.8 million annually.
The estimated ozone season reductions, total ppb improvements, and total cost are representative of single year
impacts and not cumulative impacts.
Table 3 presents estimated ppb improvements at receptors grouped by region. For the coastal Connecticut/New
York City nonattainment area receptors, total ppb improvements from Tier 1 and Tier 2 range from 0.247 to 0.356
ppb; for the receptors near Chicago, total ppb improvements range from 0.261 to 0.375 ppb; for the receptors
along the western shoreline of Lake Michigan in Wisconsin, total ppb improvements range from 0.360 to 0.443
ppb; for the Houston receptors, total ppb improvements range from 0.284 to 0.472 ppb; and for the western
receptors, ppb improvements range from <0.001 to 0.056 ppb. There are far fewer emissions reductions from
western states because there are far fewer states and impacted emissions units in the west, and the resulting air
quality improvements are noticeably lower.
For Tier 1 industries and the impactful boilers in the Tier 2 industries, Table 4 provides by state and by industry
estimated emissions reductions and costs; Table 4a provides by state, estimated emissions reductions and costs.
New Jersey and Nevada are not included in these tables because they did not have any estimated non-EGU
reductions from the Tier 1 industries and boilers in Tier 2 industries that cost up to $7,500 per ton. In addition,
Figure 2 shows the geographical distribution of ozone season reductions.
Table 5 provides by industry and east/west, the number and type of emissions units, total estimated emissions
reductions, total ppb improvements, and costs. There are 489 emissions units contributing to the total estimated
reductions of 47,186 ozone season tons and total estimated ppb improvements of 5.16 ppb.25
Table 6 includes by industry, the emissions source group, control technology, number of emissions units, ozone
season emissions reductions, and annual total cost for the emissions units in the screening assessment. Lastly,
Tables 7, 8, and 9 provide summaries of estimated ozone season emissions reductions, annual total cost, and
average cost per ton by the control technologies CoST applied (i) across all non-EGU emissions units, (ii) across
non-EGU emissions units grouped by the Tier 1 industries and impactful boilers in Tier 2 industries, and (iii) across
non-EGU emissions units grouped by the seven individual Tier 1 and 2 industries.
24 EPA submitted an information collection request (ICR) to OMB associated with the proposed monitoring, calibrating,
recordkeeping, reporting and testing activities required for non-EGU emissions units - ICR for the Proposed Rule, Federal
Implementation Plan Addressing Regional Ozone Transport for the 2015 Primary Ozone National Ambient Air Quality
Standard: Transport Obligations for non-Electric Generating Units, EPA ICR No. 2705.01. The ICR is summarized in Section
XI. B.2 of the proposed rule preamble. The ICR includes estimated monitoring, recordkeeping, reporting, and testing costs of
approximately $11.45 million per year for the first three years. These costs are not reflected in the cost estimates presented
in Tables 2 through 9.
25 While the number of units listed in Table 5 sums to 491, the emissions inventory records for two of the units in Tier 1
industries include SCCs for both boilers and industrial processes. As a result, those units appear twice in the counts.
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For the Excel workbooks with Tables 2 through 9, see Transport Proposal - NonEGU Results - ll-10-2021.xlsx and
Non-EGU Analysis Controls - ll-15-2021.xlsx in the docket.26
26 The R code that processed the CoST run results, the sector-specific (non-EGU-specific) ppb/ton values, and the 2026 AQAT
calibration factors used to prepare these tables are available upon request.
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All costs are in 2016$ and do not include monitoring, recordkeeping, reporting, or testing costs.
Table 2. Estimated Emissions Reductions (ozone season tons), Maximum PPB Improvements, and Costs
Option
Ozone Season
Emissions Reductions
(East/West)
Total PPB Improvement Max PPB Improvement
Annual Total Cost (million $) Industries (# of emissions units > 100 tpy in identified
Across All Downwind Across All Downwind
(Avg Annual Cost per Ton) industries)
Receptors Receptors
Tier 1 Industries with Known Controls that Cost up to
$7,500/ton
41,153
(37,972/3,181)
Cement and Concrete Product Manufacturing (47),
. „ „„„ Glass and Glass Product Manufacturing (44),
4.352 0.392 $356.6 ($3,610) "
Iron and Steel Mills and Ferroalloy Manufacturing (39),
Pipeline Transportation of Natural Gas (307)
Tier 2 Industry Boilers with Known Controls that Cost up
to $7,500/ton
6,033
(5,965/68)
Basic Chemical Manufacturing (17),
0.809 0.169 $54.2 ($3,744) Petroleum and Coal Products Manufacturing (10),
Pulp, Paper, and Paperboard Mills (25)
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Table 3. Estimated PPB Improvements at Receptors Grouped by Region*
Receptor ID
State
Receptor Name
Improvement Needed
Home State PPB
Contribution
Tier 1
Tier 2
Total
to Attain
90010017
CT
Greenwich
0.6/1.3
9.3
0.231
0.016
0.247
90013007
CT
Stratford
1.9/2.8
4.1
0.332
0.024
0.356
90019003
CT
Westport
3.7/3.9
2.9
0.314
0.022
0.336
90099002
CT
Madison
-/1.5
3.9
0.323
0.023
0.346
170310001
IL
Chicago/Alsip
-/1.6
19.4
0.196
0.065
0.261
170310032
IL
Chicago/South
-/0.8
16.6
0.299
0.076
0.375
170310076
IL
Chicago/ComEd
-/0.4
18.7
0.229
0.060
0.289
170314201
IL
Chicago/North brook
-/1.5
21.4
0.262
0.069
0.332
170317002
IL
Chicago/Evanston
-/l.l
18.9
0.307
0.049
0.356
550590019
Wl
Kenosha/Water Tower
0.8/1.7
5.8
0.325
0.035
0.360
550590025
Wl
Kenosha/Chiwaukee
-/0.2
2.6
0.392
0.051
0.443
551010020
Wl
Racine/Racine
-/1.2
10.8
0.353
0.044
0.397
480391004
TX
Houston/Brazoria
-/0.3
29.3
0.302
0.169
0.472
482010024
TX
Houston/Aldine
3.3/4.8
29.7
0.186
0.098
0.284
40278011
AZ
Yuma
-/0.9
2.8
0.027
0.001
0.028
60070007
CA
Butte
-/-0.8
23.5
0.000
0.000
0.000
60170010
CA
El Dorado #1
4.1/6.5
26.7
0.000
0.000
0.000
60170020
CA
El Dorado #2
2.3/4.1
28.7
0.000
0.000
0.000
60190007
CA
Fresno #1
8.6/10.4
29.1
0.001
0.000
0.001
60190011
CA
Fresno #2
11/11.9
31.1
0.002
0.000
0.002
60195001
CA
Fresno #3
11.8/14.5
30.2
0.002
0.000
0.002
60570005
CA
Nevada
6.3/9.6
25.4
0.000
0.000
0.000
60610003
CA
Placer #1
5/7.7
29.8
0.000
0.000
0.000
60610004
CA
Placer #2
0/5.1
24
0.000
0.000
0.000
60670012
CA
Sacramento
2.7/3.4
30.8
0.000
0.000
0.000
60990005
CA
Stanislaus
3.8/4.7
29.2
0.001
0.000
0.001
80350004
CO
Denver/Chatfield
-/0.2
15.6
0.055
0.001
0.056
80590006
CO
Rocky Flats
0.8/1.4
17.3
0.042
0.000
0.042
80590011
CO
Denver/NREL
1.7/2.4
17.6
0.044
0.001
0.044
490110004
UT
SLC/Bountiful
0.8/3
8
0.037
0.002
0.038
490353006
UT
SLC/Hawthorne
1.6/3.2
8.3
0.036
0.002
0.038
490353013
UT
SLC/Herriman
2.6/3.1
8.9
0.018
0.001
0.019
490570002
UT
SLC/Ogden
-/0.8
6.1
0.034
0.001
0.035
11
-------
Table 4. For Tier 1 Industries and Impactful Boilers in Tier 2 Industries, By State And By Industry, Estimated Emissions
Reductions (ozone season tons*) and Costs
Tier 1
Tier 2
Ozone Season
Annual Total Cost (million
Ozone Season
Annual Total Cost (million
State
Industry
Emissions
$) (Avg Annual Cost per
Emissions
$) (Avg Annual Cost per
Reductions
Ton)
Reductions
Ton)
AR
Basic Chemical Manufacturing
-
87
$1.1 ($5,113)
AR
Glass and Glass Product Manufacturing
47
$0.2 ($2,046)
-
-
AR
Iron and Steel Mills and Ferroalloy Manufacturing
6
$0.0 ($631)
-
-
AR
Pipeline Transportation of Natural Gas
868
$10.1 ($4,852)
-
-
AR
Pulp, Paper, and Paperboard Mills
-
-
646
$6.1 ($3,967)
CA
Cement and Concrete Product Manufacturing
1,162
$3.6 ($1,279)
-
-
CA
Glass and Glass Product Manufacturing
299
$0.9 ($1,293)
-
-
CA
Petroleum and Coal Products Manufacturing
-
-
68
$0.4 ($2,349)
CA
Pipeline Transportation of Natural Gas
137
$1.5 ($4,718)
-
-
IL
Cement and Concrete Product Manufacturing
234
$0.7 ($1,279)
-
-
IL
Glass and Glass Product Manufacturing
901
$2.6 ($1,180)
-
-
IL
Pipeline Transportation of Natural Gas
1,316
$13.7 ($4,348)
-
-
IN
Cement and Concrete Product Manufacturing
468
$1.4 ($1,279)
-
-
IN
Glass and Glass Product Manufacturing
338
$1.7 ($2,046)
-
-
IN
Iron and Steel Mills and Ferroalloy Manufacturing
1,829
$16.0 ($3,653)
-
-
IN
Petroleum and Coal Products Manufacturing
-
-
388
$2.8 ($2,989)
IN
Pipeline Transportation of Natural Gas
152
$2.0 ($5,457)
-
-
KY
Pipeline Transportation of Natural Gas
2,291
$28.7 ($5,213)
-
-
LA
Basic Chemical Manufacturing
-
-
1,611
$15.2 ($3,939)
LA
Glass and Glass Product Manufacturing
206
$1.9 ($3,770)
-
-
LA
Petroleum and Coal Products Manufacturing
-
-
477
$4.0 ($3,498)
LA
Pipeline Transportation of Natural Gas
3,915
$44.3 ($4,720)
-
-
LA
Pulp, Paper, and Paperboard Mills
-
-
561
$5.2 ($3,830)
MD
Pipeline Transportation of Natural Gas
45
$0.3 ($3,042)
-
-
Ml
Cement and Concrete Product Manufacturing
371
$1.1 ($1,279)
-
-
Ml
Glass and Glass Product Manufacturing
50
$0.3 ($2,661)
-
-
Ml
Iron and Steel Mills and Ferroalloy Manufacturing
38
$0.4 ($4,194)
-
-
Ml
Pipeline Transportation of Natural Gas
2,272
$25.9 ($4,747)
-
-
MN
Glass and Glass Product Manufacturing
115
$0.6 ($2,288)
-
-
MN
Pipeline Transportation of Natural Gas
558
$7.3 ($5,452)
-
-
MO
Cement and Concrete Product Manufacturing
1,296
$4.0 ($1,279)
-
-
MO
Glass and Glass Product Manufacturing
227
$1.1 ($1,992)
-
-
MO
Pipeline Transportation of Natural Gas
1,581
$20.2 ($5,338)
-
-
MS
Pipeline Transportation of Natural Gas
1,577
$19.0 ($5,009)
-
-
MS
Pulp, Paper, and Paperboard Mills
-
-
184
$1.4 ($3,243)
NY
Cement and Concrete Product Manufacturing
142
$0.4 ($1,279)
-
-
NY
Glass and Glass Product Manufacturing
141
$0.5 ($1,572)
-
-
NY
Pipeline Transportation of Natural Gas
106
$1.2 ($4,697)
-
-
NY
Pulp, Paper, and Paperboard Mills
-
-
Ill
$1.2 ($4,486)
12
-------
OH
Cement and Concrete Product Manufacturing
116
$0.4 ($1,279)
-
-
OH
Glass and Glass Product Manufacturing
451
$2.2 ($1,998)
-
-
OH
Iron and Steel Mills and Ferroalloy Manufacturing
847
$7.6 ($3,763)
-
-
OH
Pipeline Transportation of Natural Gas
1,198
$14.6 ($5,062)
-
-
OH
Pulp, Paper, and Paperboard Mills
-
-
179
$2.3 ($5,303)
OK
Cement and Concrete Product Manufacturing
586
$1.8 ($1,279)
-
-
OK
Glass and Glass Product Manufacturing
190
$1.2 ($2,550)
-
-
OK
Pipeline Transportation of Natural Gas
2,799
$34.1 ($5,083)
-
-
PA
Cement and Concrete Product Manufacturing
888
$2.8 ($1,336)
-
-
PA
Glass and Glass Product Manufacturing
1,379
$3.8 ($1,133)
-
-
PA
Iron and Steel Mills and Ferroalloy Manufacturing
438
$6.1 ($5,823)
-
-
PA
Petroleum and Coal Products Manufacturing
-
-
98
$0.6 ($2,349)
PA
Pipeline Transportation of Natural Gas
427
$4.1 ($3,994)
-
-
PA
Pulp, Paper, and Paperboard Mills
-
-
54
$0.9 ($7,019)
TX
Cement and Concrete Product Manufacturing
1,234
$7.8 ($2,624)
-
-
TX
Glass and Glass Product Manufacturing
1,470
$3.9 ($1,109)
-
-
TX
Pipeline Transportation of Natural Gas
1,736
$20.7 ($4,966)
-
-
UT
Cement and Concrete Product Manufacturing
520
$1.6 ($1,279)
-
-
UT
Pipeline Transportation of Natural Gas
237
$2.7 ($4,718)
-
-
VA
Cement and Concrete Product Manufacturing
398
$1.2 ($1,279)
-
-
VA
Glass and Glass Product Manufacturing
174
$0.9 ($2,154)
-
-
VA
Iron and Steel Mills and Ferroalloy Manufacturing
92
$1.0 ($4,357)
-
-
VA
Pipeline Transportation of Natural Gas
801
$10.5 ($5,457)
-
-
VA
Pulp, Paper, and Paperboard Mills
-
-
98
$1.4 ($5,903)
Wl
Glass and Glass Product Manufacturing
677
$2.5 ($1,517)
-
-
Wl
Pulp, Paper, and Paperboard Mills
-
-
1,472
$11.7 ($3,307)
WV
Cement and Concrete Product Manufacturing
230
$0.7 ($1,279)
-
-
WV
Pipeline Transportation of Natural Gas
751
$6.5 ($3,612)
-
-
WY
Cement and Concrete Product Manufacturing
446
$1.4 ($1,279)
-
-
WY
Pipeline Transportation of Natural Gas
380
$4.9 ($5,349)
-
-
Grand Total
41,153
$356.6 ($3,610)
6,033
$54.2 ($3,744)
Note that New Jersey and Nevada did not have any estimated non-EGU reductions that cost up to $7,500 per ton from the
Tier 1 industries and boilers in Tier 2 industries.
-------
Table 4a. For Tier 1 Industries and Impactful Boilers in Tier 2 Industries, By State, Estimated Emissions
Reductions (ozone season tons) and Costs
Tier 1
Tier 2
Ozone Season
Annual Total Cost (million
Ozone Season
Annual Total Cost (million
State
Emissions
$) (Avg Annual Cost per
Emissions
$) (Avg Annual Cost per
Reductions
Ton)
Reductions
Ton)
AR
922
$10.4 ($4,679)
732
$7.2 ($4,102)
CA
1,598
$6.0 ($1,576)
68
$0.4 ($2,349)
IL
2,452
$17.0 ($2,890)
-
-
IN
2,787
$21.1 ($3,157)
388
$2.8 ($2,989)
KY
2,291
$28.7 ($5,213)
-
-
LA
4,121
$46.2 ($4,673)
2,649
$24.4 ($3,837)
MD
45
$0.3 ($3,042)
-
-
Ml
2,731
$27.7 ($4,230)
-
-
MN
673
$7.9 ($4,910)
-
-
MO
3,103
$25.3 ($3,399)
-
-
MS
1,577
$19.0 ($5,009)
184
$1.4 ($3,243)
NY
389
$2.2 ($2,316)
111
$1.2 ($4,486)
OH
2,611
$24.7 ($3,944)
179
$2.3 ($5,303)
OK
3,575
$37.1 ($4,325)
-
-
PA
3,132
$16.8 ($2,237)
152
$1.5 ($4,013)
TX
4,440
$32.4 ($3,038)
-
-
UT
757
$4.3 ($2,356)
-
-
VA
1,465
$13.6 ($3,861)
98
$1.4 ($5,903)
Wl
677
$2.5 ($1,517)
1,472
$11.7 ($3,307)
WV
982
$7.2 ($3,065)
-
-
WY
826
$6.2 ($3,152)
-
-
14
-------
Figure 2. Geographical Distribution of Ozone Season NOx Reductions and Summary of Reductions by Industry and by State
Non-EGU Ozone Season NOx Reductions
•
Cement and Concrete Product Manufacturing
o
>1000 tons
•
Glass and Glass Product Manufacturing
o
500-1000 tons
o
Iron and Steel Mills and Ferroalloy Manufacturing
o
100-500 tons
o
Pipeline Transportation of Natural Gas
o
Under 100 tons
c
High Emitting Equipment from Tier 2 industries
State
Cement and
Concrete
Product
Manufacturing
Glass and
Glass
Product
Manufacturing
Iron and
Steel Mills
and
Ferroalloy
Manufacturing
Pipeline
Transportation
of Natural
Gas
High
Emitting
Equipment
from Tier 2
industries
Total
LA
0
206
0
3,915
2,649
6,769
TX
1,234
1,470
0
1,736
0
4,440
OK
586
190
0
2,799
0
3,575
PA
888
1,379
438
427
152
3,284
IN
468
338
1,829
152
388
3,175
MO
1,296
227
0
1,581
0
3,103
OH
116
451
847
1,198
179
2,790
Ml
371
50
38
2,272
0
2,731
IL
234
901
0
1,316
0
2,452
KY
0
0
0
2,291
0
2,291
Wl
0
677
0
0
1,472
2,150
MS
0
0
0
1,577
184
1,761
OA
1,162
299
0
137
68
1,666
AR
0
47
6
868
732
1,654
VA
398
174
92
801
98
1,563
WV
230
0
0
751
0
982
WY
446
0
0
380
0
826
UT
520
0
0
237
0
757
MN
0
115
0
558
0
673
NY
142
141
0
106
111
500
MD
0
0
0
45
0
45
-------
Table 5. By Industry, Number and Type of Emissions Units, Total Estimated Emissions Reductions (ozone season tons), Total PPB Improvements, and
Costs
Number of Units by Type
Ozone Season Emissions Reductions (tons)
Total PPB Improvement Across Downwind
by Type of Unit
Receptors (Max Improvement At Receptor)
Annual Total Cost
(million $) (Avg Annual
Cost per Ton)
Industry
Region
Boilers
Internal
Combustion
Engines
Industrial
Processes
Boilers
Internal
Combustion
Engines
Industrial
Processes
East
West
Glass and Glass Product Manufacturing
East
-
-
41
-
-
6,367
0.6962 (0.0865)
0.0015 (0.0004)
$23.2 ($1,520)
West
-
-
3
-
-
299
0.0009 (0.0001)
0.0332 (0.0066)
$0.9 ($1,293)
Cement and Concrete Product Manufacturing
East
1
-
39
16
-
5,948
0.6382 (0.0707)
0.0018 (0.0006)
$22.4 ($1,566)
Iron and Steel Mills and Ferroalloy Manufacturing
East
25
.
15
2,044
.
1,207
1.1556 (0.1750)
0.0000 (0.0000)
$31.2 ($3,995)
Pipeline Transportation of Natural Gas
East
-
296
-
-
22,390
-
1.5373 (0.2815)
0.0057 (0.0020)
$263.2 ($4,898)
West
-
-
-
"7n
-
0.0086 (0.0010)
0,0588 (0.0170)
,, , ^,r
Basic Chemical Manufacturing
East
17
-
-
1,698
-
-
0.1655 (0.0107)
0.0002 (0.0000)
$537.7 ($3,999)
Petroleum and Coal Products Manufacturing
East
9
-
-
962
-
-
0.2677 (0.0258)
0.0000 (0.0000)
$242.1 ($3,176)
Pulp, Paper; and Paperboard SVIiiis
East
25
-
-
3,305
-
-
0.3678 (0.0117)
0.0002 (0.0000)
$996.5 ($3,807)
16
-------
Table 6. By Industry, Emissions Source Group, Control Technology, Number of Units, Estimated Emissions Reductions (ozone season tons), and Annual
Total Cost
Industry
Emissions Source Group
Control Technology
Number of Units
Ozone Season
Emissions
Reductions
Annual Total Cost
(million $)
Cement and Concrete Product Manufacturing
Boilers - < 10 Million BTU/hr; Industrial Processes - Kiln
Ultra Low NOx Burner; Selective Non-Catalytic Reduction
1
117
$0.5
Industrial Processes - Kiln
Selective Non-Catalytic Reduction
24
3,123
$9.7
Industrial Processes - Preheater Kiln
Selective Non-Catalytic Reduction
3
342
$1.2
Industrial Processes - Preheater/Precalciner Kiln
Selective Non-Catalytic Reduction
19
4,510
$17.5
Glass and Glass Product Manufacturing
Industrial Processes - Container Glass: Melting Furnace
Selective Catalytic Reduction
27
1,676
$8.7
Industrial Processes - Flat Glass: Melting Furnace
Selective Catalytic Reduction
13
4,674
$12.7
Industrial Processes - Furnace: General
Oxygen Enriched Air Staging
1
52
$0.1
Industrial Processes - Pressed and Blown Glass: Melting
Furnace
Selective Catalytic Reduction
3
264
$2.7
Iron and Steel Mills and Ferroalloy Manufacturing
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner and Selective Catalytic Reduction
3
383
$4.2
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner
6
282
$2.2
Boilers - > 100 Million BTU/hr
Selective Catalytic Reduction
2
106
$1.2
Boilers - > 100 Million BTU/hr; Boilers - Blast Furnace Gas
Ultra Low NOx Burner
1
166
$1.0
Boilers - > 100 Million BTU/hr; Boilers - Coke Oven Gas
Ultra Low NOx Burner
6
360
$2.9
Boilers - > 100 Million BTU/hr; Boilers - Coke Oven Gas
Selective Catalytic Reduction; Ultra Low NOx Burner and Selective
Catalytic Reduction
1
114
$1.7
Boilers - Blast Furnace Gas
Ultra Low NOx Burner
1
65
$0.4
Boilers - Blast Furnace Gas; Industrial Processes - Sintering:
Windbox; Industrial Processes - Blast Furnace:
Casting/Tapping: Local Evacuation; Industrial Processes -
Ultra Low NOx Burner; Selective Catalytic Reduction; Low NOx
Burner and Flue Gas Recirculation
1
440
$4.4
Process Gas: Process Heaters
Boilers - Coke Oven Gas
Ultra Low NOx Burner and Selective Catalytic Reduction
3
394
$3.7
Boilers - Coke Oven Gas; Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner; Ultra Low NOx Burner and Selective
Catalytic Reduction
1
116
$1.6
Industrial Processes - Basic Oxygen Furnace (BOF): Open
Hood Stack
Selective Catalytic Reduction
2
185
$1.9
Industrial Processes - Basic Oxygen Furnace (BOF): Open
Hood Stack; Industrial Processes - General
Selective Catalytic Reduction; Low NOx Burner
1
172
$1.7
Industrial Processes - Basic Oxygen Furnace (BOF): Top
Blown Furnace: Primary
Selective Catalytic Reduction
1
50
$0.5
Industrial Processes - Blast Furnace: Casting/Tapping: Local
Evacuation
Selective Catalytic Reduction
1
38
$0.4
Industrial Processes - General
Low NOx Burner
5
191
$1.7
Industrial Processes - General; Industrial Processes - Coke
Oven or Blast Furnace
Low NOx Burner; Low NOx Burner and Flue Gas Recirculation
1
84
$1.0
Industrial Processes - Other Not Classified
Low NOx Burner and Flue Gas Recirculation
2
43
$0.1
Industrial Processes - Sintering: Windbox
Selective Catalytic Reduction
1
60
$0.6
Pipeline Transportation of Natural Gas
Internal Combustion Engines - 2-cycle Clean Burn
Layered Combustion
1
60
00
o
¦CO-
Internal Combustion Engines - 2-cycle Lean Burn
Layered Combustion
136
12,645
$165.6
Internal Combustion Engines - 4-cycle Lean Burn
Selective Catalytic Reduction
41
2,656
$21.6
Internal Combustion Engines - 4-cycle Rich Burn
Non-Selective Catalytic Reduction
2
147
$0.2
Internal Combustion Engines - Reciprocating
Non-Selective Catalytic Reduction or Layered Combustion
94
6,329
$72.0
Internal Combustion Engines - Reciprocating
Adjust Air to Fuel Ratio and Ignition Retard
12
193
$1.1
Internal Combustion Engines - Reciprocating
Non-Selective Catalytic Reduction or Layered Combustion; Adjust
Air to Fuel Ratio and Ignition Retard
1
49
$0.4
Internal Combustion Engines - Turbine
Selective Catalytic Reduction and Steam Injection
17
929
$8.4
Internal Combustion Engines - Turbine
SCR + DLN Combustion
3
136
$2.1
17
-------
Basic Chemical Manufacturing
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner and Selective Catalytic Reduction
6
786
Boilers - > 100 Million BTU/hr
Selective Catalytic Reduction
2
104
Boilers - 10-100 Million BTU/hr
Ultra Low NOx Burner and Selective Catalytic Reduction
1
133
Boilers - 10-100 Million BTU/hr
Selective Catalytic Reduction
1
43
Boilers - Cogeneration
Selective Catalytic Reduction
1
68
Boilers - Distillate Oil - Grades 1 and 2: Boiler
Selective Catalytic Reduction
1
47
Boilers - Petroleum Refinery Gas
Ultra Low NOx Burner and Selective Catalytic Reduction
2
293
Boilers - Petroleum Refinery Gas
Ultra Low NOx Burner
2
138
Boilers - Subbituminous Coal: Traveling Grate (Overfeed)
Stoker
Selective Catalytic Reduction
1
87
Petroleum and Coal Products Manufacturing
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner
1
41
Boilers - > 100 Million BTU/hr; Boilers - Blast Furnace Gas
Ultra Low NOx Burner
1
38
Boilers - Boiler, >= 100 Million BTU/hr
Natural Gas Reburn
1
284
Boilers - Coke Oven Gas
Ultra Low NOx Burner
1
98
Boilers - Petroleum Refinery Gas
Ultra Low NOx Burner and Selective Catalytic Reduction
3
433
Boilers - Petroleum Refinery Gas
Ultra Low NOx Burner
3
137
Pulp, Paper, and Paperboard Mills
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner and Selective Catalytic Reduction
5
618
Boilers - > 100 Million BTU/hr
Ultra Low NOx Burner
3
151
Boilers - > 100 Million BTU/hr
Selective Catalytic Reduction
1
68
Boilers - 10-100 Million BTU/hr
Ultra Low NOx Burner
2
106
Boilers - Bituminous Coal: Cyclone Furnace
Selective Catalytic Reduction
2
662
Boilers - Bituminous Coal: Pulverized Coal: Dry Bottom
Ultra Low NOx Burner and Selective Catalytic Reduction
1
111
Boilers - Bituminous Coal: Pulverized Coal: Dry Bottom;
Boilers - > 100 Million BTU/hr
Low NOx Burner; Selective Catalytic Reduction
1
98
Boilers - Bituminous Coal: Spreader Stoker
Selective Catalytic Reduction
3
251
Boilers - Cogeneration
Ultra Low NOx Burner and Selective Catalytic Reduction
2
338
Boilers - Fluid Catalytic Cracking Unit with CO Boiler: Natural
Gas
Ultra Low NOx Burner and Selective Catalytic Reduction
2
289
Boilers - Subbituminous Coal: Boiler, Spreader Stoker
Selective Catalytic Reduction
2
348
Boilers - Subbituminous Coal: Spreader Stoker
Selective Catalytic Reduction
1
266
$7.5
$1.5
$1.0
$0.1
$0.9
$0.6
$2.8
$0.8
$1.1
$0.2
$0.4
$1.8
$0.6
$3.8
$0.9
$6.8
$1.0
$1.2
$0.5
$3.4
$1.1
$1.4
$3.2
$2.9
$2.7
$3.7
$2.3
18
-------
Table 7. Estimated Emissions Reductions (ozone season tons), Annual Total Cost, and Average Cost per Ton by Control
Technology Across All Non-EGU Emissions Units
Average Cost
Control Technology
OS NOx Reductions
Annual Total Cost
per Ton
Adjust Air to Fuel Ratio and Ignition Retard
212
$1,216,435
$2,393
Layered Combustion
12,706
$166,398,282
$5,457
Low NOx Burner
231
$2,092,579
$3,773
Low NOx Burner and Flue Gas Recirculation
200
$2,054,876
$4,288
Natural Gas Reburn
284
$1,843,948
$2,703
Non-Selective Catalytic Reduction
147
$205,808
$585
Non-Selective Catalytic Reduction or Layered Combustion
6,359
$72,383,222
$4,743
Oxygen Enriched Air Staging
52
$95,641
$764
SCR + DLN Combustion
136
$2,060,943
$6,301
Selective Catalytic Reduction
12,239
$74,692,132
$2,543
Selective Catalytic Reduction and Steam Injection
929
$8,439,921
$3,787
Selective Non-Catalytic Reduction
8,076
$28,782,335
$1,485
Ultra Low NOx Burner
1,670
$11,584,405
$2,890
Ultra Low NOx Burner and Selective Catalytic Reduction
3,946
$38,959,490
$4,114
Table 8. Estimated Emissions Reductions (ozone season tons), Annual Total Cost, and Average Cost per Ton by Control
Technology Across Non-EGU Emissions Units Grouped by the Tier 1 Industries and Impactful Boilers in Tier 2 Industries
Average Cost
Tier
Control Technology
OS NOx Reductions
Annual Total Cost
per Ton
Tier 1
Adjust Air to Fuel Ratio and Ignition Retard
212
$1,216,435
$2,393
Tier 1
Layered Combustion
12,706
$166,398,282
$5,457
Tier 1
Low NOx Burner
211
$1,852,495
$3,656
Tier 1
Low NOx Burner and Flue Gas Recirculation
200
$2,054,876
$4,288
Tier 1
Non-Selective Catalytic Reduction
147
$205,808
$585
Tier 1
Non-Selective Catalytic Reduction or Layered Combustion
6,359
$72,383,222
$4,743
Tier 1
Oxygen Enriched Air Staging
52
$95,641
$764
Tier 1
SCR + DLN Combustion
136
$2,060,943
$6,301
Tier 1
Selective Catalytic Reduction
10,219
$55,575,188
$2,266
Tier 1
Selective Catalytic Reduction and Steam Injection
929
$8,439,921
$3,787
Tier 1
Selective Non-Catalytic Reduction
8,076
$28,782,335
$1,485
Tier 1
Ultra Low NOx Burner
962
$7,172,778
$3,107
Tier 1
Ultra Low NOx Burner and Selective Catalytic Reduction
946
$10,362,549
$4,567
Tier 2
Low NOx Burner
20
$240,084
$5,022
Tier 2
Natural Gas Reburn
284
$1,843,948
$2,703
Tier 2
Selective Catalytic Reduction
2,020
$19,116,944
$3,942
Tier 2
Ultra Low NOx Burner
708
$4,411,626
$2,594
Tier 2
Ultra Low NOx Burner and Selective Catalytic Reduction
3,000
$28,596,941
$3,972
19
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Table 9. Estimated Emissions Reductions (ozone season tons), Annual Total Cost, and Average Cost per Ton by Control Technology Across Non-EGU
Emissions Units Grouped by the Seven Individual Tier 1 and Tier 2 Industries
Average Cost
Industry
Control Technology
OS NOx Reductions
Annual Total Cost
per Ton
Cement and Concrete Product Manufacturing
Selective Non-Catalytic Reduction
8,076
$28,782,335
$1,485
Cement and Concrete Product Manufacturing
Ultra Low NOx Burner
16
$169,531
$4,410
Glass and Glass Product Manufacturing
Oxygen Enriched Air Staging
52
$95,641
$764
Glass and Glass Product Manufacturing
Selective Catalytic Reduction
6,615
$24,062,362
$1,516
Iron and Steel Mills and Ferroalloy Manufacturing
Low NOx Burner
211
$1,852,495
$3,656
Iron and Steel Mills and Ferroalloy Manufacturing
Low NOx Burner and Flue Gas Recirculation
200
$2,054,876
$4,288
Iron and Steel Mills and Ferroalloy Manufacturing
Selective Catalytic Reduction
948
$9,886,092
$4,345
Iron and Steel Mills and Ferroalloy Manufacturing
Ultra Low NOx Burner
946
$7,003,247
$3,085
Iron and Steel Mills and Ferroalloy Manufacturing
Ultra Low NOx Burner and Selective Catalytic Reduction
946
$10,362,549
$4,567
Pipeline Transportation of Natural Gas
Adjust Air to Fuel Ratio and Ignition Retard
212
$1,216,435
$2,393
Pipeline Transportation of Natural Gas
Layered Combustion
12,706
$166,398,282
$5,457
Pipeline Transportation of Natural Gas
Non-Selective Catalytic Reduction
147
$205,808
$585
Pipeline Transportation of Natural Gas
Non-Selective Catalytic Reduction or Layered Combustion
6,359
$72,383,222
$4,743
Pipeline Transportation of Natural Gas
SCR + DLN Combustion
136
$2,060,943
$6,301
Pipeline Transportation of Natural Gas
Selective Catalytic Reduction
2,656
$21,626,734
$3,393
Pipeline Transportation of Natural Gas
Selective Catalytic Reduction and Steam Injection
929
$8,439,921
$3,787
Basic Chemical Manufacturing
Selective Catalytic Reduction
348
$4,198,768
$5,027
Basic Chemical Manufacturing
Ultra Low NOx Burner
138
$769,564
$2,317
Basic Chemical Manufacturing
Ultra Low NOx Burner and Selective Catalytic Reduction
1,211
$11,326,715
$3,896
Petroleum and Coal Products Manufacturing
Natural Gas Reburn
284
$1,843,948
$2,703
Petroleum and Coal Products Manufacturing
Ultra Low NOx Burner
313
$2,110,773
$2,808
Petroleum and Coal Products Manufacturing
Ultra Low NOx Burner and Selective Catalytic Reduction
433
$3,762,867
$3,624
Pulp, Paper, and Paperboard Mills
Low NOx Burner
20
$240,084
$5,022
Pulp, Paper, and Paperboard Mills
Selective Catalytic Reduction
1,672
$14,918,176
$3,717
Pulp, Paper, and Paperboard Mills
Ultra Low NOx Burner
257
$1,531,289
$2,484
Pulp, Paper, and Paperboard Mills
Ultra Low NOx Burner and Selective Catalytic Reduction
1,356
$13,507,360
$4,151
20
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VI. Request for Comment and Additional Information
In this screening assessment the EPA used CoST, the CMDB, and the 2019 emissions inventory to assess emission
reduction potential from non-EGU emissions units in several industries. We identified emissions units that were
uncontrolled or that could be better controlled and then applied control technologies to estimate emissions reductions
and costs. As noted above, the cost estimates do not include monitoring, recordkeeping, reporting, or testing costs.
As discussed in Section VI.D.2.a of the proposal preamble, the EPA requests comment on the capital and annual costs of
several potential control technologies, and in particular whether ultra-low NOx burners or low NOx burners are generally
considered part of the process or add-on controls for ICI boilers (and how process changes or retrofits to accommodate
controls would affect the cost estimates); the effectiveness of low emissions combustion in controlling NOx from
reciprocating IC engines, compared to other potential NOx controls for these engines; and whether controls on ICI boilers
and reciprocating IC engines are likely to be run all year or only during the ozone season.
The EPA also requests comment on the time needed to install the various control technologies across all of the emissions
units in the Tier 1 and Tier 2 industries. In particular, the EPA solicits comment on the time needed to obtain permits, the
availability of vendors and materials, and the earliest possible installation times for SCR on glass furnaces; SNCR on
cement kilns; ultra-low NOx burners, low NOx burners, and SCR on ICI boilers (coal-fired, gas-fired, or oil-fired); low NOx
burners on large non-EGU ICI boilers; and low emissions combustion, layered emissions combustion, NSCR, and SCR on
reciprocating rich-burn or lean-burn IC engines.
Finally, with respect to emissions monitoring requirements, the EPA requests comment on the costs of installing and
operating CEMS at non-EGU sources without NOx emissions monitors; the time needed to program and install CEMS at
non-EGU sources; whether monitoring techniques other than CEMS, such as predictive emissions monitoring systems
(PEMS), may be sufficient for certain non-EGU facilities, and the types of non-EGU facilities for which such PEMS may be
sufficient; and the costs of installing and operating monitoring techniques other than CEMS.
21
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APPENDIX A - Analysis of Industry Contribution Data
This appendix describes the analyses performed to help focus the non-EGU analytical framework and resulting
screening assessment on the most impactful industries.
To inform this analysis, first using the procedure described in Section III, Step 1 above, we estimated contributions
from each of 41 industries to each nonattainment and maintenance receptor in 2023 and used these data to
calculate the 5 metrics identified in Table A-l.27,28 A summary of the data for each metric for each industry is
provided in Table A-3. These metrics were selected to provide air quality information to inform an evaluation of the
magnitude and geographic scope of contributions from individual industries. Metrics 1, 2, and 3 provide information
on the magnitude of the contribution. Metric 4 provides information on the geographic scope of the downwind
impact, whereas Metric 5 provides information on the geographic scope of upwind state contributions. Of the three
air quality metrics we chose to analyze the data for Metric 2, the maximum contribution to any downwind receptor,
because this metric aligns with the air quality metric used in Step 2 of the four-step interstate transport framework
to identify linked upwind states for further review in Step 3 of the interstate transport framework. To examine the
geographic breadth of the industry contributions we chose Metric 4 because that metric provides information on the
extent of impacts on downwind air quality problems.
Table A-l. Contribution Metrics for Non-EGU Assessment
1
Total contribution to all downwind receptors
2
Maximum contribution to any downwind receptor
3
Average contribution across all receptors
4
Number of receptors with contributions >= 0.01 ppb
5
Number of linked upwind states with highest industry contribution >= 0.01 ppb
Next, we evaluated the maximum downwind contributions to identify the most impactful industries for further
analysis. This approach included a semi-quantitative examination of rank-ordered maximum contributions to identify
breakpoints in the data that might serve as an initial screen to eliminate non-impactful industries from further
analysis of the contribution data. The distribution of maximum contributions provided in Table A-3 indicate that
there is a large range in the values across the 41 industries. Specifically, 5 industries individually contribute more
than 0.10 ppb, 3 industries contribute between 0.05 ppb and 0.10 ppb, 11 industries contribute between 0.01 and
0.05 ppb, 8 industries contribution between 0.005 and 0.01 ppb, and 14 industries contribute less than 0.005 ppb.
The rank-ordered maximum downwind contributions from individual industries are shown in Figure A-l. In this figure
each point represents the maximum contribution to a downwind receptor from a particular industry. Note that the
values for the highest contributing industries are not show in the figure in order to provide greater resolution of the
shape of the distribution at the lower end of the values. The declining curve in Figure A-l exhibits a shape similar to a
harmonic distribution. Initially, there is a fairly steep drop in contributions with a breakpoint between roughly 0.04
and 0.06 ppb followed by a steady decline to 0.01 ppb. Beyond 0.01 ppb the shape of the distribution is much flatter.
The data suggest that perhaps 0.05 ppb or 0.01 ppb could serve as breakpoints in the data. Based on the distribution
27 Receptors in California were not considered in evaluating the impacts of non-EGU sources because EPA's contributions from upwind
states to these receptors at Step 2 of the four-step interstate transport framework finds that these monitoring sites are overwhelmingly
impacted by in-state emissions to a degree not comparable with any other identified nonattainment or maintenance-only receptors in the
country. In this regard, EPA is proposing a determination that California receptors are not sufficiently impacted by interstate transport of
ozone to warrant proceeding with a Step 3 evaluation of emissions reduction opportunities.
28 The methods for identifying receptors are described in the Air Quality Modeling TSD for this proposed rule.
22
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of the data we determined that 0.01 ppb provides a meaningful conservative breakpoint for screening out non-
impactful industries from the non-EGU contribution analysis. The specific industries with a maximum downwind
contribution >= 0.01 ppb are identified in Table A-2.
0.15
0.14
0,13
0.12
0.11
o.io
0.09
0.08
0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.00
-
...
-
1 n n n fl n n n n n n n n n _ _
Figure A-l. Rank-ordered maximum downwind contributions from individual industries
We then examined the data for Metrics 2 and 4 for each industry that has a maximum contribution >= 0.01 ppb. The data for
Metric 4, as shown in Figure A-2, suggests that there as a breakpoint between those industries that contribute to 10 or more
receptors versus those industries that contribute to fewer than 10 receptors. Table A-2 provides the data for Metrics 2 and 4,
ranked by the magnitude of Metric 4. The data show that 8 industries contribute >= 0.01 ppb to more than 10 receptors. Of
these 8 industries, 5 have a maximum contributions of > 0.10 ppb to one of these receptors. In addition, one industry, Basic
Chemical Manufacturing, contributes to only 9 receptors, but the maximum contribution to one of these receptors is >0.10
ppb. Using this information, we grouped the 9 industries into one of 2 tiers based on considering both the magnitude of the
contribution and the downwind extent of affected receptors. Tier 1 includes the 4 industries that each have (1) a maximum
contribution to any one receptor of >0.10 ppb and (2) a contribution >= 0.01 ppb to at least 10 receptors, Tier 2 includes the
5 industries that each have (1) a maximum contribution to any one receptor >=0.10 ppb but contribute >=0.01 ppb to fewer
than 10 receptors, or (2) a maximum contribution <0.10 ppb but contribute >=0.01 ppb to at least 10 receptors.
23
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Figure A-2. Number of downwind receptors with contributions >= 0.10 ppb for each industry with a maximum
downwind contribution >= 0.01 ppb
Table A-2. Maximum downwind contribution and number of receptors with contributions >= 0.01 ppb
Max
Downwind
# Receptors with
Industry
Contribution
Contributions >= 0.01 ppb
Cement and Concrete Products
0.231
19
Metal Ore Mining
0.079
15
Lime and Gypsum Products
0.066
13
Pipeline Transportation of Natural Gas
0.287
12
Petroleum and Coal Products
0.098
12
Iron and Steel Mills and Ferroalloy
0.129
11
Glass and Glass Products
0.105
11
Pulp, Paper, and Paperboard Mills
0.043
11
Basic Chemical
0.123
9
Oil and Gas Extraction
0.035
9
Resin, Synthetic Rubber, and Fibers and Filaments
0.027
7
Nonmetallic Mineral Mining and Quarrying
0.035
4
Clay Product and Refractory
0.024
4
Water, Sewage and OtherSystems
0.016
4
Pesticide, Fertilizer, and Other Ag
0.044
3
OtherChemical Products
0.024
3
Chemical and Allied Products
0.019
2
Natural Gas Distribution
0.016
1
Pharmaceutical and Medicine
0.011
1
24
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Table A-3. Estimated Total, Maximum, and Average Contributions from Each Industry, and Number of Receptors with Contributions >= 0.01
ppb for 2023
Industry
# Facilities with Units
>100tpy
# Units > 100 tpy
Ozone Season
Emissions
Total Contribution
Max Contribution
Average Contribution
# Receptors with
Contributions >= 0.01
ppb
# States with Highest
Contribution >= 0.01
ppb
Pipeline Transportation of Natural Gas
144
399
34,343
1.679
0.287
0.084
12
12
Cement and Concrete Product Manufacturing
61
84
36,244
1.871
0.231
0.094
19
13
Iron and Steel Millsand Ferroalloy Manufacturing
14
43
4,622
0.577
0.129
0.029
11
1
Basic Chemical Manufacturing
38
78
9,612
0.293
0.123
0.015
9
2
Glass and Glass Product Manufacturing
38
53
12,059
0.695
0.105
0.035
11
7
Petroleum and Coal Products Manufacturing
47
94
8,163
0.733
0.098
0.037
12
6
Metal Ore Mining
9
21
17,778
0.687
0.079
0.034
15
3
Lime and Gypsum Product Manufacturing
31
60
8,856
0.531
0.066
0.027
13
3
Pesticide, Fertilizer, and Other Agricultural Chemical Manufacturing
16
27
3,680
0.162
0.044
0.008
3
1
Pulp, Paper, and Paperboard Mills
46
73
6,773
0.306
0.043
0.015
11
3
Oil and Gas Extraction
59
139
9,150
0.207
0.035
0.010
9
2
Nonmetallic Mineral Mining and Quarrying
8
18
3,808
0.167
0.035
0.008
4
1
Resin, Synthetic Rubber, and Artificial and Synthetic Fibers and Filaments Manufacturing
10
16
1,779
0.152
0.027
0.008
7
2
Other Chemical Product and Preparation Manufacturing
7
8
683
0.074
0.024
0.004
3
1
Clay Product and Refractory Manufacturing
1
2
1,098
0.088
0.024
0.004
4
1
Chemical and Allied Products Merchant Wholesalers
1
4
573
0.032
0.019
0.002
2
1
Natural Gas Distribution
6
17
1,027
0.058
0.016
0.003
1
1
Water, Sewage and Other Systems
6
6
375
0.069
0.016
0.003
4
1
Pharmaceutical and Medicine Manufacturing
2
2
300
0.057
0.011
0.003
1
1
Grain and Oilseed Milling
4
4
376
0.042
0.009
0.002
0
0
Lessors of Real Estate
2
2
138
0.037
0.009
0.002
0
0
Nonferrous Metal (except Aluminum) Production and Processing
1
4
408
0.025
0.008
0.001
0
0
Sugar and Confectionery Product Manufacturing
5
10
1,068
0.043
0.008
0.002
0
0
Electric Power Generation, Transmission and Distribution
4
4
296
0.039
0.006
0.002
0
0
Engine, Turbine, and PowerTransmission Equipment Manufacturing
2
2
112
0.020
0.005
0.001
0
0
Agriculture, Construction, and Mining Machinery Manufacturing
1
1
73
0.012
0.005
0.001
0
0
Colleges, Universities, and Professional Schools
4
4
263
0.030
0.005
0.002
0
0
Coal Mining
5
5
283
0.015
0.004
0.001
0
0
Plastics Product Manufacturing
2
2
126
0.012
0.004
0.001
0
0
Architectural, Engineering, and Related Services
2
2
117
0.013
0.003
0.001
0
0
Motor Vehicle Parts Manufacturing
1
1
62
0.011
0.003
0.001
0
0
Advertising, Public Relations, and Related Services
51
0.009
Waste Treatment and Disposal
376
0.010
National Security and International Affairs
1
1
42
0.002
Legend
Support Activities for Mining
1
1
56
0.003
# States with
Beverage Manufacturing
1
1
45
0.002
# Receptors with
Contributions
Highest
Contribution
Veneer, Plywood, and Engineered Wood Product Manufacturing
1
1
9
0.001
IVIdAIIIIUIIl
Contribution
>=0.01 ppb
Total Contribution
>= 0.01
Scientific Research and Development Services
1
1
78
0.001
Break Points
0.01 to 0.04
> 1 to 9
0.1 to 0.4
> 1 to 9
Alumina and Aluminum Production and Processing
1
1
13
0.000
>= 0.05
>= 10
>= 0.5
>= 10
Other Food Manufacturing
1
1
45
0.000
Office Administrative Services
1
1
5
0.000
1st Tier of Industries for Further Analysis Based on AQ Contributions |
These industries H) have a maximum contribution to anv one receotor of >0.10 oob
AND (2) contribute >= 0.01 ppb to at least 10 receptors.
Total
591
1,199
164,962
8.77
2nd Tier of Industries for Further Analysis Based on AQ Contributions
Tier 1 Industries
257
579
87,267
4.82
These industries either have:
Tier 2 Industries
171
326
51,182
2.55
(1) a maximum contribution to any one receptor >=0.10 ppb but contribute >=0.01 ppb
Tier 1 Industries {% of Total)
43%
48%
53%
55%
to fewer than 10 receptors, or
(2) a maximum contribution <0.10 ppb but contribute >—0.01 ppb to at least 10 receptors
Tier 2 Industries {% of Total)
29%
27%
31%
29%
25
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APPENDIX B - SUMMARY OF FACILITIES REMOVED in the SCREENING ASSESSMENT for 2026
REGION CD
FACILITY ID
Reason for Removal
state
county
site name
naics code
naics_description
city
24001
7763811
Closure
MD
Allegany
Luke Paper Company
322121
Paper (except Newsprint) Mills
Luke
06029
4789011
Subject to Consent Decree
CA
Kern
LEHIGH SOUTHWEST CEMENT CO.
327310
Cement Manufacturing
MONOLITH
06029
4789311
Subject to Consent Decree
CA
Kern
CALIFORNIA PORTLAND CEMENT CO.
327310
Cement Manufacturing
MOJAVE
06071
4841311
Subject to Consent Decree
CA
San Bernardino
CEMEX- BLACK MOUNTAIN QUARRY PLANT
327310
Cement Manufacturing
APPLE VALLEY
18093
8225311
Units to be replaced by new kiln by 2023
IN
Lawrence
LEHIGH CEMENT COMPANY LLC
32731
Cement Manufacturing
Mitchell
26007
8127411
Subject to Consent Decree
Ml
Alpena
Holcim (US) Inc. DBA Lafarge Alpena Plant
327310
Cement Manufacturing
ALPENA
26
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