TECHNICAL MEMORANDUM

TO:	Docket for Rulemaking, "Federal Good Neighbor Plan Addressing Regional Ozone Transport

for the 2015 Ozone National Ambient Air Quality Standards" (EPA-HQ-OAR-2021-0668)

DATE:	March 15, 2023

SUBJECT: Summary of Final Rule Applicability Criteria and Emissions Limits for Non-EGU Emissions
Units, Assumed Control Technologies for Meeting the Final Emissions Limits, and Estimated
Emissions Units, Emissions Reductions, and Costs

I. Background

For the February 28, 2022 Proposed Federal Implementation Plan Addressing Regional Ozone Transport for
the 2015 Ozone National Ambient Air Quality Standards (proposed FIP), the EPA developed an analytical
framework to facilitate decisions about industries and emissions unit types for including emissions units in the
non-electric generating unit "sector" (non-EGUs) in a proposed FIP for the 2015 ozone national ambient air
quality standards (NAAQS) transport obligations. A February 28, 2022 memorandum, titled Screening
Assessment of Potential Emissions Reductions, Air Quality Impacts, and Costs from Non-EGU Emissions Units
for 2026 (Non-EGU Screening Assessment), documents the analytical framework that the EPA used to identify
industries and emissions unit types included in the proposed FIP.1

To further evaluate the industries and emissions unit types identified and to establish the proposed emissions
limits, the EPA reviewed Reasonably Available Control Technology (RACT) rules, New Source Performance
Standards (NSPS) rules, National Emissions Standards for Hazardous Air Pollutants (NESHAP) rules, existing
technical studies, rules in approved state implementation plan (SIP) submittals, consent decrees, and permit
limits. That evaluation is detailed in the EPA's December 2021 technical support document for the proposed FIP
entitled Technical Support Document (TSD) for the Proposed Rule, Non-EGU Sectors TSD (Non-EGU Sectors
TSD).2

Finally, in the proposed FIP the EPA proposed to find, based on the most recent information available from the
EPA's August 2016 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),3 that controls on all of the non-EGU emissions units
could not be installed by the 2023 ozone season. The proposed FIP estimated controls could be installed on non-
EGU emissions units by the 2026 ozone season. For this final rule, the EPA prepared a report entitled NOx
Emission Control Technology Installation Timing for Non-EGU Sources (Non-EGU Control Installation Timing
Report)4 that includes estimates of the amount of time needed to install the control equipment identified in the
EPA's final rule and associated Technical Support Document (TSD) for the Final Rule, Non-EGU Sectors TSD

1	The Non-EGU Screening Assessment is available in the docket here: https://www.regulations.gov/document/EPA-HQ-
OAR-2021-0668-0150.

2	The Non-EGU Sectors TSD is available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-
0668-0145.

3	The CSAPR Update Non-EGU TSD is available here: https://www.epa.gov/csapr/assessment-non-egu-NOx-emission-
controls-cost-controls-and-time-compliance-final-tsd.

4	The Non-EGU Control Installation Timing Report is available in the docket here:
https ://www. regulations. gov/document/EP A-HQ-0 AR-2021-0668.

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(Final Non-EGU Sectors TSD).5 All stages of the process to install control equipment, including but not limited
to time for contract award, permitting, construction, and actual installation, are included in the control
equipment installation time estimate. In addition, we included information on materials and labor needed to
complete installation, including equipment vendor capacity.

This memorandum summarizes the emissions unit types, applicability criteria, emissions limits, estimated list of
emissions units captured by the applicability criteria, and estimated emissions reductions and costs for the year
2026 associated with the final Federal Good Neighbor Plan Addressing Regional Ozone Transport for the 2015
Ozone National Ambient Air Quality Standards. The remainder of this memorandum includes the following
sections:

II. Applicability Criteria for Non-EGU Emissions Units Subject to the Final Rule
III Emissions Limits for the Final Rule

IV. Assumed Control Technologies that Meet the Emissions Limits in the Final Rule
V. Estimating Emissions Units, Emissions Reductions, and Costs

II. Applicability Criteria for Non-EGU Emissions Units Subject to the Final Rule

The EPA is finalizing rate-based limits and production-based limits to directly control emissions of nitrogen
oxides (NOx) from the types of non-EGU emissions units identified in the proposed FIP. In addition, in Section
V.B.3.b of the preamble for the proposed FIP, the EPA included a discussion of the potential for NOx emissions
reductions from municipal waste combustors (MWCs) and solicited comment on whether these units should be
included in a final FIP to address the 2015 ozone NAAQS transport obligations. The EPA is including these
units in the final rule. For all of the non-EGU emissions units, the EPA developed emissions control
requirements using applicability criteria based on size and type of unit and, in some cases, emissions thresholds.
Table 1 below (Table II. A-1 of the final rule preamble) lists the nine non-EGU industries covered by the rule,
identified by North American Industry Classification System (NAICS) codes. Table 2 below summarizes the
industries, emissions unit types, and applicability requirements.

Table 1. Industries and NAICS Codes Covered by Rule

Industry

NAICS

Pipeline Transportation of Natural Gas

4862

Cement and Concrete Product Manufacturing

3273

Iron and Steel Mills and Ferroalloy Manufacturing

3311

Glass and Glass Product Manufacturing

3272

Metal Ore Mining6

2122

Basic Chemical Manufacturing

3251

Petroleum and Coal Products Manufacturing

3241

Pulp, Paper, and Paperboard Mills

3221

Solid Waste Combustors and Incinerators

562213

5	The Final Non-EGU Sectors TSD is available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-
2021-0668.

6	The analytical framework applied in the Non-EGU Screening Assessment did not identify any boilers in the Metal Ore
Mining industry with > 100 tpy NOx emissions. As such, no boilers were reflected in the proxy results from the screening
assessment for proposal. The proposed and final applicability criterion for boilers is not based on tpy and is based on design
capacity >100 MMBtu/hour. Metal Ore Mining has a few boilers with a design capacity of >100 MMBtu/hour that could be
subject to the final emissions limits. See Section H.A., Table ll.A-1 of the final rule preamble.

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Table 2. Summary of Industries, Non-EGU Emissions Unit Types, and Applicability Requirements

Industry

Emissions Unit Type

Applicability Requirements

Pipeline Transportation of Natural Gas

Reciprocating Internal
Combustion Engines

Nameplate rating of >1000 braking
horsepower (bhp)

Cement and Concrete Product Manufacturing

Kilns

Directly emits or has the potential to emit
100 tpy or more of NOx

Iron and Steel Mills and Ferroalloy Manufacturing

Reheat Furnaces

Directly emits or has the potential to emit
100 tpy or more of NOx

Glass and Glass Product Manufacturing

Furnaces

Directly emits or has the potential to emit
100 tons per year (tpy) or more of NOx

Iron and Steel Mills and Ferroalloy Manufacturing

Metal Ore Mining

Basic Chemical Manufacturing

Petroleum and Coal Products Manufacturing

Pulp, Paper, and Paperboard Mills

Boilers

Design capacity of >100 mmBtu/hr

Solid Waste Combustors and Incinerators

Combustors or
Incinerators

Design capacity > 250 tons of waste/day

Any emissions unit that meets the applicability criteria in the final rule (as summarized in Table 2) and is
located at a facility within one of the industries listed in Table 1 in any of the 20 states with non-EGU emissions
control obligations7 is subject to the final emissions limits. A detailed discussion of the applicability criteria for
non-EGU sources is provided in Section VI.C of the preamble to the final rule.

III. Emissions Limits for the Final Rule

Establishing emissions limits for emissions units based on size and type of unit and, in some cases, emissions
thresholds, will achieve the necessary reductions commensurate with the EPA's analysis of non-EGU industries
and emissions units at Step 3 of the interstate transport framework. Between the proposal and this final rule, the
EPA made several adjustments to the proposed emissions limits for the emissions units in non-EGU industries.

•	For Pipeline Transportation of Natural Gas, the EPA is finalizing the emissions limits as proposed;
however, the EPA is adjusting the applicability criteria to exclude emergency engines. Additionally, the
final rule allows source owners/operators to request EPA approval of facility-wide emissions averaging
plans on a case-by-case basis, where specified criteria are met. An approved facility-wide averaging
plan would allow the source to install controls on the engines with the largest potential for emissions
reductions at cost-effective thresholds.

•	For Cement and Concrete Product Manufacturing, in the final rule the EPA has removed the daily
source cap limit, which could have resulted in an artificially restrictive NOx emissions limit for affected
cement kilns due to lower operating periods resulting from to the COVID-19 pandemic.

•	For Iron and Steel and Ferroalloy Manufacturing, the EPA is finalizing only a test-and-set requirement
for reheat furnaces premised on the installation of low-NOx burners. Based on commenters' concerns
regarding the proposed requirements for other unit types in this industry, the EPA is not finalizing the
proposed emissions limits for other emissions units in this industry.

•	For Glass and Glass Product Manufacturing, the EPA is finalizing alternative requirements that may
apply during startup, shutdown, and idling conditions.

•	For boilers in Iron and Steel and Ferroalloy Manufacturing, Metal Ore Mining, Basic Chemical
Manufacturing, Petroleum and Coal Products Manufacturing, and Pulp, Paper, and Paperboard Mills,

7 The EPA is requiring emissions reductions from non-EGU sources to address interstate transport obligations for the 2015
ozone NAAQS for the following 20 states: Arkansas, California, Illinois, Indiana, Kentucky, Louisiana, Maryland,
Michigan, Mississippi, Missouri, Nevada, New Jersey, New York, Ohio, Oklahoma, Pennsylvania, Texas, Utah, Virginia,
West Virginia.

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the EPA is finalizing a low-use exemption to eliminate the need to install controls on low-use boilers
that would have resulted in relatively small reductions.

More details on the bases for these changes can be found in the Section VI.C of the preamble to the final rule
and in the Final Non-EGU Sectors TSD. Table 3 summarizes the industries, emissions unit types, the form of
the final emissions limits, and the final emissions limits.

Table 3. Summary of Non-EGU Industries, Emissions Unit Types, Form of Final Emissions Limits, and
Final Emissions Limits

Industry

Emissions

Form of Final Emissions

Final Emissions Limits



Unit Type

Limits



Pipeline Transportation of

Reciprocating

Grams per horsepower per

Four Stroke Rich Burn: 1.0 g/hp-hr

Natural Gas

Internal

hours (g/hp-hr)

Four Stroke Lean Burn: 1.5 g/hp-hr



Combustion



Two Stroke Lean Burn: 3.0 g/hp-hr



Engines





Cement and Concrete Product

Kilns

Pounds per ton (lbs/ton) of

Long Wet: 4.0 lb/ton

Manufacturing



clinker

Long Dry: 3.0 lb/ton







Preheater: 3.8 lb/ton







Precalciner: 2.3 lb/ton







Preheater/Precalciner: 2.8 lb/ton

Iron and Steel Mills and

Reheat

lbs/mmBtua

Test and set limit based on

Ferroalloy Manufacturing

Furnaces



installation of Low-NOx Burners

Glass and Glass Product

Furnaces

lbs/ton glass produced

Container Glass Furnace: 4.0 lb/ton

Manufacturing





Pressed/Blown Glass Furnace: 4.0







lb/ton







Fiberglass Furnace: 4.0 lb/ton







Flat Glass Furnace: 9.2 lb/ton

Iron and Steel Mills and

Boilers

lbs/mmBtua

Coal: 0.20 lb/mmBtu

Ferroalloy Manufacturing





Residual Oil: 0.20 lb/mmBtu

Metal Ore Mining





Distillate Oil: 0.12 lb/mmBtu

Basic Chemical Manufacturing





Natural Gas: 0.08 lb/mmBtu

Petroleum and Coal Products







Manufacturing







Pulp, Paper, and Paperboard







Mills







Solid Waste Combustors and

Combustors or

ppmvd on a 24-hour

110 ppmvd on a 24-hour averaging

Incinerators

Incinerators

averaging period and

period





ppmvd on a 30-day

105 ppmvd on a 30-day averaging





averaging period

period

a Heat input limit.

IV. Assumed Control Technologies that Meet the Final Emissions Limits

Because the EPA does not have complete information on the operating characteristics of every emissions unit
potentially captured by the applicability criteria (e.g., existing emissions limit), the EPA made assumptions for
each industry and emissions unit type about the control technology needed to meet the final emissions limits.
Table 4 summarizes the industries, emissions unit types, and assumed control technologies that the EPA
anticipates will meet the final emissions limits. The estimated emissions reductions and costs presented in
Section V below reflect these assumed control technologies. A more detailed discussion of the EPA's basis for
concluding that these assumed control technologies would meet the final emission limits is included in Section
VI.C of the preamble to the final rule and in the Final Non-EGU Sectors TSD, both located in the docket.

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Table 4. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control Technologies that
Meet Final Emissions Limits

Industry

Emissions Unit Type

Assumed Control Technologies that Meet
Final Emissions Limits

Pipeline Transportation of Natural Gas

Reciprocating Internal
Combustion Engines

Layered Combustion (2-cycle Lean Burn)3
SCR (4-cycle Lean Burn)

NSCR (4-cycle Rich Burn)

Cement and Concrete Product
Manufacturing

Kilns

SNCR

Iron and Steel Mills and Ferroalloy
Manufacturing

Reheat Furnaces

LNB

Glass and Glass Product Manufacturing

Furnaces

LNB

Iron and Steel Mills and Ferroalloy
Manufacturing

Metal Ore Mining

Boilers

LNB + FGR (Natural Gas, No Coal or Oil)
SCR (Any Coal, Any Oil)

Basic Chemical Manufacturing
Petroleum and Coal Products
Manufacturing





Pulp, Paper, and Paperboard Mills





Solid Waste Combustors and
Incinerators

Combustors or Incinerators

ANSCRb

LN*™ and SNCR b c

a Several emissions units, or engines, in the 2019 inventory had Source Classification Codes (SCC) indicating that the units were
reciprocating without specifying the type of engine. We assumed NSCR or layered combustion as the control for these emissions units.
b Municipal Waste Combustor Workgroup Report, prepared by the Ozone Transport Commission Stationary and Area Sources
Committee, Revised April 2022.

0 Covanta has developed a proprietary low NOx combustion system (LN™) that involves staging of combustion air. The
system is a trademarked system and Covanta has received a patent for the technology.

V. Estimating Emissions Units, Emissions Reductions, and Costs

With the exception of Solid Waste Combustors and Incinerators (also referred to as Municipal Waste
Combustors or MWCs), for each industry and emissions unit type, using a 2019 inventory prepared from the
emissions inventory system (EIS) the EPA first estimated a list of emissions units captured by the applicability
criteria for the final rule.8 For Solid Waste Combustors and Incinerators, the EPA estimated the list for MWCs
using the 2019 inventory and the NEEDS-v6-summer-2021 -reference-case workbook.9 Appendix A introduces
the inventory data used and the general steps taken to filter the inventory data to estimate an initial list of units.
In addition, there are Excel workbooks for each industry, as well as for reciprocating internal combustion
engines, boilers, and MWCs available in the docket.10 Using the 2019 inventory from the EIS, the EPA reviewed
permits for the estimated emissions units in the Cement and Concrete Product Manufacturing, Glass and Glass
Product Manufacturing, and Iron and Steel Mills and Ferroalloy Manufacturing industries. Because the number
of estimated emissions units for reciprocating internal combustion engines and boilers was larger, the EPA

8	Using a projected emissions inventory for 2026 introduces challenges associated with the growth of emissions at sources
over time. The EPA determined that the 2019 inventory was appropriate because it provided a more accurate prediction of
potential near-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 using the 2019
inventory, however, we did not account for any growth or decrease in emissions that might occur at individual units.

9	Available here: https://www.epa.gov/power-sector-modeling/national-electric-energy-data-system-needs-v6.

10	The Excel workbooks are titled (i) Engines List for Costs and Reductions, xlsx, (ii) Cement List for Costs and
Reductions.xlsx, (iii) Iron and Steel List for Costs and Reductions.xlsx, (iv) Glass List for Costs and Reductions.xlsx, (v)
Boilers List for Costs and Reductions.xlsx, and (vi) MWC List for Costs and Reductions.xlsx. These Excel workbooks are
available in the docket here: https://www.regulations.gov/document/EPA-HQ-OAR-2021-0668.

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reviewed a smaller set of permits for those units. For boilers, the EPA also reviewed the database used in the
July 2022 revised Boiler MACT.

Each workbook includes a worksheet labeled README with the detailed steps taken to estimate the list of
emissions units captured by the applicability criteria (these steps are included in Appendix A). In developing the
list, we assumed that the information in the 2019 inventory was accurate unless we updated that information
through the permit reviews, information found in a dataset from the July 2022 revised boiler MACT rule, or
information from other existing emissions inventories. In addition, each workbook includes a worksheet labeled
Units Will Need Controls that represents the initial list of emissions units the EPA estimates could need the
assumed controls to meet the emissions limits in the final rule.

For the final rule, the EPA did not run the Control Strategy Tool (CoST) to estimate emissions reductions and
costs, as we did for the proposed rule, and instead programmed the assessment using R.11 Using with the list of
emissions units estimated to be captured by the applicability criteria, the assumed control technologies identified
in Table 4, and information on control efficiencies and default cost/ton values from the control measures
database (CMDB)12, the EPA then estimated emissions reductions and costs for the year 2026. We estimated
emissions reductions using the actual emissions (not potential to emit) from the 2019 emissions inventory. It is
not clear what the impact of using actual emissions is on the estimated emissions reductions. As an example, if
these emissions units were not subject to the emissions limits in this rule and their actual emissions were lower
than their potential to emit, they could have increased emissions in 2026 (compared to actual emissions in
2019), resulting in greater estimated emissions reductions.

There were a few cases where an emissions unit had an existing control indicated in the inventory, but we
estimated that the existing control might not enable the unit to meet the emissions limit and additional emissions
reductions could be needed for the unit to meet the applicable emissions limit. When running CoST, the EPA
can specify that a replacement control be applied if it achieves a specified, additional percent emissions
reduction. In this analysis, we assumed a replacement control would need to result in 11% more emissions
reductions than the control currently on an emissions unit. Lastly, when incorporating additional information on
existing controls from other existing emissions inventories or when assessing replacement controls, we
identified existing controls on some emissions units. In some cases, after identifying an existing control on an
emissions unit, the control we assumed was needed to meet the final emissions limit actually was not.13

Finally, in the assessment the EPA matched emissions units by Source Classification Code (SCC) from the
inventory to the applicable control technologies in the CMDB.1415 We modified SCC codes as necessary to
match control technologies to inventory records. For each emissions unit type and industry, the following
summarizes the approach used and data modifications made to estimate emissions reductions and costs.

11	R is a free software environment for statistical computing and graphics. Additional information is available here:
https://www.r-project.org/.

12	More information about the Control Strategy Tool (CoST) and the control measures database (CMDB) can be found at
the following link: https://www.epa.gov/economic-and-cost-analysis-air-pollution-regulations/cost-analysis-modelstools-
air-pollution.

13	As a result, the number of emissions units in the Units Will Need Controls worksheet may be larger than the number of
emissions units in the Excel results workbook titled Non-EGUResults - 11-17-2022.xlsx (available in the docket here:
https ://www. regulations. gov/document/EP A-HQ-0 AR-2021-0668).

14	The control measures in the CMDB have applicable SCC codes associated with them, facilitating the matching of
inventory SCCs to control measure SCCs.

15	The 2019 emissions inventory data, the control measure and default cost/ton data in the CMDB used to prepare the
emission reduction and cost estimates, and the R code that processed these data are available upon request.

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•	For reciprocating internal combustion engines in the Pipeline Transportation of Natural Gas industry -
The EPA used the control efficiencies and default cost/ton values from the CMDB for the assumed
control and calculated emissions reductions and costs reflecting information on existing controls
gathered from the review of a smaller set of permits, where available. The default cost/ton values from
the CMDB may result in lower cost/ton values than is likely for some lower emitting units. We made
some modifications where the inventory record and the CMDB had incompatible SCC codes or the
CMDB had a gap in SCC coverage. For the inventory records with SCC codes specified as
Reciprocating, we applied NSCR or Layered Combustion. Also, for two records with SCCs 20100202
and 203 00201, we expanded the NSCR or Layered Combustion control in the CMDB to cover these
SCCs.

•	For the kilns in Cement and Concrete Product Manufacturing - The EPA reviewed permits and public
comments on the proposed FIP to identify existing control information, where available, and estimated
reductions using this information. The EPA used the control efficiency and default cost/ton values from
the CMDB for the assumed control.

•	For the reheat furnaces in Iron and Steel and Ferroalloy Manufacturing - The EPA reviewed permits to
identify existing control information, where available, and estimated reductions using this information.
The EPA used the control efficiency and default cost/ton values from the CMDB for the assumed
control. We made some modifications where the inventory record and the CMDB had incompatible
SCC codes or the CMDB had a gap in SCC coverage. For inventory records, we replaced SCC codes for
all reheat furnaces with 30390003. Lastly, for the LNB control, the CMDB currently has two low NOx
burner controls and to be conservative we used the control with a lower control efficiency.

•	For the furnaces in Glass and Glass Product Manufacturing - The EPA reviewed permits to identify
existing control information, where available, and estimated reductions using this information. The EPA
used the control efficiency and default cost/ton values from the CMDB for the assumed control. For one
inventory record, we changed an SCC code (30501401) and applied the LNB control measure.

•	For boilers in Iron and Steel Mills and Ferroalloy Manufacturing. Metal Ore Mining. Basic Chemical
Manufacturing. Petroleum and Coal Products Manufacturing, and Pulp. Paper, and Paperboard Mills
industries - The EPA used the control efficiencies and default cost/ton values from the CMDB for the
assumed control and calculated emissions reductions and costs reflecting information on existing
controls gathered from the review of a smaller set of permits or information found in a dataset from the
July 2022 revised boiler MACT rule, where available. The default cost/ton values from the CMDB may
result in lower cost/ton values than is likely for some lower emitting units. In addition, the default
control efficiency in the CMDB for LNB for boilers is 50 percent and the default control efficiency for
LNB+FGR is 61%. In assessing replacement controls, we assumed boilers that already have LNB will
find another way to comply with the final emissions limits and not install FGR.

We made some modifications where the inventory record and the CMDB had incompatible SCC codes
or the CMDB had a gap in SCC coverage. For several inventory records, we replaced SCC codes for
Electric Generation: Boilers and Commercial/Industrial: Boilers with Industrial: Boilers SCC codes for
the same fuel type to assign control technology consistently across the industries. In the process level
emissions inventory file, emissions can sometimes be below the 25 tpy threshold for which a default
cost/ton gets used for LNB+FGR. We used the default cost/ton for the LNB+FGR control measure for
some processes below the 25 tpy threshold.

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• For combustors or incinerators in Solid Waste Combustors and Incinerators - The EPA estimated
reductions by comparing current emissions limits to the final rule's emissions limits and multiplied the
percent difference by a unit's actual emissions. We assumed ANSCR or low NOx technology (LN™)
and SNCR would meet final rule emissions limits and used costs for those technologies from the
Municipal Waste Combustor Workgroup Report, prepared by the Ozone Transport Commission
Stationary and Area Sources Committee, Revised April 2022.16 See Appendix B for a summary of
information from the Municipal Waste Combustor Workgroup Report used to estimate costs for waste
combustors or incinerators.

Table 5 summarizes the industries, emissions unit types, assumed control technologies, and number of control
installations expected to meet the final rule emissions limits. Table 6 summarizes the industries, emissions unit
types, assumed control technologies, and estimated average cost/ton values. Table 7 summarizes the industries,
emissions unit types, assumed control technologies, estimated total annual costs, and estimated ozone season
NOx emissions reductions in 2026. Table 8 summarizes the industries, emissions unit types, estimated total
annual costs, and estimated annual and ozone season NOx emissions reductions in 2026.

The data used in this assessment is sufficient to inform the EPA's identification of which emissions from non-
EGU industries and emissions units are "significant" under Step 3 of the 4-step interstate transport framework.
Further, this assessment for the final rule reflects comments we received regarding the relationship between
EPA's Step 3 and Step 4 analyses for non-EGU industries and emissions units at proposal. In this assessment the
EPA has more directly incorporated into the analysis at Step 3 the emissions controls that we estimate would
likely be installed at these emissions units. This allows the EPA to assess whether these controls could result in
emissions reductions and air quality benefits at downwind receptors that are relatively cost-effective when
compared with the control strategies for EGUs (see Section V.D.2 of the preamble for a more detailed
discussion).

The estimates presented below using the 2019 inventory and information from the CMDB identify proxies for
emissions units, as well as emissions reductions, and costs associated with the assumed control technologies that
would meet the final emissions limits. Emissions units subject to the final rule emissions limits may be different
than those estimated in this assessment; the estimated emissions reductions from and costs to meet the final rule
emissions limits may be different than those estimated in this assessment. The costs do not include monitoring,
recordkeeping, reporting, or testing costs. In the regulatory provisions that implement these emissions limits at
Step 4, the EPA has incorporated mechanisms that are designed to accommodate unique circumstances on a
unit-specific basis, such as allowing for an extension of time to install controls or developing an alternative
emissions limit where it can be established to be necessary. See Section VI. C. of the preamble for further
discussion.

16 Thq Municipal Waste Combustor Workgroup Report, prepared by the Ozone Transport Commission Stationary and Area
Sources Committee, Revised April 2022 is available here:

https://otcair.org/upload/Documents/Reports/MWC%20Report_revised%2020220425.pdf.

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Table 5. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control Technologies that
Meet Final Emissions Limits, Estimated Number of Control Installations	

Industry/Industries

Emissions Unit Type

Assumed Control
Technologies that Meet
Final Emissions Limits

Estimated
Number of Units
Per Assumed
Control

Pipeline Transportation of Natural Gas

Reciprocating Internal
Combustion Engines

NSCR or Layered
Combustion
(Reciprocating)

Layered Combustion (2-
cycle Lean Burn)

SCR (4-cycle Lean Burn)

NSCR (4-cycle Rich Burn)

323

394
158
30

Cement and Concrete Product
Manufacturing

Kiln

SNCR

16

Iron and Steel Mills and Ferroalloy
Manufacturing

Reheat Furnaces

LNB

19

Glass and Glass Product Manufacturing

Furnaces

LNB

61

Iron and Steel Mills and Ferroalloy
Manufacturing

Boilers

LNB + FGR (Natural Gas,
No Coal or Oil)

151

Metal Ore Mining



SCR (Any Coal, Any Oil)

15

Basic Chemical Manufacturing
Petroleum and Coal Products
Manufacturing







Pulp, Paper, and Paperboard Mills







Solid Waste Combustors and Incinerators3

Combustors or Incinerators

ANSCR

LN™ and SNCR

57
4



Total



1,228

a Twelve MWCs have existing controls, and we estimated these units will use more reagent in those controls to meet the final emissions
limits.

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Table 6. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control Technologies, Estimated
Average Cost/Ton (2016$)	

Industry/Industries

Emissions Unit Type

Assumed Control Technologies
that Meet Final Emissions Limits

Average
Cost/Ton
Values (2016$)

Pipeline Transportation of Natural Gas

Reciprocating Internal Combustion
Engine

NSCR or Layered Combustion,
Layered Combustion, SCR, NSCR

4,981

Cement and Concrete Product Manufacturing

Kiln

SNCR

1,632

Iron and Steel Mills and Ferroalloy
Manufacturing

Reheat Furnaces

LNB

3,656

Glass and Glass Product Manufacturing

Furnaces

LNB

939

Iron and Steel Mills and Ferroalloy
Manufacturing

Boilers

SCR orLNB + FGR

8,369

Metal Ore Mining





14,595

Basic Chemical Manufacturing





11,845

Petroleum and Coal Products Manufacturing





14,582

Pulp, Paper, and Paperboard Mills





14,134

Solid Waste Combustors and Incinerators

Combustors or Incinerators

ANSCR or LN™ and SNCRa

7,836





Overall Average Cost/Ton

5,339

Table 7. Summary of Non-EGU Industries, Emissions Unit Types, Assumed Control Technologies,
Estimated Total Annual Costs (2016$), Ozone Season NOx Emissions Reductions in 2026	

Industry/Industries

Emissions Unit Type

Assumed Control
Technologies that Meet Final
Emissions Limits

Annual Costs
(2016$)

Ozone Season
Emissions
Reductions

Pipeline Transportation of Natural Gas

Reciprocating Internal
Combustion Engine

NSCR or Layered Combustion,
Layered Combustion, SCR,
NSCR

385,463,197

32,247

Cement and Concrete Product Manufacturing

Kiln

SNCR

10,078,205

2,573

Iron and Steel Mills and Ferroalloy
Manufacturing

Reheat Furnaces

LNB

3,579,294

408

Glass and Glass Product Manufacturing

Furnaces

LNB

7,052,088

3,129

Iron and Steel Mills and Ferroalloy
Manufacturing

Boilers

SCR, LNB + FGR

8,838,171

440

Metal Ore Mining





621,496

18

Basic Chemical Manufacturing





49,697,848

1,748

Petroleum and Coal Products Manufacturing





5,128,439

147

Pulp, Paper, and Paperboard Mills





62,268,540

1,836

Solid Waste Combustors and Incinerators

Combustors or
Incinerators

ANSCR or LN™ and SNCR

38,949,560

2,071





Totals

571,676,839

44,616

10


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Table 8. Summary by Industries, Estimated Total Annual Costs (2016$), Annual and Ozone Season NOx
Emissions Reductions in 2026

Industry/Industries

Emissions Unit Type

Annual Costs
(2016$)

Annual
Emissions
Reductions

Ozone Season
Emissions
Reductions

Pipeline Transportation of Natural Gas

Reciprocating Internal
Combustion Engine

385,463,197

77,392

32,247

Cement and Concrete Product Manufacturing

Kiln

10,078,205

6,174

2,573

Iron and Steel Mills and Ferroalloy
Manufacturing

Reheat Furnaces

3,579,294

979

408

Glass and Glass Product Manufacturing

Furnaces

7,052,088

7,510

3,129

Iron and Steel Mills and Ferroalloy
Manufacturing

Boilers

8,838,171

1,056

440

Metal Ore Mining



621,496

43

18

Basic Chemical Manufacturing



49,697,848

4,196

1,748

Petroleum and Coal Products Manufacturing



5,128,439

352

147

Pulp, Paper, and Paperboard Mills



62,268,540

4,406

1,836

Solid Waste Combustors and Incinerators

Combustors or Incinerators

38,949,560

4,971

2,071



Totals

571,676,839

107,077

44,616

In addition, Table 9 summarizes annual cost, estimated annual and ozone season NOx emissions reductions in
2026, and average cost/ton by state and by industry, and Table 10 summarizes annual cost, estimated annual and
ozone season NOx emissions reductions in 2026, and average cost/ton by state. Figure 1 shows the geographical
distribution of estimated ozone season NOx reductions, along with the summary of reductions by state and by
industry. Note that while Nevada is a linked state in 2026, we did not estimate that any emissions units would
need to apply the assumed control technologies to meet the final emissions limits.

11


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Table 9. By State And By Industry, Estimated Annual Cost (2016$), Estimated Annual and Ozone Season NOx Emissions Reductions in
2026, and Estimated Average Cost/Ton (2016$)

Average





Annual Cost

Annual

OS Emissions

Cost/Ton

State

NAICS Description

(2016$)

Reductions

Reductions

(2016$)

AR

Basic Chemical Manufacturing

1,632,223

208

87

7,851

AR

Glass and Glass Product Manufacturing

123,157

90

37

1,376

AR

Iron and Steel Mills and Ferroalloy Manufacturing

309,447

85

35

3,656

AR

Pipeline Transportation of Natural Gas

13,129,973

2,555

1,065

5,139

AR

Pulp, Paper, and Paperboard Mills

9,518,419

774

323

12,290

CA

Cement and Concrete Product Manufacturing

3,486,679

2,725

1,135

1,279

CA

Glass and Glass Product Manufacturing

296,407

383

160

774

CA

Pipeline Transportation of Natural Gas

2,414,437

512

213

4,718

CA

Waste Treatment and Disposal

2,271,068

221

92

10,271

IL

Basic Chemical Manufacturing

588,959

24

10

24,690

IL

Glass and Glass Product Manufacturing

551,552

712

297

775

IL

Petroleum and Coal Products Manufacturing

1,952,466

148

62

13,221

IL

Pipeline Transportation of Natural Gas

20,610,074

4,664

1,943

4,419

IN

Cement and Concrete Product Manufacturing

3,192,728

1,148

478

2,782

IN

Glass and Glass Product Manufacturing

727,048

528

220

1,376

IN

Iron and Steel Mills and Ferroalloy Manufacturing

3,579,696

697

291

5,133

IN

Petroleum and Coal Products Manufacturing

564,315

80

33

7,031

IN

Pipeline Transportation of Natural Gas

9,272,053

1,768

737

5,243

IN

Waste Treatment and Disposal

1,706,754

520

217

3,282

KY

Glass and Glass Product Manufacturing

130,692

52

22

2,493

KY

Iron and Steel Mills and Ferroalloy Manufacturing

111,147

30

13

3,656

KY

Pipeline Transportation of Natural Gas

32,782,561

6,297

2,624

5,206

KY

Pulp, Paper, and Paperboard Mills

394,020

16

7

24,690

LA

Basic Chemical Manufacturing

19,965,275

1,886

786

10,584

LA

Glass and Glass Product Manufacturing

614,449

276

115

2,229

LA

Petroleum and Coal Products Manufacturing

497,471

20

8

24,690

LA

Pipeline Transportation of Natural Gas

72,118,746

14,880

6,200

4,847

LA

Pulp, Paper, and Paperboard Mills

1,045,465

79

33

13,221

MD

Pipeline Transportation of Natural Gas

164,447

30

13

5,457

12


-------
MD	Waste Treatment and Disposal

MI	Basic Chemical Manufacturing

MI	Glass and Glass Product Manufacturing

MI	Metal Ore Mining

MI	Pipeline Transportation of Natural Gas

MI	Pulp, Paper, and Paperboard Mills

MI	Waste Treatment and Disposal

MO	Cement and Concrete Product Manufacturing

MO	Glass and Glass Product Manufacturing

MO	Pipeline Transportation of Natural Gas

MS	Pipeline Transportation of Natural Gas

MS	Pulp, Paper, and Paperboard Mills

NJ	Glass and Glass Product Manufacturing

NJ	Waste Treatment and Disposal

NY	Glass and Glass Product Manufacturing

NY	Iron and Steel Mills and Ferroalloy Manufacturing

NY	Pipeline Transportation of Natural Gas

NY	Pulp, Paper, and Paperboard Mills

NY	Waste Treatment and Disposal

OH	Basic Chemical Manufacturing

OH	Glass and Glass Product Manufacturing

OH	Iron and Steel Mills and Ferroalloy Manufacturing

OH	Petroleum and Coal Products Manufacturing

OH	Pipeline Transportation of Natural Gas

OH	Pulp, Paper, and Paperboard Mills

OK	Cement and Concrete Product Manufacturing

OK	Glass and Glass Product Manufacturing

OK	Pipeline Transportation of Natural Gas

OK	Pulp, Paper, and Paperboard Mills

OK	Waste Treatment and Disposal

PA	Cement and Concrete Product Manufacturing

PA	Glass and Glass Product Manufacturing

PA	Iron and Steel Mills and Ferroalloy Manufacturing

2,069,959

347

145

5,965

649,287

26

11

24,690

35,459

65

27

549

621,496

43

18

14,595

31,429,866

6,329

2,637

4,966

5,896,625

559

233

10,551

1,137,836

142

59

8,002

759,911

273

114

2,782

249,721

182

76

1,376

22,471,530

4,501

1,875

4,993

29,429,138

5,828

2,428

5,050

3,468,462

170

71

20,424

59,949

44

18

1,376

6,776,981

538

224

12,596

349,137

191

80

1,826

82,491

23

9

3,656

2,698,676

553

230

4,884

1,956,608

278

116

7,031

10,195,093

1,255

523

8,125

1,820,887

88

37

20,635

861,166

660

275

1,305

6,109,926

874

364

6,993

195,795

8

3

24,690

27,466,909

5,386

2,244

5,100

6,568,693

436

182

15,049

891,978

663

276

1,346

334,023

243

101

1,376

42,845,192

8,631

3,596

4,964

7,406,196

754

314

9,827

1,706,754

240

100

7,104

526,032

411

171

1,279

1,268,316

1,899

791

668

1,607,318

239

99

6,735

13


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PA	Pipeline Transportation of Natural Gas

PA	Pulp, Paper, and Paperboard Mills

PA	Waste Treatment and Disposal

TX	Basic Chemical Manufacturing

TX	Glass and Glass Product Manufacturing

TX	Petroleum and Coal Products Manufacturing

TX	Pipeline Transportation of Natural Gas

TX	Pulp, Paper, and Paperboard Mills

UT	Pipeline Transportation of Natural Gas

VA	Basic Chemical Manufacturing

VA	Cement and Concrete Product Manufacturing

VA	Glass and Glass Product Manufacturing

VA	Iron and Steel Mills and Ferroalloy Manufacturing

VA	Pipeline Transportation of Natural Gas

VA	Pulp, Paper, and Paperboard Mills

VA	Waste Treatment and Disposal

WV	Basic Chemical Manufacturing

WV	Pipeline Transportation of Natural Gas

WV	Pulp, Paper, and Paperboard Mills	

Totals

6,599,932

1,377

574

4,792

4,446,769

197

82

22,540

10,809,443

1,118

466

9,670

20,677,319

1,549

645

13,353

1,144,406

1,963

818

583

1,918,392

96

40

20,047

38,681,714

7,611

3,171

5,082

1,010,352

41

17

24,690

2,848,769

604

252

4,717

362,998

15

6

24,690

1,220,878

954

398

1,279

306,606

223

93

1,376

617,441

88

37

7,031

12,732,010

2,326

969

5,473

20,150,279

1,084

452

18,583

2,275,672

589

246

3,862

4,000,899

400

167

10,004

17,767,169

3,540

1,475

5,019

406,652

16

7

24,690

571,676,839

107,077

44,616

5,339

14


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Table 10. By State, Annual Cost (2016$), Estimated Annual and Ozone Season NOx Emissions Reductions
in 2026, and Estimated Average Cost/Ton (2016$)

State

Annual Cost
(2016$)

Annual
Reductions

OS Emissions
Reductions

Average
Cost/Ton
(2016$)

AR

24,713,219

3,711

1,546

6,659

CA

8,468,591

3,841

1,600

2,205

IL

23,703,051

5,547

2,311

4,273

IN

19,042,595

4,742

1,976

4,015

KY

33,418,421

6,396

2,665

5,225

LA

94,241,407

17,141

7,142

5,498

MD

2,234,405

377

157

5,924

MI

39,770,569

7,164

2,985

5,552

MO

23,481,162

4,955

2,065

4,739

MS

32,897,600

5,998

2,499

5,485

NJ

6,836,929

582

242

11,755

NY

15,282,005

2,299

958

6,646

OH

43,023,376

7,452

3,105

5,773

OK

53,184,143

10,530

4,388

5,051

PA

25,257,811

5,241

2,184

4,819

TX

63,432,182

11,259

4,691

5,634

UT

2,848,769

604

252

4,717

VA

37,665,883

5,279

2,200

7,135

wv

22,174,720

3,956

1,649

5,605

Total

571,676,839

107,077

44,616

5,339

15


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Figure 1. Geographical Distribution of Ozone Season NOx Reductions in 2026 and Summary of
Estimated Reductions by Industry and by State

Non-EGU Ozone Season NOx Reductions

O 500-1000 tons	#	Cement and Concrete Product Manufacturing

O 100-500 tons	#	Glass and Glass Product Manufacturing

° Under 100 tons	O	Iron and Steel Mills and Ferroalloy Manufacturing

O	Pipeline Transportation of Natural Gas

#	Applicable Boilers from Affected industries

#	Municipal Waste Combustors



Cement and

Glass and

Iron and
Steel Mills

and
Ferroalloy
/lanufacturin

Pipeline

Applicable
Boilers





State

Concrete Glass
Product Product
Manufacturing Manufacturing

Transportation
of Natural
Gas

3

from
Affected
Industries

Waste
Combustors

Total

LA

0

115

0

6,200

827



7,142

TX

0

618

0

3,171

702



4,691

OK

276

101

0

3,596

314

100

4.388

OH

0

275

114

2,244

472



3,105

Ml

0

27

0

2,637

262

59

2,985

KY

0

22

13

2,624

7



2.685

MS

0



0

2,428

71



2,499

11

0

297

0

1,943

71



2,311

VA

398

93

0

969

495

246

2.200

PA

171

791

9

574

173

466

2,184

MO

114

76

0

1,875

0



2.065

IN

478

220

228

737

96

217

1.976

WV

0



0

1.475

174



1.649

CA

1.135

160

0

213

0

92

1,600

AR

0

37

35

1,065

409



1.546

NY

0

80

9

230

116

523

958

UT

0



0

252

0



252

NJ

0

18

0

0

0

224

242

MD

0



0

13

0

145

157

Lastly, because the estimated number of emissions units for the reciprocating internal combustion engines and
the boilers was large, the EPA reviewed a smaller set of permits to gather or confirm information on existing
controls on engines and boilers.17 To consider the potential impact this limited review could have on the
estimated emissions reductions and costs for engines and boilers, the EPA prepared a sensitivity assessment.
The sensitivity assessment included subsets of the engines and boilers for which the limited review was
conducted because we determined these subsets of engines and boilers would need controls.18 We estimated the
emissions reductions and costs for these engines and boilers both without (i.e., based only on information in the
emissions inventory) and with the supplemental information (i.e., based on information in the emissions
inventory, supplemented with information from the limited permit review or found in a dataset from the July
2022 revised boiler MACT rule). We calculated the percent differences in the emissions reductions and costs
between those two estimates.

For reciprocating internal combustion engines when comparing the estimates (i) the estimated emissions
reductions (annual and ozone season) using the supplemental information were 12 percent lower, and (ii) the
estimated annual costs using the supplemental information were 10 percent lower. For boilers, when comparing

17	The limited permit review was completed for approximately 330 engines and 40 boilers.

18	The subset of engines reviewed that were identified in the Units Will Need Controls worksheet were approximately 135
engines. The subset of boilers reviewed that were identified in the Units Will Need Controls worksheet were approximately
28 boilers.

16


-------
the estimates (i) the estimated emissions reductions (annual and ozone season) using the supplemental
information were 25 percent lower, and (ii) the estimated annual costs using the supplemental information were
approximately 22 percent higher.

The reason the estimated costs are higher and reductions are lower for boilers is that we are accounting for the
increment of emission reduction beyond any existing control identified in supplemental information that was not
reflected in the emissions inventory. These additional tons are likely more expensive, so as a conservative
estimate we calculated the cost of the control based on the total tons reduced by that control if the source was
uncontrolled. However, so as to not overstate the potential emission reduction, we report only the incremental
emission reduction.

17


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Appendix A - Using 2019 Inventory Data to Identify Emissions Units

Boilers ~ Steps taken to filter 2019 NEI data to estimate a list of boilers captured by the applicability criteria for

the final rule.

1.	Filter to 23 States

2.	Remove any units that for any process associated with the unit lists an SCC Code that has SCC Level-4
equal to "< 10 Million BTU/hr", "10-100 Million BTU/hr", or "Boiler < 100 Million BTU, except
tangential"

3.	Limit boilers to units in the following NAICS:

Tier 1 Industries

3311 - Iron and Steel Mills and Ferroalloy Manufacturing
Tier 2 Industries

2122 - Metal Ore Mining

3274 - Lime and Gypsum Product Manufacturing
3221 - Pulp, Paper, and Paperboard Mills
3241 - Petroleum and Coal Products Manufacturing
3251 - Basic Chemical Manufacturing

4.	Remove any processes that do not list Unit Type equal to "Boiler" or "Unclassified".

5.	Remove any processes that do not have SCC Level-2 equal to "Commercial/Institutional: Boilers",
"Electric Generation: Boilers", or "Industrial: Boilers"

6.	Remove any processes that do not have SCC Level-3 equal to "Natural Gas", "Residual Oil", "Distillate
Oil", or "Bituminous/Subbituminous Coal" and re-confirm that SCC Level-4 is not equal to "< 10
Million BTU/hr", "10-100 Million BTU/hr", or "Boiler < 100 Million BTU, except tangential"

7.	Select units from the EIS unit-level file that have processes that were not filtered out during Step 1-6
(559 Units)

8.	Remove any units with actual NOx emissions less than 7.5 tpy (380 units after removals)

9.	Remove any units with Design Capacity UOM="E6BTU/HR" and Design Capacity<100, unless Design
Capacity is default value of 0.1 or 0.01 (329 units after removals)

Note: The default values may need to be expanded.

10.	Remove any units where Facility Status="PS" or Unit Status="PS" (323 units after removals)

11.	Added in 2 with Design Capacity default of 1 (325 units).

12.	Removed recovery boilers/furnaces and process heaters by reviewing SCC codes or the Unit Level
Description (Column AI).

For other industries and reciprocating internal combustion engines, ~ Steps taken to filter 2019 NEI data to

estimate units captured by the applicability criteria for the final rule.

1.	Rely on NAICS Codes, SCC Codes, and Unit Types in NEI Data

2.	Combine 2019 NEI data with other available data from comments, previous data collections, limited
permit review to fill in missing design capacity where possible

3.	Conduct permit reviews to fill in missing information to determine applicability (boiler and engine
design capacity, MWC PTE and tons/day, and PTE for remaining industries)

4.	Review available data and permits to determine controls currently installed on emissions units

5.	Narrow the list of applicable units to only include those that will need to install controls (e.g., remove
low utilization boilers)

18


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Appendix B - Municipal Waste Combustor Workgroup Report — Information Used to Estimate Costs for
Waste Combustors or Incinerators

1.	Cost/ton values were taken from the Municipal Waste Combustor Workgroup Report, prepared by the
Ozone Transport Commission Stationary and Area Sources Committee, Revised April 2022
(https://otcair.org/upload/Documents/Reports/MWC%20Report_revised%2020220425.pdf).

2.	For units that need to install ASNCR or low NOx technology (LN™) and SNCR

a.	The annual cost of ASNCR ~ the Municipal Waste Combustor Workgroup Report cited
$1,812,930 total annual costs (operating and capital) to install ASNCR at an MWC with 3
incinerators. We divided the value by 3 to derive an estimated annual cost of $604,310 per
incinerator to install ASNCR.

b.	The annual cost of Covanta's LN™ and SNCR ~ the Municipal Waste Combustor Workgroup
Report cited total annual costs (operating and capital) for 1 incinerator ranging from $297,679
to $580,181. Using this information, we conservatively assumed $580,181 for any incinerator
type that Covanta has indicated can install LN™ and SNCR.

3.	For units that already have ASNCR or LN™ and SNCR installed

a.	The annual costs for facilities that already have ASNCR installed ~ The Municipal Waste
Combustor Workgroup Report cited $995,000 for the annual operating costs of ASNCR at an
MWC with 3 incinerators. Because these facilities already have ASNCR installed, we did not
include the capital costs. We divided the value by 3, to derive an estimated annual operating
cost of $331,667 per incinerator to operate ASNCR. We believe this estimate is conservative
because these units are already operating the installed ASNCR at a lower reagent usage and
paying a portion of the $331,667 annual operating costs.

b.	For annual cost for facilities that already have Covanta LN™ and SNCR installed ~ The
Municipal Waste Combustor Workgroup Report cited annual operating costs for 1 incinerator
ranging from $181,146 to $401,243. Because these facilities already have LN™ and SNCR
installed, we did not include the capital costs. Using this information, we conservatively
assumed $401,243 for the additional operating costs. We believe this estimate is conservative
because these units are already operating the installed LN™ and SNCR at a lower reagent usage
and paying a portion of the $401,243 annual operating costs.

19


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