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. 1 ------- (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. 2 ------- 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. 3 ------- 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. 4 ------- 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. 5 ------- 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. 6 ------- 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. 7 ------- 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. 8 ------- 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. 9 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- 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 ------- |