The EPA solicits comment on the availability of beta gauge instruments, on the current average costs of non-beta gauge PM CEMS instruments and installation, on ICAC's annual costs, and on Envea /Altech's annual costs. When commenting on EPA model estimates or ICAC's or Envea /Altech's estimates, please provide specific PM CEMS instrument type, manufacturer, and model; cost information broken down by initial cost including instrument type and installation cost, and annual cost, including operation and maintenance, audit, and other costs in your comments. Moreover, please identify in your comments specific items included in your cost information, such as installation, operation, and maintenance provisions. The EPA also solicits comment on the cost-effectiveness of PM CEMS as compared to quarterly PM emissions testing. Finally, the EPA solicits comment on the availability of PM CEMS and their use for compliance purposes, especially when compared to less frequent, more expensive measures.
 Review of the Hg Emission Standards
 Overview of Hg Emissions from Combustion of Coal
Mercury is a naturally occurring element found in small and varying quantities in coal. During combustion of coal, Hg is volatilized and converted to elemental Hg vapor (Hg[0]) in the high temperature regions of the boiler. Hg[0] vapor is difficult to capture because it is typically nonreactive and insoluble in aqueous solutions. However, under certain conditions, the Hg0 vapor in the flue gas can be oxidized to divalent Hg (Hg[2+]). The Hg[2+] can bind to the surface of solid particles (e.g., fly ash) in the flue gas stream, often referred to as "particulate bound Hg" (Hgp), and be removed in a downstream PM control device. Oxidized Hg compounds can also be soluble and can be removed in a wet scrubber. The presence of chlorine in gas-phase equilibrium favors the formation of mercuric chloride (HgCl2) at flue gas cleaning temperatures. However, Hg[0] oxidation reactions are kinetically limited as the flue gas cools and, as a result, Hg often enters the flue gas cleaning device(s) as a mixture of Hg[0], Hg[2+] compounds, and Hgp. This partitioning into various species of Hg has considerable influence on selection of Hg control approaches. In general, because of the presence of higher amounts of halogen (especially chlorine) in bituminous coals, most of the Hg in the flue gas from bituminous coal-fired boilers is in the form of Hg[2+] compounds, typically HgCl2 and is more easily captured in downstream control equipment. Conversely, both subbituminous coal and lignite have lower halogen content, compared to that of bituminous coals, and the Hg in the flue gas from boilers firing those fuels tends to be in the form of Hg[0] and is more challenging to control in downstream control equipment.
Fly ash is typically classified as acidic (pH less than 7.0), mildly alkaline (pH greater than 7.0 to 9.0), or strongly alkaline (pH greater than 9.0). The pH of the fly ash is usually determined by the calcium/sulfur ratio and the amount of halogen. The ash from bituminous coals tends to be acidic due to the relatively higher sulfur and halogen content and the glassy (nonreactive) nature of the calcium present in the ash. Conversely, the ash from subbituminous and lignite coals tends to be more alkaline due to the lower amounts of sulfur and halogen and a more alkaline and reactive (non-glassy) form of calcium in the ash. The natural alkalinity of the subbituminous and lignite fly ash can effectively neutralize the limited free halogen in the flue gas and prevent oxidation of the Hg[0].
Some coal-fired power plants  --  especially those firing bituminous coal  --  achieve some level of Hg emissions control using existing equipment that was installed to remove other pollutants, including PM, SO2, and nitrogen oxides (NOX). Particulate-bound Hg (Hgp) is effectively removed along with PM in PM control equipment such as FFs and ESPs. Soluble Hg[2+] compounds (such as HgCl2) can be effectively captured in wet FGD systems. And, while a selective catalytic reduction (SCR) system that has been installed for NOx control does not itself capture Hg, it can, under the right conditions enhance the oxidation of Hg[0] in the flue gas for increased Hg removal in a downstream PM control device or in a wet FGD scrubber.
However, because the Hg in their flue gas tends to be present in the non-reactive Hg[0] phase, EGUs firing subbituminous coal or lignite often get little to no control from equipment designed and installed for other pollutants. While some bituminous coal-fired EGUs require use of additional Hg -specific control technology, such as injection of a sorbent or chemical additive, to supplement the control that these units already achieve from criteria pollutant control equipment, these Hg-specific control technologies are often required as part of the Hg emission reduction strategy at EGUs that are firing subbituminous coal or lignite. As mentioned, the Hg in the flue gas for those EGUs tends to be in the non-reactive Hg[0] phase due to lack of free halogen to promote the oxidation reaction. To alleviate this challenge, activated carbon and other sorbent providers and control technology vendors developed methods to introduce halogen into the flue gas to improve the control of Hg emissions from EGUs firing subbituminous coal and lignite. This was primarily through the injection of pre-halogenated (often pre-brominated) activated carbon sorbents or through the injections of halogen-containing chemical additives along with conventional sorbents. This challenge to controlling Hg emissions was a challenge for EGUs firing subbituminous coal and for EGUs firing lignite.
 Hg Emission Standards in the 2012 MATS Final Rule
In the 2012 MATS Final Rule, the EPA promulgated a beyond-the-floor standard for Hg for the subcategory of existing coal-fired units designed for low rank virgin coal (i.e., lignite) based on the use of ACI for Hg control. See 77 FR 9304, February 16, 2012. The EPA established a final Hg emission standard of 4.0 pounds of Hg per trillion British thermal units of heat input (lb Hg/TBtu) for lignite-fired utility boilers. The EPA promulgated a final Hg emission standard for EGUs firing non-lignite coals, including bituminous and subbituminous coal, of 1.2 lb Hg/TBtu.
Under CAA section 112(d)(1), the Administrator has the discretion to "distinguish among classes, types, and sizes of sources within a category or subcategory" in establishing standards. Any basis for subcategorization must be related to an effect on HAP emissions that is due to the difference in class, type, or size of the units. See 76 FR 25036 - 25037.
When developing the MATS rule, the EPA examined available Hg emissions data from coal-fired EGUs and found that there were no lignite-fired EGUs among the top performing 12 percent. The EPA then determined that the difference in the emissions from the lignite-fired EGUs was due to a difference in the class, type, or size of those units and finalized two subcategories of coal-fired EGUs for Hg emissions. See 76 FR 25036 - 67. The EPA considered basing the subcategory definition solely on an EGU (1) being designed to burn lignite and (2) burning lignite. However, the EPA decided not to do so because of the concern that such a definition would allow sources to potentially meet the definition by combusting very small amounts of low rank virgin lignite. In the preamble of the 2012 MATS Final Rule, the EPA suggested a scenario where an EGU that was not designed to burn lignite and did not routinely burn lignite could import one truck full of low rank virgin coal and burn a very small quantity of it periodically to meet the subcategory definition. To avoid creating this potential loophole, the EPA also finalized a requirement that the unit be constructed and operated at or near a mine containing the low rank virgin coal it burns. The EPA indicated that the final definition would prevent other EGUs that are not firing lignite from complying with the less stringent Hg emission standard. The final definition, as specified in the 2012 MATS Final Rule (77 FR 9369, February 16, 2012), was: "Unit designed for low rank virgin coal subcategory means any coal-fired EGU that is designed to burn and that is burning non-agglomerating virgin coal having a calorific value (moist, mineral matter-free basis) of less than 19,305 kJ/ kg (8,300 Btu/lb) that is constructed and operates at or near the mine that produces such coal."
 Beyond-the-Floor Analysis for the 2012 MATS Final Rule
For the 2012 MATS Final Rule, the EPA calculated beyond-the-floor costs for Hg controls by assuming injection of brominated activated carbon at a rate of 3.0 pounds of sorbent per million actual cubic feet of flue gas (lb/MMacf) for lignite-fired EGUs with an ESP for PM control and at an injection rate of 2.0 lb/MMacf for lignite-fired units with a baghouse (also known as a fabric filter, FF). The sorbent injection rate of 2.0 lb/MMacf for lignite-fire units with FFs is consistent with the rate assumed for all other coal types. The EPA assumed a sorbent injection rate of 3.0 lb/MMacf for lignite-fired units with ESPs, which is lower than the sorbent injection rate of 5.0 lb/MMacf that the EPA assumed for EGUs firing using other (non-lignite) coal types. In the Beyond-the-Floor Memo (see Docket ID No. EPA-HQ-OAR-2009-0234-20130), the EPA indicated that this lower sorbent injection rate was appropriate, because a higher rate would likely result in Hg emission reductions greater those needed to meet the beyond-the-floor standard of 4.0 lb/TBtu noting that greater than 90 percent control can be achieved at lignite-fired units at a 2.0 lb/MMacf injection rate for units with installed FF and using treated (i.e., brominated) activated carbon or at an injection rate of 3.0 lb/MMacf for units using treated activated carbon with installed ESPs.
Petitioners challenged the beyond-the-floor standard for lignite-fired EGUs, claiming that the final standard is not achievable because they asserted that the standard would require unrealistically high levels of Hg reduction. In White Stallion v. EPA, the Court of Appeals of the District of Columbia Circuit rejected petitioners' challenge to the final beyond-the-floor standard on the basis that the EPA had adequately concluded during the rulemaking process that the standard for lignite units were achievable if sources increased their use of a particular control technology, ACI. See White Stallion Energy Center, LLC v. EPA, 748 F.3d 1222, 1251 (D.C. Cir. 2014).
 Hg Emission Reductions Since Promulgation of the 2012 MATS Final Rule
The EPA estimated Hg emissions from coal-fired power plants in 2010 (pre-MATS) to be 29 tons. In 2017, after full implementation of the MATS rule, the EPA estimated Hg emissions had been reduced to 4 tons, an 86 percent decrease. This decline due to the installation and use of Hg controls as well as other significant changes in the power sector (e.g., coal plant retirements, increase use of natural gas and renewable energy, etc.) in the same time period.
  Hg Emissions from Coal-Fired EGUs in 2021
Hg emission reductions have continued to decline since 2017 as more coal-fired EGUs have retired or reduced utilization. The EPA estimated that 2021 Hg emissions from coal-fired EGUs were 3 tons (a 90 percent decrease compared to pre-MATS levels). However, units burning lignite coal (or permitted to burn lignite) accounted for a disproportionate amount of the total Hg emissions in 2021. As shown in Table 5 below, 16 of the top 20 Hg-emitting EGUs were lignite-fired EGUs located in North Dakota and Texas. Overall, lignite-fired EGUs were responsible for almost 30 percent of all Hg emitted from coal-fired EGUs in 2021, while generating about 7 percent of total 2021 megawatt-hours. Lignite accounted for 8 percent of total U.S. coal production in 2021.
                   Table 5  --  Top Hg-Emitting EGUs in 2021
                                     Rank
                                      EGU
                                     Fuel
                            2021 Hg Emissions (lb)
                                     State
                                       1
                                 Coal Creek 2
                                    Lignite
                                     181.8
                                      ND
                                       2
                                 Coal Creek 1
                                    Lignite
                                     175.6
                                      ND
                                       3
                                  Oak Grove 2
                                    Lignite
                                     149.8
                                      TX
                                       4
                                 Martin Lake 3
                             Lignite/Subbituminous
                                     134.4
                                      TX
                                       5
                                  Oak Grove 1
                                    Lignite
                                     112.7
                                      TX
                                       6
                                 Martin Lake 2
                             Lignite/Subbituminous
                                     111.0
                                      TX
                                       7
                               Milton R Young B2
                                    Lignite
                                     103.1
                                      ND
                                       8
                                 Martin Lake 1
                             Lignite/Subbituminous
                                     100.7
                                      TX
                                       9
                              Antelope Valley B2
                                    Lignite
                                     89.8
                                      ND
                                      10
                                   Coyote B1
                                    Lignite
                                     79.9
                                      ND
                                      11
                           H W Pirkey Power Plant 1*
                             Lignite/Subbituminous
                                     71.1
                                      TX
                                      12
                              Antelope Valley B1
                                    Lignite
                                     69.6
                                      ND
                                      13
                                San Miguel SM-1
                                    Lignite
                                     64.6
                                      TX
                                      14
                        Sandy Creek Energy Station S01
                                 Subbituminous
                                     53.5
                                      TX
                                      15
                                Limestone LIM2
                             Lignite/Subbituminous
                                     52.5
                                      TX
                                      16
                               Milton R Young B1
                                    Lignite
                                     52.4
                                      ND
                                      17
                                  Comanche 3
                                 Subbituminous
                                     50.3
                                      CO
                                      18
                                 Leland Olds 2
                                    Lignite
                                     50.1
                                      ND
                                      19
                              James H Miller Jr 3
                                 Subbituminous
                                     42.9
                                      AL
                                      20
                                   Labadie 2
                                 Subbituminous
                                     42.5
                                      MO
 *This unit has announced its intention to retire in 2023

 Limited CAA Section 114 Request
In May 2021, pursuant to authority in section 114 of the CAA, 42 U.S.C. § 7414(a), the EPA solicited information related to Hg emissions and Hg control technologies from certain lignite-fired EGUs to inform this CAA section 112(d)(6) technology review. The selected lignite-fired EGUs were asked to provide information on their control configuration for Hg and for other air pollutants (e.g., criteria pollutants such as PM, NOX, SO2). Selected information on lignite-fired EGU control configurations that was obtained from the CAA section 114 information request is shown below in Table 6. Additional information on the location, size (capacity), firing configuration, and control configuration of lignite-fired EGUs (including those few that were not included in the CAA section 114 information request) is also included. The additional information was obtained from the EPA's NEEDS database.
           Table 6  --  Control Configurations for Lignite-Fired EGUs
                                  Plant Name
                                     State
                                 Capacity (MW)
                                    Firing
                                   Control
                                 Configuration
                            Hg Control Description
                                  Hg Control
                              Antelope Valley #1
                                      ND
                                      450
                                    tangent
                                ACI + SDA + FF
Does not use activated carbon as its sorbent, instead injects a liquid sorbent to the scrubber. The facility stopped using refined coal in December 2021.
Nalco non-carbon, non-halogenated liquid sorbent added to dry scrubber; M-Sorb additive (bromide)
                              Antelope Valley #2
                                      ND
                                      450
                                    tangent
                                ACI + SDA + FF

                                 Coal Creek #1
                                      ND
                                      574
                                    tangent
                               ACI + ESPC + WFGD
               Information not collected in the CAA 114 request
                                 Coal Creek #2
                                      ND
                                      573
                                    tangent
                               ACI + ESPC + WFGD

                                    Coyote
                                      ND
                                      429
                                    cyclone
                                ACI + SDA + FF
               Information not collected in the CAA 114 request
                                Leland Olds #1
                                      ND
                                      222
                                     wall
                           SNCR + ACI + ESPC + WFGD
            Activated carbon and oxidizer injections for Hg control
               ME2C SEA SF10 Oxidizer and SB24 Activated Carbon
                                Leland Olds #2
                                      ND
                                      445
                                    cyclone
                           SNCR + ACI + ESPC + WFGD

                               Milton R Young #1
                                      ND
                                      237
                                    cyclone
                           SNCR + ACI + ESPC + WFGD
Hg controlled by Powdered Activated Carbon Injection plus Oxidizing Agent/Halogen Injection System
  DARCO Hg-H non-halogenated Powdered Activated Carbon + ADA M-Prove additive
                               Milton R Young #2
                                      ND
                                      447
                                    cyclone
                           SNCR + ACI + ESPC + WFGD

                              Spiritwood Station
                                      ND
                                      92
                                      FBC
                             SNCR + ACI + SDA + FF
Hg emissions are controlled by activated carbon injection system and a CEMS. The activated carbon injection feed rate is adjusted to maintain emissions below the 4.0 lb/Tbtu standard.
                   Activated Carbon sorbent (not specified)
                                 Limestone #1
                                      TX
                                      831
                                    tangent
                           SNCR + ACI + ESPC + WFGD
               Information not collected in the CAA 114 request
                                 Limestone #2
                                      TX
                                      858
                                    tangent
                           SNCR + ACI + ESPC + WFGD

                                 Major Oak #1
                                      TX
                                      152
                                      FBC
                      Reagent Injection + SNCR + ACI + FF
Hg is controlled by the introduction of activated carbon into each boiler duct directly in front of the baghouse. A halogen fuel additive is also applied to the lignite before it enters the day silos.
         Cabot DARCO Hg-H non-Brominated AC + ADA-ES M-Prove additive
                                 Major Oak #2
                                      TX
                                      153
                                      FBC
                      Reagent Injection + SNCR + ACI + FF

                                Martin Lake #1
                                      TX
                                      800
                                    tangent
                               ACI + ESPC + WFGD
Brominated additive injected into the furnace and activated carbon injected upstream of the air heater. In 2020 and 2021 Refined Coal System applied an aqueous bromine salt solution to the coal.
           ME2C SEA process (non-Brominated AC + chemical additive)
                                Martin Lake #2
                                      TX
                                      805
                                    tangent
                               ACI + ESPC + WFGD

                                Martin Lake #3
                                      TX
                                      805
                                    tangent
                               ACI + ESPC + WFGD

                                 Oak Grove #1
                                      TX
                                      855
                                    tangent
                             SCR + ACI + FF + WFGD
Brominated activated carbon injected downstream of the air heater. From 2018 to 2021, the unit was equipped with a Refined Coal System for Hg control. This system applied an aqueous bromine salt solution to the coal downstream of the crusher. The refined coal system is no longer in service.
                                 ADA-CS Br-AC
                                 Oak Grove #2
                                      TX
                                      855
                                     wall
                             SCR + ACI + FF + WFGD

                                 Red Hills #1
                                      MS
                                      220
                                      FBC
                         Reagent Injection + ACI + FF
Hg is controlled by injection of activated carbon into each boiler duct directly in front of the baghouse. A fuel additive is also applied to the lignite before it enters the day silos. The application of fuel additives ended in December 2021.
                 ADA-CS non-Br AC + ADA-ES M45 liquid additive
                                 Red Hills #2
                                      MS
                                      220
                                      FBC
                         Reagent Injection + ACI + FF

                                  San Miguel
                                      TX
                                      391
                                     wall
                           SNCR + ACI + ESPC + WFGD
Hg is captured using a sorbent enhanced additive (SEA) injected onto the lignite at the pulverizer feeders or directly into the furnace to promote the oxidation and capture of Hg. This is followed by an ACI system located in the boiler exit duct work upstream of the air heaters.
The scrubber system also reduces Hg emissions.
         ME2C SEA process (non-Br AC + powder-based chemical additive)
Note: ACI = activated carbon injection; SDA = spray dryer absorber (dry scrubber); FF = fabric filter; ESPC = cold side electrostatic precipitator; WFGD = wet flue gas desulfurization scrubber; SNCR = selective non-catalytic reduction (NOx control); reagent injection = sorbent injection into fluidized bed combustor

Most, but not all, of the EGUs utilized a combination of the use of a chemical additive and injection of a sorbent as their Hg control strategy. One facility in North Dakota (Antelope Valley) uses a liquid sorbent that is injected to the SO2 scrubber (spray dryer absorber, SDA). Many of the EGUs used "refined coal." Refined coal is typically produced by mixing proprietary additives to feedstock coal to help capture emissions when the coal is burned. For example, these additives may promote the oxidation of Hg to Hg[2+] compounds for capture in downstream control equipment (e.g., FGD scrubbers, PM control devices). Several of the facilities noted that use of refined coal as a part of their Hg control strategy was discontinued at the end of 2021 when the refined coal production tax credit (created by the American Jobs Creation Act of 2004) expired. According to a U.S. Government Accountability Office audit report, refined coal producers claimed approximately $8.9 billion in tax credits between 2010 and 2020.
According to fuel use information supplied to EIA (on form 923), 13 of 22 EGUs that were designed to burn lignite utilized refined coal to some extent in 2021, as summarized in Table 7. EIA form 923 does not specify the type of coal that is "refined." For this technology review, the EPA has assumed that the facilities have utilized "refined lignite." However, several "lignite-fired EGUs" located in Texas reported very high use of subbituminous coal in 2021 (ranging from 76 percent up to > 99 percent).
                Table 7  --  2021 Fuel Use At Lignite-Fired EGUs
                                  Plant Name
                            Distillate Fuel Oil (%)
                                Natural Gas (%)
                               Lignite Coal (%)
                               Refined Coal (%)
                            Subbituminous Coal (%)
                               Antelope Valley 1
                                     0.0%
                                     0.6%
                                     5.8%
                                     93.5%
                                     0.0%
                               Antelope Valley 2
                                     0.0%
                                     0.6%
                                     5.8%
                                     93.5%
                                     0.0%
                                 Coal Creek 1
                                     0.1%
                                     0.0%
                                     0.0%
                                     99.9%
                                     0.0%
                                 Coal Creek 2
                                     0.1%
                                     0.0%
                                     0.0%
                                     99.9%
                                     0.0%
                                   Coyote 1
                                     0.3%
                                     0.0%
                                     99.7%
                                     0.0%
                                     0.0%
                                 Leland Olds 1
                                     0.3%
                                     0.0%
                                     37.6%
                                     62.1%
                                     0.0%
                                 Leland Olds 2
                                     0.3%
                                     0.0%
                                     6.2%
                                     93.6%
                                     0.0%
                               Milton R Young 1
                                     0.4%
                                     0.0%
                                     17.0%
                                     82.6%
                                     0.0%
                               Milton R Young 2
                                     0.2%
                                     0.0%
                                     12.1%
                                     87.6%
                                     0.0%
                             Spiritwood Station 1
                                     0.0%
                                     35.6%
                                     0.0%
                                     64.4%
                                     0.0%
                                  Limestone 1
                                     0.0%
                                     0.2%
                                     0.0%
                                     0.0%
                                     99.8%
                                  Limestone 2
                                     0.0%
                                     0.8%
                                     0.0%
                                     0.0%
                                     99.2%
                               Major Oak Power 1
                                     0.0%
                                     0.2%
                                     99.8%
                                     0.0%
                                     0.0%
                               Major Oak Power 2
                                     0.0%
                                     0.0%
                                    100.0%
                                     0.0%
                                     0.0%
                                 Martin Lake 1
                                     0.1%
                                     0.0%
                                     23.5%
                                     0.0%
                                     76.4%
                                 Martin Lake 2
                                     0.1%
                                     0.0%
                                     22.4%
                                     0.0%
                                     77.5%
                                 Martin Lake 3
                                     0.1%
                                     0.0%
                                     19.2%
                                     0.0%
                                     80.6%
                                  Oak Grove 1
                                     0.0%
                                     1.9%
                                     3.4%
                                     94.7%
                                     0.0%
                                  Oak Grove 2
                                     0.0%
                                     0.0%
                                     3.7%
                                     96.3%
                                     0.0%
                        Red Hills Generating Facility 1
                                     0.0%
                                     0.3%
                                     0.0%
                                     99.7%
                                     0.0%
                        Red Hills Generating Facility 2
                                     0.0%
                                     0.3%
                                     0.0%
                                     99.7%
                                     0.0%
                                 San Miguel 1
                                     0.2%
                                     0.0%
                                     99.8%
                                     0.0%
                                     0.0%

 CAA Section 112(d)(6) Technology Review of the Hg Standards
 Review of the Hg Emission Standard for Non-Lignite-Fired EGUs
The final MATS Hg emission limit for EGUs firing non-lignite coals (i.e., bituminous and subbituminous coals) is 1.2 lb Hg/TBtu. To review that emission standard, the EPA evaluated the 2021 performance of EGUs firing non-lignite coals and found that EGUs firing primarily bituminous coal emitted Hg at an average annual rate of 0.4 lb Hg/TBtu (with a range of roughly 0.2 to 1.2 lb Hg/TBtu). EGUs firing primarily subbituminous coal in 2021 (not including those EGUs that are permitted to burn lignite but burned a significant amount of subbituminous coal) emitted Hg at an average annual rate of 0.6 lb Hg/TBtu (with a range of 0.1 to 1.2 lb/TBtu). This represents a control range of 98 to 77 percent (assuming an average inlet concentration of 5.5 lb/TBtu). The EPA has information on the control configurations of these non-lignite EGUs but does not have detailed information on the type of sorbent injected (e.g., activated carbon or non-carbonaceous; pre-halogenated, etc.). The EPA also does not have detailed information on the injection rate of sorbents used for Hg control (if any). Similarly, the EPA does not have information on the type of quantity of chemical additives used (if any). However, the bituminous coal-fired EGUs are already achieving an average annual rate of 0.4 lb/TBtu and the subbituminous coal-fired EGUs are already achieving an average annual rate of 0.6 lb/TBtu. The typical Hg control performance curves for sorbent injection show a leveling off such that increasing the amount of sorbent results in diminishing improvement in Hg control. Based on full-scale demonstration testing of Hg sorbents, this leveling off takes place somewhere greater than 90 percent capture. Without knowing the type of sorbent being injected or the rate of the sorbent injection, it is difficult to determine whether additional emission reductions could be achieved in a cost-effective manner. For bituminous coal-fired EGUs that do not utilize sorbent injection but rely on co-benefit control from equipment installed for criteria pollutants, it is difficult to determine whether additional Hg emission reduction could be obtained in a cost-effective manner with knowledge of the levels of Hg control achieved in each of the installed controls and, if chemical additives are injected, the type and rate of chemical additive injection. For those reasons, the EPA is not proposing to adjust the Hg emission standard for non-lignite-fired EGUs.
 Review of the Hg Emission Standard for Lignite-Fired EGUs
The final MATS Hg emission limit for EGUs firing lignite coal is 4.0 lb Hg/TBtu --  more than three times the standard for non-lignite coal. To review that emission standard, the EPA evaluated the data obtained in the 2022 CAA section 114 data survey along with the emissions data reported to the EPA and the fuel use data submitted to EIA. The 2021 performance of lignite-fired EGUs (including those permitted to burn lignite but that utilized significant amounts of subbituminous coal in 2021) is shown in Table 8 below. The table shows a "Hg Inlet" level which reflects the maximum Hg content of the range of feedstock coals that the EPA assumes is available to each of the plants in the Integrated Planning Model, IPM, the estimated control (percentage) needed to meet an emission standard of 4.0 lb Hg/TBtu (the current standard for lignite-fired EGUs) and the estimated control (percentage) to meet an emission standard of 1.2 lb Hg/TBtu (the current standard for non-lignite-fired EGUs). The table also shows the estimated 2021 Hg inlet concentration from actual 2021 fuel usage (as mentioned earlier, some units utilized significant quantities of non-lignite fuel, e.g., subbituminous coal, natural gas, etc.) and the 2021 Hg emissions reported to the EPA. The EPA then estimated the apparent level of Hg control for 2021 and the level of control that would been needed to achieve the emission standard applicable to the non-lignite-firing EGUs (1.2 lb Hg/TBtu).
Table 8  --  Hg Emissions and Control Performance of Lignite-Fired EGUs in 2021
                                  Plant Name
                              Hg Inlet (lb/TBtu)
                       Est Hg Control at 4.0 lb/Tbtu (%)
                       Est Hg Control at 1.2 lb/TBtu (%)
                          Est 2021 Hg Inlet (lb/TBtu)
                            2021 Hg Outlet (lbTBtu)
                            Est 2021 Hg Control (%)
                    Est 2021 Hg Control at 1.2 lb/TBtu (%)
                              Antelope Valley #1
                                     7.81
                                     48.8
                                     84.6
                                     7.76
                                     2.87
                                     63.0
                                     84.5
                              Antelope Valley #2
                                     7.81
                                     48.8
                                     84.6
                                     7.76
                                     2.74
                                     64.6
                                     84.5
                                 Coal Creek #1
                                     7.81
                                     48.8
                                     84.6
                                     7.80
                                     3.62
                                     53.6
                                     84.6
                                 Coal Creek #2
                                     7.81
                                     48.8
                                     84.6
                                     7.80
                                     3.89
                                     50.2
                                     84.6
                                    Coyote
                                     7.81
                                     48.8
                                     84.6
                                     7.79
                                     3.17
                                     59.2
                                     84.6
                                Leland Olds #1
                                     7.81
                                     48.8
                                     84.6
                                     7.79
                                     2.51
                                     67.8
                                     84.6
                                Leland Olds #2
                                     7.81
                                     48.8
                                     84.6
                                     7.79
                                     3.02
                                     61.3
                                     84.6
                               Milton R Young #1
                                     7.81
                                     48.8
                                     84.6
                                     7.78
                                     3.23
                                     58.4
                                     84.6
                               Milton R Young #2
                                     7.81
                                     48.8
                                     84.6
                                     7.79
                                     3.20
                                     58.9
                                     84.6
                              Spiritwood Station
                                     7.81
                                     48.8
                                     84.6
                                     5.03
                                     1.86
                                     63.1
                                     76.1

                                 Limestone #1
                                     14.88
                                     73.1
                                     91.9
                                     6.24
                                     0.94
                                     84.9
                                     80.8
                                 Limestone #2
                                     14.88
                                     73.1
                                     91.9
                                     6.20
                                     1.59
                                     74.4
                                     80.7
                                 Major Oak #1
                                     14.65
                                     72.7
                                     91.8
                                     14.62
                                     1.24
                                     91.5
                                     91.8
                                 Major Oak #2
                                     14.65
                                     72.7
                                     91.8
                                     14.65
                                     1.31
                                     91.1
                                     91.8
                                Martin Lake #1
                                     14.65
                                     72.7
                                     91.8
                                     8.22
                                     2.32
                                     71.8
                                     85.4
                                Martin Lake #2
                                     14.65
                                     72.7
                                     91.8
                                     8.13
                                     2.99
                                     63.2
                                     85.2
                                Martin Lake #3
                                     14.65
                                     72.7
                                     91.8
                                     7.85
                                     3.04
                                     61.3
                                     84.7
                                 Oak Grove #1
                                     14.88
                                     73.1
                                     91.9
                                     14.60
                                     2.01
                                     86.2
                                     91.8
                                 Oak Grove #2
                                     14.88
                                     73.1
                                     91.9
                                     14.88
                                     2.59
                                     82.6
                                     91.9
                                 Red Hills #1
                                     12.44
                                     67.8
                                     90.4
                                     12.40
                                     1.33
                                     89.3
                                     90.3
                                 Red Hills #2
                                     12.44
                                     67.8
                                     90.4
                                     12.40
                                     1.35
                                     89.1
                                     90.3
                                  San Miguel
                                     14.65
                                     72.7
                                     91.8
                                     14.62
                                     2.81
                                     80.8
                                     91.8

As can be seen in the table, all lignite-fired EGUs are estimated to meet the current standard by achieving a level of control of less than 75 percent. The average reported 2021 Hg emission rate for lignite-fired EGUs located in North Dakota was 3.0 lb Hg/TBtu with an average control of 83.7 percent. The average reported 2021 Hg emission rate for lignite-fired EGUs located in Texas and Mississippi was 2.0 lb Hg/TBtu (with an average control of 88.2 percent).
 Proposed Revision of the Hg Emission Standard for Lignite-Fired EGUs
Several commenters have provided information on new developments in Hg control technology. One commenter indicated that improvements in halogen and ACI technologies have significantly lowered the costs of those pollution control systems. The use of computational fluid dynamics and physical modeling has also improved pollutant capture and reduced sorbent consumption. The commenter further noted that ACI systems operate more reliably, and many users utilize technology to improve the dispersion of sorbents in flue gas for better performance. After reviewing the available literature and other studies and available information, the assumptions made regarding Hg control in the 2012 MATS Final Rule, and the information obtained from compliance reports and the 2022 CAA section 114 information collection, the EPA has determined that there are developments in practices, processes, and control technologies since 2012 that warrant consideration of revising the Hg standards for lignite-fired EGUs. As explained below, the EPA has further determined that available controls and methods of operation that will allow lignite-fired EGUs to meet the same Hg emission standard that is being met by EGUs firing on non-lignite coals, and that the costs of doing so are reasonable. Therefore, the EPA is proposing to revise the Hg emission standard for lignite-fired EGUs to 1.2E-06 lb/MMBtu.
  Both Lignite and Subbituminous Coal are Low Rank Coals with Low Halogen Content
Coal is classified into four main types, or ranks: anthracite, bituminous, subbituminous, and lignite. The ranking depends on heating value of the coal. Anthracite has the highest heating value of all ranks of coal and is mostly used by the metals industry (it is rarely using for power production). Anthracite accounted for less than 1 percent of the coal mined in the U.S. in 2021. Bituminous coal is also considered a "high rank coal" because of its higher heating value. It is the most abundant rank of domestic coal and accounted for about 45 percent of total U.S. coal production in 2021. Bituminous coal is used to generate electricity and in other industries.
Subbituminous coal and lignite are referred to as "low rank coals." They both have lower heating values than bituminous coal. Subbituminous coal accounted for about 46 percent of total U.S. coal production in 2021, with the vast majority produced in the Powder River Basin (PRB) of Wyoming and Montana. Lignite has the lowest energy content of all coal ranks. Lignite accounted for about 8 percent of total U.S. coal production in 2021. About 56 percent was mined in North Dakota (Fort Union lignite) and about 36 percent was mined in Texas (Gulf Coast lignite).
Chlorine is the most abundant halogen in coal. Bromine may also be present in coal but is typically in much lower concentrations than chlorine. Low-rank coals such as lignite and subbituminous generally have lower chlorine contents than higher rank coals such as bituminous coal.
As mentioned earlier, the halogen content of the coal  --  especially chlorine  --  largely influences the oxidation state of Hg in the flue gas stream. As a result, the halogen content of the coal directly influences the ability to capture and contain the Hg before it is emitted into the atmosphere. As explained earlier, ash from lignite and subbituminous coals tends to be more alkaline (relative to that from bituminous coal) due to the lower amounts of sulfur and halogen and the presence of a more alkaline and reactive (non-glassy) form of calcium in the ash. The natural alkalinity of the subbituminous and lignite fly ash can effectively neutralize the limited free halogen in the flue gas and prevent oxidation of the Hg[0]. This makes control of Hg from both subbituminous coal-fired EGUs and lignite-fired EGUs more challenging than the control of Hg from bituminous coal-fired EGUs. However, because control strategies and technologies were developed to introduce halogens to the flue gas stream, EGUs firing subbituminous coals have been able to meet the 1.2 lb/TBtu emission standard in the 2012 MATS Final Rule. As mentioned earlier, EGUs firing subbituminous coal in 2021 emitted Hg at an average annual rate of 0.6 lb Hg/TBtu with measured values as low as 0.1 lb/TBtu. Clearly EGUs firing subbituminous coal have found control options to meet  -  and exceed  -  the 1.2 lb/TBtu emission standard despite the challenges presented by the low natural halogen content of the coal and production of difficult-to-control elemental Hg vapor in the flue gas stream.
 The Hg Content of North Dakota Lignite and PRB Subbituminous Coal are Similar
As can be seen in Table 8 above, for the 2012 MATS Final Rule, the EPA estimated the North Dakota lignite-fired EGUs inlet Hg concentration at up to 7.8 lb/TBtu and estimated the inlet Hg concentration of subbituminous coal-fired EGUs at up to 8.65 lb/TBtu. These values are very similar to results from a published study that found the average Hg concentration of North Dakota lignite and PRB subbituminous coals to be very similar. The study found that the North Dakota lignite samples contained an average of 8.5 lb/TBtu and the PRB subbituminous coal samples contained an average of 7.5 lb/TBtu. Despite the similarities in Hg content, halogen content, and alkalinity between North Dakota lignite and PRB subbituminous coal, EGUs firing subbituminous coal in 2021 emitted Hg at an average annual rate of 0.6 lb Hg/TBtu while those firing on North Dakota lignite emitted Hg at an average annual rate of 3.0 lb Hg/TBtu. While the EGUs firing North Dakota lignite at an average emission rate of 3.0 lb Hg/TBtu are complying with the 2012 MATS Final Rule emission standard of 4.0 lb Hg/TBtu, it is difficult to justify why those units should not meet a similar level of Hg control as that of the EGUs firing PRB subbituminous coal given the similarities between the two fuels  -  especially the similarities in Hg content, halogen content, and alkalinity.
 The Hg Content of Gulf Coast Lignite is Greater than that of North Dakota Lignite; and Several Lignite-Fired EGUs in Texas have Co-Fired Significant Quantities of Subbituminous Coal
The Hg content of Gulf Coast lignite tends to be higher than that of the North Dakota lignite. As can be seen in Table 8 above, for the 2012 MATS Final Rule, the EPA estimated the inlet Hg concentration for Gulf Coast lignite-fired EGUs at an average inlet Hg concentration of up to 14.9 lb/TBtu (as compared to average inlet Hg concentrations of up to 7.8 lb/TBtu for North Dakota lignite). Despite the higher Hg content, EGUs permitted as lignite-fired had, in 2021, an average Hg emission rate of 2.0 lb/TBtu  -  exceeding the 2021 average emission rate of EGUs firing North Dakota lignite (at 3.0 lb/TBtu). This is due, in part, because some EGUs in Texas that are permitted as lignite-fired units (and thus subject to the Hg emission standard of 4.0 lb/TBtu) were, in 2021, firing significant amounts of subbituminous coal. Firing high levels of non-lignite coal (in some cases greater than 99 percent non-lignite coal), while remaining subject to the less stringent Hg emission standard for the subcategory of lignite-fired EGUs seems to fit the scenario that the EPA expressed concern about in the 2012 MATS Final Rule preamble  -  that "sources to potentially meet the definition by combusting very small amounts of low rank virgin coal [lignite]." See 77 FR 9379.
 The Proposed More Stringent Hg Emission Standard Can be Achieved, Cost-Effectively, Using Available Control Technology
For the 2012 MATS Final Rule, the EPA calculated beyond-the-floor costs for Hg controls by assuming injection of brominated activated carbon at a rate of 3.0 lb/MMacf for units with ESPs and injection rates of 2.0 lb/MMacf for units with baghouses (also known as FF). Yet, in responses to the CAA section 114 information survey, only one facility (Oak Grove) explicitly indicated use of brominated activated carbon. Oak Grove units #1 and #2 (both using FF for PM control) reported use of brominated activated carbon at an average injection rate of less than 0.5 lb/MMacf for operation at capacity factor greater than 70 percent. The Oak Grove units fired, in 2021, using mostly refined coal. That injection rate is considerably less than the 2.0 lb/MMaCF assumed.
From the CAA 114 information survey, the average injection rate reported for non-halogenated sorbents was 2.5 lb/MMacf. The average sorbent injection rate ranged from 10  -  65 percent of the maximum design sorbent injection rate (the average was 36 percent of the maximum design rate). As mentioned earlier, most sources utilized a control strategy of sorbent injection coupled with chemical (usually halogenated) additives. In the beyond-the-floor analysis in the 2012 MATS Final Rule, we noted that the results from various demonstration projects suggests that greater than 90 percent Hg control can be achieved at lignite-fired units using brominated activated carbon sorbent at an injection rate of 2.0 lb/MMacf for units with installed FFs for PM control and at an injection rate of 3.0 lb/MMacf for units with installed ESPs for PM control. As shown in Table 8 above, all units (in 2021) would have needed to control their Hg emissions to less than 92 percent to meet an emission standard of 1.2 lb/TBtu. Based on this, we expect that the units could meet the proposed, more stringent, emission standard of 1.2 lb/TBtu by utilizing brominated activated carbon at the injection rates suggested in the beyond-the-floor memo from the 2012 MATS Final Rule.
To determine the cost-effectiveness of that strategy, we calculated the incremental cost-effectiveness (cost per lb of Hg controlled) for a model 800 MW lignite-fired EGU. We calculated the incremental cost of injecting non-brominated activated carbon sorbent at a conservative injection rate of 5.0 lb/MMacf to achieve an emission rate of 1.2 lb/TBtu versus the cost to meet an emission rate of 4.0 lb/TBtu using non-brominated activated carbon sorbent at an emission rate of 2.5 lb/MMacf. For an 800 MW lignite-fired EGU, the incremental cost effectiveness was $8,703 per incremental lb of Hg removed. This is a conservative value as it is unlikely that sources will need to inject brominated activated carbon sorbent at rates as high as 5.0 lb/MMacf (the Oak Grove units were injecting less than 0.5 lb/MMacf) and is well below the cost that the EPA has found to be acceptable in previous rulemakings.
In summary, the EPA is proposing to revise the Hg emission standard for lignite-fired EGUs from 4.0E-06 lb/MMBtu to 1.2E-06 lb/MMBtu, which is the same Hg emission limit that non-lignite-fired EGUs must meet. We are proposing to revise this emission standard while recognizing that Hg from the combustion of lignite is challenging to capture because of the lack of naturally occurring halogen in the fuel and because of the natural alkalinity of the resulting fly ash. However, Hg from the combustion of subbituminous coal is similarly challenging to capture for the same reasons. Yet, EGUs firing subbituminous coal in 2021 emitted Hg at an average rate of 0.6 lb/TBtu and some as low as 0.1 lb/TBtu. From the CAA section 114 information survey, very few lignite-fired EGUs are using the control technology that the EPA identified as the most effective for Hg control in the 2012 MATS Final Rule, brominated ACI, which many demonstration projects have shown can achieve Hg control of greater than 90 percent. And, we have shown that use of brominated activated carbon sorbent injection can be used to cost-effectively meet the more stringent emission.
We also considered the energy implications and non-air environmental impacts of this proposed revision of the Hg emission standard for lignite-fired EGUs. We do not anticipate any energy implications from this proposed revision as most units are already using sorbent injection technology as part of the Hg control strategy and we do not project significant changes in unit operations as a result of the proposed revision. Regarding the non-air environmental impact, we anticipate that there may be positive non-air environmental impacts. The current strategies employed by most lignite-fired EGUs involve the injection of oxidizing halogen additives and, separately, injection of sorbent (typically non-brominated activated carbon). Because homogeneous (gas-phase) oxidation of Hg[0] is kinetically limited, most of the Hg[0] oxidation is thought to occur as heterogeneous (solid-phase) reactions resulting from halogens or other oxidants attached to flue gas solids (e.g., unburned carbon, other). This is essentially a two-step process where the injected (or natural) halogen (chloride or bromide) must first attach to a flue gas solid and then contact and react with gas-phase Hg[0]. The addition of sorbent that has already been pre-halogenated (most often brominated) is more efficient as the first step takes prior to injection. This means that less bromine will be unutilized and captured in a downstream control device or potentially included in the plant water effluent discharge. The EPA requests comment on its expectation that most EGUs (including lignite-fired EGUs) will no longer use "refined coal" due to the expiration of the refined coal tax credit. The amount of Br on brominated activated carbon is much less than that used to produce refine coal, and Br is retained on the activated carbon sorbent where it reacts with gas phase Hg and is captured by downstream control devices. Thus, the EPA believes that cross-media transfers of bromine to receiving waterbodies and emitted to the atmosphere, especially when wet FGD is not employed, are not expected (or would certainly be lower) with the use of brominated sorbents as compared to use of refined coal and that any negative health, ecological, and productivity effects associated with bromine transfer to water effluent will be minimized or avoided, especially given the EPA's proposed zero-discharge requirements under the Clean Water Act [insert Fed. Reg. citation when available].
 No Revisions to Work Practice Standards for Organic HAP
Following promulgation of the 2020 Final Action, in which the EPA found no developments in new technology or methods of operation that would result in cost-effective emission reductions of organic HAP and thus did not revise the work practice standards for organic HAP, the EPA received a petition for reconsideration that, in relevant part, requested the EPA to reconsider work practice standards for organic HAP. Our review of new technology and of methods of operation conducted as part of this technology review proposal also found no developments that would result in cost-effective emission reductions of organic HAP. Likewise, we are not proposing revisions to the organic HAP work practice standards finalized in the 2012 MATS Final Rule. The EPA acknowledges that it received a petition for reconsideration from environmental organizations that, in relevant part, sought the EPA's reconsideration of organic HAP work practice standards, which the EPA continues to review and will respond to in a separate action.
 No Proposed Revisions to the Acid Gas Standards for Coal-fired EGUs
The EPA evaluated the use of control technologies and strategies that are commonly used for control of acid gas HAP (e.g., HCl, HF). These control technologies and strategies include the use of wet FGD scrubbers, spray drier absorber (SDA) scrubbers, reagent injection (for fluidized combustors), dry sorbent injection (DSI), and use of low sulfur or low halogen fuels. As described in section III of this preamble, EGUs in six subcategories are subject to numeric emission limits for acid gas HAP (e.g., HCl, HF). Emission standards for HCl serve as a surrogate for all acid gas HAP, with an alternate standard for SO2 that may be used as a surrogate for the acid gas HAP at coal-fired EGUs with operational FGD systems and SO2 CEMS.
When the EPA finalized the 2012 MATS Final Rule, the primary air pollution control devices installed at EGUs for the control of acid gases were wet scrubbers (wet FGD), dry scrubbers (dry FGD or spray dryer absorber, SDA), and reagent injection (at fluidized bed combustors). These technologies are still in wide use for acid gas HAP control. An additional acid gas control technology  -  dry sorbent injection (DSI)  -  was in limited use in the power sector at the time the MATS rule was finalized but has seen increased use since (approximately 20 percent of EGUs operating in 2021 utilized DSI for acid gas control for one reason or another).
A wet FGD scrubber uses an alkaline liquid slurry (usually a limestone or lime slurry) to remove acidic gases from an exhaust stream. The acid gases react with the alkaline compounds in the slurry is removed as scrubber solids (e.g., CaSO3 or CaSO4) or may be captured due to their solubility in the scrubber slurry. Most wet FGD scrubbers have SO2 removal efficiencies exceeding 90 percent and perform even better for HCl. Dry FGD scrubbers (SDA) are an acid gas pollution control system where an alkaline sorbent slurry is injected into the flue gas stream to react with and neutralize acid gases in the exhaust stream forming a dry powder material which is then captured in a downstream PM control device (usually an FF). Alkaline sorbent injection systems (reagent injection) are also used in fluidized bed combustors (FBC) and circulating fluidized bed (CFB) boilers for control of acid gases. In that use, the alkaline sorbent (usually powered limestone) is injected into the combustion chamber with the primary fuel. Dry sorbent injection (DSI) is an add-on air pollution control system in which a dry alkaline powdered sorbent (typically sodium- or calcium-based) is injected into the flue gas steam upstream of a PM control device to react with and neutralize acid gases in the exhaust stream forming a dry powder material that may be removed in a primary or secondary PM control device. The EPA evaluated the use of these control technologies (wet FGD scrubbers, SDA, reagent injection, and DSI), and the strategic use of low sulfur or low halogen fuels.
The EPA reviewed compliance data for SO2 and/or HCl, as shown in Figure 3 of the Technical Memo, showing EGUs with highest SO2 emissions in 2021 to those with the lowest SO2 emissions in 2021. Approximately two-thirds of coal-fired EGUs have demonstrated compliance with the alternative SO2 emission standard rather than the HCl emission limit. About one-third of EGUs have demonstrated compliance with the primary acid gas emission limit for HCl. And some sources have reported emissions data that demonstrates compliance with either of the standards. The emission rates for HCl that are shown in Figure 3 of the Technical Memo distinguish between EGUs that utilize some sort of acid gas control system  -  which would be a wet FGD scrubber, a dry scrubber (an SDA), reagent injection or DSI - and EGUs that do not have a wet FGD scrubber or an SDA and do not utilize either reagent injection or DSI. All of the EGUs with no acid gas controls are units that were firing subbituminous coal and were able to demonstrate compliance with the HCl emission standard due to the low natural chlorine content and high alkalinity of most subbituminous coals.
All sources submit SO2 emissions data to comply with other CAA requirements (e.g., the Acid Rain Program). As mentioned earlier, some sources submitted emissions data that demonstrates compliance with either the HCl standard or the alternative SO2 standard. The average SO2 emission rate for units at or below the alternative SO2 emission limit was 0.09 lb SO2/MMBtu, which is approximately 55 percent below the SO2 emission limit of 0.20 lb SO2/MMBtu. The average HCl emission rate for units demonstrating compliance with the SO2 standard but also reporting HCl emissions was 0.0004 lb HCl/MMBtu, which is approximately 80 percent below the HCl emission limit of 0.002 lb HCl/MMBtu. This is consistent with the EPA's rationale for establishing the alternative SO2 emission limit  -  because HCl emissions are more easily controlled than SO2 (it is more reactive and more soluble), controlling emissions of SO2 using FGD controls effectively controls emissions of HCl. Note that an EGU may demonstrate compliance with the acid gas surrogate SO2 standard if the unit has some type of installed acid gas control and an operational SO2 CEMS.
The EPA looked further at the HCl emissions of the EGUs operating in 2021 with and without acid gas controls. The average emission rate of EGUs with no add-on acid gas control was 0.0008 lb HCl/MMBtu, which is 60 percent below the SO2 emission limit.
The EPA looked closer at the relative performance of acid gas controls for HCl emissions. The best performing EGUs tend to be those that utilize either wet or dry FGD scrubbers, with units utilizing sorbent injection emitting at slightly higher rates. The units that utilize DSI with an FF tend to have lower HCl emissions than those that utilized DSI with an ESP. This is an expected outcome as the filter cake on the FF provides great opportunity for contact with the gas phase acid gases.
Overall, the EPA has evaluated acid gas emissions data from MATS-affected EGUs and have determined that some units have demonstrated compliance with the primary HCl emission standard using acid gas control technologies (wet FGD scrubbers, SDA, reagent injection, and DSI) and through the strategic use of low-halogen, high-alkalinity fuels. Other units have demonstrated compliance with acid gas emission limits by meeting or exceeding the alternative SO2 emission standard. The average HCl emission rates for units with add-on acid gas controls was 0.0004 lb HCl/MMBtu which is approximately 80 percent below the MATS HCl emission limit. The average HCl emission rates for units with no add-on acid gas controls was 0.0008 lb HCl/MMBtu (approximately 60 percent below the MATS HCl emission limit). It is not clear that improvements in a wet or dry FGD scrubber would result in additional HCl emission reductions since HCl emissions are already much easier to control than SO2 emissions. The EPA does not have information on the injection rates for DSI systems; so, we cannot assess whether increased sorbent injection rates would result in additional HCl emission reductions. Units using DSI in combination with an ESP would almost certainly see improved performance if they were to replace the ESP with a FF. However, that small incremental reduction in HCl emissions would come at a high cost and would certainly not be a cost-effective option.
In the 2020 Technology Review, the EPA concluded that "the existing acid gas pollution control technologies that are currently in use are well-established and provide the capture efficiencies necessary for compliance with the promulgated MATS rule limits." Comments received during the 2020 Proposal did not provide any new practices, processes, or control technologies for acid gas control. One commenter noted that "in the short time since the RTR was finalized, there have been no developments in practices, processes, or control technologies, nor any new technologies or practices for the control of... acid gas HAP" (Docket ID No. EPA-HQ-OAR-2018-5121). Another commenter pointed to an independent comprehensive report to show acid gas emission controls had better performance and lower capital costs than the EPA assumed in the 2011 modeling (Docket ID No. EPA-HQ-OAR-2018-0794-4962). That report suggested control technology improvements to acid gas controls to achieve revised HCl emission standards of 0.001 lb HCl/MMBtu, 0.0006 lb HCl/MMBtu, and 0.00001 lb HCl/MMBtu through addition of new DSI systems, upgrades to existing DSI systems, upgrades to existing wet and dry scrubbers, and, for the more stringent options, installation of new FFs. However, as mentioned earlier, it is not clear that such improvements would result in corresponding reductions in HCl emissions.
In summary, the EPA has not identified any new control technologies or any improvements to existing acid gas controls that would result in additional cost-effective acid gas HAP emission reductions from coal-fired EGUs and is, therefore, not proposing revisions to the acid gas emission standards or for the surrogate SO2 emission standard.
 No Proposed Revisions to Standards for Continental Liquid Oil-fired EGUs
The annual capacity factors of most continental liquid oil-fired units are low. Based on available data reported to the EIA) and the EPA's Clean Air Markets Program Data (CAMPD), in 2021 the average annual capacity factor for liquid oil-fired units was 3 percent. Additionally, there were only two continental liquid oil-fired units identified with 2-year capacity factors greater than 8 percent. Those two units primarily fire natural gas but had heat input-based percentages of natural gas firing that were about 16 percent in at least one of the years from 2019 through 2021 (i.e., slightly above the 15 percent that would qualify them as oil-fired units). Therefore, it is likely that there are very few continental liquid oil-fired units that would be outside of the definition of the limited-use liquid oil-fired subcategory.
Furthermore, for the continental liquid oil-fired units with available data that are likely limited-use units, the cumulative percentage of heat input from residual fuel oil in 2021 was 32 percent, the heat input of distillate fuel oil was 4 percent, and the heat input from natural gas was 64 percent. Because the capacity factors of most continental liquid oil-fired units are low, and most combustion by those units is using fuel (i.e., natural gas) with low metallic HAP emission rates, the EPA is not proposing changes to the total HAP metals (which includes Hg), nor to the standards for the individual HAP metals, nor to the HAP metal surrogate fPM emission standard for continental liquid oil-fired electricity generating units.
 No Proposed Revisions to Standards for Non-Continental Liquid Oil-Fired EGUs
Hawaiian Electric Company (HECO) operates 12 liquid oil-fired boilers at its Waiau Generating Station (Pearl City, HI) and at its Kahe Generating Station (Kapolei, HI). Their average capacity factor in 2021 was 29.6 percent (on a net basis) and they fire on residual fuel oil. HECO has, in compliance reports, reported fPM emission rates to the EPA that are below the fPM emission rate of 3.0E-02 lb/MMBtu.
In Puerto Rico, there are 14 liquid oil-fired MATS-affected EGUs (3,552 MW total capacity) at four separate facilities operated by the Puerto Rico Electric Power Authority (PREPA). The EGUs operate using residual fuel oil and do not currently have any emission controls for NOx, PM or SO2. At least two of the units has dual fuel capabilities and has operated on high levels of natural gas. There is limited stack testing data available, but testing done in 2021 and 2022 indicated fPM emission rates ranging from 2.6E-02 lb/MMBtu to 2.9E-02 lb/MMBtu, a range that is just below the fPM emission rate of 3.0E-02 lb/MMBtu.
As mentioned earlier in section IV.A of this preamble summarizing the 2020 Residual Risk Review, the results of the chronic inhalation cancer risk assessment based on actual emissions indicated that the estimated maximum individual lifetime cancer risk (cancer MIR) was 9-in-1 million, with nickel emissions from oil-fired EGUs at these four facilities in Puerto Rico as the major contributor to the risk. The total estimated cancer incidence from this source category was 0.04 excess cancer cases per year, or one excess case in every 25 years. Approximately 193,000 people were estimated to have cancer risks at or above 1-in-1 million from HAP emitted from the facilities in this source category. The estimated maximum chronic noncancer TOSHI for the source category was 0.2 (respiratory), which was driven by emissions of nickel and cobalt from the oil-fired EGUs.
Since these oil-fired EGUs do not have installed control devices for HAP metals (PM controls), there is no opportunity to improve their performance in the same ways the EPA found that some coal-fired EGUs will be able to. PREPA has recently proposed near-term retirement dates (by 2026) for 10 of the 14 oil-fired EGUs with two of the other four remaining boilers burning mostly natural gas.
Because of the low capacity factors of the Hawaii oil-fired EGUs and the near-term retirement dates of most of the Puerto Rico liquid oil-fired EGUs and plans for a transition to greater use of natural gas for the remaining boilers, the EPA is not proposing to revise emission standards for non-continental oil-fired EGUs.
 What other actions are we proposing, and what is the rationale for those actions?
In addition to the proposed actions described above, we are proposing additional revisions to the NESHAP.
 1. Startup Requirements
In the Reconsideration of Certain Startup/Shutdown Issues: National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional and Small Industrial-Commercial-Institutional Steam Generating Units (79 FR 68777; November 19, 2014), the EPA took final action on its reconsideration of the startup and shutdown provisions by adding an alternative work practice standard for startup periods. That alternative work practice standard, referred to as paragraph (2) of the definition of "startup", required clean fuel use to the maximum extent possible, operation of PM control devices within 1 hour of introduction of primary fuel (i.e., coal, residual oil, or solid oil-derived fuel) to the EGU, collection and submission of records of clean fuel use and emissions control device capabilities and operation, as well as adherence to applicable numerical standards within 4 hours of the generation of electricity or thermal energy for use either on site or for sale over the grid (i.e., the end of startup) and to continue to maximize clean fuel use throughout that period. The EPA provided this alternative work practice because many commenters asserted it would be difficult, if not impossible, for their EGUs to meet the already-promulgated startup work practices. In this action, and in conjunction with the EPA's authority pursuant to CAA section 112(d)(6), the EPA is granting in part petitions for reconsideration which sought the EPA's review of startup and shutdown provisions. As part of our obligation to address the remand on this issue, we reviewed the information available to us. As discussed below, that information shows that the conditions contained in the alternative work practice standard do not represent what the best performers are able to do; moreover, as a practical matter, few EGUs have chosen to use the alternative work practice standard.
The EPA was able to identify 14 EGUs with the ability to generate up to 8.4 GW that chose to use the alternative work practice for startup periods. As shown in Table 9 below, six of those EGUs with the ability to generate up to 3.2 GW have retired and one of those EGUs with the ability to generate up to 0.7 GW will retire by 2025.
Table 9  --  EGUs Relying On Paragraph (2) of the Definition of "Startup" EGU Name
                                     Unit
                                   ORIS Code
                                      MW
                                     Notes
                                     Fuel
Prairie State Generating
                                       1
                                                                          55856
                                                                            877

                                  Bituminous
Prairie State Generating
                                       2
                                                                          55856
                                                                            877

                                  Bituminous
Brame Energy Center
                                 Rodemacher 2
                                                                           6190
                                                                            552

                                 Subbituminous
Brame Energy Center
                                  Madison 3-1
                                                                           6190
                                                                            600

                             Petroleum coke, coal
Brame Energy Center
                                  Madison 3-2
                                                                           6190
                                                                            600

                             Petroleum coke, coal
Dolet Hills
                                       1
                                                                             51
                                                                            720
                                 Retired 2021
                                    Lignite
Sherburne
                                       3
                                                                           6090
                                                                          938.7
                                 Retires 2034
                                 Subbituminous
Westwood
                                       1
                                                                          50611
                                                                             36

                                  Waste coal
Centralia
                                     BW21
                                                                           3845
                                                                          729.9
                                 Retired 2020
                                 Subbituminous
Centralia
                                     BW22
                                                                           3845
                                                                          729.9
                                 Retires 2025
                                 Subbituminous
St Johns River
                                       1
                                                                            207
                                                                            679
                                 Retired 2018
                                  Bituminous
St Johns River
                                       2
                                                                            207
                                                                            679
                                 Retired 2018
                                  Bituminous
HMP&L Station 2
                                      H1
                                                                           1382
                                                                            200
                                 Retired 2019
                                  Bituminous
HMP&L Station 2
                                      H2
                                                                           1382
                                                                            200
                                 Retired 2019
                                  Bituminous

After the planned retirements in 2025, just seven EGUs with the ability to generate up to 4.5 GW will remain; this represents less than 0.4 percent of electrical generation from all affected sources and less than 1.7 percent of the 278 GW of coal-fired and other, non-natural gas fossil-fired electrical generation available in 2022. We solicit comment on whether we have identified all of the EGUs relying on paragraph (2) of the definition of "startup", as well as their associated retirement dates as reported to the Department of Energy's EIA. Commenters, particularly owners or operators of affected EGUs, should provide us with corrected information as, or if, necessary. Despite comments from EGU owners or operators and their industry representatives opposing use of paragraph (1) of the definition of "startup", the owners or operators of coal- and oil-fired EGUs that generated over 98 percent of electricity in 2022 have made the requisite adjustments, whether through greater clean fuel capacity, better tuned equipment, better trained staff, a more efficient or better design structure, or a combination of factors, to be able to meet the requirements of paragraph (1) of the definition of "startup."
Consistent with the MACT emission standard setting requirement for using the average of the best performing 12 percent of sources to establish emission standards, we propose to remove the alternative work practice standards, i.e., those contained in paragraph (2) of the definition of "startup", from the rule. As demonstrated by the majority of EGUs currently relying on the work practice standards in paragraph (1) of the definition of "startup", we believe such a change is achievable by all EGUs; further, we expect such a change would result in little to no additional expenditure since the additional recordkeeping and reporting provisions associated with the work practice standards of paragraph (2) of the definition of "startup" were more expensive than the requirements of paragraph (1) of the definition of "startup." We solicit comment on our proposal to remove the work practice standards of paragraph (2) of the definition of "startup."
 Removing Non-Hg Metals Limits
The current MATS rule contains individual and total non-Hg metals emissions limits, as well as fPM emission limits. Those fPM emission limits serve as alternative emission limits because fPM was found to be a surrogate for either individual or total non-Hg metals emissions. As explained and used above to quantify individual and total non-Hg metals reductions from our proposed fPM emission limit revision, the relationship between individual and total non-Hg metals and fPM was determined by EGU fuel type and control device using data collected by the 2010 ICR. While EGU owners or operators have the ability to use individual or total non-Hg metals emissions as the compliance method for the 358 EGUs when this action takes effect and with generation of at least 25 MW, we are aware of just one owner or operator who provides non-Hg metals data  -  both individual and total  -  along with fPM data for compliance purposes for one waste coal-fired EGU with generating capacity of 46.1 MW. Given that owners or operators of the other EGUs applicable to MATS have chosen to demonstrate compliance with only the fPM emission limit, we propose to remove the non-Hg metals emission limits  -  both individual and total  -  from MATS. Removal of the non-Hg metals emission limits renders the LEE option for non-Hg metals (individual and total) obsolete and the EPA is proposing to remove those standards as well. Removal of the non-Hg metals emissions limits simplifies the compliance determination path for EGU owners or operators and reduces the amount of regulatory text, making the rule clearer yet continuing to ensure that non-Hg metals emissions remain below limits on an ongoing basis, particularly when the fPM is measured as proposed with PM CEMS, given that non-Hg metals emissions provided for one EGU are obtained via quarterly stack testing. We solicit comment on the number of EGUs that currently rely on non-Hg metals emissions measurement for MATS compliance purposes; to the extent that other EGU owners or operators rely on non-Hg metals emissions for compliance purposes, please be sure to identify each EGU, its nameplate generating capacity, its anticipated or announced retirement date (if applicable), and its Office of Regulatory Information Systems (ORIS) Code. We solicit comment on our proposal to remove the non-Hg metals emission limits from all existing MATS-affected EGUs.
If we were to change our position by deciding against removing the non-Hg metals emission limits from MATS and if our proposal to revise the fPM emission limits was accepted, we would develop non-Hg emission limits by multiplying the revised fPM emission limit by each individual (or total) non-Hg PM ratio identified in the aforementioned Emission Factor Development for RTR Risk Modeling Dataset for Coal- and Oil-fired EGUs memorandum. The resulting values would become the individual non-Hg metals emission limits; their sum would become the total non-Hg metals emission limit. We solicit comment on our proposed approach to develop non-Hg metals emission limits in the event that our preferred approach  -  removing the non-Hg metals emission limits  -  is not selected. Note that should our proposed approach to remove non-Hg metals emission limits from MATS not be finalized, we would need to adjust the compliance determination method because the current quarterly emissions testing would not be consistent with the continuous monitoring and compliance determination method afforded by acceptance of our proposal to require use of PM CEMS for compliance with the fPM emission limit. At least one CEMS manufacturer offers a multi-metals instrument that would be suitable or could be adjusted if necessary to account for appropriate detection levels for ongoing compliance purposes. In addition, were our proposal to remove non-Hg metals from the rule not be finalized, very frequent emissions testing, perhaps on the order of weekly, might be able to provide more information on compliance status. While not continuous, as provided by CEMS, such information would be more frequent than provided by the quarterly emissions testing required by the rule. We solicit comment on appropriate means to determine compliance with non-Hg metals emission limits, provided our proposed approach  -  removal of non-Hg metals emission limits  -  is not finalized. Please include in your comments information related to the frequency of collected data, the continuity of data supplied by your suggested means of compliance, and initial and ongoing annual costs of your suggested means of compliance.
3. Removing Use of PM CPMS for Compliance Determinations
Use of PM CPMS for compliance purposes appears to be limited to four EGUs at one site in South Carolina, and these EGUs account for less than 0.5 percent of all EGUs in operation. According to submitted reports, each of the EGUs relies on an instrument (Sick Maihak RWE-200) which provides a milliamp signal that is used to develop an ongoing operating limit; this instrument is advertised by its maker to be able to serve as a PM CEMS with little to no modification, meaning that the instrument can provide direct measurement of fPM in terms of the emission standard  -  pounds per million BTU. Given that PM CPMS use costs more than PM CEMS use, that PM CPMS does not provide continuous values in terms of the emission standard, that PM CPMS is rarely in use among EGUs, and that the existing PM CPMS can be used as PM CEMS, we propose to remove the ability to use PM CPMS for compliance purposes in MATS. The EPA solicits comment on the use of PM CPMS for compliance purposes; to the extent there are other EGU owners or operators using PM CPMS, commenters should identify each EGU, along with its ORIS code and MW nameplate capacity, as well as the PM CPMS manufacturer and model in use. The EPA also solicits comment on the proposal to replace PM CPMS with PM CEMS for compliance use in MATS; when providing comments, please provide detailed costs  -  including initial instrument cost, installation cost, and operating and maintenance costs  -  as well as a description of ongoing operating activities from those EGUs with existing PM CPMS used for compliance purposes.
 What compliance dates are we proposing, and what is the rationale for the proposed compliance dates?
The EPA is proposing to revise the fPM emission limit for existing coal-fired EGUs and the Hg emission limit for lignite-fired EGUs. The EPA is proposing up to 3 years after the effective date for EGUs subject to MATS to meet these new emission limits. The EPA considers 3 years to be as expedient as can be required considering the potential need to upgrade control systems. In addition, the EPA is proposing that affected EGUs demonstrate compliance with the fPM emission limit using PM CEMS, removing the alternative compliance options. Sources must demonstrate that compliance has been achieved, by conducting the required performance tests, and other activities as specified in 40 CFR part 63, subpart UUUUU, including a minimum sampling collection time of 3 hours per run, no later than 3 years after the promulgation date. To demonstrate initial compliance using PM CEMS, the initial performance test consists of 30-boiler operating days. If the PM CEMS is certified prior to the compliance date, the test begins with the first operating day on or after that date. If the PM CEMS is not certified prior to the compliance date, the test begins with the first operating day after certification testing is successfully completed. Continuous compliance with the revised fPM emission limit is required to be demonstrated on a 30-boiler operating day rolling average basis. The EPA proposes to remove the use of PM CPMS for compliance determinations and the non-Hg metal emission limits -- both individual and total -- 3 years after the promulgation date. The EPA considers 3 years to be as expedient as can be required considering the potential need to upgrade or replace monitoring systems. Additionally, the EPA proposes to remove fPM and the total and individual non-Hg HAP metals from the LEE program no later than 3 years after the promulgation date to align with the proposed compliance method of PM CEMS. Lastly, the EPA is proposing to remove the alternative work practice standard in paragraph (2) of the definition of "startup." The EPA proposes that affected sources must utilize paragraph (1) of the definition of "startup" as specified in 40 CFR part 63, subpart UUUUU, no later than 180 days after the compliance date.
 Summary of Cost, Environmental, and Economic Impacts
 What are the affected sources?
The EPA estimates that there are 302 coal- and 56 oil-fired EGUs that will be subject to the MATS rule by the compliance date.
 What are the air quality impacts?
The EPA estimated emissions reductions under the proposed rule for the years 2028, 2030, and 2035 based upon IPM projections. The emissions reduction estimates include reductions in pollutants directed targeted by this rule, such as Hg, and changes in other pollutants emitted from the power sector as a result of the compliance actions projected under this proposed rule. Table 10 presents the projected emissions reductions under the proposed rule.
Table 10  --  Projected EGU Emissions in the Baseline and Under the Proposed Rule: 2028, 2030, and 2035

                                Total Emissions
                             Change from Baseline

                                     Year
                                 Baseline Run
                                 Proposed Rule
                                 Proposed Rule
                                      Hg
                                     (lbs)
                                     2028
                                     5,019
                                     4,957
                                      -62

                                     2030
                                     4,206
                                     4,139
                                      -67

                                     2035
                                     3,219
                                     3,137
                                      -82
                                    PM2.5
                                (thousand tons)
                                     2028
                                     74.6
                                     74.2
                                     -0.4

                                     2030
                                     65.5
                                     65.1
                                     -0.4

                                     2035
                                     46.6
                                     45.8
                                     -0.8
                                     SO2
                                (thousand tons)
                                     2028
                                      394
                                      393
                                     -0.9

                                     2030
                                      282
                                      282
                                     -0.5

                                     2035
                                      130
                                      128
                                     -1.5
                       Ozone-season NOX (thousand tons)
                                     2028
                                      195
                                      195
                                     -0.2

                                     2030
                                      163
                                      163
                                     -0.4

                                     2035
                                      104
                                      101
                                     -3.2
                                  Annual NOX
                                (thousand tons)
                                     2028
                                      457
                                      456
                                     -0.4

                                     2030
                                      368
                                      367
                                     -0.8

                                     2035
                                      214
                                      211
                                     -3.4
                                     CO2
                             (million metric tons)
                                     2028
                                     1,222
                                     1,222
                                     -0.2

                                     2030
                                      972
                                      971
                                     -0.8

                                     2035
                                      608
                                      604
                                     -4.6
                                     HCl
                                (million tons)
                                     2028
                                      2.6
                                      2.6
                                     0.00

                                     2030
                                      1.8
                                      1.8
                                     0.00

                                     2035
                                      0.9
                                      0.9
                                     0.00

Section 3 of the RIA presents a detailed discussion of the emissions projections under the proposed requirements, as well as emissions projections under a more stringent regulatory option. Section 3 also describes the compliance actions that are projected to produce the emissions reductions in Table 10.
 What are the cost impacts?
The power industry's compliance costs are represented in this analysis as the change in electric power generation costs between the baseline and policy scenarios. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the proposed requirements. The compliance cost estimates were developed with EPA's Power Sector Modeling Platform v6 using IPM, a state-of-the-art, peer-reviewed dynamic, deterministic linear programming model of the contiguous U.S. electric power sector. IPM provides forecasts of least cost capacity expansion, electricity dispatch, and emission control strategies while meeting electricity demand and various environmental, transmission, dispatch, and reliability constraints. The model includes state-of-the-art estimates of the cost and performance of air pollution control technologies with respect to Hg and other HAP controls.
We estimate the present value (PV) of the projected compliance costs over the 2028 to 2037 period, as well as estimate the equivalent annual value (EAV) of the flow of the compliance costs over this period. All dollars are in 2019 dollars. Consistent with Executive Order 12866 guidance, we estimate the PV and EAV using 3 and 7 percent discount rates. The PV of the compliance costs, discounted at the 3-percent rate, is estimated to be about $330 million, with an EAV of about $38 million. At the 7-percent discount rate, the PV of the compliance costs is estimated to be about $230 million, with an EAV of about $33 million.
Section 4 of the RIA presents a detailed discussion of the compliance cost projections for the proposed requirements, as well as projections of compliance costs for less and more stringent regulatory options. For a detailed description of these compliance cost projections, please see Section 4 of the RIA, which is available in the docket for this action.
 What are the economic impacts?
This proposed action has energy market implications. The power sector analysis supporting this action indicates that there are important power sector impacts that are worth noting, although they are small relative to recent market-driven changes in the sector and compared to some other EPA air regulatory actions for EGUs.
There are several small national changes in energy prices projected to result from the proposed revisions to the MATS rule. Retail electricity prices are projected to increase in the contiguous U.S. by an average of less than 0.1 percent in 2028, 2030, and 2035. In 2035, the delivered natural gas price is anticipated to increase by less than 0.1 percent in response to the proposed rule. There are several other types of energy impacts associated with the proposed revisions to MATS. Some coal-fired capacity, about 500 MW (less than 1 percent of operational coal capacity), is projected to become uneconomic to maintain by 2028. Coal production for use in the power sector is not projected to change significantly by 2028.
The short-term estimates for employment needed to design, construct, and install the control equipment in the 3-year period before the compliance date are also provided using an approach that estimates employment impacts for the environmental protection sector based on projected changes from IPM on the number and scale of pollution controls and labor intensities in relevant sectors. Finally, some of the other types of employment impacts that will be ongoing are estimated using IPM outputs and labor intensities, as reported in Section 5 of the RIA.
 What are the benefits?
Pursuant to EO 12866, the RIA for this action analyzes the benefits associated with the projected emissions reductions under this proposal to inform the EPA and the public about these projected impacts. This proposed rule is projected to reduce emissions of Hg and non-Hg metal HAP, PM2.5, SO2, NOX, and CO2 nationwide. The potential impacts of these emissions reductions are discussed in detail in Section 4 of the RIA.
The projected reductions in Hg are expected to reduce the bioconcentration of methylmercury in fish. Subsistence fishing is associated with vulnerable populations, including minorities and those of low socioeconomic status. Further reductions in Hg emissions from lignite-fired facilities could help address exposure inequities for the subsistence fisher sub-population. The projected reductions in non-Hg metal HAP are expected to help the EPA maintain an ample margin of safety by reducing exposure to carcinogenic metal HAP.
This proposed rule is projected to reduce PM2.5 and ozone concentrations, producing a projected PV of monetized health benefits of about $1.9 billion, with an EAV of about $220 million discounted at 3 percent. The proposed rule is also projected to reduce greenhouse gas emissions in the form of CO2, producing a projected PV of monetized climate benefits of about $1.4 billion, with an EAV of about $170 million using the SC-CO2 discounted at 3 percent. The PV of the projected compliance costs are $330 million, with an EAV of about $38 million discounted at 3 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of $3 billion and EAV of $350 million.
At a 7 percent discount rate, this proposed rule is expected to generate projected PV of monetized health benefits of $1.2 billion, with an EAV of about $170 million discounted at 7 percent. Climate benefits remain discounted at 3 percent in this net benefits analysis. Thus, this proposed rule would generate a PV of monetized benefits of $1.6 billion, with an EAV of $340 million discounted at a 7 percent rate. The PV of the projected compliance costs are $230 million, with an EAV of $33 million discounted at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of $2.4 billion and an EAV of $300 million.
The potential benefits from reducing Hg and non-Hg metal HAP were not monetized and are therefore not reflected in the benefit-cost estimates associated with this proposal. Potential benefits from the increased transparency and accelerated identification of anomalous emission anticipated from requiring CEMS requiring were also not monetized in this analysis and are therefore not directly reflected in the quantified benefit-cost comparisons We anticipate that taking these non-monetized effects into account would show the proposal to have a greater net benefit.
 What analysis of environmental justice did we conduct?
Executive Order 12898 directs the EPA to identify the populations of concern who are most likely to experience unequal burdens from environmental harms; specifically, minority populations, low-income populations, and Indigenous peoples. Additionally, Executive Order 13985 is intended to advance racial equity and support underserved communities through federal government actions. The EPA defines environmental justice (EJ) as the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. The EPA further defines the term fair treatment to mean that "no group of people should bear a disproportionate burden of environmental harms and risks, including those resulting from the negative environmental consequences of industrial, governmental, and commercial operations or programs and policies." In recognizing that minority and low-income populations often bear an unequal burden of environmental harms and risks, the EPA continues to consider ways of protecting them from adverse public health and environmental effects of air pollution.
The EPA's EJ technical guidance states that "[t]he analysis of potential EJ concerns for regulatory actions should address three questions:
 Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern in the baseline?
 Are there potential EJ concerns associated with environmental stressors affected by the regulatory action for population groups of concern for the regulatory option(s) under consideration?
 For the regulatory option(s) under consideration, are potential EJ concerns created or mitigated compared to the baseline?"
To address these questions in the EPA's first quantitative EJ analysis in the context of a MATS rule, the EPA developed a unique analytical approach that considers the purpose and specifics of the proposed rulemaking, as well as the nature of known and potential exposures and impacts. However, due to data limitations, it is possible that our analysis failed to identify disparities that may exist, such as potential EJ characteristics (e.g., residence of historically red lined areas), environmental impacts (e.g., other ozone metrics), and more granular spatial resolutions (e.g., neighborhood scale) that were not evaluated.
For this proposed rule, we employ two types of analysis to respond to the previous three questions: proximity analyses and exposure analyses. Both types of analyses can inform whether there are potential EJ concerns for population groups of concern in the baseline (question 1). In contrast, only the exposure analyses, which are based on future air quality modeling, can inform whether there will be potential EJ concerns after implementation of the regulatory options under consideration (question 2) and whether potential EJ concerns will be created or mitigated compared to the baseline (question 3). While the exposure analysis can respond to all three questions, several caveats should be noted. For example, the air pollutant exposure metrics are limited to those used in the benefits assessment. For ozone, that is the maximum daily 8-hour average, averaged across the April through September warm season (AS-MO3) and for PM2.5 that is the annual average. This ozone metric likely smooths potential daily ozone gradients and is not directly relatable to the NAAQS, whereas the PM2.5 metric is more similar to the long term PM2.5 standard. The air quality modeling estimates are also based on state level emission data paired with facility-level baseline emissions and provided at a resolution of 12 km[2]. Additionally, here we focus on air quality changes due to this proposed rulemaking and infer post-policy exposure burden impacts.
Exposure analysis results are provided in two formats: aggregated and distributional. The aggregated results provide an overview of potential ozone exposure differences across populations at the national- and state-levels, while the distributional results show detailed information about ozone concentration changes experienced by everyone within each population.
In Section 6 of the RIA we utilize the two types of analysis to address the three EJ questions by quantitatively evaluating: 1) the proximity of affected facilities to populations of potential EJ concern (Section 6.3); and 2) the potential for disproportionate ozone and PM2.5 concentrations in the baseline and concentration changes after rule implementation across different demographic groups (Section 6.4). Each of these analyses depends on mutually exclusive assumptions, was performed to answer separate questions, and is associated with unique limitations and uncertainties.
Baseline demographic proximity analyses can be relevant for identifying populations that may be exposed to local pollutants, such as local HAP, NO2, and SO2 emitted from affected sources in this proposed rule The baseline analysis indicates that on average the percentage of the population living within 10 km of coal plants potentially subject to the proposed or alternate filterable PM standards have a higher percentage of people living two times below the poverty level than the national average. In addition, on average the percentage of the Native American population living within 10 km of lignite plants potentially subject to proposed Hg standard is higher than the national average. Relating these results to question 1 from Section 6.3 of the RIA, we conclude that there may be potential EJ concerns associated with directly emitted pollutants that are affected by the regulatory action (e.g., NO2) for certain population groups of concern in the baseline (question 1). However, as proximity to affected facilities does not capture variation in baseline exposure across communities, nor does it indicate that any exposures or impacts will occur, these results should not be interpreted as a direct measure of exposure or impact.
Whereas proximity analyses are limited to evaluating the representativeness of populations residing nearby affected facilities, the ozone and PM2.5 exposure analyses can provide insight into all three EJ questions. Even though both the proximity and exposure analyses can potentially improve understanding of baseline EJ concerns (question 1), the two should not be directly compared. This is because the demographic proximity analysis does not include air quality information and is based on current, not future, population information.
The baseline analysis of ozone and PM2.5 concentration burden responds to question 1 from EPA's EJ Technical Guidance document more directly than the proximity analyses, as it evaluates a form of the environmental stressor targeted by the regulatory action. Baseline ozone and PM2.5 analyses show that certain populations, such as Hispanics, Asians, those linguistically isolated, those less educated, and children may experience somewhat higher ozone and PM2.5 concentrations compared to the national average. Therefore, also in response to question 1, there likely are potential EJ concerns associated with ozone and PM2.5 exposures affected by the regulatory action for population groups of concern in the baseline. However, these baseline exposure results have not been fully explored and additional analyses are likely needed to understand potential implications. In addition, we infer that post-policy EJ ozone and PM2.5 concentration burdens are likely to remain after implementation of the regulatory action or alternative under consideration, due to the small magnitude of the concentration changes associated with the rulemaking, relative to the magnitude of the baseline disparities (question 2).
Question 3 asks whether potential EJ concerns will be created or mitigated as compared to the baseline. Due to the very small differences in the distributional analyses of post-policy ozone and PM2.5 exposure impacts across populations, we do not find evidence that potential EJ concerns related to ozone and PM2.5 concentrations will be created or mitigated as compared to the baseline.
Prior to this proposed rule, the EPA initiated a public outreach effort to gather input from stakeholder groups likely to be interested in this proposed rule. Specifically, the EPA presented on a National EJ call on September 20, 2022, to share information about the proposed rule and solicit feedback about potential EJ considerations. The webinar was attended by individuals representing state governments, federally recognized tribes, environmental NGOs, higher education institutions, industry, and the EPA.
In addition to the engagement conducted prior to this proposed rule, the EPA is providing the public, including those communities disproportionately impacted by the burdens of pollution, opportunities to engage in the EPA's public comment period for this proposed rule, including by hosting a public hearing. This public hearing will occur according to the schedule identified in the PUBLIC PARTICIPATION section of this proposed rule.
 Request for Comments
We solicit comments on this proposed action. In addition to general comments on this proposed action, we are also interested in additional data that may improve the analyses. We are specifically interested in receiving any information regarding developments in practices, processes, and control technologies that reduce HAP emissions.
 Statutory and Executive Order Reviews
      Additional information about these statutes and Executive Orders can be found at https://www.epa.gov/laws-regulations/laws-and-executive-orders.
 A. Executive Order 12866: Regulatory Planning and Review and Executive Order 13563: Improving Regulation and Regulatory Review
This action is an economically significant regulatory action that was submitted to the OMB for review. Any changes made in response to OMB recommendations have been documented in the docket. The EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, "Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review" (Ref. EPA-452/R-23-002), is available in the docket, and is briefly summarized in section VI of this preamble and here.
In selecting a standard, as discussed in detail below, the EPA considered the statutory direction and factors laid out by Congress in CAA section 112. Separately, pursuant to EO 12866, the EPA prepared an analysis of the potential costs and benefits associated with this action. This analysis, "Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review" (Ref. EPA-452/R-23-002) can be found in the docket for this action.
Table 11 presents the estimated present values (PV) and equivalent annualized values (EAV) of the projected health benefits, climate benefits, compliance costs, and net benefits of the proposed rule in 2019 dollars discounted to 2023. The estimated monetized net benefits are the projected monetized benefits minus the projected monetized costs of the proposed rule.
Under EO 12866, the EPA is directed to consider all of the costs and benefits of its actions, not just those that stem from the regulated pollutant. Moreover, as explained in detail [cross reference A&N proposal], it is not possible to monetize the vast majority of the public health benefits associated with reductions of HAP. Accordingly, the projected monetized health benefits include those related to public health associated with projected reductions in fine particulate matter (PM2.5) and ozone concentrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent. The projected climate benefits in this table are based on estimates of the social cost of carbon (SC-CO2) at a 3 percent discount rate and are discounted using a 3 percent discount rate to obtain the PV and EAV estimates in the table. The power industry's compliance costs are represented in this analysis as the change in electric power generation costs between the baseline and policy scenarios. In simple terms, these costs are an estimate of the increased power industry expenditures required to implement the proposed requirements.
These results present an incomplete overview of the potential effects of the proposal because important categories of benefits -- including benefits from reducing Hg and non-Hg metal HAP and the benefits from increased transparency and accelerated identification of anomalous emission anticipated from requiring CEMS  -- were not monetized and are therefore not reflected in the benefit-cost tables. We anticipate that taking non-monetized effects into account would show the proposal to have a greater net benefit than this table reflects.
Table 11  --  Projected Monetized Benefits, Compliance Costs, and Net Benefits of the Proposed Rule, 2028 through 2037
                    [Millions 2019$, Discounted to 2023][a]

                               3% Discount Rate
                               7% Discount Rate
                                 Present Value
                              Health Benefits [c]
                                    $1,900
                                    $1,200

                             Climate Benefits [d]
                                    $1,400
                                    $1,400

                               Compliance Costs
                                     $320
                                     $230

                               Net Benefits [e]
                                    $3,000
                                    $2,400
                       Equivalent Annualized Value [b]
                              Health Benefits [c]
                                     $220
                                     $170

                             Climate Benefits [d]
                                     $170
                                     $170

                               Compliance Costs
                                     $37
                                     $33

                               Net Benefits [e]
                                     $350
                                     $300
[a] Values have been rounded to two significant figures. Rows may not appear to sum correctly due to rounding.
[b] The annualized present value of costs and benefits are calculated over the 10-year period from 2028 to 2037.
[c] The projected monetized benefits include those related to public health associated with reductions in PM2.5 and ozone concentrations. The projected health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent.
[d] Climate benefits are based on changes (reductions) in CO2 emissions. Climate benefits in this table are based on estimates of the SC-CO2 at a 3 percent discount rate and are discounted using a 3 percent discount rate to obtain the PV and EAV estimates in the table. The EPA does not have a single central SC-CO2 point estimate. We emphasize the importance and value of considering the benefits calculated using all four SC- SC-CO2 estimates. As discussed in Section 4.4 of the RIA, consideration of climate benefits calculated using discount rates below 3 percent, including 2 percent and lower, is also warranted when discounting intergenerational impacts.
[e] Several categories of benefits remain unmonetized and are thus not reflected in the table. Non-monetized benefits include important benefits from reductions in HAP emissions.

As shown in Table 11, this proposed rule is projected to reduce PM2.5 and ozone concentrations, producing a projected PV of monetized health benefits of about $1.9 billion, with an EAV of about $220 million discounted at 3 percent. The proposed rule is also projected to reduce greenhouse gas emissions in the form of carbon dioxide (CO2), producing a projected PV of monetized climate benefits of about $1.4 billion, with an EAV of about $170 million using the SC-CO2 discounted at 3 percent. The PV of the projected compliance costs are $320 million, with an EAV of about $37 million discounted at 3 percent. Combining the projected benefits with the preinjected compliance costs yields a net benefit PV estimate of $3 billion and EAV of $350 million.
At a 7 percent discount rate, this proposed rule is expected to generate projected PV of monetized health benefits of $1.2 billion, with an EAV of about $170 million. Climate benefits remain discounted at 3 percent in this net benefits analysis. Thus, this proposed rule would generate a PV of monetized benefits of $2.6 billion, with an EAV of $340 million discounted at a 7 percent rate. The PV of the projected compliance costs are $230 million, with an EAV of $33 million discounted at 7 percent. Combining the projected benefits with the projected compliance costs yields a net benefit PV estimate of $2.4 billion and an EAV of $300 million.
The potential benefits from reducing Hg and non-Hg metal HAP were not monetized and are therefore not reflected in the benefit-cost estimates associated with this proposal. Potential benefits from the increased transparency and accelerated identification of anomalous emission anticipated from requiring CEMS requiring were also not monetized in this analysis and are therefore not directly reflected in the quantified benefit-cost comparisons We anticipate that taking these non-monetized effects into account would show the proposal to have a greater net benefit.
 B. Paperwork Reduction Act (PRA)
The information collection activities in this proposed rule have been submitted for approval to the OMB under the PRA. The ICR document that the EPA prepared has been assigned EPA ICR number 2137-11. You can find a copy of the ICR in the docket for this rule, and it is briefly summarized here.
The information collection activities in this proposed rule include continuous emission monitoring, performance testing, notifications and periodic reports, recording information, monitoring and the maintenance of records. The information generated by these activities will be used by the EPA to ensure that affected facilities comply with the emission limits and other requirements. Records and reports are necessary to enable delegated authorities to identify affected facilities that may not be in compliance with the requirements. Based on reported information, delegated authorities will decide which units and what records or processes should be inspected. The recordkeeping requirements require only the specific information needed to determine compliance. These recordkeeping and reporting requirements are specifically authorized by CAA section 114 (42 U.S.C. 7414).
Respondents/affected entities: The respondents are owners or operators of coal- and oil-fired EGUs. The NAICS codes for the Coal- and Oil-fired EGU industry are 221112, 221122, and 921150.
		Respondent's obligation to respond: Mandatory per 42 U.S.C. 7414 et seq.
	Estimated number of respondents: 187 per year.
	Frequency of response: The frequency of responses varies depending on the burden item. Responses include daily calibrations, quarterly inspections, and semiannual compliance reports.
	Total estimated burden: 443,000 hours (per year). Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $100,100,000 (per year), includes $49,600,000 annualized capital or operation & maintenance costs.
An agency may not conduct or sponsor, and a person is not required to respond to, a collection of information unless it displays a currently valid OMB control number. The OMB control numbers for the EPA's regulations in 40 CFR are listed in 40 CFR part 9.
Submit your comments on the EPA's need for this information, the accuracy of the provided burden estimates and any suggested methods for minimizing respondent burden to the EPA using the docket identified at the beginning of this rule. The EPA will respond to any ICR-related comments in the final rule. You may also send your ICR-related comments to OMB's Office of Information and Regulatory Affairs using the interface at https://www.reginfo.gov/public/do/PRAMain. Find this particular information collection by selecting "Currently under Review - Open for Public Comments" or by using the search function. OMB must receive comments no later than [INSERT DATE 60 DAYS AFTER DATE OF PUBLICATION IN THE FEDERAL REGISTER].
 C. Regulatory Flexibility Act (RFA)
The EPA certifies that this proposed action will not have a significant economic impact on a substantial number of small entities under the Regulatory Flexibility Act (RFA). The EPA chose to examine the projected impacts of a more stringent regulatory option than proposed on small entities in order to present a scenario of "maximum cost impact." As projected cost impacts of the proposed rule is dominated by cost impacts of the more stringent alternative also examined in the RIA, a no SISNOSE conclusion for the more stringent option can be extended to the proposed rule and less stringent option.
In 2028, the EPA identified 26 potentially affected small entities operating 41 units at 27 facilities, and of these 26, only three small entities may experience compliance cost increases greater than 1 percent of revenue.  Details of this analysis are presented in Section 5 of the RIA, which is in the public docket.
 D. Unfunded Mandates Reform Act of 1995 (UMRA)