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delivered coal, natural gas, and retail

electricity prices are not projected to

change. The EPA does not project

incremental changes in existing

operational capacity to occur in

response to the final rule. 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.

E. What are the benefits?

The RIA for this action analyzes the

benefits associated with the projected

emission reductions under this rule.

This final rule is projected to reduce

emissions of Hg and non-Hg HAP

metals, as well as PM , SO , NO and

CO nationwide. The potential impacts

of these emission reductions are

discussed in detail in section 4 of the

RIA. The EPA notes that the benefits

analysis is distinct from the statutory

determinations finalized herein, which

are based on the statutory factors the

EPA is required to consider under CAA

section 112. The assessment of benefits

described here and in the RIA is

presented solely for the purposes of

complying with Executive Order 12866,

as amended by Executive Order 14094,

and providing the public with a

complete depiction of the impacts of the

rulemaking.

Hg is a persistent, bioaccumulative

toxic metal emitted from power plants

that exists in three forms: gaseous

elemental Hg, inorganic Hg compounds,

and organic Hg compounds ( e.g.,

methylmercury). Hg can also be emitted

in a particle-bound form. Elemental Hg

can exist as a shiny silver liquid, but

readily vaporizes into air. Airborne

elemental Hg does not quickly deposit

or chemically react in the atmosphere,

resulting in residence times that are

long enough to contribute to global scale

deposition. Oxidized Hg and particlebound Hg deposit quickly from the

atmosphere impacting local and

regional areas in proximity to sources.

Methylmercury is formed by microbial

action in the top layers of sediment and

soils, after Hg has precipitated from the

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air and deposited into waterbodies or

land. Once formed, methylmercury is

taken up by aquatic organisms and

bioaccumulates up the aquatic food

web. Larger predatory fish may have

methylmercury concentrations many

times that of the concentrations in the

freshwater body in which they live.

All forms of Hg are toxic, and each

form exhibits different health effects.

Acute (short-term) exposure to high

levels of elemental Hg vapors results in

central nervous system (CNS) effects

such as tremors, mood changes, and

slowed sensory and motor nerve

function. Chronic (long-term) exposure

to elemental Hg in humans also affects

the CNS, with effects such as erethism

(increased excitability), irritability,

excessive shyness, and tremors. The

major effect from chronic ingestion or

inhalation of low levels of inorganic Hg

is kidney damage.

Methylmercury is the most common

organic Hg compound in the

environment. Acute exposure of

humans to very high levels of

methylmercury results in profound CNS

effects such as blindness and spastic

quadriparesis. Chronic exposure to

methylmercury, most commonly by

consumption of fish from Hg

contaminated waters, also affects the

CNS with symptoms such as paresthesia

(a sensation of pricking on the skin),

blurred vision, malaise, speech

difficulties, and constriction of the

visual field. Ingestion of methylmercury

can lead to significant developmental

effects, such as IQ loss measured by

performance on neurobehavioral tests,

particularly on tests of attention, fine

motor-function, language, and visual

spatial ability. In addition, evidence in

humans and animals suggests that

methylmercury can have adverse effects

on both the developing and the adult

cardiovascular system, including fatal

and non-fatal ischemic heart disease

(IHD). Further, nephrotoxicity,

immunotoxicity, reproductive effects

(impaired fertility), and developmental

effects have been observed with

methylmercury exposure in animal

studies. Methylmercury has some

genotoxic activity and can cause

chromosomal damage in several

experimental systems. The EPA has

concluded that mercuric chloride and

methylmercury are possibly

carcinogenic to humans.

The projected emissions reductions of

Hg are expected to lower deposition of

Hg into ecosystems and reduce U.S.

EGU attributable bioaccumulation of

methylmercury in wildlife, particularly

for areas closer to the effected units

subject to near-field deposition.

Subsistence fishing is associated with

vulnerable populations. Methylmercury

exposure to subsistence fishers from

lignite-fired units is below the current

RfD for methylmercury

neurodevelopmental toxicity. The EPA

considers exposures at or below the RfD

for methylmercury unlikely to be

associated with appreciable risk of

deleterious effects across the

population. However, the RfD for

methylmercury does not represent an

exposure level corresponding to zero

risk; moreover, the RfD does not

represent a bright line above which

individuals are at risk of adverse effects.

Reductions in Hg emissions from

lignite-fired facilities should further

reduce exposure to methylmercury for

subsistence fisher sub-populations

located in the vicinity of these facilities,

which are all located in North Dakota,

Texas, and Mississippi.

In addition, U.S. EGUs are a major

source of HAP metals emissions

including selenium, arsenic, chromium,

nickel, and cobalt, cadmium, beryllium,

lead, and manganese. Some HAP metals

emitted by U.S. EGUs are known to be

persistent and bioaccumulative and

others have the potential to cause

cancer. Exposure to these HAP metals,

depending on exposure duration and

levels of exposures, is associated with a

variety of adverse health effects. The

emissions reductions projected under

this final rule are expected to reduce

human exposure to non-Hg HAP metals,

including carcinogens.

Furthermore, there is the potential for

reductions in Hg and non-Hg HAP metal

emissions to enhance ecosystem

services and improve ecological

outcomes. The reductions will

potentially lead to positive economic

impacts although it is difficult to

estimate these benefits and,

consequently, they have not been

included in the set of quantified

benefits.

As explained in section IX.B., the

continuous monitoring of fPM required

in this rule may induce further

reductions of fPM and non-Hg HAP

metals than we project in the RIA for

Agency for Toxic Substances and Disease

Registry (ATSDR). Toxicological Profile for

Mercury. Public Health Service, U.S. Department of

Health and Human Services, Atlanta, GA. 2022.

U.S. Environmental Protection Agency.

Integrated Risk Information System (IRIS) on

Methylmercury. National Center for Environmental

Assessment, Office of Research and Development,

Washington, DC. 2001.

U.S. Environmental Protection Agency.

Integrated Risk Information System (IRIS) on

Mercuric Chloride. National Center for

Environmental Assessment, Office of Research and

Development, Washington, DC. 1995.

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this action. As a result, there may be

additional unquantified beneficial

health impacts from these potential

reductions. The continuous monitoring

of fPM required in this rule is also likely

to provide several additional benefits to

the public which are not quantified in

this rule, including greater certainty,

accuracy, transparency, and granularity

in fPM emissions information than

exists today.

The rule is also expected to reduce

emissions of direct PM , NO , and SO

nationally throughout the year. Because

NO and SO are also precursors to

secondary formation of ambient PM

,

reducing these emissions would reduce

human exposure to ambient PM

throughout the year and would reduce

the incidence of PM -attributable

health effects. The rule is also expected

to reduce ozone-season NO emissions

nationally in most years of analysis. In

the presence of sunlight, NO , and

volatile organic compounds (VOCs) can

undergo a chemical reaction in the

atmosphere to form ozone. Reducing

NO emissions in most locations

reduces human exposure to ozone and

reduces the incidence of ozone-related

health effects, although the degree to

which ozone is reduced will depend in

part on local concentration levels of

VOCs.

The health effect endpoints, effect

estimates, benefit unit values, and how

they were selected, are described in the

technical support document titled

and OzoneEstimating PM

Attributable Health Benefits (2023). This

document describes our peer-reviewed

approach for selecting and quantifying

adverse effects attributable to air

pollution, the demographic and health

data used to perform these calculations,

and our methodology for valuing these

effects.

Because of projected changes in

dispatch under the final requirements,

the rule is also projected to impact CO

emissions. The EPA estimates the

climate benefits of CO emission

reductions expected from the final rule

using estimates of the social cost of

carbon (SC–CO ) that reflect recent

advances in the scientific literature on

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climate change and its economic

impacts and that incorporate

recommendations made by the National

Academies of Science, Engineering, and

Medicine. The EPA published and

used these estimates in the RIA for the

December 2023 Natural Gas Sector final

rule titled Standards of Performance for

New, Reconstructed, and Modified

Sources and Emissions Guidelines for

Existing Sources: Oil and Natural Gas

Sector Climate Review (2023 Oil and

Natural Gas NSPS/EG). The EPA

solicited public comment on the

methodology and use of these estimates

in the RIA for the Agency’s December

2022 Oil and Natural Gas Sector

supplemental proposal

that preceded

the 2023 Oil and Natural Gas NSPS/EG

and has conducted an external peer

review of these estimates. The response

to public comments document and the

response to peer reviewer

recommendations can be found in the

docket for the 2023 Oil and Natural Gas

NSPS/EG action. Complete information

about the peer review process is also

available on the EPA’s website.

Section 4.4 within the RIA for this

final rulemaking provides an overview

of the methodological updates

incorporated into the SC–CO estimates

used in this final RIA.

A more detailed

National Academies of Sciences, Engineering,

and Medicine (National Academies). 2017. Valuing

Climate Damages: Updating Estimation of the Social

Cost of Carbon Dioxide. National Academies Press.

Regulatory Impact Analysis of the Standards of

Performance for New, Reconstructed, and Modified

Sources and Emissions Guidelines for Existing

Sources: Oil and Natural Gas Sector Climate

Review, Docket ID No. EPA–HQ–OAR–2021–0317,

December 2023.

Supplemental Notice of Proposed Rulemaking

for Standards of Performance for New,

Reconstructed, and Modified Sources and

Emissions Guidelines for Existing Sources: Oil and

Natural Gas Sector Climate Review, 87 FR 74702

(December 6, 2022).

https://www.epa.gov/environmentaleconomics/scghg-tsd-peer-review.

Note that the RIA for the proposal of this

rulemaking used the SC–CO estimates from the

Interagency Working Group’s (IWG) February 2021

Social Cost of Greenhouse Gases Technical Support

Document (TSD) (IWG 2021) to estimate climate

benefits. These SC–CO estimates were interim

values recommended for use in benefit-cost

analyses until updated estimates of the impacts of

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explanation of each input and the

modeling process is provided in the

final technical report, EPA Report on

the Social Cost of Greenhouse Gases:

Estimates Incorporating Recent

Scientific Advances.

The SC–CO is the monetary value of

the net harm to society associated with

a marginal increase in CO emissions in

a given year, or the benefit of avoiding

that increase. In principle, SC–CO

includes the value of all climate change

impacts both negative and positive,

including, but not limited to, changes in

net agricultural productivity, human

health effects, property damage from

increased flood risk and natural

disasters, disruption of energy systems,

risk of conflict, environmental

migration, and the value of ecosystem

services. The SC–CO , therefore, reflects

the societal value of reducing emissions

of CO by one metric ton and is the

theoretically appropriate value to use in

conducting benefit-cost analyses of

policies that affect CO emissions. In

practice, data and modeling limitations

restrain the ability of SC–CO estimates

to include all physical, ecological, and

economic impacts of climate change,

implicitly assigning a value of zero to

the omitted climate damages. The

estimates are, therefore, a partial

accounting of climate change impacts

and likely underestimate the marginal

benefits of abatement.

Table 10 of this document presents

the estimated PV and EAV of the

projected health and climate benefits

across the regulatory options examined

in the RIA in 2019 dollars discounted to

2023.

BILLING CODE 6560–50–P

climate change could be developed. Estimated

climate benefits using these interim SC–CO values

(IWG 2021) are presented in Appendix B of the RIA

for this final rulemaking for comparison purposes.

Supplementary Material for the Regulatory

Impact Analysis for the Final Rulemaking,

‘‘Standards of Performance for New, Reconstructed,

and Modified Sources and Emissions Guidelines for

Existing Sources: Oil and Natural Gas Sector

Climate Review,’’ EPA Report on the Social Cost of

Greenhouse Gases: Estimates Incorporating Recent

Scientific Advances, Docket ID No. EPA–HQ–OAR–

2021–0317, November 2023.

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This final rule is projected to reduce

PM and ozone concentrations,

producing a projected PV of monetized

health benefits of about $300 million,

with an EAV of about $33 million

discounted at 2 percent. The projected

PV of monetized climate benefits of the

final rule is estimated to be about $130

million, with an EAV of about $14

million using the SC–CO discounted at

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2 percent.

Thus, this final rule would

Monetized climate benefits are discounted

using a 2 percent discount rate, consistent with the

EPA’s updated estimates of the SC–CO . The 2003

version of OMB’s Circular A–4 had generally

recommended 3 percent and 7 percent as default

discount rates for costs and benefits, though as part

of the Interagency Working Group on the Social

Cost of Greenhouse Gases, OMB had also long

recognized that climate effects should be

discounted only at appropriate consumption-based

discount rates. In November 2023, OMB finalized

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an update to Circular A–4, in which it

recommended the general application of a 2 percent

discount rate to costs and benefits (subject to

regular updates), as well as the consideration of the

shadow price of capital when costs or benefits are

likely to accrue to capital (OMB 2023). Because the

SC–CO estimates reflect net climate change

damages in terms of reduced consumption (or

monetary consumption equivalents), the use of the

social rate of return on capital (7 percent under

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generate a PV of monetized benefits of

$420 million, with an EAV of $47

million discounted at a 2 percent rate.

At a 3 percent discount rate, this final

rule is expected to generate projected

PV of monetized health benefits of $260

million, with an EAV of about $31

million discounted at 3 percent. Climate

benefits remain discounted at 2 percent

in this benefits analysis and are

estimated to be about $130 million, with

an EAV of about $14 million using the

SC–CO . Thus, this final rule would

generate a PV of monetized benefits of

$390 million, with an EAV of $45

million discounted at a 3 percent rate.

At a 7 percent discount rate, this final

rule is expected to generate projected

PV of monetized health benefits of $180

million, with an EAV of about $25

million discounted at 7 percent. Climate

benefits remain discounted at 2 percent

in this benefits analysis and are

estimated to be about $130 million, with

an EAV of about $14 million using the

SC–CO . Thus, this final rule would

generate a PV of monetized benefits of

$300 million, with an EAV of $39

million discounted at a 7 percent rate.

The benefits from reducing Hg and

non-Hg HAP metals and from

unquantified improvements in water

quality were not monetized and are

therefore not directly reflected in the

monetized benefit-cost estimates

associated with this rulemaking.

Potential benefits from the increased

transparency and accelerated

identification of anomalous emission

anticipated from requiring PM CEMS

were also not monetized in this analysis

and are therefore also not directly

reflected in the monetized benefit-cost

comparisons. We nonetheless consider

these impacts in our evaluation of the

net benefits of the rule and find that, if

we were able to monetize these

beneficial impacts, the final rule would

have greater net benefits than shown in

table 11 of this document.

F. What analysis of environmental

justice did we conduct?

For purposes of analyzing regulatory

impacts, the EPA relies upon its June

2016 ‘‘Technical Guidance for Assessing

Environmental Justice in Regulatory

Analysis,’’ which provides

recommendations that encourage

analysts to conduct the highest quality

analysis feasible, recognizing that data

limitations, time, resource constraints,

and analytical challenges will vary by

OMB Circular A–4 (2003)) to discount damages

estimated in terms of reduced consumption would

inappropriately underestimate the impacts of

climate change for the purposes of estimating the

SC–CO . See Section 4.4 of the RIA for more

discussion.

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media and circumstance. The Technical

Guidance states that a regulatory action

may involve potential EJ concerns if it

could: (1) create new disproportionate

impacts on communities with EJ

concerns; (2) exacerbate existing

disproportionate impacts on

communities with EJ concerns; or (3)

present opportunities to address

existing disproportionate impacts on

communities with EJ concerns through

this action under development.

The EPA’s EJ technical guidance

states that ‘‘[t]he analysis of potential EJ

concerns for regulatory actions should

address three questions: (A) Are there

potential EJ concerns associated with

environmental stressors affected by the

regulatory action for population groups

of concern in the baseline? (B) 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? (C) For the

regulatory option(s) under

consideration, are potential EJ concerns

created or mitigated compared to the

baseline?’’

The environmental justice analysis is

presented for the purpose of providing

the public with as full as possible an

understanding of the potential impacts

of this final action. The EPA notes that

analysis of such impacts is distinct from

the determinations finalized in this

action under CAA section 112, which

are based solely on the statutory factors

the EPA is required to consider under

that section. 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 this rulemaking, as well

as the nature of known and potential

disproportionate and adverse 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. Also due

to data and resource limitations, we

discuss HAP and climate EJ impacts of

this action qualitatively (section 6 of the

RIA).

For this rule, we employ two types of

analysis to respond to the previous three

questions: proximity analyses and

exposure analyses. Both types of

See https://www.epa.gov/environmental

justice/technical-guidance-assessingenvironmental-justice-regulatory-analysis.

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analysis can inform whether there are

potential EJ concerns 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 PM that is the annual average. This

ozone metric likely smooths potential

daily ozone gradients and is not directly

relatable to the National Ambient Air

Quality Standards (NAAQS), whereas

the PM metric is more similar to the

long-term PM

standard. The air

quality modeling estimates are also

based on state and fuel level emission

data paired with facility-level baseline

emissions and provided at a resolution

of 12 square kilometers. Additionally,

here we focus on air quality changes

due to this rulemaking and infer postexposure

policy ozone and PM

burden impacts. Note, we discuss HAP

and climate EJ impacts of this action

qualitatively (section 6 of the RIA).

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 various local populations

with potential EJ concerns (section 6.4);

and (2) the potential for

disproportionate ozone and PM

concentrations in the baseline and

concentration changes after rule

implementation across different

demographic groups on the basis of

race, ethnicity, poverty status,

employment status, health insurance

status, life expectancy, redlining, Tribal

land, age, sex, educational attainment,

The baseline for proximity analyses is current

population information, whereas the baseline for

ozone exposure analyses are the future years in

which the regulatory options will be implemented

(e.g., 2023 and 2026).

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and degree of linguistic isolation

(section 6.5). It is important to note that

due to the small magnitude of

underlying emissions changes, and the

corresponding small magnitude of the

ozone and PM concentration changes,

the rule is expected to have only a small

impact on the distribution of exposures

across each demographic group. Each of

these analyses should be considered

independently of each other, as each

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 environmental stressors, such as

local NO and SO emitted from affected

sources in this final rule, traffic, or

noise. The baseline analysis indicates

that on average the populations living

within 10 kilometers of coal plants

potentially impacted by the amended

fPM standards have a higher percentage

of people living below two times the

poverty level than the national average.

In addition, on average the percentage of

the American Indian population living

within 10 kilometers of lignite plants

potentially impacted by the amended

Hg standard is higher than the national

average. Assessing these results, we

conclude that there may be potential EJ

concerns associated with directly

emitted pollutants that are affected by

the regulatory action ( e.g., SO ) for

various population groups 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.

As HAP exposure results generated as

part of the 2020 Residual Risk Review

were below both the presumptive

acceptable cancer risk threshold and

noncancer health benchmarks and this

regulation should further reduce

exposure to HAP, there are no

‘‘disproportionate and adverse effects’’

of potential EJ concern. Therefore, we

did not perform a quantitative EJ

assessment of HAP risk. However, the

potential reduction in non-Hg HAP

metal emissions would likely reduce

exposures to people living nearby coal

plants potentially impacted by the

amended fPM standards.

This rule is also expected to reduce

emissions of direct PM , NO , and SO

nationally throughout the year. Because

NO and SO are also precursors to

secondary formation of ambient PM

and because NO is a precursor to ozone

formation, reducing these emissions

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would impact human exposure.

Quantitative ozone and PM

exposure

analyses can provide insight into all

three EJ questions, so they are

performed to evaluate potential

disproportionate impacts of this

rulemaking. 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

PM concentration burden responds to

question 1 from the EPA’s EJ technical

guidance more directly than the

proximity analyses, as it evaluates a

form of the environmental stressor

targeted by the regulatory action.

Baseline PM and ozone exposure

analyses show that certain populations,

such as residents of redlined census

tracts, those linguistically isolated,

Hispanic, Asian, those without a high

school diploma, and the unemployed

may experience higher ozone and PM

exposures as compared to the national

average. American Indian, residents of

Tribal Lands, populations with higher

life expectancy or with life expectancy

data unavailable, children, and insured

populations may also experience

disproportionately higher ozone

concentrations than the reference group.

Hispanic, Black, below the poverty line,

and uninsured populations may also

experience disproportionately higher

PM concentrations than the reference

group. Therefore, also in response to

question 1, there likely are potential EJ

concerns associated with ozone and

PM 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. Due

to the small magnitude of the exposure

changes across population

demographics associated with the

rulemaking relative to the magnitude of

the baseline disparities, we infer that

post-policy EJ ozone and PM

concentration burdens are likely to

remain after implementation of the

regulatory action or alternative under

consideration (question 2).

Question 3 asks whether potential EJ

concerns will be created or mitigated as

compared to the baseline. Due to the

very small magnitude of differences

across demographic population postpolicy ozone and PM

exposure

impacts, we do not find evidence that

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potential EJ concerns related to ozone

and PM concentrations will be created

or mitigated as compared to the

baseline.

X. Statutory and Executive Order

Reviews

Additional information about these

statutes and Executive Orders can be

found at https://www.epa.gov/lawsregulations/laws-and-executive-orders.

A. Executive Order 12866: Regulatory

Planning and Review and Executive

Order 14094: Modernizing Regulatory

Review

This action is a ‘‘significant regulatory

action,’’ as defined under section 3(f)(1)

of Executive Order 12866, as amended

by Executive Order 14094. Accordingly,

the EPA submitted this action to the

Office of Management and Budget

(OMB) for Executive Order 12866

review. Documentation of any changes

made in response to the Executive Order

12866 review is available 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 Final

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–24–005), is briefly summarized

in section IX. of this preamble and here.

This analysis is also available in the

docket.

Table 11 of this document presents

the estimated PV and EAV of the

monetizable projected health benefits,

climate benefits, compliance costs, and

net benefits of the final rule in 2019

dollars discounted to 2023. The

estimated monetized net benefits are the

projected monetized benefits minus the

projected monetized costs of the final

rule.

Under Executive Order 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. Accordingly, the projected

monetized benefits of the final rule

include health benefits associated with

and ozone

projected reductions in PM

concentration. The projected monetized

benefits also include climate benefits

due to reductions in CO emissions. The

projected health benefits are associated

with several point estimates and are

presented at real discount rates of 2, 3,

and 7 percent. The projected climate

Please note that results for ozone and PM

exposures should not be extrapolated to other air

pollutants that were not included in the assessment,

including HAP. Detailed EJ analytical results can be

found in section 6 of the RIA.

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benefits in this table are based on

estimates of the SC–CO at a 2 percent

near-term Ramsey discount rate and are

discounted using a 2 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 finalized

requirements and represent the EPA’s

best estimate of the social cost of the

final rulemaking.

BILLING CODE 6560–50–C

producing a projected PV of monetized

health benefits of about $300 million,

with an EAV of about $33 million

discounted at 2 percent. The rule is also

projected to reduce greenhouse gas

emissions in the form of CO , producing

As shown in table 11 of this

document, this rule is projected to

reduce PM and ozone concentrations,

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a projected PV of monetized climate

benefits of about $130 million, with an

EAV of about $14 million using the SC–

CO discounted at 2 percent. Thus, this

final rule would generate a PV of

monetized benefits of $420 million,

with an EAV of $47 million discounted

at a 2 percent rate. The PV of the

projected compliance costs are $860

million, with an EAV of about $96

million discounted at 2 percent.

Combining the projected benefits with

the projected compliance costs yields a

net benefit PV estimate of

$440

million and EAV of

$49 million.

At a 3 percent discount rate, this rule

is expected to generate projected PV of

monetized health benefits of $260

million, with an EAV of about $31

million. Climate benefits remain

discounted at 2 percent in this net

benefits analysis. Thus, this final rule

would generate a PV of monetized

benefits of $390 million, with an EAV

of $45 million discounted at a 3 percent

rate. The PV of the projected

compliance costs are $790 million, with

an EAV of $92 million discounted at 3

percent. Combining the projected

benefits with the projected compliance

costs yields a net benefit PV estimate of

$400 million and an EAV of

$47

million.

At a 7 percent discount rate, this rule

is expected to generate projected PV of

monetized health benefits of $160

million, with an EAV of about $23

million. Climate benefits remain

discounted at 2 percent in this net

benefits analysis. Thus, this final rule

would generate a PV of monetized

benefits of $300 million, with an EAV

of $39 million discounted at a 3 percent

rate. The PV of the projected

compliance costs are $560 million, with

an EAV of $80 million discounted at 7

percent. Combining the projected

benefits with the projected compliance

costs yields a net benefit PV estimate of

$260 million and an EAV of

$41

million.

The potential benefits from reducing

Hg and non-Hg HAP metals and

potential improvements in water quality

and availability were not monetized and

are therefore not directly reflected in the

monetized benefit-cost estimates

associated with this final rule. Potential

benefits from the increased transparency

and accelerated identification of

anomalous emission anticipated from

requiring CEMS were also not

monetized in this analysis and are

therefore also not directly reflected in

the monetized benefit-cost comparisons.

We nonetheless consider these impacts

in our evaluation of the net benefits of

the rule and find, if we were able to

quantify and monetize these beneficial

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impacts, the final rule would have

greater net benefits than shown in table

11 of this preamble.

B. Paperwork Reduction Act (PRA)

The information collection activities

in this 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 2137–12. You can find a copy

of the ICR in the docket for this rule,

and it is briefly summarized here. The

information collection requirements are

not enforceable until OMB approves

them. OMB has previously approved the

information collection activities

contained in the existing regulations

and has assigned OMB control number

2060–0567.

The information collection activities

in this 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). The burden and cost

estimates below represent the total

burden and cost for the information

collection requirements of the NESHAP

for Coal- and Oil-Fired EGUs, not just

the burden associated with the

amendments in this final rule. The

incremental cost associated with these

amendments is $2.4 million per year.

Respondents/affected entities: The

respondents are owners or operators of

coal- and oil-fired EGUs. The North

American Industry Classification

System (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:

192 per year.

Frequency of response: The frequency

of responses varies depending on the

burden item. Responses include daily

Each facility is a respondent and some

facilities have multiple EGUs.

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calibrations, monthly recordkeeping

activities, semiannual compliance

reports, and annual reports.

Total estimated burden: 447,000

hours (per year). Burden is defined at 5

CFR part 1320.3(b).

Total estimated cost: $106,600,000

(per year), includes $53,100,000 in

annual labor costs and $53,400,000

annualized capital and operation and

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. When

OMB approves this ICR, the Agency will

announce that approval in the Federal

Register and publish a technical

amendment to 40 CFR part 9 to display

the OMB control number for the

approved information collection

activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

The EPA certifies that this action will

not have a significant economic impact

on a substantial number of small entities

under the RFA. In the 2028 analysis

year, the EPA identified 24 potentially

affected small entities operating 45 units

at 26 facilities, and of these 24, only one

small entity may experience compliance

cost increases greater than one percent

of revenue under the final rule. Details

of this analysis are presented in section

5 of the RIA, which is in the public

docket.

D. Unfunded Mandates Reform Act

(UMRA)

This action does not contain an

unfunded mandate of $100 million or

more (adjusted for inflation) as

described in UMRA, 2 U.S.C. 1531–

1538, and does not significantly or

uniquely affect small governments. The

costs involved in this action are

estimated not to exceed $100 million or

more (adjusted for inflation) in any one

year.

E. Executive Order 13132: Federalism

This action does not have federalism

implications. It will not have substantial

direct effects on the states, on the

relationship between the national

government and the states, or on the

distribution of power and

responsibilities among the various

levels of government.

F. Executive Order 13175: Consultation

and Coordination With Indian Tribal

Governments

This action does not have tribal

implications as specified in Executive

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Order 13175. The Executive order

defines tribal implications as ‘‘actions

that have substantial direct effects on

one or more Indian tribes, on the

relationship between the Federal

Government and Indian tribes.’’ The

amendments in this action would not

have a substantial direct effect on one or

more tribes, change the relationship

between the Federal Government and

tribes, or affect the distribution of power

and responsibilities between the Federal

Government and Indian tribes. Thus,

Executive Order 13175 does not apply

to this action.

Although this action does not have

tribal implications as specified in

Executive Order 13175, the EPA

consulted with tribal officials during the

development of this action. On

September 1, 2022, the EPA sent a letter

to all federally recognized Indian tribes

initiating consultation to obtain input

on this action. The EPA did not receive

any requests for consultation from

Indian tribes. The EPA also participated

in the September 2022 National Tribal

Air Association EPA Air Policy Update

Call to solicit input on this action.

H. Executive Order 13211: Actions

Concerning Regulations That

Significantly Affect Energy Supply,

Distribution, or Use

G. Executive Order 13045: Protection of

Children From Environmental Health

Risks and Safety Risks

J. Executive Order 12898: Federal

Actions To Address Environmental

Justice in Minority Populations and

Low-Income Populations and Executive

Order 14096: Revitalizing Our Nation’s

Commitment to Environmental Justice

for All

Executive Order 13045 directs Federal

agencies to include an evaluation of the

health and safety effects of the planned

regulation on children in federal health

and safety standards and explain why

the regulation is preferable to

potentially effective and reasonably

feasible alternatives. This action is

subject to Executive Order 13045

because it is a significant regulatory

action under section 3(f)(1) of Executive

Order 12866. Accordingly, we have

evaluated the potential for

environmental health or safety effects

from exposure to HAP, ozone, and PM

on children. The EPA believes that,

even though the 2020 residual risk

assessment showed all modeled

exposures to HAP to be below

thresholds for public health concern,

the rule should reduce HAP exposure by

reducing emissions of Hg and non-Hg

HAP with the potential to reduce HAP

exposure to vulnerable populations,

including children. The action

described in this rule is also expected to

lower ozone and PM

in many areas,

including those areas that struggle to

attain or maintain the NAAQS, and thus

mitigate some pre-existing health risks

across all populations evaluated,

including children. The results of this

evaluation are contained in the RIA and

are available in the docket for this

action.

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This action is not a ‘‘significant

energy action’’ because it is not likely to

have a significant adverse effect on the

supply, distribution, or use of energy.

For 2028, the compliance year for the

standards, the EPA does not project a

significant change in retail electricity

prices on average across the contiguous

U.S., coal-fired electricity generation,

natural gas-fired electricity generation,

or utility power sector delivered natural

gas prices. Details of the projected

energy effects are presented in section 3

of the RIA, which is in the public

docket.

I. National Technology Transfer and

Advancement Act (NTTAA) and 1 CFR

Part 51

The following standards appear in the

amendatory text of this document and

were previously approved for the

locations in which they appear: ANSI/

ASME PTC 19.10–1981, ASTM D6348–

03(R2010), and ASTM D6784–16.

The EPA believes that the human

health or environmental conditions that

exist prior to this action result in or

have the potential to result in

disproportionate and adverse human

health or environmental effects on

communities with environmental justice

concerns. For this rule, we employ the

proximity demographic analysis and the

PM and ozone exposure analyses to

evaluate disproportionate and adverse

human health and environmental effects

on communities with EJ concerns that

exist prior to the action. The proximity

demographic analysis indicates that on

average the population living within 10

kilometers of coal plants potentially

impacted by the fPM standards have a

higher percentage of people living

below two times the poverty level than

the national average. In addition, on

average the percentage of the American

Indian population living within 10

kilometers of lignite-fired plants

potentially impacted by the Hg standard

is higher than the national average.

Baseline PM and ozone and exposure

analyses show that certain populations,

such as residents of redlined census

tracts, those linguistically isolated,

Hispanic, Asian, those without a high

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38563

school diploma, and the unemployed

may experience disproportionately

higher ozone and PM

exposures as

compared to the national average.

American Indian, residents of Tribal

Lands, populations with higher life

expectancy or with life expectancy data

unavailable, children, and insured

populations may also experience

disproportionately higher ozone

concentrations than the reference group.

Hispanics, Blacks, those below the

poverty line, and uninsured populations

may also experience disproportionately

higher PM concentrations than the

reference group.

The EPA believes that this action is

not likely to change existing

disproportionate and adverse effects on

communities with environmental justice

concerns. 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 final rule, and

whether potential EJ concerns will be

created or mitigated. We infer that

baseline disparities in ozone and PM

concentration burdens are likely to

remain after implementation of the final

regulatory option due to the small

magnitude of the exposure changes

across population demographics

associated with the rulemaking relative

to the baseline disparities. We also do

not find evidence that potential EJ

concerns related to ozone or PM

exposures will be exacerbated or

mitigated in the final regulatory option,

compared to the baseline due to the very

small differences in the magnitude of

exposure

post-policy ozone and PM

impacts across demographic

populations. Additionally, the potential

reduction in Hg and non-Hg HAP metal

emissions would likely reduce

exposures to people living nearby coal

plants potentially impacted by the

amended fPM standards.

The information supporting this

Executive Order review is contained in

section IX.F. of this preamble and in

section 6, Environmental Justice

Impacts of the RIA, which is in the

public docket (EPA–HQ–OAR–2018–

0794).

K. Congressional Review Act (CRA)

This action is subject to the CRA, and

the EPA will submit a rule report to

each House of the Congress and to the

Comptroller General of the United

States. This action meets the criteria set

forth in 5 U.S.C. 804(2).

List of Subjects in 40 CFR Part 63

Environmental protection,

Administrative practice and procedures,

Air pollution control, Hazardous

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substances, Incorporation by reference,

Intergovernmental relations, Reporting

and recordkeeping requirements.

Michael S. Regan,

Administrator.

For the reasons set forth in the

preamble, 40 CFR part 63 is amended as

follows:

PART 63—NATIONAL EMISSION

STANDARDS FOR HAZARDOUS AIR

POLLUTANTS FOR SOURCE

CATEGORIES

1. The authority citation for part 63

continues to read as follows:

Authority: 42 U.S.C. 7401 et seq.

Subpart A—General Provisions

2. In § 63.14, paragraph (f)(1) is

amended by removing the text ‘‘tables 4

and 5 to subpart UUUUU’’ and adding,

in its place, the text ‘‘table 5 to subpart

UUUUU’’.

Subpart UUUUU—National Emission

Standards for Hazardous Air

Pollutants: Coal- and Oil-Fired Electric

Utility Steam Generating Units

3. Section 63.9991 is amended by

revising paragraph (a)(2) to read as

follows:

§ 63.9991 What emission limitations, work

practice standards, and operating limits

must I meet?

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(a) * * *

(2) Before July 6, 2027, you must meet

each operating limit in Table 4 to this

subpart that applies to your EGU.

*

*

*

*

*

4. Amend § 63.10000 by:

a. Revising paragraph (c)(1)(i) and

paragraph (c)(1)(i)(A);

b. Redesignating paragraph (c)(1)(i)(C)

as paragraph (c)(1)(i)(D);

c. Adding new paragraph (c)(1)(i)(C);

d. Revising paragraph (c)(1)(iv);

e. Adding new paragraphs (c)(1)(iv)(A)

through (C);

f. Revising paragraphs (c)(2)(i) and (ii);

g. Revising paragraph (d)(5)(i); and

h. Revising paragraph (m)

introductory text.

The revisions and additions read as

follows:

§ 63.10000 What are my general

requirements for complying with this

subpart?

*

*

*

*

*

(c) * * *

(1) * * *

(i) For a coal-fired or solid oil-derived

fuel-fired EGU or IGCC EGU, you may

conduct initial performance testing in

accordance with § 63.10005(h), to

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determine whether the EGU qualifies as

a low emitting EGU (LEE) for one or

more applicable emission limits, except

as otherwise provided in paragraphs

(c)(1)(i)(A) through (C) of this section:

(A) Except as provided in paragraph

(c)(1)(i)(D) of this section, you may not

pursue the LEE option if your coal-fired,

IGCC, or solid oil-derived fuel-fired

EGU is equipped with a main stack and

a bypass stack or bypass duct

configuration that allows the effluent to

bypass any pollutant control device.

*

*

*

*

*

(C) On or after July 6, 2027, you may

not pursue the LEE option for filterable

PM, total non-Hg HAP metals, or

individual non-Hg HAP metals for coalfired and solid oil-derived fuel-fired

EGUs.

*

*

*

*

*

(iv)(A) Before July 6, 2027, if your

coal-fired or solid oil derived fuel-fired

EGU does not qualify as a LEE for total

non-mercury HAP metals, individual

non-mercury HAP metals, or filterable

particulate matter (PM), you must

demonstrate compliance through an

initial performance test and you must

monitor continuous performance

through either use of a particulate

matter continuous parametric

monitoring system (PM CPMS), a PM

CEMS, or, for an existing EGU,

compliance performance testing

repeated quarterly.

(B) On and after July 6, 2027, you may

not pursue or continue to use the LEE

option for your coal-fired or solid oil

derived fuel-fired EGU for filterable PM

or for non-mercury HAP metals. You

must demonstrate compliance through

an initial performance test, and you

must monitor continuous performance

with the applicable filterable PM

emissions limit through the use of a PM

CEMS or HAP metals CMS.

(C) If your IGCC EGU does not qualify

as a LEE for total non-mercury HAP

metals, individual non-mercury HAP

metals, or filterable PM, you must

demonstrate compliance through an

initial performance test and you must

monitor continuous performance

through either use of a PM CPMS, a PM

CEMS, or, for an existing EGU,

compliance performance testing

repeated quarterly.

*

*

*

*

*

(2) * * *

(i) For an existing liquid oil-fired unit,

you may conduct the performance

testing in accordance with

§ 63.10005(h), to determine whether the

unit qualifies as a LEE for one or more

pollutants. For a qualifying LEE for Hg

emissions limits, you must conduct a

30-day performance test using Method

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30B at least once every 12 calendar

months to demonstrate continued LEE

status. For a qualifying LEE of any other

applicable emissions limits, you must

conduct a performance test at least once

every 36 calendar months to

demonstrate continued LEE status. On

or after July 6, 2027, you may not

pursue the LEE option for filterable PM,

total non-Hg HAP metals, or individual

non-Hg HAP metals.

(ii) Before July 6, 2027, if your liquid

oil-fired unit does not qualify as a LEE

for total HAP metals (including

mercury), individual metals (including

mercury), or filterable PM you must

demonstrate compliance through an

initial performance test and you must

monitor continuous performance

through either use of a PM CPMS, a PM

CEMS, or, for an existing EGU,

performance testing conducted

quarterly. On and after July 6, 2027, you

may not pursue or continue to use the

LEE option for your liquid oil-fired EGU

for filterable PM or for non-mercury

HAP metals. You must demonstrate

compliance through an initial

performance test, and you must monitor

continuous performance with the

applicable filterable PM emissions limit

through the use of a PM CEMS or HAP

metals CMS.

(d) * * *

(5) * * *

(i) Installation of the CMS or sorbent

trap monitoring system sampling probe

or other interface at a measurement

location relative to each affected process

unit such that the measurement is

representative of control of the exhaust

emissions (e.g., on or downstream of the

last control device). See § 63.10010(a)

for further details. For PM CPMS

installations (which with the exception

of IGCC units, are only applicable before

July 6, 2027), follow the procedures in

§ 63.10010(h).

*

*

*

*

*

(m) Should you choose to rely on

paragraph (2) of the definition of

‘‘startup’’ in § 63.10042 for your EGU

(only allowed before January 2, 2025),

on or before the date your EGU is

subject to this subpart, you must install,

verify, operate, maintain, and quality

assure each monitoring system

necessary for demonstrating compliance

with the work practice standards for PM

or non-mercury HAP metals controls

during startup periods and shutdown

periods required to comply with

§ 63.10020(e). On and after January 2,

2025 you will no longer be able to

choose paragraph (2) of the ‘‘startup’’

definition in § 63.10042.

*

*

*

*

*

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5. Amend § 63.10005 by revising

paragraphs (a)(1), (b) introductory text,

(c), (d)(2) introductory text, (h)

introductory text, and (h)(1)

introductory text to read as follows:

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§ 63.10005 What are my initial compliance

requirements and by what date must I

conduct them?

(a) * * *

(1) To demonstrate initial compliance

with an applicable emissions limit in

Table 1 or 2 to this subpart using stack

testing, the initial performance test

generally consists of three runs at

specified process operating conditions

using approved methods. Before July 6,

2027, if you are required to establish

operating limits (see paragraph (d) of

this section and Table 4 to this subpart),

you must collect all applicable

parametric data during the performance

test period. On and after July 6, 2027,

the requirements in Table 4 are not

applicable, with the exception of IGCC

units. Also, if you choose to comply

with an electrical output-based emission

limit, you must collect hourly electrical

load data during the test period.

*

*

*

*

*

(b) Performance testing requirements.

If you choose to use performance testing

to demonstrate initial compliance with

the applicable emissions limits in

Tables 1 and 2 to this subpart for your

EGUs, you must conduct the tests

according to 40 CFR 63.10007 and Table

5 to this subpart. Notwithstanding these

requirements, when Table 5 specifies

the use of isokinetic EPA test Method 5,

5I, 5D, 26A, or 29 for a stack test, if

concurrent measurement of the stack gas

flow rate or moisture content is needed

to convert the pollutant concentrations

to units of the standard, separate

determination of these parameters using

EPA test Method 2 or EPA test Method

4 is not necessary. Instead, the stack gas

flow rate and moisture content can be

determined from data that are collected

during the EPA test Method 5, 5I, 5D,

6, 26A, or 29 test ( e.g., pitot tube (delta

P) readings, moisture collected in the

impingers, etc.). For the purposes of the

initial compliance demonstration, you

may use test data and results from a

performance test conducted prior to the

date on which compliance is required as

specified in 40 CFR 63.9984, provided

that the following conditions are fully

met:

*

*

*

*

*

(c) Operating limits. In accordance

with § 63.10010 and Table 4 to this

subpart, you may be required to

establish operating limits using PM

CPMS and using site-specific

monitoring for certain liquid oil-fired

units as part of your initial compliance

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demonstration. With the exception of

IGCC units, on and after July 6, 2027,

you may not demonstrate compliance

with applicable filterable PM emissions

limits with the use of PM CPMS or

quarterly stack testing, you may only

use PM CEMS.

*

*

*

*

*

(d) * * *

(2) For affected coal-fired or solid oilderived fuel-fired EGUs that

demonstrate compliance with the

applicable emission limits for total nonmercury HAP metals, individual nonmercury HAP metals, total HAP metals,

individual HAP metals, or filterable PM

listed in Table 1 or 2 to this subpart

using initial performance testing and

continuous monitoring with PM CPMS

(with the exception of IGCC units, the

use of PM CPMS is only allowed before

July 6, 2027):

*

*

*

*

*

(h) Low emitting EGUs. The

provisions of this paragraph (h) apply to

pollutants with emissions limits from

new EGUs except Hg and to all

pollutants with emissions limits from

existing EGUs. With the exception of

IGCC units, on or after July 6, 2027 you

may not pursue the LEE option for

filterable PM. You may pursue this

compliance option unless prohibited

pursuant to § 63.10000(c)(1)(i).

(1) An EGU may qualify for low

emitting EGU (LEE) status for Hg, HCl,

HF, filterable PM, total non-Hg HAP

metals, or individual non-Hg HAP

metals (or total HAP metals or

individual HAP metals, for liquid oilfired EGUs) if you collect performance

test data that meet the requirements of

this paragraph (h) with the exception

that on or after July 6, 2027, you may

not pursue the LEE option for filterable

PM, total non-Hg HAP metals, or

individual non-Hg HAP metals for any

existing, new or reconstructed EGUs

(this does not apply to IGCC units), and

if those data demonstrate:

*

*

*

*

*

6. Amend § 63.10006 by revising

paragraph (a) to read as follows:

§ 63.10006 When must I conduct

subsequent performance tests or tune-ups?

(a) For liquid oil-fired, solid oilderived fuel-fired and coal-fired EGUs

and IGCC units using PM CPMS before

July 6, 2027 to monitor continuous

performance with an applicable

emission limit as provided for under

§ 63.10000(c), you must conduct all

applicable performance tests according

to Table 5 to this subpart and § 63.10007

at least every year. On or after July 6,

2027 you may not use PM CPMS to

demonstrate compliance for liquid oil-

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38565

fired, solid oil-derived fuel-fired and

coal-fired EGUs. This prohibition

against the use of PM CPMS does not

apply to IGCC units.

*

*

*

*

*

7. Amend § 63.1007 by revising

paragraphs (a)(3) and (c) to read as

follows:

§ 63.10007 What methods and other

procedures must I use for the performance

tests?

(a) * * *

(3) For establishing operating limits

with particulate matter continuous

parametric monitoring system (PM

CPMS) to demonstrate compliance with

a PM or non-Hg metals emissions limit

(the use of PM CPMS is only allowed

before July 6, 2027 with the exception

of IGCC units), operate the unit at

maximum normal operating load

conditions during the performance test

period. Maximum normal operating

load will be generally between 90 and

110 percent of design capacity but

should be representative of site specific

normal operations during each test run.

*

*

*

*

*

(c) If you choose the filterable PM

method to comply with the PM

emission limit and demonstrate

continuous performance using a PM

CPMS as provided for in § 63.10000(c),

you must also establish an operating

limit according to § 63.10011(b),

§ 63.10023, and Tables 4 and 6 to this

subpart. Should you desire to have

operating limits that correspond to loads

other than maximum normal operating

load, you must conduct testing at those

other loads to determine the additional

operating limits. On and after July 6,

2027, you must demonstrate continuous

compliance with the applicable

filterable PM emission standard through

the use of a PM CEMS (with the

exception that IGCC units are not

required to use PM CEMS and may

continue to use PM CPMS).

Alternatively, you may demonstrate

continuous compliance with the non-Hg

metals emission standard if you request

and receive approval for the use of a

HAP metals CMS under § 63.7(f).

*

*

*

*

*

8. Amend § 63.10010 by revising

paragraphs (a) introductory text, (h)

introductory text, (i) introductory text,

(j), and (l) introductory text to read as

follows:

§ 63.10010 What are my monitoring,

installation, operation, and maintenance

requirements?

(a) Flue gases from the affected units

under this subpart exhaust to the

atmosphere through a variety of

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different configurations, including but

not limited to individual stacks, a

common stack configuration or a main

stack plus a bypass stack. For the CEMS,

PM CPMS (which on or after July 6,

2027 you may not use PM CPMS for

filterable PM compliance

demonstrations unless it is for an IGCC

unit), and sorbent trap monitoring

systems used to provide data under this

subpart, the continuous monitoring

system installation requirements for

these exhaust configurations are as

follows:

*

*

*

*

*

(h) If you use a PM CPMS to

demonstrate continuous compliance

with an operating limit (only applicable

before July 6, 2027 unless it is for an

IGCC unit), you must install, calibrate,

maintain, and operate the PM CPMS

and record the output of the system as

specified in paragraphs (h)(1) through

(5) of this section.

*

*

*

*

*

(i) If you choose to comply with the

PM filterable emissions limit in lieu of

metal HAP limits (which on or after July

6, 2027 you may not use non-mercury

metal HAP limits for compliance

demonstrations for existing EGUs unless

you request and receive approval for the

use of a HAP metals CMS under

§ 63.7(f)), you may choose to install,

certify, operate, and maintain a PM

CEMS and record and report the output

of the PM CEMS as specified in

paragraphs (i)(1) through (8) of this

section. With the exception of IGCC

units, on or after July 6, 2027 owners/

operators of existing EGUs must comply

with filterable PM emissions limits in

Table 2 of this subpart and demonstrate

continuous compliance using a PM

CEMS unless you request and receive

approval for the use of a HAP metals

CMS under § 63.7(f). Compliance with

the applicable PM emissions limit in

Table 1 or 2 to this subpart is

determined on a 30-boiler operating day

rolling average basis.

*

*

*

*

*

(j) You may choose to comply with

the metal HAP emissions limits using

CMS approved in accordance with

§ 63.7(f) as an alternative to the

performance test method specified in

this rule. If approved to use a HAP

metals CMS, the compliance limit will

be expressed as a 30-boiler operating

day rolling average of the numerical

emissions limit value applicable for

your unit in tables 1 or 2. If approved,

you may choose to install, certify,

operate, and maintain a HAP metals

CMS and record the output of the HAP

metals CMS as specified in paragraphs

(j)(1) through (5) of this section.

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(1)(i) Install, calibrate, operate, and

maintain your HAP metals CMS

according to your CMS quality control

program, as described in § 63.8(d)(2).

The reportable measurement output

from the HAP metals CMS must be

expressed in units of the applicable

emissions limit ( e.g., lb/MMBtu, lb/

MWh) and in the form of a 30-boiler

operating day rolling average.

(ii) Operate and maintain your HAP

metals CMS according to the procedures

and criteria in your site specific

performance evaluation and quality

control program plan required in

§ 63.8(d).

(2) Collect HAP metals CMS hourly

average output data for all boiler

operating hours except as indicated in

section (j)(4) of this section.

(3) Calculate the arithmetic 30-boiler

operating day rolling average of all of

the hourly average HAP metals CMS

output data collected during all

nonexempt boiler operating hours data.

(4) You must collect data using the

HAP metals CMS at all times the

process unit is operating and at the

intervals specified in paragraph (a) of

this section, except for required

monitoring system quality assurance or

quality control activities, and any

scheduled maintenance as defined in

your site-specific monitoring plan.

(i) You must use all the data collected

during all boiler operating hours in

assessing the compliance with your

emission limit except:

(A) Any data collected during periods

of monitoring system malfunctions and

repairs associated with monitoring

system malfunctions. You must report

any monitoring system malfunctions as

deviations in your compliance reports

under 40 CFR 63.10031(c) or (g) (as

applicable);

(B) Any data collected during periods

when the monitoring system is out of

control as specified in your site-specific

monitoring plan, repairs associated with

periods when the monitoring system is

out of control, or required monitoring

system quality assurance or quality

control activities conducted during outof-control periods. You must report any

out of control periods as deviations in

your compliance reports under 40 CFR

63.10031(c) or (g) (as applicable);

(C) Any data recorded during required

monitoring system quality assurance or

quality control activities that

temporarily interrupt the measurement

of emissions ( e.g., calibrations, certain

audits, routine probe maintenance); and

(D) Any data recorded during periods

of startup or shutdown.

(ii) You must record and report the

results of HAP metals CMS system

performance audits, in accordance with

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40 CFR 63.10031(k). You must also

record and make available upon request

the dates and duration of periods when

the HAP metals CMS is out of control

to completion of the corrective actions

necessary to return the HAP metals CMS

to operation consistent with your sitespecific performance evaluation and

quality control program plan.

*

*

*

*

*

(l) Should you choose to rely on

paragraph (2) of the definition of

‘‘startup’’ in § 63.10042 for your EGU

(only allowed before January 2, 2025),

you must install, verify, operate,

maintain, and quality assure each

monitoring system necessary for

demonstrating compliance with the PM

or non-mercury metals work practice

standards required to comply with

§ 63.10020(e). On and after January 2,

2025 you will no longer be able to

choose paragraph (2) of the ‘‘startup’’

definition in § 63.10042 for your EGU.

*

*

*

*

*

9. Amend § 63.10011 by revising

paragraphs (b), (g)(3), and (4)

introductory text to read as follows:

§ 63.10011 How do I demonstrate initial

compliance with the emissions limits and

work practice standards?

*

*

*

*

*

(b) If you are subject to an operating

limit in Table 4 to this subpart, you

demonstrate initial compliance with

HAP metals or filterable PM emission

limit(s) through performance stack tests

and you elect to use a PM CPMS to

demonstrate continuous performance

(with the exception of existing IGCC

units, on or after July 6, 2027 you may

not use PM CPMS for compliance

demonstrations with the applicable

filterable PM limits and the Table 4 p.m.

CPMS operating limits do not apply), or

if, for an IGCC unit, and you use

quarterly stack testing for HCl and HF

plus site-specific parameter monitoring

to demonstrate continuous performance,

you must also establish a site-specific

operating limit, in accordance with

§ 63.10007 and Table 6 to this subpart.

You may use only the parametric data

recorded during successful performance

tests (i.e., tests that demonstrate

compliance with the applicable

emissions limits) to establish an

operating limit. On or after July 6, 2027

you may not use PM CPMS for

compliance demonstrations with the

applicable filterable PM limits and the

Table 6 procedures for establishing PM

CPMS operating limits do not apply

unless it is an IGCC unit.

*

*

*

*

*

(g) * * *

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Where:

Hpv is the hourly parameter value for hour

i and n is the number of valid hourly

parameter values collected over 30 boiler

operating days.

khammond on DSKJM1Z7X2PROD with RULES4

*

*

*

*

*

(i) Before January 2, 2025, if you are

relying on paragraph 2 of the definition

of startup in 40 CFR 63.10042, you must

provide reports concerning activities

and periods of startup and shutdown

that occur on or prior to January 1, 2024,

in accordance with 40 CFR

63.10031(c)(5), in your semiannual

compliance report. For startup and

shutdown incidents that occur on and

after January 1, 2024, you must provide

the applicable information referenced in

40 CFR 63.10031(c)(5)(ii) and 40 CFR

63.10020(e) quarterly, in PDF files, in

accordance with 40 CFR 63.10031(i). On

or after January 2, 2025 you may not use

paragraph 2 of the definition of startup

in 40 CFR 63.10042.

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and (e)(3)(i) introductory text to read as

follows:

§ 63.10020 How do I monitor and collect

data to demonstrate continuous

compliance?

*

*

*

*

*

(e) Additional requirements during

startup periods or shutdown periods if

you choose to rely on paragraph (2) of

the definition of ‘‘startup’’ in § 63.10042

for your EGU (only allowed before

January 2, 2025).

*

*

*

*

*

(3) * * *

(i) Except for an EGU that uses PM

CEMS or PM CPMS to demonstrate

compliance with the PM emissions

limit, or that has LEE status for filterable

PM or total non-Hg HAP metals for nonliquid oil-fired EGUs (or HAP metals

emissions for liquid oil-fired EGUs), or

individual non-mercury metals CMS

(except that unless it is for an IGCC unit,

on or after July 6, 2027 you may not use

PM CPMS for compliance

demonstrations with the applicable

filterable PM emissions limits, and you

may not purse or continue to use the

LEE option for filterable PM, total nonHg HAP metals, or individual non-Hg

HAP metals), you must:

*

*

*

*

*

12. Section 63.10022 is amended by

revising paragraphs (a)(2) and (3) to read

as follows:

§ 63.10022 How do I demonstrate

continuous compliance under the

emissions averaging provision?

(a) * * *

(2) For each existing unit participating

in the emissions averaging option that is

equipped with PM CPMS, maintain the

average parameter value at or below the

operating limit established during the

most recent performance test. On or

after July 6, 2027 you may not use PM

CPMS for filterable PM compliance

demonstrations unless it is for an IGCC

unit;

(3) For each existing unit participating

in the emissions averaging option

venting to a common stack

configuration containing affected units

from other subcategories, maintain the

appropriate operating limit for each unit

as specified in Table 4 to this subpart

that applies. Since on or after July 6,

2027 you may not use PM CPMS, unless

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11. Section 63.10021 is amended by

revising paragraphs (c) introductory text

and (i) to read as follows:

§ 63.10021 How do I demonstrate

continuous compliance with the emission

limitations, operating limits, and work

practice standards?

*

*

*

*

*

(c) If you use PM CPMS data (only

allowed before July 6, 2027 unless it is

for an IGCC unit) to measure

compliance with an operating limit in

Table 4 to this subpart, you must record

the PM CPMS output data for all periods

when the process is operating and the

PM CPMS is not out-of-control. You

must demonstrate continuous

compliance by using all quality-assured

hourly average data collected by the PM

CPMS for all operating hours to

calculate the arithmetic average

operating parameter in units of the

operating limit ( e.g., milliamps, PM

concentration, raw data signal) on a 30

operating day rolling average basis,

updated at the end of each new boiler

operating day. Use Equation 9 to

determine the 30 boiler operating day

average. On or after July 6, 2027 you

may not use PM CPMS for compliance

demonstrations unless it is for an IGCC

unit.

it is for an IGCC unit, for compliance

demonstrations with the applicable

filterable PM limits, the Table 4 p.m.

CPMS operating limits do not apply.

*

*

*

*

*

13. Section 63.10023 is amended by

adding introductory text to the section

to read as follows:

§ 63.10023 How do I establish my PM

CPMS operating limit and determine

compliance with it?

The provisions of this section

§ 63.10023 are only applicable before

July 6, 2027 unless it is for an IGCC

unit. On or after July 6, 2027 you may

not use PM CPMS, unless it is an IGCC

unit, for demonstrating compliance with

the filterable PM emissions limits of this

subpart.

*

*

*

*

*

14. Section 63.10030 is amended by

revising paragraphs (e)(3), (8)

introductory text, and (8)(i) introductory

text to read as follows:

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ER07MY24.079<•GPH>

(3) You must report the emissions

data recorded during startup and

shutdown. If you are relying on

paragraph (2) of the definition of startup

in 40 CFR 63.10042 (only allowed

before January 2, 2025), then for startup

and shutdown incidents that occur on

or prior to December 31, 2023, you must

also report the applicable

supplementary information in 40 CFR

63.10031(c)(5) in the semiannual

compliance report. For startup and

shutdown incidents that occur on or

after January 1, 2024, you must provide

the applicable information in 40 CFR

63.10031(c)(5)(ii) and 40 CFR

63.10020(e) quarterly, in PDF files, in

accordance with 40 CFR 63.10031(i).

(4) If you choose to use paragraph (2)

of the definition of ‘‘startup’’ in

§ 63.10042 (only allowed before January

2, 2025), and you find that you are

unable to safely engage and operate your

particulate matter (PM) control(s) within

1 hour of first firing of coal, residual oil,

or solid oil-derived fuel, you may

choose to rely on paragraph (1) of

definition of ‘‘startup’’ in § 63.10042 or

you may submit a request to use an

alternative non-opacity emissions

standard, as described below.

*

*

*

*

*

10. Section 63.10020 is amended by

revising paragraphs (e) introductory text

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§ 63.10030 What notifications must I

submit and when?

*

*

*

*

*

(e) * * *

(3) Identification of whether you plan

to demonstrate compliance with each

applicable emission limit through

performance testing; fuel moisture

analyses; performance testing with

operating limits ( e.g., use of PM CPMS—

which on or after July 6, 2027—you may

not use for filterable PM compliance

demonstrations, unless it is for an IGCC

unit); CEMS; or a sorbent trap

monitoring system.

*

*

*

*

*

(8) Identification of whether you plan

to rely on paragraph (1) or (2) of the

definition of ‘‘startup’’ in § 63.10042. On

or after January 2, 2025 you may not use

paragraph (2) of the definition of startup

in § 63.10042.

(i) Before January 2, 2025 should you

choose to rely on paragraph (2) of the

definition of ‘‘startup’’ in § 63.10042 for

your EGU, you shall include a report

that identifies:

*

*

*

*

*

15. Section 63.10031 is amended by

revising paragraphs (a)(4), (c)(5)

introductory text, (f)(2), (i), and (k) to

read as follows:

khammond on DSKJM1Z7X2PROD with RULES4

§ 63.10031 What reports must I submit and

when?

(a) * * *

(4) Before July 6, 2027, if you elect to

demonstrate continuous compliance

using a PM CPMS, you must meet the

electronic reporting requirements of

appendix D to this subpart. Except for

IGCC units, on or after July 6, 2027 you

may not use PM CPMS for compliance

demonstrations. Electronic reporting of

the hourly PM CPMS output shall begin

with the later of the first operating hour

on or after January 1, 2024; or the first

operating hour after completion of the

initial performance stack test that

establishes the operating limit for the

PM CPMS.

(c) * * *

(5) Should you choose to rely on

paragraph (2) of the definition of

‘‘startup’’ in § 63.10042 for your EGU

(only allowed before January 2, 2025),

for each instance of startup or shutdown

you shall:

*

*

*

*

*

(f) * * *

(2) If, for a particular EGU or a group

of EGUs serving a common stack, you

have elected to demonstrate compliance

using a PM CEMS, an approved HAP

metals CMS, or a PM CPMS (on or after

July 6, 2027 you may not use PM CPMS

for compliance demonstrations, unless

it is for an IGCC unit), you must submit

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quarterly PDF reports in accordance

with paragraph (f)(6) of this section,

which include all of the 30-boiler

operating day rolling average emission

rates derived from the CEMS data or the

30-boiler operating day rolling average

responses derived from the PM CPMS

data (as applicable). The quarterly

reports are due within 60 days after the

reporting periods ending on March 31st,

June 30th, September 30th, and

December 31st. Submission of these

quarterly reports in PDF files shall end

with the report that covers the fourth

calendar quarter of 2023. Beginning

with the first calendar quarter of 2024,

the compliance averages shall no longer

be reported separately, but shall be

incorporated into the quarterly

compliance reports described in

paragraph (g) of this section. In addition

to the compliance averages for PM

CEMS, PM CPMS, and/or HAP metals

CMS, the quarterly compliance reports

described in paragraph (g) of this

section must also include the 30(or, if applicable 90-) boiler operating

day rolling average emission rates for

Hg, HCl, HF, and/or SO , if you have

elected to (or are required to)

continuously monitor these pollutants.

Further, if your EGU or common stack

is in an averaging plan, your quarterly

compliance reports must identify all of

the EGUs or common stacks in the plan

and must include all of the 30- (or

90-) group boiler operating day rolling

weighted average emission rates

(WAERs) for the averaging group.

*

*

*

*

*

(i) If you have elected to use

paragraph (2) of the definition of

‘‘startup’’ in 40 CFR 63.10042 (only

allowed before January 2, 2025), then,

for startup and shutdown incidents that

occur on or prior to December 31, 2023,

you must include the information in 40

CFR 63.10031(c)(5) in the semiannual

compliance report, in a PDF file. If you

have elected to use paragraph (2) of the

definition of ‘‘startup’’ in 40 CFR

63.10042, then, for startup and

shutdown event(s) that occur on or after

January 1, 2024, you must use the

ECMPS Client Tool to submit the

information in 40 CFR 63.10031(c)(5)

and 40 CFR 63.10020(e) along with each

quarterly compliance report, in a PDF

file, starting with a report for the first

calendar quarter of 2024. The applicable

data elements in paragraphs (f)(6)(i)

through (xii) of this section must be

entered into ECMPS with each startup

and shutdown report.

*

*

*

*

*

(k) If you elect to demonstrate

compliance using a PM CPMS (on or

after July 6, 2027 you may not

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demonstrate compliance with filterable

PM emissions limits using a PM CPMS,

unless it is for an IGCC unit) or an

approved HAP metals CMS, you must

submit quarterly reports of your QA/QC

activities ( e.g., calibration checks,

performance audits), in a PDF file,

beginning with a report for the first

quarter of 2024, if the PM CPMS or HAP

metals CMS is used for the compliance

demonstration in that quarter.

Otherwise, submit a report for the first

calendar quarter in which the PM CPMS

or HAP metals CMS is used to

demonstrate compliance. These reports

are due no later than 60 days after the

end of each calendar quarter. The

applicable data elements in paragraph

(f)(6)(i) through (xii) of this section must

be entered into ECMPS with the PDF

report.

16. Section 63.10032 is amended by

revising paragraphs (a) introductory text

and (f)(2) introductory text to read as

follows:

§ 63.10032

What records must I keep?

(a) You must keep records according

to paragraphs (a)(1) and (2) of this

section. If you are required to (or elect

to) continuously monitor Hg and/or HCl

and/or HF and/or PM emissions, or if

you elect to use a PM CPMS (unless it

is for an IGCC unit, you may only use

PM CPMS before July 6, 2027), you must

keep the records required under

appendix A and/or appendix B and/or

appendix C and/or appendix D to this

subpart. If you elect to conduct periodic

(e.g., quarterly or annual) performance

stack tests, then, for each test completed

on or after January 1, 2024, you must

keep records of the applicable data

elements under 40 CFR 63.7(g). You

must also keep records of all data

elements and other information in

appendix E to this subpart that apply to

your compliance strategy.

*

*

*

*

*

(f) * * *

(2) Should you choose to rely on

paragraph (2) of the definition of

‘‘startup’’ in § 63.10042 for your EGU

(on or after January 2, 2025 you may not

use paragraph (2) of the definition of

startup in § 63.10042), you must keep

records of:

*

*

*

*

*

17. Section 63.10042 is amended by

revising the definition ‘‘Startup’’ to read

as follows:

§ 63.10042

subpart?

What definitions apply to this

*

*

*

*

*

Startup means:

(1) The first-ever firing of fuel in a

boiler for the purpose of producing

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electricity, or the firing of fuel in a

boiler after a shutdown event for any

purpose. Startup ends when any of the

steam from the boiler is used to generate

electricity for sale over the grid or for

any other purpose (including on-site

use). Any fraction of an hour in which

startup occurs constitutes a full hour of

startup.

(2) Alternatively, prior to January 2,

2025, the period in which operation of

an EGU is initiated for any purpose.

Startup begins with either the firing of

any fuel in an EGU for the purpose of

If your EGU is in this subcategory . . .

For the following

pollutants . . .

1. Coal-fired unit not low rank virgin coal

a. Filterable particulate matter

(PM).

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

2. Coal-fired units low rank virgin coal ...

khammond on DSKJM1Z7X2PROD with RULES4

producing electricity or useful thermal

energy (such as heat or steam) for

industrial, commercial, heating, or

cooling purposes (other than the firstever firing of fuel in a boiler following

construction of the boiler) or for any

other purpose after a shutdown event.

Startup ends 4 hours after the EGU

generates electricity that is sold or used

for any other purpose (including on site

use), or 4 hours after the EGU makes

useful thermal energy (such as heat or

steam) for industrial, commercial,

heating, or cooling purposes (16 U.S.C.

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

a. Filterable particulate matter

(PM).

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

OR

Sulfur dioxide

(SO ) .

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You must meet the

following emission

limits and work

practice standards

. . .

9.0E–2 lb•MWh

...

796(18)(A) and 18 CFR 292.202(c)),

whichever is earlier. Any fraction of an

hour in which startup occurs constitutes

a full hour of startup.

*

*

*

*

*

18. Revise table 1 to subpart UUUUU

of part 63 to read as follows:

Table 1 to Subpart UUUUU of Part 63—

Emission Limits for New or

Reconstructed EGUs

As stated in § 63.9991, you must

comply with the following applicable

emission limits:

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

Collect a minimum catch of 6.0 milligrams or a minimum

sample volume of 4 dscm per run.

OR

6.0E–2 lb•GWh .....

Collect a minimum of 4 dscm per run.

OR

...............................

Collect a minimum of 3 dscm per run.

8.0E–3 lb•GWh.

3.0E–3 lb•GWh.

6.0E–4 lb•GWh.

4.0E–4 lb•GWh.

7.0E–3 lb•GWh.

2.0E–3 lb•GWh.

2.0E–2 lb•GWh.

4.0E–3 lb•GWh.

4.0E–2 lb•GWh.

5.0E–2 lb•GWh.

1.0E–2 lb•MWh .....

38569

For Method 26A at appendix A–8 to part 60 of this chapter, collect a minimum of 3 dscm per run. For ASTM

D6348–03(Reapproved 2010) or Method 320 at appendix A to part 63 of this chapter, sample for a minimum of 1 hour.

1.0 lb•MWh ............

SO CEMS.

3.0E–3 lb•GWh .....

9.0E–2 lb•MWh ...

Hg CEMS or sorbent trap monitoring system only.

Collect a minimum catch of 6.0 milligrams or a minimum

sample volume of 4 dscm per run.

OR

6.0E–2 lb•GWh .....

Collect a minimum of 4 dscm per run.

OR

...............................

Collect a minimum of 3 dscm per run.

8.0E–3 lb•GWh.

3.0E–3 lb•GWh.

6.0E–4 lb•GWh.

4.0E–4 lb•GWh.

7.0E–3 lb•GWh.

2.0E–3 lb•GWh.

2.0E–2 lb•GWh.

4.0E–3 lb•GWh.

4.0E–2 lb•GWh.

5.0E–2 lb•GWh.

1.0E–2 lb•MWh .....

1.0 lb•MWh ............

Fmt 4701

Sfmt 4700

For Method 26A, collect a minimum of 3 dscm per run For

ASTM D6348–03(Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

SO CEMS.

E:\FR\FM\07MYR4.SGM

07MYR4

120a

38570

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

c. Mercury (Hg) .....

3. IGCC unit ...........................................

khammond on DSKJM1Z7X2PROD with RULES4

4. Liquid oil-fired unit—continental (excluding limited-use liquid oil-fired subcategory units).

5. Liquid oil-fired unit—non-continental

(excluding limited-use liquid oil-fired

subcategory units).

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

a. Filterable particulate matter

(PM).

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

a. Filterable particulate matter

(PM).

OR

Total HAP metals ..

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

Mercury (Hg) .........

You must meet the

following emission

limits and work

practice standards

. . .

Before July 8,

2024: 4.0E–2 lb•

GWh; On or after

July 8, 2024:

1.3E–2 lb•GWh.

7.0E–2 lb•MWh

9.0E–2 lb•MWh .

Collect a minimum catch of 3.0 milligrams or a minimum

sample volume of 2 dscm per run.

Collect a minimum of 1 dscm per run.

OR

...............................

Collect a minimum of 2 dscm per run.

2.0E–2 lb•GWh.

2.0E–2 lb•GWh.

1.0E–3 lb•GWh.

2.0E–3 lb•GWh.

4.0E–2 lb•GWh.

4.0E–3 lb•GWh.

9.0E–3 lb•GWh.

2.0E–2 lb•GWh.

7.0E–2 lb•GWh.

3.0E–1 lb•GWh.

2.0E–3 lb•MWh .....

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26 at appendix A–8 to part 60 of this chapter,

collect a minimum of 120 liters per run.

For ASTM D6348–03(Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

4.0E–1 lb•MWh .....

SO CEMS.

3.0E–3 lb•GWh .....

3.0E–1 lb•MWh ...

Hg CEMS or sorbent trap monitoring system only.

Collect a minimum of 1 dscm per run.

OR

2.0E–4 lb•MWh .....

OR

...............................

1.0E–2 lb•GWh.

3.0E–3 lb•GWh.

5.0E–4 lb•GWh.

2.0E–4 lb•GWh.

2.0E–2 lb•GWh.

3.0E–2 lb•GWh.

8.0E–3 lb•GWh.

2.0E–2 lb•GWh.

9.0E–2 lb•GWh.

2.0E–2 lb•GWh.

1.0E–4 lb•GWh .....

4.0E–4 lb•MWh .....

c. Hydrogen fluoride (HF).

4.0E–4 lb•MWh .....

a. Filterable particulate matter

(PM).

OR

Total HAP metals ..

OR

Individual HAP

metals:.

Antimony (Sb) .......

2.0E–1 lb•MWh

Frm 00064

Hg CEMS or sorbent trap monitoring system only.

OR

4.0E–1 lb•GWh .....

b. Hydrogen chloride (HCl).

PO 00000

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

...

OR

7.0E–3 lb•MWh .....

OR

...............................

Collect a minimum of 2 dscm per run.

Collect a minimum of 2 dscm per run.

For Method 30B at appendix A–8 to part 60 of this chapter sample volume determination (Section 8.2.4), the estimated Hg concentration should nominally be < / the

standard.

For Method 26A, collect a minimum of 3 dscm per run.

For ASTM D6348–03(Reapproved 2010) or Method

320, sample for a minimum of 1 hour.

For Method 26A, collect a minimum of 3 dscm per run.

For ASTM D6348–03 (Reapproved 2010) or Method

320, sample for a minimum of 1 hour.

Collect a minimum of 1 dscm per run.

Collect a minimum of 1 dscm per run.

Collect a minimum of 3 dscm per run.

8.0E–3 lb•GWh.

Fmt 4701

Sfmt 4700

E:\FR\FM\07MYR4.SGM

07MYR4

121a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

6. Solid oil-derived fuel-fired unit ...........

For the following

pollutants . . .

You must meet the

following emission

limits and work

practice standards

. . .

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

Mercury (Hg) .........

6.0E–2 lb•GWh.

2.0E–3 lb•GWh.

2.0E–3 lb•GWh.

2.0E–2 lb•GWh.

3.0E–1 lb•GWh.

3.0E–2 lb•GWh.

1.0E–1 lb•GWh.

4.1E0 lb•GWh.

2.0E–2 lb•GWh.

4.0E–4 lb•GWh .....

b. Hydrogen chloride (HCl).

2.0E–3 lb•MWh .....

c. Hydrogen fluoride (HF).

5.0E–4 lb•MWh .....

a. Filterable particulate matter

(PM).

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

3.0E–2 lb•MWh

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

...

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 30B sample volume determination (Section

8.2.4), the estimated Hg concentration should nominally

be < / the standard.

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26, collect a minimum of 120 liters per run. For

ASTM D6348–03 (Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

For Method 26A, collect a minimum of 3 dscm per run.

For ASTM D6348–03 (Reapproved 2010) or Method

320, sample for a minimum of 1 hour.

Collect a minimum of 1 dscm per run.

OR

6.0E–1 lb•GWh .....

Collect a minimum of 1 dscm per run.

OR

...............................

Collect a minimum of 3 dscm per run.

8.0E–3 lb•GWh.

3.0E–3 lb•GWh.

6.0E–4 lb•GWh.

7.0E–4 lb•GWh.

6.0E–3 lb•GWh.

2.0E–3 lb•GWh.

2.0E–2 lb•GWh.

7.0E–3 lb•GWh.

4.0E–2 lb•GWh.

6.0E–3 lb•GWh.

4.0E–4 lb•MWh .....

38571

For Method 26A, collect a minimum of 3 dscm per run.

For ASTM D6348–03 (Reapproved 2010) or Method

320, sample for a minimum of 1 hour.

1.0 lb•MWh ............

SO CEMS.

2.0E–3 lb•GWh .....

Hg CEMS or Sorbent trap monitoring system only.

Gross output.

Incorporated by reference, see § 63.14.

You may not use the alternate SO limit if your EGU does not have some form of FGD system (or, in the case of IGCC EGUs, some other

acid gas removal system either upstream or downstream of the combined cycle block) and SO CEMS installed.

Duct burners on syngas; gross output.

Duct burners on natural gas; gross output.

khammond on DSKJM1Z7X2PROD with RULES4

19. Revise table 2 to subpart UUUUU

of part 63 to read as follows:

If your EGU is in this subcategory . . .

1. Coal-fired unit not low rank virgin coal

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

Table 2 to Subpart UUUUU of Part 63—

Emission Limits for Existing EGUs

As stated in § 63.9991, you must

comply with the following applicable

emission limits:

For the following

pollutants . . .

a. Filterable particulate matter

(PM).

PO 00000

Frm 00065

You must meet the

following emission

limits and work

practice standards

. . .

Before July 6,

2027: 3.0E–2 lb•

MMBtu or 3.0E–

1 lb•MWh .

Fmt 4701

Sfmt 4700

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

Before July 6, 2027: Collect a minimum of 1 dscm per

run.

E:\FR\FM\07MYR4.SGM

07MYR4

122a

38572

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

On or after July 6,

2027: 1.0E–2 lb•

MMBtu or 1.0E–

1 lb•MWh .

OR

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

khammond on DSKJM1Z7X2PROD with RULES4

Chromium (Cr) ......

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

PO 00000

You must meet the

following emission

limits and work

practice standards

. . .

Frm 00066

Before July 6,

2027: 5.0E–5 lb•

MMBtu or 5.0E–

1 lb•GWh.

On or after July 6,

2027: 1.7E–5 lb•

MMBtu or 1.7E–

1 lb•GWh.

OR

...............................

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

On or after July 6, 2027: Collect a minimum catch of 6.0

milligrams or a minimum sample volume of 4 dscm per

run.

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 3 dscm per run.

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Before July 6,

2027: 1.1E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 3.7E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 2.0E–1 lb•

TBtu or 2.0E–3

lb•GWh.

On or after July 6,

2027: 6.7E–2 lb•

TBtu or 6.7E–4

lb•GWh.

Before July 6,

2027: 3.0E–1 lb•

TBtu or 3.0E–3

lb•GWh.

On or after July 6,

2027: 1.0E–1 lb•

TBtu or 1.0E–3

lb•GWh.

Before July 6,

2027: 2.8E0 lb•

TBtu or 3.0E–2

lb•GWh.

On or after July 6,

2027: 9.3E–1 lb•

TBtu or 1.0E–2

lb•GWh.

Fmt 4701

Sfmt 4700

E:\FR\FM\07MYR4.SGM

07MYR4

123a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

khammond on DSKJM1Z7X2PROD with RULES4

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

2. Coal-fired unit low rank virgin coal ....

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

a. Filterable particulate matter

(PM).

PO 00000

Frm 00067

You must meet the

following emission

limits and work

practice standards

. . .

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Before July 6,

2027: 1.2E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 4.0E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 4.0E0 lb•

TBtu or 5.0E–2

lb•GWh.

On or after July 6,

2027: 1.3E0 lb•

TBtu or 1.7E–2

lb•GWh.

Before July 6,

2027: 3.5E0 lb•

TBtu or 4.0E–2

lb•GWh.

On or after July 6,

2027: 1.2E0 lb•

TBtu or 1.3E–2

lb•GWh.

Before July 6,

2027: 5.0E0 lb•

TBtu or 6.0E–2

lb•GWh.

On or after July 6,

2027: 1.7E0 lb•

TBtu or 2.0E–2

lb•GWh.

2.0E–3 lb•MMBtu

or 2.0E–2 lb•

MWh.

38573

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 26A at appendix A–8 to part 60 of this chapter, collect a minimum of 0.75 dscm per run; for Method

26, collect a minimum of 120 liters per run. For ASTM

D6348–03 (Reapproved 2010) or Method 320 at appendix A to part 63 of this chapter, sample for a minimum of 1 hour.

2.0E–1 lb•MMBtu

SO CEMS.

or 1.5E0 lb•MWh.

1.2E0 lb•TBtu or

LEE Testing for 30 days with a sampling period consistent

1.3E–2 lb•GWh.

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B at appendix A–8 to part 60 of

this chapter run or Hg CEMS or sorbent trap monitoring

system only.

OR

1.0E0 lb•TBtu or

LEE Testing for 90 days with a sampling period consistent

1.1E–2 lb•GWh.

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B run or Hg CEMS or sorbent

trap monitoring system only.

Before July 6,

Before July 6, 2027: Collect a minimum of 1 dscm per

2027: 3.0E–2 lb•

run.

MMBtu or 3.0E–

On or after July 6, 2027: Collect a minimum catch of 6.0

1 lb•MWh .

milligrams or a minimum sample volume of 4 dscm per

On or after July 6,

run.

2027: 1.0E–2 lb•

MMBtu or 1.0E–

1 lb•MWh .

Fmt 4701

Sfmt 4700

E:\FR\FM\07MYR4.SGM

07MYR4

124a

38574

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

You must meet the

following emission

limits and work

practice standards

. . .

OR

OR

Total non-Hg HAP

metals.

Before July 6,

2027: 5.0E–5 lb•

MMBtu or 5.0E–

1 lb•GWh.

On or after July 6,

2027: 1.7E–5 lb•

MMBtu or 1.7E–

1 lb•GWh.

OR

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

khammond on DSKJM1Z7X2PROD with RULES4

Chromium (Cr) ......

Cobalt (Co) ...........

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

PO 00000

Frm 00068

...............................

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 3 dscm per run.

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Before July 6,

2027: 1.1E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 3.7E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 2.0E–1 lb•

TBtu or 2.0E–3

lb•GWh.

On or after July 6,

2027: 6.7E–2 lb•

TBtu or 6.7E–4

lb•GWh.

Before July 6,

2027: 3.0E–1 lb•

TBtu or 3.0E–3

lb•GWh.

On or after July 6,

2027: 1.0E–1 lb•

TBtu or 1.0E–3

lb•GWh.

Before July 6,

2027: 2.8E0 lb•

TBtu or 3.0E–2

lb•GWh.

On or after July 6,

2027: 9.3E–1 lb•

TBtu or 1.0E–2

lb•GWh.

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Fmt 4701

Sfmt 4700

E:\FR\FM\07MYR4.SGM

07MYR4

125a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

3. IGCC unit ...........................................

a. Filterable particulate matter

(PM).

khammond on DSKJM1Z7X2PROD with RULES4

OR

Total non-Hg HAP

metals.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

PO 00000

Frm 00069

You must meet the

following emission

limits and work

practice standards

. . .

Before July 6,

2027: 1.2E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 4.0E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 4.0E0 lb•

TBtu or 5.0E–2

lb•GWh.

On or after July 6,

2027: 1.3E0 lb•

TBtu or 1.7E–2

lb•GWh.

Before July 6,

2027: 3.5E0 lb•

TBtu or 4.0E–2

lb•GWh.

On or after July 6,

2027: 1.2E0 lb•

TBtu or 1.3E–2

lb•GWh.

Before July 6,

2027: 5.0E0 lb•

TBtu or 6.0E–2

lb•GWh.

On or after July 6,

2027: 1.7E0 lb•

TBtu or 2.0E–2

lb•GWh.

2.0E–3 lb•MMBtu

or 2.0E–2 lb•

MWh.

OR

2.0E–1 lb•MMBtu

or 1.5E0 lb•MWh.

Before July 6,

2027: 4.0E0 lb•

TBtu or 4.0E–2

lb•GWh.

On or after July 6,

2027: 1.2E0 lb•

TBtu or 1.3E–2

lb•GWh.

4.0E–2 lb•MMBtu

or 4.0E–1 lb•

MWh .

OR

6.0E–5 lb•MMBtu

or 5.0E–1 lb•

GWh.

OR

...............................

38575

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 26A, collect a minimum of 0.75 dscm per run;

for Method 26 at appendix A–8 to part 60 of this chapter, collect a minimum of 120 liters per run. For ASTM

D6348–03 (Reapproved 2010) or Method 320, sample

for a minimum of 1 hour.

SO CEMS.

LEE Testing for 30 days with a sampling period consistent

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B run or Hg CEMS or sorbent

trap monitoring system only.

Before July 6, 2027: Collect a minimum of 1 dscm per

run.

On or after July 6, 2027: Collect a minimum catch of 3.0

milligrams or a minimum sample volume of 2 dscm per

run.

Collect a minimum of 1 dscm per run.

Collect a minimum of 2 dscm per run.

1.4E0 lb•TBtu or

2.0E–2 lb•GWh.

1.5E0 lb•TBtu or

2.0E–2 lb•GWh.

1.0E–1 lb•TBtu or

1.0E–3 lb•GWh.

1.5E–1 lb•TBtu or

2.0E–3 lb•GWh.

2.9E0 lb•TBtu or

3.0E–2 lb•GWh.

Fmt 4701

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E:\FR\FM\07MYR4.SGM

07MYR4

126a

38576

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

4. Liquid oil-fired unit—continental (excluding limited-use liquid oil-fired subcategory units).

2.5E0 lb•TBtu or

3.0E–2 lb•GWh.

a. Filterable particulate matter

(PM).

OR

3.0E–2 lb•MMBtu

or 3.0E–1 lb•

MWh .

OR

Total HAP metals ..

8.0E–4 lb•MMBtu

or 8.0E–3 lb•

MWh.

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

khammond on DSKJM1Z7X2PROD with RULES4

Mercury (Hg) .........

VerDate Sep<11>2014

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1.2E0 lb•TBtu or

2.0E–2 lb•GWh.

1.9E+2 lb•TBtu or

1.8E0 lb•GWh.

2.5E0 lb•TBtu or

3.0E–2 lb•GWh.

6.5E0 lb•TBtu or

7.0E–2 lb•GWh.

2.2E+1 lb•TBtu or

3.0E–1 lb•GWh.

5.0E–4 lb•MMBtu

or 5.0E–3 lb•

MWh.

c. Mercury (Hg) .....

OR

5. Liquid oil-fired unit—non-continental

(excluding limited-use liquid oil-fired

subcategory units).

You must meet the

following emission

limits and work

practice standards

. . .

...............................

1.3E+1 lb•TBtu or

2.0E–1 lb•GWh.

2.8E0 lb•TBtu or

3.0E–2 lb•GWh.

2.0E–1 lb•TBtu or

2.0E–3 lb•GWh.

3.0E–1 lb•TBtu or

2.0E–3 lb•GWh.

5.5E0 lb•TBtu or

6.0E–2 lb•GWh.

2.1E+1 lb•TBtu or

3.0E–1 lb•GWh.

8.1E0 lb•TBtu or

8.0E–2 lb•GWh.

2.2E+1 lb•TBtu or

3.0E–1 lb•GWh.

1.1E+2 lb•TBtu or

1.1E0 lb•GWh.

3.3E0 lb•TBtu or

4.0E–2 lb•GWh.

2.0E–1 lb•TBtu or

2.0E–3 lb•GWh.

b. Hydrogen chloride (HCl).

2.0E–3 lb•MMBtu

or 1.0E–2 lb•

MWh.

c. Hydrogen fluoride (HF).

4.0E–4 lb•MMBtu

or 4.0E–3 lb•

MWh.

a. Filterable particulate matter

(PM).

3.0E–2 lb•MMBtu

or 3.0E–1 lb•

MWh .

PO 00000

Frm 00070

Fmt 4701

Sfmt 4700

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26, collect a minimum of 120 liters per run. For

ASTM D6348–03 (Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

LEE Testing for 30 days with a sampling period consistent

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B run or Hg CEMS or sorbent

trap monitoring system only.

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

For Method 30B sample volume determination (Section

8.2.4), the estimated Hg concentration should nominally

be < / the standard.

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26, collect a minimum of 120 liters per run. For

ASTM D6348–03 (Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26, collect a minimum of 120 liters per run. For

ASTM D6348–03 (Reapproved 2010) or Method 320,

sample for a minimum of 1 hour.

Collect a minimum of 1 dscm per run.

E:\FR\FM\07MYR4.SGM

07MYR4

127a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

You must meet the

following emission

limits and work

practice standards

. . .

OR

OR

Total HAP metals ..

6.0E–4 lb•MMBtu

or 7.0E–3 lb•

MWh.

OR

OR

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

Mercury (Hg) .........

6. Solid oil-derived fuel-fired unit ...........

2.0E–4 lb•MMBtu

or 2.0E–3 lb•

MWh.

c. Hydrogen fluoride (HF).

a. Filterable particulate matter

(PM).

6.0E–5 lb•MMBtu

or 5.0E–4 lb•

MWh.

8.0E–3 lb•MMBtu

or 9.0E–2 lb•

MWh .

OR

OR

Total non-Hg HAP

metals.

4.0E–5 lb•MMBtu

or 6.0E–1 lb•

GWh.

OR

khammond on DSKJM1Z7X2PROD with RULES4

Individual HAP

metals:.

Antimony (Sb) .......

Arsenic (As) ..........

16:50 May 06, 2024

Jkt 262001

2.2E0 lb•TBtu or

2.0E–2 lb•GWh.

4.3E0 lb•TBtu or

8.0E–2 lb•GWh.

6.0E–1 lb•TBtu or

3.0E–3 lb•GWh.

3.0E–1 lb•TBtu or

3.0E–3 lb•GWh.

3.1E+1 lb•TBtu or

3.0E–1 lb•GWh.

1.1E+2 lb•TBtu or

1.4E0 lb•GWh.

4.9E0 lb•TBtu or

8.0E–2 lb•GWh.

2.0E+1 lb•TBtu or

3.0E–1 lb•GWh.

4.7E+2 lb•TBtu or

4.1E0 lb•GWh.

9.8E0 lb•TBtu or

2.0E–1 lb•GWh.

4.0E–2 lb•TBtu or

4.0E–4 lb•GWh.

b. Hydrogen chloride (HCl).

OR

VerDate Sep<11>2014

...............................

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...............................

38577

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 2 dscm per run.

For Method 30B sample volume determination (Section

8.2.4), the estimated Hg concentration should nominally

be < / the standard.

For Method 26A, collect a minimum of 1 dscm per run; for

Method 26, collect a minimum of 120 liters per run. For

ASTM D6348–03 (Reapproved 2010) or Method 320,

sample for a minimum of 2 hours.

For Method 26A, collect a minimum of 3 dscm per run.

For ASTM D6348–03 (Reapproved 2010) or Method

320, sample for a minimum of 2 hours.

Before July 6, 2027: Collect a minimum of 1 dscm per

run.

On or after July 6, 2027: Collect a minimum catch of 6.0

milligrams or a minimum sample volume of 4 dscm per

run.

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 3 dscm per run.

8.0E–1 lb•TBtu or

7.0E–3 lb•GWh.

3.0E–1 lb•TBtu or

5.0E–3 lb•GWh.

Fmt 4701

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E:\FR\FM\07MYR4.SGM

07MYR4

128a

38578

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

Nickel (Ni) .............

Selenium (Se) .......

b. Hydrogen chloride (HCl).

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

7. Eastern Bituminous Coal Refuse

(EBCR)-fired unit.

a. Filterable particulate matter

(PM).

OR

Total non-Hg HAP

metals.

OR

khammond on DSKJM1Z7X2PROD with RULES4

Individual HAP

metals:.

Antimony (Sb) .......

VerDate Sep<11>2014

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You must meet the

following emission

limits and work

practice standards

. . .

6.0E–2 lb•TBtu or

5.0E–4 lb•GWh.

3.0E–1 lb•TBtu or

4.0E–3 lb•GWh.

8.0E–1 lb•TBtu or

2.0E–2 lb•GWh.

1.1E0 lb•TBtu or

2.0E–2 lb•GWh.

8.0E–1 lb•TBtu or

2.0E–2 lb•GWh.

2.3E0 lb•TBtu or

4.0E–2 lb•GWh.

9.0E0 lb•TBtu or

2.0E–1 lb•GWh.

1.2E0 lb•TBtu or

2.0E–2 lb•GWh.

5.0E–3 lb•MMBtu

or 8.0E–2 lb•

MWh.

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 26A, collect a minimum of 0.75 dscm per run;

for Method 26, collect a minimum of 120 liters per run.

For ASTM D6348–03 (Reapproved 2010) or Method

320, sample for a minimum of 1 hour.

OR

3.0E–1 lb•MMBtu

SO CEMS.

or 2.0E0 lb•MWh.

2.0E–1 lb•TBtu or

LEE Testing for 30 days with a sampling period consistent

2.0E–3 lb•GWh.

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B run or Hg CEMS or sorbent

trap monitoring system only.

Before July 6,

Before July 6, 2027: Collect a minimum of 1 dscm per

2027: 3.0E–2 lb•

run.

MMBtu or 3.0E–

On or after July 6, 2027: Collect a minimum catch of 6.0

1 lb•MWh .

milligrams or a minimum sample volume of 4 dscm per

On or after July 6,

run.

2027: 1.0E–2 lb•

MMBtu or 1.0E–

1 lb•MWh .

OR

On or after July 6, 2027 you may only demonstrate compliance with the following total non-Hg HAP metals

emission limit if you request and receive approval for

the use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

Collect a minimum of 1 dscm per run.

Before July 6,

2027: 5.0E–5 lb•

MMBtu or 5.0E–

1 lb•GWh.

On or after July 6,

2027: 1.7E–5 lb•

MMBtu or 1.7E–

1 lb•GWh.

OR

On or after July 6, 2027 you may only demonstrate compliance with the following individual HAP metals emissions limits if you request and receive approval for the

use of a non-Hg HAP metals CMS under 40 CFR

63.7(f).

............................... Collect a minimum of 3 dscm per run.

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Fmt 4701

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E:\FR\FM\07MYR4.SGM

07MYR4

129a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Arsenic (As) ..........

Beryllium (Be) .......

Cadmium (Cd) ......

Chromium (Cr) ......

Cobalt (Co) ...........

Lead (Pb) ..............

Manganese (Mn) ...

khammond on DSKJM1Z7X2PROD with RULES4

Nickel (Ni) .............

VerDate Sep<11>2014

16:50 May 06, 2024

Jkt 262001

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Frm 00073

You must meet the

following emission

limits and work

practice standards

. . .

38579

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

Before July 6,

2027: 1.1E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 3.7E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 2.0E–1 lb•

TBtu or 2.0E–3

lb•GWh.

On or after July 6,

2027: 6.7E–2 lb•

TBtu or 6.7E–4

lb•GWh.

Before July 6,

2027: 3.0E–1 lb•

TBtu or 3.0E–3

lb•GWh.

On or after July 6,

2027: 1.0E–1 lb•

TBtu or 1.0E–3

lb•GWh.

Before July 6,

2027: 2.8E0 lb•

TBtu or 3.0E–2

lb•GWh.

On or after July 6,

2027: 9.3E–1 lb•

TBtu or 1.0E–2

lb•GWh.

Before July 6,

2027: 8.0E–1 lb•

TBtu or 8.0E–3

lb•GWh.

On or after July 6,

2027: 2.7E–1 lb•

TBtu or 2.7E–3

lb•GWh.

Before July 6,

2027: 1.2E0 lb•

TBtu or 2.0E–2

lb•GWh.

On or after July 6,

2027: 4.0E–1 lb•

TBtu or 6.7E–3

lb•GWh.

Before July 6,

2027: 4.0E0 lb•

TBtu or 5.0E–2

lb•GWh.

On or after July 6,

2027: 1.3E0 lb•

TBtu or 1.7E–2

lb•GWh.

Before July 6,

2027: 3.5E0 lb•

TBtu or 4.0E–2

lb•GWh.

On or after July 6,

2027: 1.2E0 lb•

TBtu or 1.3E–2

lb•GWh.

Fmt 4701

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130a

38580

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is in this subcategory . . .

For the following

pollutants . . .

Selenium (Se) .......

b. Hydrogen chloride (HCl).

OR

Sulfur dioxide

(SO ) .

c. Mercury (Hg) .....

You must meet the

following emission

limits and work

practice standards

. . .

Before July 6,

2027: 5.0E0 lb•

TBtu or 6.0E–2

lb•GWh.

On or after July 6,

2027: 1.7E0 lb•

TBtu or 2.0E–2

lb•GWh.

4.0E–2 lb•MMBtu

or 4.0E–1 lb•

MWh.

Using these requirements, as appropriate (e.g., specified

sampling volume or test run duration) and limitations with

the test methods in Table 5 to this Subpart . . .

For Method 26A at appendix A–8 to part 60 of this chapter, collect a minimum of 0.75 dscm per run; for Method

26, collect a minimum of 120 liters per run. For ASTM

D6348–03 (Reapproved 2010) or Method 320 at appendix A to part 63 of this chapter, sample for a minimum of 1 hour.

6E–1 lb•MMBtu or

9E0 lb•MWh.

1.2E0 lb•TBtu or

1.3E–2 lb•GWh.

SO CEMS.

1.0E0 lb•TBtu or

1.1E–2 lb•GWh.

LEE Testing for 90 days with a sampling period consistent

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B run or Hg CEMS or sorbent

trap monitoring system only.

LEE Testing for 30 days with a sampling period consistent

with that given in section 5.2.1 of appendix A to this

subpart per Method 30B at appendix A–8 to part 60 of

this chapter run or Hg CEMS or sorbent trap monitoring

system only.

OR

For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must

be increased nominally by a factor of 2. With the exception of IGCC units, on or after July 6, 2027 you may not pursue the LEE option for filterable PM, total non-Hg metals, and individual HAP metals and you may not comply with the total non-Hg HAP metals or individual HAP metals

emissions limits for all existing EGU subcategories unless you request and receive approval for the use of a HAP metals CMS under § 63.7(f).

Gross output.

Incorporated by reference, see § 63.14.

You may not use the alternate SO limit if your EGU does not have some form of FGD system and SO CEMS installed.

Table 3 to Subpart UUUUU of Part 63—

Work Practice Standards

20. Revise table 3 to subpart UUUUU

of part 63 to read as follows:

As stated in § 63.9991, you must

comply with the following applicable

work practice standards:

If your EGU is . . .

You must meet the following . . .

1. An existing EGU .............................................

Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar

months, or each 48 calendar months if neural network combustion optimization software is

employed, as specified in § 63.10021(e).

Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar

months, or each 48 calendar months if neural network combustion optimization software is

employed, as specified in § 63.10021(e).

a. Before January 2, 2025 you have the option of complying using either of the following work

practice standards in paragraphs (1) and (2). On or after January 2, 2025 you may not

choose to use paragraph (2) of the definition of startup in § 63.10042 and the following associated work practice standards in paragraph (2).

2. A new or reconstructed EGU .........................

khammond on DSKJM1Z7X2PROD with RULES4

3. A coal-fired, liquid oil-fired (excluding limiteduse liquid oil-fired subcategory units), or solid

oil-derived fuel-fired EGU during startup.

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131a

Federal Register / V ol. 89, No. 89 / T uesday, May 7, 2024 / Rules and Regulations

If your EGU is . . .

You must meet the following . . .

khammond on DSKJM1Z7X2PROD with RULES4

4. A coal-fired, liquid oil-fired (excluding limiteduse liquid oil-fired subcategory units), or solid

oil-derived fuel-fired EGU during shutdown.

VerDate Sep<11>2014

16:50 May 06, 2024

38581

Jkt 262001

(1) If you choose to comply using paragraph (1) of the definition of ‘‘startup’’ in § 63.10042,

you must operate all CMS during startup. Startup means either the first-ever firing of fuel in

a boiler for the purpose of producing electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the steam from the boiler is used to

generate electricity for sale over the grid or for any other purpose (including on site use).

For startup of a unit, you must use clean fuels as defined in § 63.10042 for ignition. Once

you convert to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the

applicable control technologies except dry scrubber and SCR. You must start your dry

scrubber and SCR systems, if present, appropriately to comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all

times except for periods that meet the applicable definitions of startup and shutdown in this

subpart. You must keep records during startup periods. You must provide reports concerning activities and startup periods, as specified in § 63.10011(g) and § 63.10021(h) and

(i). If you elect to use paragraph (2) of the definition of startup in 40 CFR 63.10042, you

must report the applicable information in 40 CFR 63.10031(c)(5) concerning startup periods

as follows: For startup periods that occur on or prior to December 31, 2023, in PDF files in

the semiannual compliance report; for startup periods that occur on or after January 1,

2024, quarterly, in PDF files, according to 40 CFR 63.10031(i).

(2) If you choose to comply using paragraph (2) of the definition of ‘‘startup’’ in § 63.10042,

you must operate all CMS during startup. You must also collect appropriate data, and you

must calculate the pollutant emission rate for each hour of startup.

For startup of an EGU, you must use one or a combination of the clean fuels defined in

§ 63.10042 to the maximum extent possible, taking into account considerations such as boiler or control device integrity, throughout the startup period. You must have sufficient clean

fuel capacity to engage and operate your PM control device within one hour of adding coal,

residual oil, or solid oil-derived fuel to the unit. You must meet the startup period work practice requirements as identified in § 63.10020(e).

Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions to the

main stack(s). You must comply with the applicable emission limits beginning with the hour

after startup ends. You must engage and operate your PM control(s) within 1 hour of first firing of coal, residual oil, or solid oil-derived fuel.

You must start all other applicable control devices as expeditiously as possible, considering

safety and manufacturer•supplier recommendations, but, in any case, when necessary to

comply with other standards made applicable to the EGU by a permit limit or a rule other

than this subpart that require operation of the control devices.

b. Relative to the syngas not fired in the combustion turbine of an IGCC EGU during startup,

you must either: (1) Flare the syngas, or (2) route the syngas to duct burners, which may

need to be installed, and route the flue gas from the duct burners to the heat recovery

steam generator.

c. If you choose to use just one set of sorbent traps to demonstrate compliance with the applicable Hg emission limit, you must comply with the limit at all times; otherwise, you must

comply with the applicable emission limit at all times except for startup and shutdown periods.

d. You must collect monitoring data during startup periods, as specified in § 63.10020(a) and

(e). You must keep records during startup periods, as provided in §§ 63.10021(h) and

63.10032. You must provide reports concerning activities and startup periods, as specified in

§§ 63.10011(g), 63.10021(i), and 63.10031. Before January 2, 2025, if you elect to use paragraph (2) of the definition of startup in 40 CFR 63.10042, you must report the applicable information in 40 CFR 63.10031(c)(5) concerning startup periods as follows: For startup periods that occur on or prior to December 31, 2023, in PDF files in the semiannual compliance

report; for startup periods that occur on or after January 1, 2024, quarterly, in PDF files, according to 40 CFR 63.10031(i). On or after January 2, 2025 you may not use paragraph (2)

of the definition of startup in § 63.10042.

You must operate all CMS during shutdown. You must also collect appropriate data, and you

must calculate the pollutant emission rate for each hour of shutdown for those pollutants for

which a CMS is used.

While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must vent emissions to the main stack(s) and operate all applicable control devices and continue to operate

those control devices after the cessation of coal, residual oil, or solid oil-derived fuel being

fed into the EGU and for as long as possible thereafter considering operational and safety

concerns. In any case, you must operate your controls when necessary to comply with other

standards made applicable to the EGU by a permit limit or a rule other than this subpart and

that require operation of the control devices.

If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown process, that additional fuel must be one or a combination of the clean

fuels defined in § 63.10042 and must be used to the maximum extent possible, taking into

account considerations such as not compromising boiler or control device integrity.

Relative to the syngas not fired in the combustion turbine of an IGCC EGU during shutdown,

you must either: (1) Flare the syngas, or (2) route the syngas to duct burners, which may

need to be installed, and route the flue gas from the duct burners to the heat recovery

steam generator.

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07MYR4

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If your EGU is . . .

You must meet the following . . .

You must comply with all applicable emission limits at all times except during startup periods

and shutdown periods at which time you must meet this work practice. You must collect

monitoring data during shutdown periods, as specified in § 63.10020(a). You must keep

records during shutdown periods, as provided in §§ 63.10032 and 63.10021(h). Any fraction

of an hour in which shutdown occurs constitutes a full hour of shutdown. You must provide

reports concerning activities and shutdown periods, as specified in §§ 63.10011(g),

63.10021(i), and 63.10031. Before January 2, 2025, if you elect to use paragraph (2) of the

definition of startup in 40 CFR 63.10042, you must report the applicable information in 40

CFR 63.10031(c)(5) concerning shutdown periods as follows: For shutdown periods that

occur on or prior to December 31, 2023, in PDF files in the semiannual compliance report;

for shutdown periods that occur on or after January 1, 2024, quarterly, in PDF files, according to 40 CFR 63.10031(i). On or after January 2, 2025 you may not use paragraph (2) of

the definition of startup in § 63.10042.

21. Revise table 4 to subpart UUUUU

of part 63 to read as follows:

Table 4 to Subpart UUUUU of Part 63—

Operating Limits for EGUs

Before July 6, 2027, as stated in

§ 63.9991, you must comply with the

If you demonstrate compliance using . . .

PM CPMS ............................

You must meet these operating limits . . .

Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the requirements of § 63.10023(b)(2) and obtained during the most recent performance test run demonstrating compliance

with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual

non-mercury HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s).

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22. Revise table 5 to subpart UUUUU

of part 63 to read as follows:

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applicable operating limits in table 4.

However, on or after July 6, 2027 you

may not use PM CPMS for compliance

demonstrations, unless it is for an IGCC

unit.

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Performance Testing Requirements

for performance testing for existing, new

or reconstructed affected sources:

As stated in § 63.10007, you must

comply with the following requirements

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Regarding emissions data collected

during periods of startup or shutdown, see

§§ 63.10020(b) and (c) and 63.10021(h). With

the exception of IGCC units, on or after July

6, 2027: You may not use quarterly

performance emissions testing to

demonstrate compliance with the filterable

PM emissions standards and for existing

EGUs you may not choose to comply with the

total or individual HAP metals emissions

limits unless you request and receive

approval for the use of a HAP metals CMS

under § 63.7(f).

See tables 1 and 2 to this subpart for

required sample volumes and/or sampling

run times.

Incorporated by reference, see § 63.14.

23. Revise table 6 to subpart UUUUU

of part 63 to read as follows:

If you have an

applicable

emission limit

for . . .

And you choose

to establish PM

CPMS operating

limits, you must . . .

Filterable Particulate

matter (PM), total

non-mercury HAP

metals, individual

non-mercury HAP

metals, total HAP

metals, or individual

HAP metals for an

EGU.

Install, certify, maintain, and

operate a PM CPMS for

monitoring emissions discharged to the atmosphere

according to

§ 63.10010(h)(1).

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Table 6 to Subpart UUUUU of Part 63—

Establishing PM CPMS Operating

Limits

Before July 6, 2027, as stated in

§ 63.10007, you must comply with the

following requirements for establishing

operating limits in table 6. However, on

or after July 6, 2027 you may not use PM

CPMS for compliance demonstrations,

unless it is for an IGCC unit.

And . . .

Using . . .

Establish a site-specific operating limit

in units of PM

CPMS output signal (e.g.,

milliamps, mg•

acm, or other raw

signal).

Data from the PM

CPMS and the

PM or HAP metals

performance tests.

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According to the

following

procedures . . .

1. Collect PM CPMS output data during

the entire period of the performance

tests.

2. Record the average hourly PM CPMS

output for each test run in the performance test.

3. Determine the PM CPMS operating

limit in accordance with the requirements of § 63.10023(b)(2) from data

obtained during the performance test

demonstrating compliance with the filterable PM or HAP metals emissions

limitations.

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24. Revise table 7 to subpart UUUUU

of part 63 to read as follows:

Table 7 to Subpart UUUUU of Part 63—

Demonstrating Continuous Compliance

38591

emission limitations for affected sources

according to the following:

As stated in § 63.10021, you must

show continuous compliance with the

If you use one of the following to meet applicable emissions limits, operating limits, or work practice standards . . .

1. CEMS to measure filterable PM, SO , HCl, HF, or Hg emissions, or

using a sorbent trap monitoring system to measure Hg.

2. PM CPMS to measure compliance with a parametric operating limit.

(On or after July 6, 2027 you may not use PM CPMS for compliance

demonstrations, unless it is for an IGCC unit.).

3. Site-specific monitoring using CMS for liquid oil-fired EGUs for HCl

and HF emission limit monitoring.

4. Quarterly performance testing for coal-fired, solid oil derived fired, or

liquid oil-fired EGUs to measure compliance with one or more nonPM (or its alternative emission limits) applicable emissions limit in

Table 1 or 2, or PM (or its alternative emission limits) applicable

emissions limit in Table 2. (On or after July 6, 2027 you may not use

quarterly performance testing for filterable PM compliance demonstrations, unless it is for an IGCC unit.).

5. Conducting periodic performance tune-ups of your EGU(s) ...............

6. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during startup.

7. Work practice standards for coal-fired, liquid oil-fired, or solid oil-derived fuel-fired EGUs during shutdown.

25. Revise table 8 to subpart UUUUU

of part 63 to read as follows:

You demonstrate continuous compliance by . . .

Calculating the 30- (or 90-) boiler operating day rolling arithmetic average emissions rate in units of the applicable emissions standard

basis at the end of each boiler operating day using all of the quality

assured hourly average CEMS or sorbent trap data for the previous

30- (or 90-) boiler operating days, excluding data recorded during

periods of startup or shutdown.

Calculating the 30- (or 90-) boiler operating day rolling arithmetic average of all of the quality assured hourly average PM CPMS output

data (e.g., milliamps, PM concentration, raw data signal) collected for

all operating hours for the previous 30- (or 90-) boiler operating

days, excluding data recorded during periods of startup or shutdown.

If applicable, by conducting the monitoring in accordance with an approved site-specific monitoring plan.

Calculating the results of the testing in units of the applicable emissions standard.

Conducting periodic performance tune-ups of your EGU(s), as specified in § 63.10021(e).

Operating in accordance with Table 3.

Operating in accordance with Table 3.

Table 8 to Subpart UUUUU of Part 63—

Reporting Requirements

requirements, as they apply to your

compliance strategy]

[In accordance with 40 CFR 63.10031,

you must meet the following reporting

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You must submit the following reports . . .

1. The electronic reports required under 40 CFR 63.10031 (a)(1), if you continuously monitor Hg emissions.

2. The electronic reports required under 40 CFR 63.10031 (a)(2), if you continuously monitor HCl and•or HF emissions.

Where applicable, these reports are due no later than 30 days after the end of each calendar quarter.

3. The electronic reports required under 40 CFR 63.10031(a)(3), if you continuously monitor PM emissions.

Reporting of hourly PM emissions data using ECMPS shall begin with the first operating hour after: January 1, 2024, or the hour of completion of the initial PM CEMS correlation test, whichever is later.

Where applicable, these reports are due no later than 30 days after the end of each calendar quarter.

4. The electronic reports required under 40 CFR 63.10031(a)(4), if you elect to use a PM CPMS (on or after July 6, 2027 you may not use PM

CPMS for compliance demonstrations, unless it is for an IGCC unit).

Reporting of hourly PM CPMS response data using ECMPS shall begin with the first operating hour after January 1, 2024, or the first operating hour after completion of the initial performance stack test that establishes the operating limit for the PM CPMS, whichever is later.

Where applicable, these reports are due no later than 30 days after the end of each calendar quarter.

5. The electronic reports required under 40 CFR 63.10031(a)(5), if you continuously monitor SO emissions.

Where applicable, these reports are due no later than 30 days after the end of each calendar quarter.

6. PDF reports for all performance stack tests completed prior to January 1, 2024 (including 30- or 90-boiler operating day Hg LEE test reports

and PM test reports to set operating limits for PM CPMS), according to the introductory text of 40 CFR 63.10031(f) and 40 CFR

63.10031(f)(6).

For each test, submit the PDF report no later than 60 days after the date on which testing is completed.

For a PM test that is used to set an operating limit for a PM CPMS, the report must also include the information in 40 CFR

63.10023(b)(2)(vi).

For each performance stack test completed on or after January 1, 2024, submit the test results in the relevant quarterly compliance report

under 40 CFR 63.10031(g), together with the applicable reference method information in sections 17 through 31 of appendix E to this

subpart.

7. PDF reports for all RATAs of Hg, HCl, HF, and•or SO monitoring systems completed prior to January 1, 2024, and for correlation tests,

RRAs and•or RCAs of PM CEMS completed prior to January 1, 2024, according to 40 CFR 63.10031(f)(1) and (6).

For each test, submit the PDF report no later than 60 days after the date on which testing is completed.

For each SO or Hg system RATA completed on or after January 1, 2024, submit the electronic test summary required by appendix A to

this subpart or part 75 of this chapter (as applicable) together with the applicable reference method information in sections 17 through 30

of appendix E to this subpart, either prior to or concurrent with the relevant quarterly emissions report.

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You must submit the following reports . . .

For each HCl or HF system RATA, and for each correlation test, RRA, and RCA of a PM CEMS completed on or after January 1, 2024,

submit the electronic test summary in accordance with section 11.4 of appendix B to this subpart or section 7.2.4 of appendix C to this

part, as applicable, together with the applicable reference method information in sections 17 through 30 of appendix E to this subpart.

8. Quarterly reports, in PDF files, that include all 30-boiler operating day rolling averages in the reporting period derived from your PM CEMS,

approved HAP metals CMS, and•or PM CPMS (on or after July 6, 2027 you may not use PM CPMS, unless it is for an IGCC unit), according

to 40 CFR 63.10031(f)(2) and (6). These reports are due no later than 60 days after the end of each calendar quarter.

The final quarterly rolling averages report in PDF files shall cover the fourth calendar quarter of 2023.

Starting with the first quarter of 2024, you must report all 30-boiler operating day rolling averages for PM CEMS, approved HAP metals

CMS, PM CPMS, Hg CEMS, Hg sorbent trap systems, HCl CEMS, HF CEMS, and•or SO CEMS (or 90-boiler operating day rolling averages for Hg systems), in XML format, in the quarterly compliance reports required under 40 CFR 63.10031(g).

If your EGU or common stack is in an averaging plan, each quarterly compliance report must identify the EGUs in the plan and include all

of the 30- or 90-group boiler operating day WAERs for the averaging group.

The quarterly compliance reports must be submitted no later than 60 days after the end of each calendar quarter.

9. The semiannual compliance reports described in 40 CFR 63.10031(c) and (d), in PDF files, according to 40 CFR 63.10031(f)(4) and (6). The

due dates for these reports are specified in 40 CFR 63.10031(b).

The final semiannual compliance report shall cover the period from July 1, 2023, through December 31, 2023.

10. Notifications of compliance status, in PDF files, according to 40 CFR 63.10031(f)(4) and (6) until December 31, 2023, and according to 40

CFR 63.10031(h) thereafter.

11. Quarterly electronic compliance reports, in accordance with 40 CFR 63.10031(g), starting with a report for the first calendar quarter of 2024.

The reports must be in XML format and must include the applicable data elements in sections 2 through 13 of appendix E to this subpart.

These reports are due no later than 60 days after the end of each calendar quarter.

12. Quarterly reports, in PDF files, that include the applicable information in 40 CFR 63.10031(c)(5)(ii) and 40 CFR 63.10020(e) pertaining to

startup and shutdown events, starting with a report for the first calendar quarter of 2024, if you have elected to use paragraph 2 of the definition of startup in 40 CFR 63.10042 (see 40 CFR 63.10031(i)). On or after January 2, 2025 you may not use paragraph 2 of the definition of

startup in 40 CFR 63.10042.

These PDF reports shall be submitted no later than 60 days after the end of each calendar quarter, along with the quarterly compliance reports required under 40 CFR 63.10031(g).

13. A test report for the PS 11 correlation test of your PM CEMS, in accordance with 40 CFR 63.10031(j).

If, prior to November 9, 2020, you have begun using a certified PM CEMS to demonstrate compliance with this subpart, use the ECMPS

Client Tool to submit the report, in a PDF file, no later than 60 days after that date.

For correlation tests completed on or after November 9, 2020, but prior to January 1, 2024, submit the report, in a PDF file, no later than

60 days after the date on which the test is completed.

For correlation tests completed on or after January 1, 2024, submit the test results electronically, according to section 7.2.4 of appendix C

to this subpart, together with the applicable reference method data in sections 17 through 31 of appendix E to this subpart.

14. Quarterly reports that include the QA•QC activities for your PM CPMS (on or after July 6, 2027 you may not use PM CPMS, unless it is for

an IGCC unit) or approved HAP metals CMS (as applicable), in PDF files, according to 40 CFR 63.10031(k).

The first report shall cover the first calendar quarter of 2024, if the PM CPMS or HAP metals CMS is in use during that quarter. Otherwise,

reporting begins with the first calendar quarter in which the PM CPMS or HAP metals CMS is used to demonstrate compliance.

These reports are due no later than 60 days after the end of each calendar quarter.

26. In appendix C to subpart UUUUU:

a. Revise sections 1.2, 1.3, 4.1, and

4.1.1.

b. Add sections 4.1.1.1 and 4.2.3.

c. Revise sections 5.1.1, 5.1.4, and the

section heading for section 6.

The revisions and additions read as

follows:

Appendix C to Subpart UUUUU of Part

63—PM Monitoring Provisions

1. General Provisions

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*

*

*

*

*

1.2 Initial Certification and

Recertification Procedures. You, as the owner

or operator of an affected EGU that uses a PM

CEMS to demonstrate compliance with a

filterable PM emissions limit in Table 1 or 2

to this subpart must certify and, if applicable,

recertify the CEMS according to Performance

Specification 11 (PS–11) in appendix B to

part 60 of this chapter. Beginning on July 6,

2027, when determining if your PM CEMS

meets the acceptance criteria in PS–11, the

value of 0.015 lb/MMBtu is to be used in

place of the applicable emission standard, or

emission limit, in the calculations.

1.3 Quality Assurance and Quality

Control Requirements. You must meet the

applicable quality assurance requirements of

Procedure 2 in appendix F to part 60 of this

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chapter. Beginning on July 6, 2027, when

determining if your PM CEMS meets the

acceptance criteria in Procedure 2, the value

of 0.015 lb/MMBtu is to be used in place of

the applicable emission standard, or

emission limit, in the calculations.

*

*

*

*

*

4. Certification and Recertification

Requirements

4.1 Certification Requirements. You must

certify your PM CEMS and the other CMS

used to determine compliance with the

applicable emissions standard before the PM

CEMS can be used to provide data under this

subpart. However, if you have developed and

are using a correlation curve, you may

continue to use that curve, provided it

continues to meet the acceptance criteria in

PS–11 and Procedure 2 as discussed below.

Redundant backup monitoring systems (if

used) are subject to the same certification

requirements as the primary systems.

4.1.1 PM CEMS. You must certify your

PM CEMS according to PS–11 in appendix B

to part 60 of this chapter. A PM CEMS that

has been installed and certified according to

PS–11 as a result of another state or federal

regulatory requirement or consent decree

prior to the effective date of this subpart shall

be considered certified for this subpart if you

can demonstrate that your PM CEMS meets

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the acceptance criteria in PS–11 and

Procedure 2 in appendix F to part 60 of this

chapter.

4.1.1.1 Beginning on July 6, 2027, when

determining if your PM CEMS meets the

acceptance criteria in PS–11 and Procedure

2 the value of 0.015 lb/MMBtu is to be used

in place of the applicable emission standard,

or emission limit, in the calculations.

*

*

*

*

*

*

*

*

*

*

*

*

*

*

*

4.2 Recertification.

4.2.3 Beginning on July 6, 2027 you must

use the value of 0.015 lb/MMBtu in place of

the applicable emission standard, or

emission limit, in the calculations when

determining if your PM CEMS meets the

acceptance criteria in PS–11 and Procedure

2.

5. Ongoing Quality Assurance (QA) and Data

Validation

*

*

*

*

*

5.1.1 Required QA Tests. Following

initial certification, you must conduct

periodic QA testing of each primary and (if

applicable) redundant backup PM CEMS.

The required QA tests and the criteria that

must be met are found in Procedure 2 of

appendix F to part 60 of this chapter

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(Procedure 2). Except as otherwise provided

in section 5.1.2 of this appendix, the QA tests

shall be done at the frequency specified in

Procedure 2.

value of 0.015 lb/MMBtu is to be used in

place of the applicable emission standard, or

emission limit, when determining whether

the RCA and RRA are acceptable.

*

*

*

*

*

*

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5.1.4 RCA and RRA Acceptability. The

results of your RRA or RCA are considered

acceptable provided that the criteria in

section 10.4(5) of Procedure 2 in appendix F

to part 60 of this chapter are met for an RCA

or section 10.4(6) of Procedure 2 in appendix

F to part 60 of this chapter are met for an

RRA. However, beginning on July 6, 2027 a

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*

*

*

*

6. Data Reduction and Calculations

*

*

*

*

*

27. Appendix D to subpart UUUUU of

part 63 is amended by adding

introductory text to the appendix to

read as follows:

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Appendix D to Subpart UUUUU of Part

63—PM CPMS Monitoring Provisions

On or after July 6, 2027 you may not use

PM CPMS for compliance demonstrations

with the applicable filterable PM emissions

limits, unless it is for an IGCC unit.

*

*

*

*

*

[FR Doc. 2024–09148 Filed 5–6–24; 8:45 am]

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USCA Case #24-1119

Document #2058570

Filed: 06/07/2024

Page 2 of 16

Declaration of Frank H. Chang

I, Frank H. Chang, declare as follows:

1.

I am over the age of 18, of sound mind, and otherwise competent to sign

this declaration.

2.

I am an attorney at the law firm Consovoy McCarthy PLLC and counsel

for Petitioner State of North Dakota.

3.

Attached to the declaration is a true and accurate copy of a PowerPoint

presentation (Bates stamp ED_006414_00000550-001-ED_006414_00000550-011)—

entitled “Power Sector Strategy: Climate, Public Health, Environmental Justice,

Briefing for Gina McCarthy and Ali Zaidi (Feb. 4, 2021)”—that EPA produced in

response to a FOIA request submitted by Energy Policy Advocates, a nonprofit

organization focused on educating the public about energy and environmental policies.

4.

I obtained the PowerPoint slides from Energy Policy Advocates’ litigation

counsel, Mr. Christopher C. Horner.

5.

According to EPA, these powerpoint slides were created by Joe Goffman,

then-Principal Deputy Assistant Administrator of EPA’s Office of Air and Radiation,

for a briefing with Gina McCarthy (then-National Climate Advisor) and Ali Zaidi (then

Deputy National Climate Advisor) in the White House Office of Domestic Climate

Policy. See Decl. of John Shoaff ¶9, Energy Pol’y Advocs. v. EPA, No. 1:22-cv-00298-TJK

(D.D.C. Jan 27, 2023), ECF 16-3.

(Page 518 of Total)

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6.

Document #2058570

Filed: 06/07/2024

Page 3 of 16

EPA heavily redacted these slides by asserting the deliberative-process

privilege under Exemption 5. In order to justify redacting these PowerPoint slides,

however, EPA had to explain what the redacted portions are about in litigation before

the U.S. District Court for the District of Columbia. In doing so, EPA confirmed that

the slides were used “to brief and consult with the White House on potential policy

options for regulating power plant emissions.” EPA-MSJ-Br. at 12, Energy Pol’y Advocs.

v. EPA, No. 1:22-cv-00298-TJK (D.D.C. Jan. 27, 2023), ECF 16-1.

7.

EPA explained that one of the slides presented to the White House Office

of Domestic Climate Policy discusses the Biden Administration’s strategies for using

the “Air Toxics Standards (e.g., MATS Rule)” to reduce power plant emissions. See Decl.

of John Shoaff ¶27, Energy Pol’y Advocs. v. EPA, No. 1:22-cv-00298-TJK (D.D.C. Jan.

27, 2023), ECF 16-3 (“Slide 6 (page 6) of the PowerPoint identifies potential strategies

for reducing emissions through Air Toxics Standards, including potential future

rulemakings and other regulatory actions under the Air Toxics program….”)

(referencing ED_006414_00000550-006).

8.

EPA further explained that other slides appearing in that powerpoint

presentation to the White House Office of Domestic Climate Policy discuss other

regulatory tools—including the nonattainment provisions under the Clean Air Act

(CAA), Section 111(d) of the CAA, Section 111(b) of the CAA, and the Regional Haze

program, etc.—are also about “regulating power sector emissions.” Decl. of John

(Page 519 of Total)

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USCA Case #24-1119

Document #2058570

Filed: 06/07/2024

Page 4 of 16

Shoaff ¶¶30, 33, 36, Energy Pol’y Advocs. v. EPA, No. 1:22-cv-00298-TJK (D.D.C. Jan.

27, 2023), ECF 16-3.

9.

Pursuant to 28 U.S.C. §1746, I declare under penalty of perjury that the

foregoing is true and correct.

Executed on May 24, 2024

Frank H. Chang

(Page 520 of Total)

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ATTACHMENT

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Power Sector Strategy:

Climate, Public Health,

Environmental Justice

The Building Blocks

Briefing for Gina McCarthy and Ali Zaidi

February 4, 2021

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EPA Has Responsibility Across Multiple

Media to Address Environmental

Effects of the Power Sector

• Air

• Toxics

• NAAQS Pollutants

• GHGs

• Regional Haze

• Water

• Effluent Limitation Guidelines

• Cooling water requirements

• Solid Waste

• Coal Combustion Residuals

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Key Considerations - Timing

• Timing

Ex. 5 Deliberative Process(DP)

• Air Toms Standards (Flagged in EO)

Ex. 5 Deliberative Process(DP)

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Key Constraints - Geographic

Scope

• Some authorities apply to all units across the

country while others only apply to a subset of units

• National Rules Include

• Air Toxics Standards

• GHG Standards

• Water Standards

• Coal Combustion Res

a Standards

• Authorities that would cover a subset of units include

• Non-attainment provisions (transport provisions would

generally cover a greater number of units than provisions for

non-attainment areas)

• Regional Haze

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Effluent Limitation Guidelines and

Coal Combustion Residuals

Ex. 5 Deliberative Process(DP)

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Air Toxics Standards (e.g., MATS

Rule)

ii

ii

iii Ex. 5 Deliberative Process(DP) i

ii

ii

ii

ii

ii

ii

ii

ii

ii

ii

ii

ii

i

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i

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Non-attainment Provisions

Ex. 5 Deliberative Process(DP)

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111(d) CO2 Standards

• National in scope, but requires two step process

(EPA guidelines followed by State Plans)

1

Ex. 5 Deliberative Process(DP)

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Regional Haze

i

ii

ii

i•

Ex.

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.4•

i

5 Deliberative Process(DP) iii

i

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Next Steps for Coal-Fired Units

Ex. 5 Deliberative Process(DP)

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New Natural Gas Units and 111(b)

Ex. 5 Deliberative Process(DP)

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IN THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

STATE OF NORTH DAKOTA, STATE

OF WEST VIRGINIA, STATE OF

ALASKA, STATE OF ARKANSAS,

STATE OF GEORGIA, STATE OF

IDAHO, STATE OF INDIANA, STATE

OF IOWA, STATE OF KANSAS,

COMMONWEALTH OF KENTUCKY,

STATE OF LOUISIANA, STATE OF

MISSISSIPPI, STATE OF MISSOURI,

STATE OF MONTANA, STATE OF

NEBRASKA, STATE OF OKLAHOMA,

STATE OF SOUTH CAROLINA,

STATE OF SOUTH DAKOTA, STATE

OF TENNESSEE, STATE OF TEXAS,

STATE OF UTAH, COMMONWEALTH

OF VIRGINIA, AND STATE OF

WYOMING,

Case No. 24-1119

Petitioners,

v.

U.S. ENVIRONMENTAL PROTECTION

AGENCY,

Respondent.

DECLARATION OF JULIE FEDORCHAK

IN SUPPORT OF PETITIONERS' MOTION TO STAY FINAL RULE

I, Julie Fedorchak, hereby declare and state under penalty of perjury that the following is

true and correct to the best of my knowledge and is based on my personal knowledge or

information available to me in the performance of my official duties:

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