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EPA-452/R-24-005

April 2024

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

U.S. Environmental Protection Agency

Office of Air Quality Planning and Standards

Health and Environmental Impacts Division

Research Triangle Park, NC

3.1

COSTS, EMISSIONS, AND ENERGY IMPACTS

Introduction

This section presents the compliance cost, emissions, and energy impact analysis

performed for the MATS RTR. EPA used the Integrated Planning Model (IPM), developed by

ICF Consulting, to conduct its analysis. IPM is a dynamic linear programming model that can be

used to examine air pollution control policies for SO2, NOX, Hg, HCl, PM, and other air

pollutants throughout the U.S. for the entire power system. Documentation for EPA’s Power

Sector Modeling Platform 2023 using IPM (hereafter IPM Documentation) can be found at

https://www.epa.gov/power-sector-modeling and is available in the docket for this action.

3.2

EPA’s Power Sector Modeling Platform 2023 using IPM

IPM is a state-of-the-art, peer-reviewed, dynamic linear programming model that can be

used to project power sector behavior under future business-as-usual conditions and to examine

prospective air pollution control policies throughout the contiguous U.S. for the entire electric

power system. For this RIA, EPA used IPM to project likely future electricity market conditions

with and without this rulemaking.

IPM, developed by ICF, is a multi-regional, dynamic, deterministic linear programming

model of the contiguous U.S. electric power sector. It provides estimates of least cost capacity

expansion, electricity dispatch, and emissions control strategies while meeting energy demand

and environmental, transmission, dispatch, and reliability constraints. IPM’s least-cost dispatch

solution is designed to ensure generation resource adequacy, either by using existing resources or

through the construction of new resources. IPM addresses reliable delivery of generation

resources for the delivery of electricity between the 78 IPM regions, based on current and

planned transmission capacity, by setting limits to the ability to transfer power between regions

using the bulk power transmission system. Notably, the model includes cost and performance

estimates for state-of-the-art air pollution control technologies with respect to Hg, fPM, and

other HAP controls.

EPA has used IPM for almost three decades to better understand power sector behavior

under future business-as-usual conditions and to evaluate the economic and emissions impacts of

prospective environmental policies. The model is designed to reflect electricity markets as

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accurately as possible. EPA uses the best available information from utilities, industry experts,

gas and coal market experts, financial institutions, and government statistics as the basis for the

detailed power sector modeling in IPM. The model documentation provides additional

information on the assumptions discussed here as well as all other model assumptions and

inputs. 36

The model incorporates a detailed representation of the fossil-fuel supply system that is

used to estimate equilibrium fuel prices. The model uses natural gas fuel supply curves and

regional gas delivery costs (basis differentials) to simulate the fuel price associated with a given

level of gas consumption within the system. These inputs are derived using ICF’s Gas Market

Model (GMM), a supply/demand equilibrium model of the North American gas market. 37

IPM also endogenously models the partial equilibrium of coal supply and EGU coal

demand levels throughout the contiguous U.S., taking into account assumed non-power sector

demand and imports/exports. IPM reflects 36 coal supply regions, 14 coal grades, and the coal

transport network, which consists of over four thousand linkages representing rail, barge, and

truck and conveyer linkages. The coal supply curves in IPM were developed during a thorough

bottom-up, mine-by-mine approach that depicts the coal choices and associated supply costs that

power plants would face if selecting that coal over the modeling time horizon. The IPM

documentation outlines the methods and data used to quantify the economically recoverable coal

reserves, characterize their cost, and build the 36 coal regions’ supply curves. 38

To estimate the annualized costs of additional capital investments in the power sector,

EPA uses a conventional and widely accepted approach that applies a capital recovery factor

(CRF) multiplier to capital investments and adds that to the annual incremental operating

expenses. The CRF is derived from estimates of the power sector’s cost of capital (i.e., private

discount rate), the amount of insurance coverage required, local property taxes, and the life of

capital. 39 It is important to note that there is no single CRF factor applied in the model; rather, the

Detailed information and documentation of EPA’s Baseline run using EPA’s Power Sector Modeling Platform

2023 using IPM, including all the underlying assumptions, data sources, and architecture parameters can be found

on EPA’s website at: https://www.epa.gov/power-sector-modeling.

See Chapter 8 of EPA's IPM Documentation, available at: https://www.epa.gov/power-sector-modeling.

See Chapter 7 EPA's IPM Documentation, available at: https://www.epa.gov/power-sector-modeling.

See Chapter 10 of EPA's IPM Documentation, available at: https://www.epa.gov/power-sector-modeling.

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CRF varies across technologies, book life of the capital investments, and regions in the model in

order to better simulate power sector decision-making.

EPA has used IPM extensively over the past three decades to analyze options for

reducing power sector emissions. Previously, the model has been used to estimate the costs,

emission changes, and power sector impacts in the RIAs for the Clean Air Interstate Rule (U.S.

EPA, 2005), the Cross-State Air Pollution Rule (U.S. EPA, 2011a), the Mercury and Air Toxics

Standards (U.S. EPA, 2011b), the Clean Power Plan for Existing Power Plants (U.S. EPA,

2015b), the Cross-State Air Pollution Update Rule (U.S. EPA, 2016), the Repeal of the Clean

Power Plan, and the Emission Guidelines for Greenhouse Gas Emissions from Existing Electric

Utility Generating Units (U.S. EPA, 2019), the Revised Cross-State Air Pollution Update Rule

(U.S. EPA, 2021), and the Good Neighbor Plan (2023b).

EPA has also used IPM to estimate the air pollution reductions and power sector impacts

of water and waste regulations affecting EGUs, including contributing to RIAs for the Cooling

Water Intakes (316(b)) Rule (U.S. EPA, 2014a), the Disposal of Coal Combustion Residuals

from Electric Utilities rule (U.S. EPA, 2015c), the Steam Electric Effluent Limitation Guidelines

(U.S. EPA, 2015a), and the Steam Electric Reconsideration Rule (U.S. EPA, 2020).

The model and EPA's input assumptions undergo periodic formal peer review. The

rulemaking process also provides opportunity for expert review and comment by a variety of

stakeholders, including owners and operators of capacity in the electricity sector that is

represented by the model, public interest groups, and other developers of U.S. electricity sector

models. The feedback that the Agency receives provides a highly detailed review of key input

assumptions, model representation, and modeling results. IPM has received extensive review by

energy and environmental modeling experts in a variety of contexts. For example, in September

2019, U.S. EPA commissioned a peer review 40 of EPA’s v6 Reference Case using the Integrated

Planning Model (IPM). Additionally, and in the late 1990s, the Science Advisory Board

reviewed IPM as part of the CAA Amendments Section 812 prospective studies 41 that are

periodically conducted. The Agency has also used the model in a number of comparative

modeling exercises sponsored by Stanford University’s Energy Modeling Forum over the past 20

See Response and Peer Review Report EPA Reference Case Version 6 Using IPM, available at:

https://www.epa.gov/power-sector-modeling/ipm-peer-reviews.

http://www2.epa.gov/clean-air-act-overview/benefits-and-costs-clean-air-act.

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years. IPM has also been employed by states (e.g., for the Regional Greenhouse Gas Initiative,

the Western Regional Air Partnership, Ozone Transport Assessment Group), other Federal and

state agencies, environmental groups, and industry.

3.3

Baseline

The modeled “baseline” for any regulatory impact analysis is a business-as-usual

scenario that represents expected behavior in the electricity sector under market and regulatory

conditions in the absence of a regulatory action. As such, the baseline run represents an element

of the baseline for this RIA. 42 EPA frequently updates the baseline modeling to reflect the latest

available electricity demand forecasts from the U.S. EIA as well as expected costs and

availability of new and existing generating resources, fuels, emission control technologies, and

regulatory requirements.

For our analysis of the MATS RTR rule, EPA used EPA’s Power Sector Modeling

Platform 2023 using IPM to provide power sector emissions projections for air quality modeling,

as well as a companion updated database of EGU units (the National Electricity Energy Data

System or NEEDS for IPM 2023 43) that is used in EPA’s modeling applications of IPM. The

baseline for this final rule includes the Good Neighbor Plan (Final GNP), the Revised CSAPR

Update, CSAPR Update, and CSAPR, as well as MATS. The baseline run also includes the 2015

Effluent Limitation Guidelines (ELG) and the 2015 Coal Combustion Residuals (CCR), and the

recently finalized 2020 ELG and CCR rules. 44

This version of the model, which is used as the baseline for this RIA, also includes recent

updates to state and federal legislation affecting the power sector, including Public Law 117-169,

136 Stat. 1818 (August 16, 2022), commonly known as the Inflation Reduction Act of 2022 (the

IRA). The IPM Documentation includes a summary of all legislation reflected in this version of

the model as well as a description of how that legislation is implemented in the model.

As described in Chapter 5 of EPA’s Guidelines for Preparing Economic Analyses, the baseline “should

incorporate assumptions about exogenous changes in the economy that may affect relevant benefits and costs (e.g.,

changes in demographics, economic activity, consumer preferences, and technology), industry compliance rates,

other regulations promulgated by EPA or other government entities, and behavioral responses to the proposed rule

by firms and the public.“ (U.S. EPA, 2014b).

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

For a full list of modeled policy parameters, please see: https://www.epa.gov/power-sector-modeling.

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Under the baseline, the impacts of the IRA result in an acceleration of the ongoing shift

towards lower emitting generation and declining generation share for fossil-fuel fired generation.

A range of studies have outlined how reliability continues to be maintained under high variable

renewable penetration scenarios. U.S. EPA (2023a) summarized results from fourteen multisector and power sector models under the IRA in 2030 and 2035. Across the models, wind and

solar resources provide 22 to 54 percent of generation (with median of 45 percent) in 2030 and

21 to 80 percent (with median of 50 percent) in 2035. The North American Renewable

Integration Study (Brinkman et al., 2021) showed how the U.S. could accommodate between 70

to 79 percent of wind and solar generation by 2050. The Solar Futures Study (DOE, 2021)

illustrated power systems with upwards of 80 percent of renewable energy by 2050. Finally, Cole

et al. (2021) demonstrates a 100 percent renewable power system for the contiguous U.S.

The inclusion of the final GNP and other regulatory actions (including federal, state, and

local actions) in the base case is necessary in order to reflect the level of controls that are likely

to be in place in response to other requirements apart from the scenarios analyzed in this section.

This base case will provide meaningful projections of how the power sector will respond to the

cumulative regulatory requirements for air emissions in totality, while isolating the incremental

impacts of MATS RTR relative to a base case with other air emission reduction requirements

separate from this final action.

The analysis of power sector cost and impacts presented in this section is based on a

single policy run compared to the baseline run. The difference between the two runs represents

the incremental impacts projected solely as a result of compliance with the final MATS RTR.

3.4

Regulatory Options Analyzed

For this RIA, EPA analyzed the regulatory options summarized in the table below, which

are described in more detail in Section 1.3.1. The remainder of this section discusses the

approach used for estimating the costs and/or emissions impacts of each provision of this final

rule.

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Table 3-1

Summary of Final Regulatory Options Examined in this RIA

Regulatory Options Examined in this RIA

Provision

Less Stringent

Final Rule

FPM Standard (Surrogate

Standard for Non-Hg HAP

Metals)

Retain existing fPM standard of

0.030 lb/MMBtu

Revised fPM standard of 0.010

lb/MMBtu

Hg Standard

Retain Hg standard for lignite-fired

EGUs of 4.0 lb/TBtu

Revised Hg standard for lignitefired EGUs of 1.2 lb/TBtu

Continuous Emissions

Monitoring Systems (PM CEMS)

Require installation of PM CEMS

to demonstrate compliance

Require installation of PM CEMS

to demonstrate compliance

Startup Definition

Remove startup definition #2

As explained in Section 1.3.1, both the final rule and less stringent options described in

Table 3-1 have not been changed from the proposed and less stringent options examined in the

RIA for the proposal of this action. The proposal RIA included a more stringent regulatory

option that projected the impacts of lowering the fPM standard to 0.006 lb/MMBtu, while

holding the other three proposed amendments unchanged from the proposed option. EPA

solicited comment on this more stringent fPM standard in the preamble of the proposed rule. As

explained in section V.A.4. of the preamble of the final rule, EPA determined not to pursue a

more stringent standard for fPM emissions, such as a limit of 0.006 lb/MMBtu. After considering

comments to the proposed rule and after conducting additional analysis, EPA determined that a

lower fPM standard would not be compatible with PM CEMS due to measurement uncertainty.

As a result, this RIA does not examine a more stringent option than the suite of requirements that

constitute the final rule; the final rule represents the most stringent suite of regulatory options

available under the technology review.

The revisions to the fPM standard and the Hg standard are modeled endogenously within

IPM. For the fPM standard, emissions controls and associated costs are modeled based on

information available in the memorandum titled “2024 Update to the 2023 Proposed Technology

Review for the Coal- and Oil-Fired EGU Source Category,” which is available in the docket.

This memorandum summarizes the fPM emissions rate for each existing EGU. Based on the

emissions rates detailed in this memorandum, EPA assumed various levels of O&M, ESP

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upgrades, upgrades to existing fabric filters, or new fabric filter installations to comply with each

of the finalized standards in the modeling. Those assumptions are detailed in Table 3-2.

Table 3-2

PM Control Technology Modeling Assumptions a

Control Strategy

Cost (in 2019 dollars)

fPM Reduction

Operation &

Maintenance (O&M)

$100,000/year

Unit-specific

Minor

ESP Upgrades

$20/kW

20%

Typical

ESP Upgrades

$40/kW

40%

ESP Rebuild

$80/kW

55%

(0.005lb/MMBtu floor)

Upgrade Existing FF Bags

Unit-specific, approximately $15K

- $500K annual O&M

50%

(0.002 lb/MMBtu floor)

New Fabric Filter

(6.0 A/C Ratio)

Unit-specific,

$150-360/kW*

90%

(0.002 lb/MMBtu floor)

Capital costs are expressed here in terms of $/kW. O&M costs are expressed here on an annual basis.

* https://www.epa.gov/system/files/documents/2021-09/attachment_57_pm_control_cost_development_methodology.pdf

The cost and reductions associated with control of Hg emissions at lignite-fired EGUs are

also modeled endogenously and reflect the assumption that each of these EGUs replace standard

powdered activated carbon (PAC) sorbent with halogenated PAC sorbent.

While more detail on the costs associated with the PM CEMS requirement and the

change in the startup definition is presented in Section 3.5.2, we note here that these costs were

estimated exogenously without the use of the model that provides the bulk of the cost analysis

for this RIA. As a result, the results of the power sector modeling do not include costs associated

with these provisions, but the costs associated with requiring PM CEMS and the change in the

startup definition are included in the total cost projections for the rule for each of the regulatory

options analyzed in this RIA. As the incremental costs of requiring PM CEMS are small relative

to the ongoing costs of operations, we do not think the endogenous incorporation of these costs

would change any projected results in a meaningful way.

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3.5

Power Sector Impacts

3.5.1 Emissions

As indicated previously, this RIA presents emissions reductions estimates in years 2028,

2030, and 2035 based on IPM projections. 45 Table 3-3 presents the estimated impact on power

sector emissions resulting from compliance with the final rule in the contiguous U.S. The

quantified emission estimates presented in the RIA include changes in pollutants directly covered

by this rule, such as Hg and non-Hg HAP metals, and changes in other pollutants emitted from

the power sector as a result of the compliance actions projected under this final rule. The model

projections capture the emissions changes associated with implementation of HAP mitigation

measures at affected sources as well as the resulting effects on dispatch as the relative operating

costs for some affected units have changed. The projections indicate that the final rule results in

reductions in emissions of Hg in all run years, of 16 percent, 17 percent, and 18 percent in 2028,

2030, and 2035, respectively, as well as reductions in PM 2.5 and PM10 emissions in all run years.

Note that baseline mercury emissions projections are higher than proposal due to a revision in final baseline

modeling to better reflect current ACI performance at existing lignite-fired units.

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Table 3-3

EGU Emissions and Projected Emissions Changes for the Baseline and the

Final Rule for 2028, 2030, and 2035a

Total Emissions

Hg (lbs.)

PM2.5 (thousand tons)

PM10 (thousand tons)

SO2 (thousand tons)

Ozone-season NOX

(thousand tons)

Annual NOX (thousand

tons)

Year

Baseline

Final Rule

Change from

Baseline

2028

6,129

5,129

-999.1

% Change

under Final

Rule

-16.3%

2030

5,863

4,850

-1,013

-17.3%

2035

4,962

4,055

-907.0

-18.3%

2028

70.5

69.7

-0.77

-1.09%

2030

66.3

65.8

-0.53

-0.79%

2035

50.7

50.2

-0.47

-0.93%

2028

2030

2035

79.5

74.5

56.0

77.4

73.1

54.8

-2.07

-1.33

-1.18

-2.60%

-1.79%

-2.11%

2028

454.3

454.0

-0.290

-0.06%

2030

333.5

0.025

0.01%

2035

239.9

-0.040

-0.02%

2028

189.0

188.8

-0.165

-0.09%

2030

174.99

175.4

0.488

0.28%

2035

116.99

1.95%

460.55

119.1

460.3

2.282282

2028

-0.283

-0.06%

392.88

392.7

-0.022

-0.01%

2028

253.44

2.474

253.5

2.474

0.066

0.000

0.03%

0.01%

2030

2.184

0.000

0.01%

2035

1.484

1.485

0.001

0.06%

2028

2030

2035

1,158.8

1,098.3

724.2

1,158.7

1,098.3

724.1

-0.0655

0.0361

-0.099

-0.01%

0.00%

-0.01%

2030

2035

HCl (thousand tons)

CO2 (million metric tons)

This analysis is limited to the geographically contiguous lower 48 states. Values are independently rounded and

may not sum.

We also estimate that the final rule will reduce at least seven tons of non-Hg HAP metals in

2028, five tons of non-Hg HAP metals in 2030, and four tons of non-Hg HAP metals in 2035.

These reductions are composed of reductions in emissions of antimony, arsenic, beryllium,

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cadmium, chromium, cobalt, lead, manganese, nickel, and selenium. 46 Table 3-4 summarizes the

total emissions reductions projected over the 2028 to 2037 analysis period.

Table 3-4

2037a,b

Cumulative Projected Emissions Reductions for the Final Rule, 2028 to

Pollutant

Emissions Reductions

Hg (pounds)

9,500

PM2.5 (tons)

5,400

CO2 (thousand tons)

650

SO2 (tons)

770

NOx (tons)

220

Non-Hg HAP metals (tons)

Values rounded to two significant figures.

Estimated reductions from model year 2028 are applied to 2028 and 2029, those from model year 2030 are applied

to 2031 and 2032, and those from model year 2035 are applied to 2032 through 2037. These values are summed to

generate total reduction figures.

Importantly, the continuous monitoring of fPM required in this rule will likely induce

additional emissions reductions that we are unable to quantify. Continuous measurements of

emissions accounts for changes to processes and fuels, fluctuations in load, operations of

pollution controls, and equipment malfunctions. By measuring emissions across all operations,

power plant operators and regulators can use the data to ensure controls are operating properly

and to assess continuous compliance with relevant standards. Because CEMS enable power plant

operators to quickly identify and correct problems with pollution control devices, it is possible

that fPM emissions could be lower than they otherwise would have been for up to three

months—or up to three years if testing less frequently under the LEE program— at a time. This

potential reduction in fPM and non-Hg HAP metals emission resulting from the information

provided by continuous monitoring coupled with corrective actions by plant operators could be

sizeable over the existing coal-fired fleet and is not quantified in this rulemaking.

As we are finalizing the removal of paragraph (2) of the definition of “startup,” the time

period for engaging fPM or non-Hg HAP metal controls after non-clean fuel use, as well as for

full operation of fPM or non-Hg HAP metal controls, is expected to be reduced when

The estimates on non-mercury HAP metals reductions were obtained my multiplying the ratio of non-mercury

HAP metals to fPM by estimates of PM10 reductions under the rule, as we do not have estimates of fPM reductions

using IPM, only PM10. The ratios of non-mercury HAP metals to fPM were based on analysis of 2010 MATS

Information Collection Request (ICR) data. As there may be substantially more fPM than PM 10 reduced by the

control techniques projected to be used under this rule, these estimates of non-mercury HAP metals reductions are

likely underestimates. More detail on the estimated reduction in non-mercury HAP metals can be found in the

docketed memorandum Estimating Non-Hg HAP Metals Reductions for the 2024 Technology Review for the CoalFired EGU Source Category.

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transitioning to paragraph (1). The reduced time period for engaging controls therefore increases

the duration in which pollution controls are employed and lowers emissions.

To the extent that the CEMS requirement and removal of the second definition of startup

leads to actions that may otherwise not occur absent the amendments to those provisions in this

final rule, there may be emissions impacts we are unable to estimate.

3.5.2 Compliance Costs

3.5.2.1 Power Sector Costs

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 and are presented in

Table 3-5. In other words, these costs are an estimate of the increased power industry

expenditures required to implement the final rule requirements. The total compliance costs,

presented in Section 3.5.2.4, are estimated for this RIA as the sum of two components. The first

component, estimated using the modeling discussed above, is presented below in Table 3-5. This

component constitutes the majority of the incremental costs for the final. The second component,

the costs of the final rule PM CEMS requirement, is discussed in Section 3.5.2.2.

EPA projects that the annual incremental compliance cost of the final rule is $110

million, $110 million, and $93 million (2019 dollars) in 2028, 2030, and 2035, respectively. The

annual incremental cost is the projected additional cost of complying with the final rule in the

year analyzed and includes the amortized cost of capital investment and any applicable costs of

operating additional pollution controls, investments in new generating sources, shifts between or

amongst various fuels, and other actions associated with compliance. This projected cost does

not include the compliance calculated outside of IPM modeling, namely the compliance costs

related to PM CEMS. See Section 3.5.2.2 for further details on these costs. EPA believes that the

cost assumptions used for this RIA reflect, as closely as possible, the best information available

to the Agency today. See Section 3.5.4 for a discussion of projected capacity changes and

Section 3.6 for a discussion of the uncertainty regarding necessary pollution controls.

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Table 3-5

Power Sector Annualized Compliance Cost Estimates under the Final Rule in

2028, 2030, and 2035 (millions of 2019 dollars)

Analysis Year

Final Rule

2028

110

2030

110

2035

Note: Values have been rounded to two significant figures. As explained in Section 3.4, the incremental costs of

requiring PM CEMS are small relative to the ongoing costs of operation, so the less stringent regulatory alternative

in this RIA was not modeled using IPM. As a result, power sector impacts are not estimated for the less stringent

regulatory option, but the costs associated with requiring PM CEMS (Table 3-6) are included in the total cost across

regulatory options (Table 3-7).

3.5.2.2 PM CEMS Costs

In addition to revising the PM emission standard for existing coal-fired EGUs, EPA is

revising the requirements for demonstrating compliance with the PM emission standard for coaland oil-fired EGUs. The final PM standard renders the current limit for the LEE program moot

since it is lower than the current PM LEE limit. Therefore, EPA is removing PM from the LEE

program. Currently, EGUs that are not LEE units can demonstrate compliance with the fPM

standard either by conducting performance testing quarterly, use of PM continuous parameter

monitoring systems (CPMS) or using PM CEMS.

After considering updated information on the costs for performance testing compared to

the cost of PM CEMS and capabilities of PM CEMS measurement abilities, as well as the

benefits of using PM CEMS, which include increased transparency, compliance assurance, and

accelerated identification of anomalous emissions, EPA is finalizing the requirement that all

coal-fired EGUs and oil-fired EGUs demonstrate compliance with the PM emission standard by

using PM CEMS.

The revision of PM limits alters the composition and duration of testing runs in facilities

that use either compliance testing methodology. Estimated costs for quarterly fPM testing and

PM CEMS are provided in the “Revised Estimated Non-Beta Gauge PM CEMS and Filterable

PM Testing Costs” memorandum, available in the docket. The annualized costs for units

currently employing EPA Method 5 quarterly testing are estimated at about $60,000. 47 EPA

calibrated its cost estimates for PM CEMS in response to observed installations, manufacturer

input, public comment, and engineering analyses. These calibrations include an assumed

EGUs receiving contractual or quantity discounts from performance test provides may incur lower costs.

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replacement lifespan of 15 years and an interest rate of 7 percent to approximate the prevailing

bank prime rate. For the portion of EGUs that employ PM CEMS, we estimate the annualized

costs to be about $72,000.

To produce an inventory of total units which would require the installation of PM CEMS

under the final rule as well as the incremental costs of the requirement, EPA began with an

inventory of all existing coal-fired EGUs with capacity great enough to be regulated by MATS.

That inventory was then filtered to remove EGUs with planned retirements or coal to gas

conversions prior to 2028 from analysis of both the baseline and final rule. Within that remaining

inventory of 314 EGUs, we used recent compliance data to determine that 120 units have

installed PM CEMS, while 177 units use quarterly testing and do not have existing PM CEMS

installations. The remaining 17 units (for which fPM compliance data were not available) are

assumed to use quarterly testing and not have existing PM CEMS installations.

Table 3-6

Incremental Cost of Final Continuous Emissions Monitoring (PM CEMS)

Requirement

Compliance

Approach in

Baseline

Units

(no.)

Baseline

Cost (per

year per

unit)

Total

Baseline

Costs (per

year)

Final Rule

(per year per

unit)

Final Rule

Costs (per

year)

Incremental

Costs (per

year)

Quarterly Testing

190

$60,000

$12,000,000

$72,000

$14,000,000

$2,300,000

PM CEMS

120

$72,000

$8,700,000

$72,000

$8,700,000

Total

320

---

$20,000,000

---

$23,000,000

$2,300,000

Note: Values rounded to two significant figures. Rows may not appear to add correctly due to rounding.

As detailed in Table 3-6, relative to the baseline scenario, revised PM CEMS cost

estimates in the final rule leads to an estimated incremental cost of about $12,000 per year per

unit for EGUs currently employing quarterly testing. The final rule results in costs of about $2.3

million per year in total.

3.5.2.3 Startup Definition Costs

EPA is finalizing the removal of one of the two options for defining the startup period for

EGUs. The first option defines startup as 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). In the second option, startup is

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defined as 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 producing electricity or useful

thermal energy (such as heat or steam) for industrial, commercial, heating, or cooling purposes

(other than the first-ever firing of fuel in a boiler following construction of the boiler) or for any

other purpose after a shutdown event. Startup ends four hours after the EGU generates electricity

that is sold or used for any other purpose (including on-site use), or four hours after the EGU

makes useful thermal energy (such as heat or steam) for industrial, commercial, heating, or

cooling purposes, whichever is earlier. This second option, referred to as paragraph (2) of the

definition of “startup,” required clean fuel use to the maximum extent possible, operation of PM

control devices within one hour of introduction of primary fuel (i.e., coal, residual oil, or solid

oil-derived fuel) to the EGU, collection and submission of records of clean fuel use and

emissions control device capabilities and operation, as well as adherence to applicable numerical

standards within four hours of the generation of electricity or thermal energy for use either on

site or for sale over the grid (i.e., the end of startup) and to continue to maximize clean fuel use

throughout that period.

According to EPA analysis, owners or operators of coal- and oil-fired EGUs that

generated over 98 percent of electricity in 2022 have made the requisite adjustments, whether

through greater clean fuel capacity, better tuned equipment, better trained staff, a more efficient

and/or better design structure, or a combination of factors, to be able to meet the requirements of

paragraph (1) of the startup definition. This ability points out an improvement in operation that

all EGUs should be able to meet at little to no additional expenditure since the additional

recordkeeping and reporting provisions associated with the work practice standards of paragraph

(2) of the startup definition were more expensive than the requirements of paragraph (1) of the

definition. As a result, this RIA does not incorporate any additional costs of this finalized

provision.

3.5.2.4 Total Compliance Costs

The estimates of the total compliance costs are presented in Table 3-7. The total costs are

composed of the change in electric power generation costs between the baseline and policy

scenarios as presented in Table 3-5 and the incremental cost of the final PM CEMS requirement

as detailed in Table 3-6. There are no anticipated costs associated with this rule prior to 2028.

3-14

3-15

Table 3-7

Stream of Projected Compliance Costs for the Final Rule and Less Stringent

Regulatory Alternative (millions of 2019 dollars)a

Regulatory Alternative

Final Ruleb

Less Stringent

110

2.3

120

2.3

860

2.3

790

2.1

Year

2028 (applied to 2028 and 2029)

2030 (applied to 2030 and 2031)

2035 (applied to 2032 to 2037)

2% Discount Rate

EAV

3% Discount Rate

EAV

7% Discount Rate

560

EAV

1.8

Values rounded to two significant figures. PV and EAV discounted to 2023.

IPM run years apply to particular calendar years as reported in the table. The run year information as applied to

individual calendar years is thus used to calculate PV and EAVs. Values rounded to two significant figures.

3.5.3 Projected Compliance Actions for Emissions Reductions

Electric generating units subject to the Hg and fPM emission limits in this final rule will

likely use various Hg and PM control strategies to comply. This section summarizes the

projected compliance actions related to each of these emissions limits.

The 2028 baseline includes approximately 5 GW of operational minemouth EGU

capacity designed to burn low rank virgin coal. All of this capacity is currently equipped with

Activated Carbon Injection (ACI) technology, and operation of this technology is reflected in the

baseline. Each of these EGUs projected to consume lignite is assigned an additional variable

operating cost that is consistent with achieving a 1.2 lb/MMBtu limit. Under the final rule, this

additional cost does not result in incremental retirements for these units, nor does it result in a

significant change to the projected generation level for these units.

The baseline also includes 11.6 GW of operational coal capacity that, based on the

analysis documented in the EPA docketed memorandum titled “2024 Update to the 2023

Proposed Technology Review for the Coal- and Oil-Fired EGU Source Category,” EPA assumes

would either need to improve existing PM controls or install new PM controls to comply with the

3-16

final rule in 2028. The various PM control upgrades that EPA assumes would be necessary to

achieve the emissions limits analyzed are summarized in Table 3-8.

Table 3-8

Projected PM Control Strategies under the Final Rule in 2028 (GW)

Additional O&M

Minor ESP Upgrades

Typical ESP Upgrades

ESP Rebuild

FF Bag Upgrade

New Fabric Filter

Projected Actions and Retrofits

under the Final Rule

3.7

0.7

2.0

2.4

1.3

1.5

Total

11.6

PM Control Strategy

Except for one facility (Colstrip, located in Montana), all of the 11.6 GW of operational

coal capacity that EPA assumes would need to take some compliance action to meet the final

standards are currently operating existing ESPs and/or fabric filters. All of that capacity is

projected to install the controls summarized in Table 3-8 and remain operational in 2028.

3.5.4 Generating Capacity

In this section, we discuss the projected changes in capacity by fuel type, building on and

adding greater context to the information presented in the previous section. We first look at total

capacity by fuel type, then retirements by fuel type, and finally new capacity builds by fuel type

for the 2028, 2030, and 2035 run years.

Table 3-9 shows the total net projected capacity by fuel type for the baseline and the final

rule for 2028, 2030, and 2035. Here, we see the net effects of projected retirements (Table 3-10)

and new capacity builds (see Table 3-11). There are no significant incremental changes in

capacity projected in response to the final rule for any given fuel type.

3-17

Table 3-9

2028, 2030, and 2035 Projected U.S. Capacity by Fuel Type for the Baseline

and the Final Rule

Total Generation Capacity (GW)

Baseline

Final Rule

Change under Final Rule

105.8

471.0

62.6

394.1

102.4

46.7

93.6

6.5

1,282.7

0.0

0.0%

85.0

478.6

64.3

440.2

103.7

58.6

90.9

6.5

1,327.7

0.0

0.0%

51.6

476.0

55.3

698.5

107.3

113.6

83.7

6.5

1,592.4

0.0

0.0%

2028

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Energy Storage

Nuclear

Other

Total

105.8

471.0

62.6

394.1

102.4

46.7

93.6

6.5

1,282.7

2030

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Energy Storage

Nuclear

Other

Total

85.0

478.6

64.3

440.2

103.7

58.6

90.9

6.5

1,327.7

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Energy Storage

Nuclear

Other

Total

51.6

476.0

55.3

698.5

107.3

113.6

83.7

6.5

1,592.4

2035

Note: In this table, “Non-Hydro RE” includes biomass, geothermal, landfill gas, solar, and wind.

3-18

Table 3-10 shows the total capacity projected to retire by fuel type for the baseline and

the final rule in all run years. The final rule is not projected to result in changes to projected

retirements.

Table 3-10 2028, 2030, and 2035 Projected U.S. Retirements by Fuel Type for the

Baseline and the Final Rule

Projected Retirements (GW)

Baseline

Final Rule

% Change under Final

Rule

37.8

1.3

12.4

2.9

0.1

0.0

54.4

0.0%

56.6

1.7

12.4

2.9

0.1

2.7

0.0

76.5

0.0%

2028

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Nuclear

Other

Total

37.8

1.3

12.4

2.9

0.1

0.0

54.4

2030

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Nuclear

Other

Total

56.7

1.7

12.4

2.9

0.1

2.7

0.0

76.5

2035

Coal

83.7

Natural Gas

4.3

Oil/Gas Steam

22.7

Non-Hydro RE

3.0

Hydro

0.1

Nuclear

9.9

Other

0.1

Total

123.7

Note: In this table, “Non-Hydro RE” includes biomass, geothermal, landfill gas, solar, and wind.

3-19

0.0%

Finally, Table 3-11 shows the projected U.S. new capacity builds by fuel type for the

baseline and the final rule in all run years. For the final rule, the incremental changes in projected

new capacity for any given fuel type are negligible.

Table 3-11 2028, 2030, and 2035 Projected U.S. New Capacity Builds by Fuel Type for

the Baseline and the Final Rule

New Capacity (GW)

Baseline

Final Rule

% Change under Final

Rule

0.0

26.2

3.2

44.8

0.0

74.3

0.0%

0.2%

0.0%

0.0

34.3

15.2

90.8

1.3

0.0

141.6

0.0%

2028

Coal

Natural Gas

Energy Storage

Non-Hydro RE

Hydro

Nuclear

Other

Total

0.0

26.2

3.2

44.8

0.0

74.3

2030

Coal

Natural Gas

Energy Storage

Non-Hydro RE

Hydro

Nuclear

Other

Total

0.0

34.3

15.2

90.8

1.3

0.0

141.5

2035

Coal

0.0

Natural Gas

34.2

Energy Storage

70.2

Non-Hydro RE

349.4

Hydro

4.9

Nuclear

0.0

Other

0.0

Total

458.6

Note: In this table, “Non-Hydro RE” includes biomass, geothermal, landfill gas, solar, and wind.

0.0%

0.1%

0.0%

3.5.5 Generation Mix

In this section, we discuss the projected changes in generation mix for 2028, 2030, and

2035 for the final rule. Table 3-12 presents the projected generation and percentage changes in

3-20

national generation mix by fuel type for run years 2028, 2030, and 2035. These generation mix

estimates reflect limited changes in energy generation as a result of the final rule in any run year.

Estimated changes in coal and natural gas use under the final rule are examined further in

Section 3.5.6.

Table 3-12 2028, 2030, and 2035 Projected U.S. Generation by Fuel Type for the

Baseline and the Final Rule

Generation Mix (TWh)

Baseline

Final Rule

Incremental Change under Final Rule

TWh

-0.1

0.1

0.0

0.0%

0.1%

0.0%

0.0

0.0%

2028

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Energy Storage

Nuclear

Other

Total

472

1,652

1,141

293

751

4,418

472

1,652

1,141

293

751

4,418

2030

Coal

Natural Gas

Oil/Gas Steam

Non-Hydro RE

Hydro

Energy Storage

Nuclear

Other

Total

410

1,670

1,329

298

729

4,560

410

1,670

1,329

298

729

4,560

2035

Coal

236

-0.1

Natural Gas

1,344

0.0

Oil/Gas Steam

0.0

Non-Hydro RE

2,229

0.0

Hydro

319

0.0

Energy Storage

148

0.1

Nuclear

667

0.0

Other

0.0

Total

4,981

0.0

Note: In this table, “Non-Hydro RE” includes biomass, geothermal, landfill gas, solar, and wind.

3-21

0.0%

-0.4%

0.0%

0.1%

0.0%

3.5.6 Coal and Natural Gas Use for the Electric Power Sector

In this section we discuss the estimated changes in coal use and natural gas use in 2028,

2030, and 2035. Table 3-13 and Table 3-14 present percentage changes in national coal usage by

EGUs by coal supply region and coal rank, respectively. These fuel use estimates show small

changes in national coal use in the final rule relative to the baseline in all run years. Additionally,

the final rule is not projected to result in significant coal switching between supply regions or

coal rank.

Table 3-13 2028, 2030, and 2035 Projected U.S. Power Sector Coal Use by Coal Supply

Region for the Baseline and the Final Rule

Million Tons

Baseline

Final Rule

Appalachia

39.8

% Change under

Final Rule

0.1%

Interior

37.8

-0.1%

Region

Waste Coal

Year

7.3

0.0%

West

166.1

166.0

-0.1%

2028

Total

250.9

250.8

0.0%

Appalachia

38.8

0.0%

Interior

35.1

0.0%

7.1

0.0%

West

141.5

0.0%

Total

222.5

0.0%

Appalachia

31.8

31.9

0.1%

Interior

19.4

-0.1%

6.8

0.0%

West

89.0

89.1

0.1%

Total

147.1

147.2

0.0%

Waste Coal

2030

2035

3-22

Table 3-14 2028, 2030, and 2035 Projected U.S. Power Sector Coal Use by Rank for the

Baseline and the Final Rule

Million Tons

Baseline

Final Rule

% Change

under Final

Rule

72.1

0.00%

145.1

0.00%

32.5

32.3

-0.60%

Total

249.6

249.5

0.00%

Bituminous

62.8

0.00%

125.8

0.00%

29.3

0.00%

Total

218

0.00%

Bituminous

42.4

0.00%

74.1

74.2

0.10%

Lignite

24.5

0.00%

Total

140.9

141

0.00%

Rank

Year

Bituminous

Subbituminous

Lignite

Subbituminous

Lignite

Subbituminous

2028

2030

2035

Table 3-15 presents the projected changes in national natural gas usage by EGUs in the

2028, 2030, and 2035 run years. These fuel use estimates reflect negligible changes in projected

gas generation in 2028, 2030, and 2035.

Table 3-15 2028, 2030, and 2035 Projected U.S. Power Sector Natural Gas Use for the

Baseline and the Final Rule

Trillion Cubic Feet

Year

Baseline

Final Rule

2028

2030

2035

11.6

11.7

9.3

11.6

11.7

9.3

% Change

under Final Rule

0.0%

3.5.7 Fuel Price, Market, and Infrastructure

The projected impacts of the final rule on coal and natural gas prices are presented below

in Table 3-16 and Table 3-17, respectively. As with the projected impact of the final rule on fuel

use, there is no significant change projected for minemouth and delivered coal prices due to the

final rule.

3-23

Table 3-16 2028, 2030, and 2035 Projected Minemouth and Power Sector Delivered Coal

Price (2019 dollars) for the Baseline and the Final Rule

$/MMBtu

Year

Minemouth

Delivered

Minemouth

Delivered

Minemouth

Delivered

2028

2030

2035

Baseline

Final Rule

0.98

% Change under

Final Rule

0.0%

1.54

0.0%

1.02

0.0%

1.56

0.0%

1.07

0.0%

1.55

0.0%

Consistent with the projection of no significant change in natural gas use under the final

rule, Henry Hub and power sector delivered natural gas prices are not projected to significantly

change under the final rule over the period analyzed. Table 3-17 summarizes the projected

impacts on Henry Hub and delivered natural gas prices in 2028, 2030, and 2035.

Table 3-17 2028, 2030, and 2035 Projected Henry Hub and Power Sector Delivered

Natural Gas Price (2019 dollars) for the Baseline and the Final Rule

$/MMBtu

Year

Henry Hub

Delivered

Henry Hub

Delivered

Henry Hub

Delivered

2028

2030

2035

Baseline

Final Rule

2.78

% Change under

Final Rule

0.0%

2.84

0.0%

2.89

0.0%

2.95

0.0%

2.87

0.0%

2.88

0.0%

3.5.8 Retail Electricity Prices

EPA estimated the change in the retail price of electricity (2019 dollars) using the Retail

Price Model (RPM). 48 The RPM was developed by ICF for EPA and uses the IPM estimates of

changes in the cost of generating electricity to estimate the changes in average retail electricity

prices. The prices are average prices over consumer classes (i.e., consumer, commercial, and

industrial) and regions, weighted by the amount of electricity used by each class and in each

region. The RPM combines the IPM annual cost estimates in each of the 64 IPM regions with

See documentation available at: https://www.epa.gov/airmarkets/retail-price-model.

3-24

EIA electricity market data for each of the 25 electricity supply regions (shown in Figure 3-1) in

the electricity market module of the National Energy Modeling System (NEMS). 49

Table 3-18, Table 3-19, and Table 3-20 present the projected percentage changes in the

retail price of electricity for the regulatory control alternatives in 2028, 2030, and 2035,

respectively. Consistent with other projected impacts presented above, the projected impacts on

average retail electricity prices at both the national and regional level are projected to be small in

all run years.

See documentation available at:

https://www.eia.gov/outlooks/aeo/nems/documentation/electricity/pdf/EMM_2022.pdf.

3-25

Table 3-18 Projected Average Retail Electricity Price by Region for the Baseline and

under the Final Rule, 2028

All Sectors

2028 Average Retail Electricity Price

(2019 mills/kWh)

Region

Baseline

Final Rule

TRE

FRCC

MISW

73.4

96.4

92.3

73.4

96.4

92.3

% Change

under Final Rule

0.0%

MISC

MISE

MISS

ISNE

NYCW

NYUP

PJME

PJMW

87.9

95.2

81.3

141.8

208.4

121.5

116.9

90.4

88.0

95.2

81.3

141.8

208.4

121.5

116.9

90.4

0.2%

0.0%

PJMC

PJMD

SRCA

SRSE

SRCE

SPPS

SPPC

SPPN

SRSG

CANO

CASO

NWPP

RMRG

BASN

72.4

70.8

94.7

96.7

71.6

75.3

98.5

64.1

101.3

138.7

170.5

75.0

96.4

96.8

72.4

70.8

94.7

96.7

71.6

75.3

98.4

64.1

101.3

138.7

170.5

75.4

96.4

96.8

0.0%

0.5%

0.0%

National

97.1

0.0%

3-26

Table 3-19 Projected Average Retail Electricity Price by Region for the Baseline and

under the Final Rule, 2030

All Sectors

2030 Average Retail Electricity Price

(2019 mills/kWh)

Region

Baseline

Final Rule

TRE

FRCC

MISW

73.3

97.6

93.2

73.3

97.6

93.2

% Change

under Final Rule

0.0%

MISC

MISE

MISS

ISNE

NYCW

NYUP

PJME

PJMW

91.3

109.4

85.7

156.6

210.3

125.7

109.9

97.3

91.5

109.4

85.7

156.6

210.3

125.7

109.9

97.3

0.2%

0.0%

PJMC

PJMD

SRCA

SRSE

SRCE

SPPS

SPPC

SPPN

SRSG

CANO

CASO

NWPP

RMRG

BASN

89.3

76.5

92.1

94.7

70.7

77.7

97.3

65.1

101.7

142.9

173.8

81.6

100.7

96.3

89.3

76.5

92.2

94.7

70.7

77.8

97.3

65.1

101.6

142.9

173.9

81.7

100.7

96.3

0.0%

0.1%

0.0%

National

99.6

0.0%

3-27

Table 3-20 Projected Average Retail Electricity Price by Region for the Baseline and

under the Final Rule, 2035

All Sectors

2035 Average Retail Electricity Price

(2019 mills/kWh)

Region

Baseline

Final Rule

TRE

FRCC

MISW

78.4

91.9

84.5

78.4

91.9

84.5

% Change

under Final Rule

0.0%

MISC

MISE

MISS

ISNE

NYCW

NYUP

PJME

PJMW

81.5

95.7

79.2

156.1

208.9

124.6

108.5

91.8

81.5

95.7

79.2

155.8

208.9

124.6

108.5

91.8

0.1%

0.0%

-0.2%

0.0%

PJMC

PJMD

SRCA

SRSE

SRCE

SPPS

SPPC

SPPN

SRSG

CANO

CASO

NWPP

RMRG

BASN

75.1

71.4

89.4

90.1

67.1

69.5

80.4

63.0

103.4

139.5

172.8

78.5

93.4

96.9

75.1

71.4

89.4

90.1

67.1

69.5

80.4

63.0

103.4

139.5

172.8

78.9

93.4

97.0

0.0%

0.4%

0.0%

National

95.9

0.0%

3-28

Figure 33-1

Electricity Market Module Regions

Source: EIA (http://www.eia.gov/forecasts/aeo/pdf/nerc_map.pdf)

3.6

Limitations of Analysis and Key Areas of Uncertainty

EPA’s power sector modeling is based on expert judgment of various input assumptions

for variables whose outcomes are uncertain. As a general matter, the Agency reviews the best

available information from engineering studies of air pollution controls and new capacity

construction costs to support a reasonable modeling framework for analyzing the cost, emission

changes, and other impacts of regulatory actions for EGUs. The annualized cost of the final rule,

as quantified here, is EPA’s best assessment of the cost of implementing the ru

rule on the power

sector.

The IPM-projected annualized cost estimates of private compliance costs provided in this

analysis are meant to show the increase in production (generating) costs to the power sector in

response to the finalized requirements. To estimate these annualized costs, as discussed earlier,

EPA uses a conventional and widely accepted approach that applies a capital recovery factor

(CRF) multiplier to capital investments and adds that to the annual incremental operating

expenses to calculate annual costs. The CRF is derived from estimates of the cost of capital

3-29

(private discount rate), the amount of insurance coverage required, local property taxes, and the

life of capital. The private compliance costs presented earlier are EPA’s best estimate of the

direct private compliance costs of the rule.

In addition, there are several key areas of uncertainty related to the electric power sector

that are worth noting, including:

• Electricity demand: The analysis includes an assumption for future electricity demand.

To the extent electricity demand is higher and lower, it may increase/decrease the

projected future composition of the fleet.

• Natural gas supply and demand: To the extent natural gas supply and delivered prices

are higher or lower, it would influence the use of natural gas for electricity generation and

overall competitiveness of other EGUs (e.g., coal and nuclear units).

• Longer-term planning by utilities: Many utilities have announced long-term clean

energy and/or climate commitments, with a phasing out of large amounts of coal capacity

by 2030 and continuing through 2050. These announcements are not necessarily reflected

in the baseline and may alter the amount of coal capacity projected in the baseline that

would be covered under this rule.

• FPM emissions and control: As discussed above, the baseline fPM emissions rates for

each unit are based on the analysis documented in the memorandum titled “2024 Update

to the 2023 Proposed Technology Review for the Coal- and Oil-Fired EGU Source

Category.” For those EGUs with rates greater than the final limit, EPA assumes that

control technology summarized in Section 3.4 would be necessary to remain operational.

While the baseline emissions rate for each EGU and the cost and performance

assumption for each PM control technology are the best available to EPA at this time, it

is possible that some EGUs may be able to achieve the revised fPM emissions limits with

less costly control technology (e.g., an ESP upgrade instead of a fabric filter installation).

It is also possible that EPA’s cost assumptions reflect higher technology costs than might

be incurred by EGUs.

These are key uncertainties that may affect the overall composition of electric power

generation fleet and/or compliance with the finalized emissions limits and could thus have an

effect on the estimated costs and impacts of this action. While it is important to recognize these

key areas of uncertainty, they do not change EPA’s overall confidence in the projected impacts

of the final rule presented in this section. EPA continues to monitor industry developments and

makes appropriate updates to the modeling platforms in order to reflect the best and most current

data available.

3-30

Estimated impacts of the Revised 2023 and Later Model Year Light-Duty Vehicle GHG

Emissions Standards are captured in the baseline, 50 while estimated impacts of the Proposed

Rule: Model Years 2027 and Later Light-Duty and Medium-Duty Vehicle Emissions Standards

are not captured in the baseline. 51 The latter rule (in its proposal) is projected to increase the total

demand for electricity by 0.4 percent in 2030 and 3.4 percent in 2040 relative to the baseline

electricity demand projections assumed in this analysis. Estimated impacts of the 2023 Final

Standards of Performance for New, Reconstructed, and Modified Sources and Emissions

Guidelines for Existing Sources: Oil and Natural Gas Sector Climate Review are also not

included in this analysis. The RIA for oil and natural gas sector rule projected small increases in

the price of natural gas as result of the requirements (U.S. EPA, 2023c). All else equal, inclusion

of these two programs would likely result in a modest increase in the fPM reductions and total

cost of compliance for this rule. While we might see less retired capacity in the baseline due to

higher electricity demand, and thus more PM controls under the RTR, the magnitude of the

potential incremental impacts would likely be very small.

3.7

References

Brinkman, G., Bain, D., Buster, G., Draxl, C., Das, P., Ho, J., . . . Zhang, J. (2021). The North

American Renewable Integration Study (NARIS): A U.S. Perspective. Retrieved from

United States: https://www.osti.gov/biblio/1804701

Cole, W. J., Greer, D., Denholm, P., Frazier, A. W., Machen, S., Mai, T., . . . Baldwin, S. F.

(2021). Quantifying the challenge of reaching a 100% renewable energy power system

for the United States. Joule, 5(7), 1732-1748. doi:10.1016/j.joule.2021.05.011

DOE. (2021). The Solar Futures Study. Retrieved from United States:

https://www.osti.gov/biblio/1820105

U.S. EPA. (2005). Regulatory Impact Analysis for the Final Clean Air Interstate Rule. Research

Triangle Park, NC: U.S. Environmental Protection Agency, Office of Air Quality

Planning and Standards, Health and Environmental Impact Division.

https://www.epa.gov/sites/default/files/2020-07/documents/transport_ria_final-clean-airinterstate-rule_2005-03.pdf

U.S. EPA. (2011a). Regulatory Impact Analysis for the Federal Implementation Plans to Reduce

Interstate Transport of Fine Particulate Matter and Ozone in 27 States; Correction of SIP

Approvals for 22 States. Research Triangle Park, NC: U.S. Environmental Protection

86 FR 43726. The RIA for this rule available at: https://nepis.epa.gov/Exe/ZyPDF.cgi?Dockey=P1012ONB.pdf.

88 FR 29184.

3-31

Agency, Office of Air Quality Planning and Standards, Health and Environmental Impact

Division. https://www3.epa.gov/ttn/ecas/docs/ria/transport_ria_final-csapr_2011-06.pdf

U.S. EPA. (2011b). Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards.

(EPA-452/R-11-011). Research Triangle Park, NC: U.S. Environmental Protection

Agency, Office of Air Quality Planning and Standards, Health and Environmental Impact

Division. http://www.epa.gov/ttn/ecas/regdata/RIAs/matsriafinal.pdf

U.S. EPA. (2014a). Economic Analysis for the Final Section 316(b) Existing Facilities Rule.

(EPA-821-R-14-001). Washington DC: U.S. Environmental Protection Agency.

https://www.epa.gov/sites/default/files/2015-05/documents/cooling-water_phase4_economics_2014.pdf

U.S. EPA. (2014b). Guidelines for Preparing Economic Analyses. (EPA 240-R-10-001).

Washington DC: U.S. Environmental Protection Agency, Office of Policy, National

Center for Environmental Economics. https://www.epa.gov/environmentaleconomics/guidelines-preparing-economic-analyses

U.S. EPA. (2015a). Benefit and Cost Analysis for the Effluent Limitations Guidelines and

Standards for the Steam Electric Power Generating Point Source Category. (EPA-821-R15-005). Washington DC: U.S. Environmental Protection Agency.

https://www.epa.gov/sites/default/files/2015-10/documents/steam-electric_benefit-costanalysis_09-29-2015.pdf

U.S. EPA. (2015b). Regulatory Impact Analysis for the Clean Power Plan Final Rule. (EPA452/R-15-003). Research Triangle Park, NC: U.S. Environmental Protection Agency,

Office of Air Quality Planning and Standards, Health and Environmental Impact

Division. https://www.epa.gov/sites/default/files/2020-07/documents/utilities_ria_finalclean-power-plan-existing-units_2015-08.pdf

U.S. EPA. (2015c). Regulatory Impact Analysis: EPA’s 2015 RCRA Final Rule Regulating Coal

Combustion Residual (CCR) Landfills and Surface Impoundments At Coal-Fired Electric

Utility Power Plants. (EPA-821-R-20-003). Washington DC: U.S. Environmental

Protection Agency. https://www.regulations.gov/document/EPA-HQ-RCRA-2009-064012034

U.S. EPA. (2016). Regulatory Impact Analysis of the Cross-State Air Pollution Rule (CSAPR)

Update for the 2008 National Ambient Air Quality Standards for Ground-Level Ozone.

(EPA-452/R-16-004). Research Triangle Park, NC: U.S. Environmental Protection

Agency, Office of Air Quality Planning and Standards, Health and Environmental Impact

Division. https://www.epa.gov/sites/default/files/2020-07/documents/transport_ria_finalcsapr-update_2016-09.pdf

U.S. EPA. (2019). Regulatory Impact Analysis for the Repeal of the Clean Power Plan, and the

Emission Guidelines for Greenhouse Gas Emissions from Existing Electric Utility

Generating Units. (EPA-452/R-19-003). Research Triangle Park, NC: U.S.

Environmental Protection Agency, Office of Air Quality Planning and Standards, Health

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and Environmental Impact Division. https://www.epa.gov/sites/production/files/201906/documents/utilities_ria_final_cpp_repeal_and_ace_2019-06.pdf

U.S. EPA. (2020). Benefit and Cost Analysis for Revisions to the Effluent Limitations

Guidelines and Standards for the Steam Electric Power Generating Point Source

Category. (EPA-821-R-20-003). Washington DC: U.S. Environmental Protection

Agency. https://www.epa.gov/sites/default/files/202008/documents/steam_electric_elg_2020_final_reconsideration_rule_benefit_and_cost_an

alysis.pdf

U.S. EPA. (2021). Regulatory Impact Analysis for the Final Revised Cross-State Air Pollution

Rule (CSAPR) Update for the 2008 Ozone NAAQS. (EPA-452/R-21-002). Research

Triangle Park, NC: U.S. Environmental Protection Agency, Office of Air Quality

Planning and Standards, Health and Environmental Impact Division.

https://www.epa.gov/sites/default/files/202103/documents/revised_csapr_update_ria_final.pdf

U.S. EPA. (2023a). Electricity Sector Emissions Impacts of the Inflation Reduction Act:

Assessment of projected CO2 emission reductions from changes in electricity generation

and use. (EPA 430-R-23-004). Retrieved from

https://www.epa.gov/system/files/documents/202309/Electricity_Emissions_Impacts_Inflation_Reduction_Act_Report_EPA-FINAL.pdf

U.S. EPA. (2023b). Regulatory Impact Analysis for the Final Federal Good Neighbor Plan

Addressing Regional Ozone Transport for the 2015 Ozone National Ambient Air Quality

Standards. (EPA-452/R-23-001). Research Triangle Park, NC: U.S. Environmental

Protection Agency, Office of Air Quality Planning and Standards, Health and

Environmental Impact Division. https://www.epa.gov/system/files/documents/202303/SAN%208670%20Federal%20Good%20Neighbor%20Plan%2020230315%20RIA_Fi

nal.pdf

U.S. EPA. (2023c). 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. (EPA-452/R-23-013). Research Triangle Park,

NC: U.S. Environmental Protection Agency, Office of Air Quality Planning and

Standards, Health and Environmental Impact Division.

https://www.epa.gov/system/files/documents/2023-12/eo12866_oil-and-gas-nsps-egclimate-review-2060-av16-ria-20231130.pdf

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4.1

BENEFITS ANALYSIS

Introduction

This rule is projected to reduce emissions of Hg and non-Hg HAP metals, fine particulate

matter (PM2.5), sulfur dioxide (SO2), nitrogen oxides (NOX), and carbon dioxide (CO2)

nationally. The projected reductions in Hg are expected to reduce the bioconcentration of MeHg

in fish. Subsistence fishing is associated with vulnerable populations, including minorities and

those of low socioeconomic status. Further reductions in Hg emissions should reduce fish

concentrations and exposure to HAP particularly for the subsistence fisher sub-population. The

projected reductions in HAP emissions should help EPA maintain an ample margin of safety by

reducing exposure to MeHg and carcinogenic HAP metals.

Regarding the potential health and ecological benefits of the rule from projected HAP

reductions, we note that these are discussed only qualitatively and not quantitatively. Exposure to

the HAP emitted by the source category, depending on the exposure duration and level of

exposure, is associated with a variety of adverse health effects. These adverse health effects may

include chronic health disorders (e.g., irritation of the lung, skin, and mucus membranes;

decreased pulmonary function, pneumonia, or lung damage; detrimental effects on the central

nervous system; cardiovascular disease; damage to the kidneys; and alimentary effects such as

nausea and vomiting), adverse neurodevelopmental impacts, and increased risk of cancer. See 76

FR 25003–25005 for a fuller discussion of the health effects associated with HAP.

The analysis of the overall EGU sector completed for EPA’s review of the 2020

appropriate and necessary finding (2023 Final A&N Review) identified significant reductions in

cardiovascular and neuro-developmental effects from exposure to MeHg (88 FR 13956).

However, the amount of Hg reduction projected under this rule is a fraction of the Hg estimates

used in the 2023 Final A&N Review. Overall, the uncertainty associated with modeling potential

benefits of Hg reduction for fish consumers would be sufficiently large as to compromise the

utility of those benefit estimates—though importantly, such uncertainty does not decrease our

confidence that reductions in emissions should result in reduced exposures of HAP to the general

population, including MeHg exposures to subsistence fishers located near these facilities.

Further, estimated risks from exposure to non-Hg HAP metals were not expected to exceed

4-1

acceptable levels, although we note that these emissions reductions should result in decreased

exposure to HAP for individuals living near these facilities.

ReducingPM2.5 and SO2 emissions is expected to reduce ground-level PM 2.5

concentrations. Reducing NOX emissions is expected to reduce both ground-level ozone and

PM2.5 concentrations. Below we present the estimated number and economic value of these

avoided PM2.5 and ozone-attributable premature deaths and illnesses. We also present the

estimated monetized climate and health benefits associated with emission reductions projected

under the final rule.

In addition to reporting results, this section details the methods used to estimate the

benefits to human health of reducing concentrations of PM 2.5 and ozone resulting from the

projected emissions reductions. This analysis uses methods for determining air quality changes

that have been used in the RIAs from multiple previous proposed and final rules (U.S. EPA,

2019b, 2020a, 2020b, 2021a, 2022c), including the RIA for the proposal of this rule (U.S. EPA,

2023b). The approach involves two major steps: (1) developing spatial fields of air quality across

the U.S. for a baseline scenario and the final rule for 2028, 2030, and 2035 using nationwide

photochemical modeling and related analyses (see Air Quality Modeling Appendix, Appendix A,

for more details); and (2) using these spatial fields in BenMAP-CE to quantify the benefits under

the final rule and each year as compared to the baseline in that year. 52 See Section 4.3.3 for more

detail on BenMAP-CE. When estimating the value of improved air quality over a multi-year time

horizon, the analysis applies population growth and income growth projections for each future

year through 2037 and estimates of baseline mortality incidence rates at five-year increments.

Additionally, elevated concentrations of GHGs in the atmosphere have been warming the

planet, leading to changes in the Earth’s climate including changes in the frequency and intensity

of heat waves, precipitation, and extreme weather events, rising seas, and retreating snow and

ice. The well-documented atmospheric changes due to anthropogenic GHG emissions are

changing the climate at a pace and in a way that threatens human health, society, and the natural

environment. There will likely be important climate benefits associated with the CO 2 emissions

Note we do not perform air quality analysis on the less stringent regulatory option because it has no quantified

emissions reductions associated with the finalized requirements for CEMS and the removal of startup definition

number two.

4-2

reductions expected from this rule. In this RIA, we monetize climate benefits from reducing

emissions of CO2 using estimates of the SC-CO2.

EPA is unable to quantify and monetize the potential benefits of requiring facilities to

utilize CEMS rather than continuing to allow the use of quarterly testing, but the requirement has

been considered qualitatively. Relative to periodic testing practices, continuous monitoring of

fPM will result in increased transparency, as well as potential emissions reductions from

identifying problems more rapidly. Hence, the final rule may induce further reductions of fPM

and non-Hg HAP metals than we project in this RIA, and these reductions would likely lead to

additional health benefits. However, due to data and methodological challenges, EPA is unable

to quantify these potential additional reductions. The continuous monitoring of fPM required in

this rule is also likely to provide several additional important 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. Additionally, to the extent that the removal of the

second definition of startup leads to actions that may otherwise not occur absent this final rule,

there may be beneficial impacts we are unable to estimate. Though the rule is likely to also yield

positive benefits associated with reducing pollutants other than Hg, non-Hg HAP metals, PM 2.5,

ozone, and CO2, time, resource, and data limitations prevented us from quantifying and

estimating the economic value of those reductions. Specifically, in this RIA EPA does not

monetize health benefits of reducing direct exposure to NO2 and SO2 nor ecosystem effects and

visibility impairment associated with changes in air quality. We qualitatively discuss these

unquantified impacts in this section of the RIA.

4.2

Hazardous Air Pollutant Benefits

This final rule is projected to reduce emissions of Hg and non-Hg HAP metals.

Specifically, projected reductions in Hg are expected to help reduce exposure to MeHg for subpopulations that rely on subsistence fishing. In addition, projected emissions reductions should

also reduce exposure to non-Hg HAP metals including carcinogens such as nickel, arsenic, and

hexavalent chromium, for residents located in the vicinity of these facilities.

4-3

4.2.1 Hg

Hg is a persistent, bioaccumulative toxic metal that is emitted from power plants in three

forms: gaseous elemental Hg (Hg0), oxidized Hg compounds (Hg+2), and particle-bound Hg

(HgP). 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

HgP deposit quickly from the atmosphere impacting local and regional areas in proximity to

sources. MeHg is formed by microbial action in the top layers of sediment and soils, after Hg has

precipitated from the air and deposited into waterbodies or land. Once formed, MeHg is taken up

by aquatic organisms and bioaccumulates up the aquatic food web. Larger predatory fish may

have MeHg concentrations many times that of the concentrations in the freshwater body in which

they live (ATSDR, 2022). MeHg can adversely impact ecosystems and wildlife.

Human exposure to MeHg is known to have several adverse neurodevelopmental

impacts, 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 MeHg 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 MeHg exposure in animal studies (ATSDR, 2022). MeHg has

some genotoxic activity and is capable of causing chromosomal damage in a number of

experimental systems. EPA has classified MeHg as a “possible” human carcinogen (U.S. EPA,

2001).

The projected reductions in Hg under this final rule are expected to reduce the

bioconcentration of MeHg in fish due to Hg emissions from MATS-affected sources. Risk from

near-field deposition of Hg to subsistence fishers has previously been evaluated, using a sitespecific assessment of a lake near three lignite-fired facilities (U.S. EPA, 2020d). The results

suggest that MeHg exposure to subsistence fishers from lignite-fired units is below the current

RfD for MeHg neurodevelopmental toxicity or IQ loss, with an estimated hazard quotient (HQ)

of 0.06. In general, EPA believes that exposures at or below the RfD are unlikely to be

associated with appreciable risk of deleterious effects.

4-4

Regarding the potential magnitude of human health risk reductions and benefits

associated with this rule, we make the following observations. All of the exposure results

generated as part of the 2020 Residual Risk analysis were below the presumptive acceptable

cancer risk threshold and noncancer health-based thresholds. While these results suggest that the

residual risks from HAP exposure are low, we do recognize that this regulation should still

reduce exposure to HAP.

Regarding potential benefits of the rule to the general population of fish consumers, while

we note that the analysis of the overall EGU sector completed for the 2023 Final A&N Review

did identify significant reductions in cardiovascular and neuro-developmental effects, given the

substantially smaller Hg reduction associated with this rule (approximately 900 to 1000 pounds

per year under the final rule compared to the approximately 29 tons of Hg evaluated in the 2023

Final A&N Review), overall uncertainty associated with modeling potential benefits for the

broader population of fish consumers would be sufficiently large as to compromise the utility of

those benefit estimates.

Despite the lack of quantifiable risks from Hg emissions, reductions would be expected to

have some impact (reduction) on the overall MeHg burden in fish for waterbodies near covered

facilities. In the appropriate and necessary determination, EPA illustrated that the burden of Hg

exposure is not equally distributed across the population and that some subpopulations bore

disproportionate risks associated with exposure to emissions from U.S. EGUs. High levels of fish

consumption observed with subsistence fishing were associated with vulnerable populations,

including minorities and those with low socioeconomic status (SES). Reductions in Hg

emissions should reduce MeHg exposure and body burden for subsistence fishers.

U.S. EGU Hg emissions can lead to increased deposition of Hg to nearby waterbodies.

Deposition of Hg to waterbodies can also have an impact on ecosystems and wildlife. Hg

contamination is present in all environmental media with aquatic systems being particularly

impacted due to bioaccumulation. Bioaccumulation refers to the net uptake of a contaminant

from all possible pathways and includes the accumulation that may occur by direct exposure to

contaminated media as well as uptake from food. Atmospheric Hg enters freshwater ecosystems

by direct deposition and through runoff from terrestrial watersheds. Once Hg deposits, it may be

converted to organic MeHg mediated primarily by sulfate-reducing bacteria. Methylation is

4-5

Table 4-1

Health Effects of PM2.5, Ambient Ozone, and Climate Effects

Category

Climate

effects

Effect

—

Information

Ozone ISA2

Section 4.4

IPCC,

Ozone ISA,

PM ISA

Valuation estimate excludes initial hospital and/or emergency department visits.

Not quantified due to data availability limitations and/or because current evidence is only suggestive of causality.

4.3.3 Calculating Counts of Air Pollution Effects Using the Health Impact Function

We use the environmental Benefits Mapping and Analysis Program—Community

Edition (BenMAP-CE) software program to quantify counts of premature deaths and illnesses

attributable to photochemical modeled changes in annual mean PM 2.5 and summer season

average ozone concentrations for the years 2030, 2035, and 2040 using health impact functions

(Sacks et al., 2020). A health impact function combines information regarding: the

concentration-response relationship between air quality changes and the risk of a given adverse

outcome; the population exposed to the air quality change; the baseline rate of death or disease in

that population; and the air pollution concentration to which the population is exposed.

BenMAP quantifies counts of attributable effects using health impact functions, which

combine information regarding the: concentration-response relationship between air quality

changes and the risk of a given adverse outcome; population exposed to the air quality change;

baseline rate of death or disease in that population; and air pollution concentration to which the

population is exposed.

The following provides an example of a health impact function, in this case for PM 2.5

mortality risk. We estimate counts of PM2.5-related total deaths ( ) during each year i among

adults aged 18 and older (a) in each county j in the contiguous U.S. (where  = 1, … ,  and J is

the total number of counties) as:

yij a yija

yija = moija ×(eij-1) × Pija,

Eq[1]

where moija is the baseline total mortality rate for adults aged a = 18-99 in county j in year i

stratified in 10-year age groups,  is the risk coefficient for total mortality for adults associated

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Page 1 of 66

NOT YET SCHEDULED FOR ORAL ARGUMENT

No. 24-1119 and consolidated cases

U.S. COURT OF APPEALS FOR THE DISTRICT OF COLUMBIA CIRCUIT

State of North Dakota, et al.,

Petitioners,

U.S. Environmental Protection Agency,

Respondent.

Petitions for Review of a Final Rule of

the U.S. Environmental Protection Agency

EPA’s Combined Opposition to Motions to Stay Final Rule

Todd Kim

Assistant Attorney General

Of counsel

Matthew McNerney

U.S. Environmental Protection Agency

Office of General Counsel

Washington, D.C.

(Page 1 of Total)

Sue Chen

Redding Cofer Cates

U.S. Department of Justice

Environment & Natural Resources Div.

Environmental Defense Section

P.O. Box 7611

Washington, D.C. 20044

202.305.0283

sue.chen@usdoj.gov

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CERTIFICATE AS TO PARTIES, RULINGS, AND RELATED CASES

As required by D.C. Circuit Rule 27(a)(4), EPA certifies:

A. Parties and amici

Petitioners are:

• Case No. 24-1119: the 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. 24-1154: NACCO Natural Resources Corporation;

• Case No. 24-1179: National Rural Electric Cooperative Association, Lignite

Energy Council, National Mining Association, Minnkota Power

Cooperative, Inc., East Kentucky Power Cooperative, Inc., Associated

Electric Cooperative Inc., Basin Electric Power Cooperative, and Rainbow

Energy Center, LLC;

• Case No. 24-1184: Oak Grove Management Company LLC and Luminant

Generation Company LLC;

• Case No. 24-1190: Talen Montana, LLC;

(Page 2 of Total)

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• Case No. 24-1194: Westmoreland Mining Holdings LLC, Westmoreland

Mining LLC, and Westmoreland Rosebud Mining LLC;

• Case No. 24-1201: America’s Power and Electric Generators MATS

Coalition;

• Case No. 24-1217: NorthWestern Corporation; and

• Case No 24-1223: Midwest Ozone Group.

Respondents are the U.S. Environmental Protection Agency and Michael S.

Regan, Administrator.

Intervenor for Petitioners is San Miguel Electric Cooperative, Inc.

Intervenors for Respondent are Air Alliance Houston, Alliance of Nurses for

Healthy Environments, American Academy of Pediatrics, American Lung

Association, American Public Health Association, Chesapeake Climate Action

Network, Citizens for Pennsylvania’s Future, Clean Air Council, Clean Wisconsin,

Downwinders at Risk, Environmental Defense Fund, Environmental Integrity

Project, Montana Environmental Information Center, Natural Resources Council of

Maine, Natural Resources Defense Council, the Ohio Environmental Council,

Physicians for Social Responsibility, and Sierra Club; and the Commonwealth of

Massachusetts, State of Minnesota, State of Connecticut, State of Illinois, State of

Maine, State of Maryland, State of Michigan, State of New Jersey, State of New

York, State of Oregon, Commonwealth of Pennsylvania, State of Rhode Island,

iii

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State of Vermont, State of Wisconsin, District of Columbia, City of Baltimore,

City of Chicago, and City of New York.

B. Rulings under review

Under review is EPA’s action “National Emission Standards for Hazardous

Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review

of the Residual Risk and Technology Review.” 89 Fed. Reg. 38508 (May 7,

2024).

C. Related cases

No related case is or was before this or any other court.

/s/ Sue Chen

Counsel for EPA

(Page 4 of Total)

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TABLE OF CONTENTS

Certificate as to Parties, Rulings, and Related Cases ............................................... ii

Table of Authorities ................................................................................................ vii

Glossary................................................................................................................... xii

Introduction ................................................................................................................1

Background ................................................................................................................2

A short history of Section 7412.............................................................2

II.

Regulating air-toxics emissions from power plants. .............................4

III.

The 2024 rule.........................................................................................5

IV.

Procedural history..................................................................................7

Standard of Review ....................................................................................................7

Argument....................................................................................................................9

Movants are unlikely to succeed on the merits. ....................................9

The technology review complies with Section

7412(d)(6). ..................................................................................9

“Developments” in practices, processes, and

technology include improvements in those areas. ............9

Section 7412 directs the technology review to

proceed independently of the risk review.......................13

The technology review is sound. ..............................................16

EPA reasonably considered feasibility and costs. ..........16

Surrogate standard. ....................................16

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Mercury standard. ......................................24

EPA properly did not rely on an analysis of

benefits and costs, but reasonably considered them

anyway. ...........................................................................30

EPA reasonably concluded that the rule would not

imperil grid reliability. ....................................................34

The 2024 rule is not a pretext for regulating greenhouse

gases. .........................................................................................37

Section 7412 directs EPA to regulate, not exempt,

sources with obsolete controls that “could” retire. ...................39

Movants show no irreparable harm. ....................................................42

Movants speculate about threats to the grid..............................42

Movants offer no evidence that they will incur great costs

imminently. ...............................................................................44

Regulated Movants. ........................................................45

Non-regulated Movants. .................................................47

III.

A stay would harm the public interest.................................................49

IV.

Any stay should be narrowly tailored. ................................................50

Conclusion ...............................................................................................................50

Certificates of Compliance and Service...................................................................52

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TABLE OF AUTHORITIES

Cases

Alfred L. Snapp & Son, Inc. v. Puerto Rico ex rel. Barez,

458 U.S. 592 (1982) .............................................................................................48

Ass’n of Battery Recyclers v. EPA,

716 F.3d 667 (D.C. Cir. 2013)..............................................................................14

Bd. of Regents of Univ. of Wash. v. EPA,

86 F.3d 1214 (D.C. Cir. 1996)................................................................. 29, 32, 37

Cuomo v. U.S. Nuclear Regul. Comm’n,

772 F.2d 972 (D.C. Cir. 1985)................................................................................7

Ctr. for Auto Safety v. Peck,

751 F.2d 1336 (D.C. Cir. 1985)............................................................................33

CTS Corp. v. EPA,

759 F.3d 52 (D.C. Cir. 2014)................................................................................38

Davis v. Pension Benefit Guar. Corp.,

734 F.3d 1161 (D.C. Cir. 2013)..................................................................... 29, 37

Dep’t of Com. v. New York,

588 U.S. 752 (2019) .............................................................................................38

FCC v. Prometheus Radio Project,

592 U.S. 414 (2021) .............................................................................................31

Gill v. Whitford,

585 U.S. 48 (2018) ...............................................................................................50

La. Env’t Action Network v. EPA,

955 F.3d 1088 (D.C. Cir. 2020)..................................................................... 13, 39

*Authorities upon which we chiefly rely are marked with asterisks

vii

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Loper Bright Enters. v. Raimondo,

144 S. Ct. 2244 (2024)................................................................................. 8, 9, 12

Michigan v. EPA,

576 U.S. 743 (2015) .........................................................................................4, 30

Miss. Comm’n on Env’t Quality v. EPA,

790 F.3d 138 (D.C. Cir. 2015)................................................................................8

Motor Vehicle Mfrs. Ass’n v. State Farm Mut. Auto. Ins. Co.,

463 U.S. 29 (1983) .................................................................................................8

*Nat’l Ass’n for Surface Finishing v. EPA,

795 F.3d 1 (D.C. Cir. 2015)................................................................. 3, 11, 12, 13

Nken v. Holder,

556 U.S. 418 (2009) .................................................................................. 8, 47, 48

NRDC v. EPA,

529 F.3d 1077 (D.C. Cir. 2008)............................................................................12

Ohio v. EPA,

144 S. Ct. 2040 (2024)............................................................................... 9, 44, 48

Pub. Utils. Comm’n of State of Cal. v. FERC,

24 F.3d 275 (D.C. Cir. 1994)................................................................................35

Sierra Club v. EPA,

353 F.3d 976 (D.C. Cir. 2004)................................................................................2

Sinclair Wyo. Refin. Co. v. EPA,

101 F.4th 871 (D.C. Cir. 2024) ............................................................................32

Skidmore v. Swift & Co.,

323 U.S. 134 (1944) ...............................................................................................9

Texas v. EPA,

829 F.3d 405 (5th Cir. 2016) ......................................................................... 34, 44

viii

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United States v. Chem. Found.,

272 U.S. 1 (1926) .................................................................................................37

United States v. Oakland Cannabis Buyers’ Co-op.,

532 U.S. 482 (2001) .............................................................................................49

USPS v. Gregory,

534 U.S. 1 (2001) .................................................................................................37

White Stallion Energy Center LLC v. EPA,

748 F.3d 1222 (D.C. Cir. 2014)........................................................................4, 17

Winter v. NRDC,

55 U.S. (2008) .......................................................................................................8

*Wis. Gas Co. v. FERC,

758 F.2d 669 (D.C. Cir. 1985)........................................................... 42, 44, 45, 48

Statutes

16 U.S.C. § 824a(c)..................................................................................................36

42 U.S.C. § 7412 ....................................................................................................1, 2

42 U.S.C. § 7412(b)(1)-(2) ........................................................................................2

42 U.S.C. § 7412(d) ...................................................................................................2

42 U.S.C. § 7412(d)(2).................................................................................. 3, 16, 34

42 U.S.C. § 7412(d)(3).........................................................................................3, 12

42 U.S.C. § 7412(d)(6).............................................................................. 3, 9, 11, 14

42 U.S.C. § 7412(f)(2) .............................................................................................13

42 U.S.C. § 7412(f)(2)(A)..........................................................................................3

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42 U.S.C. § 7412(n)(1).............................................................................................34

42 U.S.C. § 7412(n)(1)(A) ...................................................................................4, 30

42 U.S.C. § 7491 ......................................................................................................21

42 U.S.C. § 7607(d)(7)(A) ............................................................................ 8, 38, 42

42 U.S.C. § 7607(d)(9).............................................................................................42

Code of Federal Regulations

40 C.F.R. Part 51, App. Y. § IV.D.4.k.....................................................................21

40 C.F.R. Part 63, subpart UUUUU ..........................................................................4

40 C.F.R. § 63.10009 ...............................................................................................46

Federal Registers

66 Fed. Reg. 38108 (July 20, 2001) .........................................................................21

69 Fed. Reg. 48338 (Aug. 9, 2004)..........................................................................14

71 Fed. Reg. 76603 (Dec. 21, 2006) ........................................................................14

73 Fed. Reg. 66964 (Nov. 12, 2008)........................................................................15

77 Fed. Reg. 9304 (Feb. 16, 2012) ........................................................................4, 6

80 Fed. Reg. 75178 (Dec. 1, 2015) ..........................................................................20

81 Fed. Reg. 24420 (Apr. 25, 2016) ..........................................................................5

85 Fed. Reg. 31286 (May 22, 2020) ..........................................................................5

86 Fed. Reg. 7037 (Jan. 25, 2021) ...........................................................................38

87 Fed. Reg. 7624 (Feb. 9, 2022) ............................................................................36

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88 Fed. Reg. 13956 (Mar. 6, 2023) ......................................................................5, 30

88 Fed. Reg. 24854 (Apr. 24, 2023) ........................................................................25

89 Fed. Reg. 38508 (May 7, 2024) .............................................. 2, 4, 5, 6, 7, 10, 12,

........................................................................................ 13, 14, 15, 16, 17, 18, 19,

........................................................................................ 20, 22, 23, 24, 25, 26, 27,

......................................................................................... 28, 29, 30, 31, 32, 33, 34

................................................................................... 35, 36, 37, 39, 40, 41, 46, 50

89 Fed. Reg. 39798 (May 9, 2024) ..........................................................................21

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GLOSSARY

2023 Andover Report

Andover Technology Partners, Assessment

of Potential Revisions to the Mercury and

Air Toxics Standards (June 15, 2023),

attached as Lassiter Decl. Ex. A

2023 Technology Memo

EPA, Memorandum on 2023 Technology

Review for the Coal- and Oil-Fired EGU

Source Category (Jan. 2023), attached as

Lassiter Decl. Ex. B

2024 Technical Memo

EPA, Memorandum on 2024 Update to the

2023 Proposed Technology Review for the

Coal- and Oil-Fired EGU Source Category

(Jan. 2024), attached as Lassiter Decl. Ex. C

2024 Technical Memo Att. 1

Attachment 1 to 2024 Technical Memo,

attached as Lassiter Decl. Ex. D

2024 Technical Memo Att. 2

Attachment 2 to 2024 Technical Memo,

attached as Lassiter Decl. Ex. E

Am. Power Mot.

Petitioners’ Motion for Stay Pending

Judicial Review (July 8, 2024) in Case No.

24-1201, filed by America’s Power and

Electric Generators MATS Coalition

Cichanowicz Report

J. Edward Cichanowicz et al., Technical

Comments National Emission Standards for

Hazardous Air Pollutants: Coal- and Oilfired Electric Utility Steam Generating Units

Review of Residual Risk and Technology

(June 19, 2023), attached as Lassiter Decl.

Ex. F

EPA

U.S. Environmental Protection Agency

xii

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lb/MMBtu

pounds per million British thermal units of

heat input

lb/TBtu

pounds per trillion British thermal units of

heat input

Lignite Council Comment

Comment from Lignite Energy Council

(June 23, 2023), attached as Lassiter Decl.

Ex. G

Midwest Ozone Mot.

Motion for Stay (July 8, 2024) filed by

Midwest Ozone Group in Case No. 24-1223

PM CEMS Memo

EPA, Memorandum: PM CEMS Random

Error Contribution by Emission Limit (Mar.

22, 2023), attached as Lassiter Decl. Ex. H

Reg. Impact Analysis

EPA, Regulatory Impact Analysis for the

Final National Emission Standards for

Hazardous Air Pollutants: Coal- and OilFired Electric Utility Steam Generating

Units Review of the Residual Risk and

Technology Review (Apr. 2024), attached as

Lassiter Decl. Ex. I

Resource Adequacy

Memo

EPA, Resources Adequacy Analysis:

Vehicle Rules, Final 111 EGU Rules, ELG

and MATS RTR: Technical Memo (Apr.

2024), attached as Lassiter Decl. Ex. J

Resp. to Comments

EPA, Summary of Public Comments and

Responses on Proposed Rule (Apr. 2024),

attached as Lassiter Decl. Ex. K

Rural Mot.

Petitioners’ Motion for Stay of the Final

Rule (June 21, 2024) in Case No. 24-1179,

filed by National Rural Electric Cooperative

Association et al.

xiii

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Sargent & Lundy Report

Sargent & Lundy, PM Incremental

Improvement Memo (Mar. 2023), attached

as Lassiter Decl. Ex. L

States Mot.

Petitioners’ Amended Motion for Stay (June

7, 2024) in Case No. 24-1119, filed by

North Dakota et al.

Talen Mot.

Petitioner Talen Montana, LLC and

Petitioner NorthWestern Corporation’s Joint

Motion for Stay (June 27, 2024) in Case

Nos. 24-1190 and 24-1217

Westmoreland Mot.

Petitioner’s Motion for Stay of the Final

Rule (June 27, 2024) in Case No. 24-1194,

filed by Westmoreland Mining Holdings

LLC, Westmoreland Mining LLC, and

Westmoreland Rosebud Mining LLC

xiv

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INTRODUCTION

Congress’s view on toxic air pollution is simple: Less is better. To that end,

Congress decided that emission standards would be revised to reflect developments

in emission-control practices, processes, and technologies.

The Clean Air Act’s air-toxics program, 42 U.S.C. § 7412, embodies that

approach. So does EPA’s action here tightening two standards for power plants.

Better and cheaper emission controls have made stricter standards feasible and

their costs reasonable. So much so that almost all regulated entities can already

meet those standards, while a small group of laggards emits an outsized share of

toxic pollution. EPA, in line with Section 7412, thus reasonably adopted stricter

standards.

Six sets of petitioners, in filings totaling over 2,400 pages, move to stay

EPA’s action. But quantity is not quality, and Movants offer no meritorious claim

of a legal or record-based flaw in the standards. Nor can they show a clear and

present need for the extraordinary relief they seek. The most that Movants can say

is that the standards “may” (or may not) affect electricity grids, while the

compliance date is three years away (with a one-year extension also available).

That reticence confirms that there is no emergency to justify a stay. The Court

should deny the motions.

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BACKGROUND

A short history of Section 7412.

The Clean Air Act regulates emissions of hazardous air pollutants (or

colloquially, air toxics) under 42 U.S.C. § 7412. These pollutants include

neurotoxins like mercury, human carcinogens like arsenic and chromium, and a

host of other toxic chemicals. See id. § 7412(b)(1)-(2); 89 Fed. Reg. 38508,

38515/2-3 (May 7, 2024).

Section 7412 began as a risk-based program. Under that regime, EPA had to

assess a pollutant’s risk before setting emission limits. See Sierra Club v. EPA,

353 F.3d 976, 979 (D.C. Cir. 2004). That approach proved “disappointing”

because risk analysis was hard and slow going. Id.; see 89 Fed. Reg. at 38513/3.

It took EPA 20 years to regulate just 7 air toxics. 89 Fed. Reg. at 38514/1.

Frustrated with EPA’s sluggish pace in curbing air-toxics emissions,

Congress in 1990 revamped Section 7412, transforming it into a technology-driven

regime. Sierra Club, 353 F.3d at 979-80. The new regime, designed to swiftly

slash emissions based on what is technologically achievable, uses a two-phase

regulatory process. 89 Fed. Reg. at 38513/2.

In phase one, EPA sets emission standards for categories of sources that emit

air toxics. 42 U.S.C. § 7412(d). The standards, based on maximum achievable

control technologies rather than risk, are set by examining what the best2

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performing 12 percent of existing sources can do. Id. § 7412(d)(3). These

standards (dubbed the “MACT floor”) serve as the stringency floor.

EPA can go beyond that floor and set stricter standards if they are

“achievable.” Id. § 7412(d)(2). In this analysis, EPA considers “the cost of

achieving such emission reduction, and any non-air quality health and

environmental impacts and energy requirements….” Id. Once EPA sets initial

emission standards (be it the floor or beyond the floor), phase one ends.

Phase two entails reviewing existing standards. Section 7412 requires two

reviews that proceed on “distinct, parallel” tracks. Nat’l Ass’n for Surface

Finishing v. EPA, 795 F.3d 1, 5 (D.C. Cir. 2015). The first is a risk review,

required within eight years after standards are promulgated for a source category.

42 U.S.C. § 7412(f)(2)(A). In the risk review, EPA considers whether the

standards provide “an ample margin of safety” to protect public health and the

environment. Id. If they do not, EPA must tighten the standards. Id.; see Surface

Finishing, 795 F.3d at 5. Section 7412(f)(2), however, does not require EPA to

eliminate all risk to public health and the environment.

The other review—at issue here—is a technology review. This is a recurring

review that happens at least every eight years. 42 U.S.C. § 7412(d)(6). In the

technology review, EPA considers “developments in practices, processes, and

control technologies” and “revise[s the standards] as necessary.” Id. Because

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technology reviews necessarily contemplate going beyond the floor, EPA also

looks to factors enumerated in Section 7412(d)(2) to determine whether stricter

standards are achievable. See 89 Fed. Reg. at 38531/1 (explaining that technology

reviews consider “costs, technical feasibility, and other factors”).

II.

Regulating air-toxics emissions from power plants.

Coal- and oil-fired power plants are among the largest domestic emitters of

mercury, arsenic, chromium, lead, and other air toxics. Id. at 38509/3. In 2012

EPA found that it was “appropriate and necessary” to regulate air-toxics emissions

from coal- and oil-fired electric utility steam-generating units (that is, power

plants), and promulgated standards to do so. 77 Fed. Reg. 9304 (Feb. 16, 2012);

42 U.S.C. § 7412(n)(1)(A); 40 C.F.R. Part 63, subpart UUUUU.

This Court upheld the 2012 rule. See White Stallion Energy Ctr. LLC v.

EPA, 748 F.3d 1222, 1247-51 (D.C. Cir. 2014) (per curiam). On petitions for

certiorari, the Supreme Court limited review to the threshold issue of whether EPA

had to consider costs in its “appropriate and necessary” finding. Michigan v. EPA,

576 U.S. 743 (2015). Because EPA did not do so, the Supreme Court reversed this

Court’s judgment. Id. at 760. The Supreme Court never opined on the 2012

standards themselves, and this Court remanded the rule to EPA while leaving those

standards in place. Order, White Stallion, Case No. 12-1100 (D.C. Cir. Dec. 15,

2015).

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On remand, EPA completed supplemental “appropriate and necessary”

findings that address costs. 81 Fed. Reg. 24420 (Apr. 25, 2016); see 88 Fed. Reg.

13956, 13962/1-3 (Mar. 6, 2023) (summarizing administrative history). Most

recently, in 2023 EPA considered costs and found that it is appropriate and

necessary to regulate air-toxics emissions from coal- and oil-fired power plants. 88

Fed. Reg. at 13956/1. No one challenged that finding.

Meanwhile, in 2020, EPA completed its risk review and first technology

review. 85 Fed. Reg. 31286 (May 22, 2020). In the risk review, EPA concluded

that the 2012 standards provided an ample margin of safety and thus need not be

revised. Id. at 31314/3. In the technology review, EPA found no developments in

practices, processes, or control technologies to warrant revision. Id.

III.

The 2024 rule.

In 2024, EPA reviewed the 2020 action. 89 Fed. Reg. at 38508/1. It did not

reopen the 2020 risk review. Id. at 38518/1-2. But EPA disagreed with the 2020

technology review: It determined there are developments in practices, processes,

and control technologies that warrant revising the 2012 standards. Id. at 38518/3.

Although the fundamental nature of emission-control technologies had not changed

since 2012, better practices, along with technical and operational improvements,

made those controls more efficient and cheaper to use. Id. at 38530/1-2, 38537/3;

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see id. at 38541/3 (noting that the 2020 review did not address these

developments).

Movants focus on two standards that EPA revised for coal-fired units:

Surrogate standard for non-mercury metals: The 2012 rule set emission

standards for non-mercury metals like arsenic, chromium, and lead. Id. at 38510/1

& n.2. It also gave regulated entities the option to use a surrogate standard based

on filterable particulate matter, the control of which also reduces non-mercury

metals. Id. at 38510/1. Almost all coal-fired units chose to use the surrogate

standard in lieu of the metals standards. Id. In the 2024 rule, EPA tightened the

surrogate standard to a level that almost 90 percent of coal-fired units could

already meet. Id. at 38510/1, 38524/3. The stricter standard would thus bring the

stragglers in line with the rest of the industry.

Mercury standard for lignite units: Lignite coal, mined mostly in North

Dakota and Texas, ranks lowest among all coals in terms of quality because it has

the lowest energy content. 2024 Technical Memo 37. In 2021, lignite accounted

for only about 8 percent of domestic coal production. Id. By contrast, bituminous

and subbituminous coal, both ranked higher than lignite, together accounted for

over 90 percent. Id.

The 2012 rule set two mercury standards, one for units burning lignite coal,

and a stricter standard for units burning all other types of coal. 77 Fed. Reg. 9304,

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9367 (table 3) (Feb. 16, 2012); 89 Fed. Reg. at 38537/2. In the 2024 rule, EPA

determined that cost-effective controls are available for lignite units to meet the

same mercury limit that has applied to other coal-fired units, and it tightened the

standard for lignite units accordingly. 89 Fed. Reg. at 38537/3-49/2.

The rule took effect on July 8, 2024. Id. at 38508/1. Power plants have

three years, until July 2027, to comply, and their permitting authorities can grant a

one-year extension when necessary. Id. at 38519/3.

IV.

Procedural history.

States, power plants, mining companies, and others filed nine petitions for

review of the 2024 rule. Six stay motions followed. States Mot. (June 7, 2024);

Rural Mot. (June 21, 2024); Talen Mot. (June 27, 2024); Westmoreland Mot. (June

27, 2024); Midwest Ozone Mot. (July 8, 2024); Am. Power Mot. (July 8, 2024);

see Petitioner NACCO Natural Resources Corp.’s Joinder in the State Petitioners’

Motion for Stay (June 14, 2024). The Court granted EPA’s request to file a

consolidated response. Order (July 1, 2024).

STANDARD OF REVIEW

“On a motion for stay, it is the movant’s obligation to justify the court’s

exercise of such an extraordinary remedy.” Cuomo v. U.S. Nuclear Regul.

Comm’n, 772 F.2d 972, 978 (D.C. Cir. 1985) (per curiam), abrogated on other

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grounds by Winter v. NRDC, 555 U.S. 7 (2008). Movants must show (1) a

likelihood of success on the merits; (2) irreparable injury to them if relief is denied;

(3) lack of substantial harm to others; and (4) where the public interest lies. Nken

v. Holder, 556 U.S. 418, 434 (2009). The last two criteria merge here. Id. at 435.

On the merits, the disputed standards are reviewed under the same arbitraryand-capricious standard as under the Administrative Procedure Act. See 42 U.S.C.

§ 7607(d)(9)(A); Miss. Comm’n on Env’t Quality v. EPA, 790 F.3d 138, 150 (D.C.

Cir. 2015) (per curiam). The review is a “narrow” one and “a court is not to

substitute its judgment for that of the agency.” Motor Vehicle Mfrs. Ass’n v. State

Farm Mut. Auto. Ins. Co., 463 U.S. 29, 43 (1983); see also Loper Bright Enters. v.

Raimondo, 144 S. Ct. 2244, 2261 (2024) (“Section 706 [of the Administrative

Procedure Act] does mandate that judicial review of agency policymaking and

factfinding be deferential.” (emphasis omitted)). The Court should uphold a

decision when the agency considered the relevant factors and articulated a rational

connection between the facts found and the choices made. State Farm, 463 U.S. at

43. That is true even when the decision has “less than ideal clarity” so long as “the

agency’s path may reasonably be discerned.” Id. (internal quotation marks

omitted).

Finally, an agency’s “interpretations and opinions,” made in pursuance of

official duty and based on special experience, constitute a “‘body of experience

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and informed judgment to which courts and litigants could properly resort for

guidance,’ even on legal questions.” Loper Bright, 144 S. Ct. at 2259 (quoting

Skidmore v. Swift & Co., 323 U.S. 134, 139-40 (1944) (internal brackets

omitted)).

ARGUMENT

No stay should issue. Movants have not shown a likelihood of success on

the merits. Nor do they have “strong arguments about the harms they face and

equities involved.” Ohio v. EPA, 144 S. Ct. 2040, 2053 (2024). To the contrary,

Movants’ claims of irreparable harm lack evidence and the equities disfavor a stay.

Movants are unlikely to succeed on the merits.

Movants are unlikely to prevail on the merits. First, their reading of Section

7412 clashes with circuit precedent, not to mention statutory text and design.

Second, their record-based arguments ignore much of the record. Third, though

Movants accuse EPA of improper motive in the rulemaking, the record belies that

fiction. Finally, Movants’ arguments as to the Colstrip facility flout Section 7412.

The technology review complies with Section 7412(d)(6).

“Developments” in practices, processes, and technology

include improvements in those areas.

Section 7412(d)(6) requires EPA to revise existing emission standards as

necessary, “taking into account developments in practices, processes, and control

technologies.” In the 2024 rule, EPA identified a “clear trend in control efficiency,

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costs, and technological improvements” since 2012—a trend that the 2020

technology review overlooked. 89 Fed. Reg. at 38521/1, 38541/3; contra Rural

Mot. 18. These improvements include more durable filter-bag material, better

monitoring practices, and the development of sulfur-resistant chemicals designed

to capture mercury from bituminous and lignite coals. 89 Fed. Reg. at 38521/1,

38530/2, 38541/3. All these changes improved how effectively coal-fired units can

reduce their air-toxics emissions. Partly due to those improvements, meeting the

2012 standards costs less money than expected. Id. at 38530/1.

Movants’ contention that no “development” occurred runs aground on the

facts and the law. On the facts, Movants either overlook new products (like sulfurresistant chemicals) or downplay other advances. E.g., States Mot. 7; Rural Mot.

9-11; Talen Mot. 6-10; Westmoreland Mot. 17-18. But dismissing improvements

as trivial does not make them so. For example, more durable filter bags lower both

the risk that a control might fail, and the wear and tear that impairs efficacy. 89

Fed. Reg. at 38530/2; contra Westmoreland Mot. 17-18. That is a meaningful

improvement. It is unclear what kind of “validat[ion]” Movants demand, for

Section 7412(d)(6) does not require EPA to “quantify” improved efficacy. Talen

Mot. 8.

At bottom, Movants’ dismissive attitude is rooted in a misunderstanding of

the law. “Developments,” Movants urge, means changes that are both “new and

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significant.” Westmoreland Mot. 16. On that view, in technology reviews EPA

can consider only practices, processes, and technologies that differ fundamentally

from what came before. See Rural Mot. 9-11; States Mot. 6-7; Talen Mot. 6-10.

But that is not what Section 7412(d)(6) says. “Developments,” in its ordinary

usage, means “the act, process, or result of developing,” which in turn means “to

cause to evolve or unfold gradually.” See “Development” and “Developing,”

Merriam-Webster; 1 Talen Mot. 7 (offering similar definition). The statute thus

encompasses incremental changes over time. And that is how progress happens in

the real world, where true overnight revolutions in technology are rare; much more

common are modest changes that gradually but meaningfully improve the status

quo.

This Court rejected Movants’ view years ago in Surface Finishing. Though

petitioners there did not directly challenge the meaning of “developments,” they

argued that EPA had failed to identify specific developments that warranted

revising standards. 795 F.3d at 11. The Court disagreed, holding that EPA

permissibly accounted for developments under Section 7412(d)(6)—developments

that, as interpreted by EPA, covered “not only wholly new methods,” but also

“technological improvements,” “improvements in efficiency,” and “reduced costs.”

Id. (internal quotation marks omitted). In so holding, the Court necessarily agreed

Available at https://perma.cc/K9LL-9SQP; https://perma.cc/2TE7-GNUB.

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with EPA’s reading of “developments” to include technologies that, though “not

brand new,” underwent “improvements [that] resulted in emissions reductions.”

Id.; contra Talen Mot. 7. The improvements identified in the 2024 rule—longerlasting filter bags, new chemicals to control mercury emissions, improved

processes—fall squarely within the kind of developments this Court recognizes as

valid under Section 7412(d)(6). 2 See 89 Fed. Reg. at 38521/1-2.

To be sure, Surface Finishing applied the Chevron framework, which the

Supreme Court recently overruled. Loper Bright, 144 S. Ct. at 2273; see 795 F.3d

at 7. But Loper Bright did “not call into question prior cases that relied on the

Chevron framework” despite the “change in interpretive methodology.” 144 S. Ct.

at 2273. So Surface Finishing’s holding that EPA’s action was lawful remains

good law. Cf. Talen 28(j) Letter (July 17, 2024) (advising Court of Loper Bright).

In NRDC v. EPA, this Court did not rewrite the statute by reading

“developments” to mean only “technological improvements.” 529 F.3d 1077

(D.C. Cir. 2008); contra States Mot. 7; Talen Mot. 7; Westmoreland Mot. 18;

Talen 28(j) Letter 1-2. There, the Court said that technology reviews do not

involve resetting the MACT floor. 529 F.3d at 1084. But even if they did, the

Court added, petitioners had not identified any “technological innovations”

overlooked by EPA. Id. The Court never purported to interpret “developments.”

And the 2024 rule did not reset MACT floors. Contra Rural Mot. 11. That

process entails analyzing what the best-performing 12 percent of existing sources

can do. 42 U.S.C. § 7412(d)(3). EPA analyzed almost all sources here. See 2024

Technical Memo 9, 28; 89 Fed Reg. at 38553/3 & n.88 (noting that EPA lacked

relevant data for only about 6 percent of coal-fired units).

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EPA’s—and the Court’s—reading of “developments” aligns not only with

statutory text, but also statutory design. Congress rewrote Section 7412 as a

technology-based regime. Whereas it ordered a one-time risk review, Congress

specified that technology reviews recur at least every eight years. The goal is to

ensure that, over time, EPA maintains standards that are “on pace with emerging

developments that create opportunities to do even better.” La. Env’t Action

Network v. EPA, 955 F.3d 1088, 1093 (D.C. Cir. 2020) (LEAN). Congress, in

other words, wanted to keep reducing air-toxics emissions when technology

allows. 89 Fed. Reg. at 38514/3. It would stymie congressional intent to ignore

incremental advances that fall short of being “brand-new.” Rural Mot. 10-11; see

States Mot. 7; Talen Mot. 7-10; Westmoreland Mot. 16.

Section 7412 directs the technology review to proceed

independently of the risk review.

Also meritless is Movants’ insistence that EPA cannot tighten standards

found to have an ample margin of safety in the risk review. E.g., Am. Power Mot.

5-9; Midwest Ozone Mot. 5; States Mot. 6, 8; Rural Mot. 17-18; Talen 28(j) Letter

2. Once again, Movants overlook statutory text and design.

Section 7412 imposes separate and distinct requirements on risk and

technology reviews. Surface Finishing, 795 F.3d at 5. The risk review asks

whether, given currently available information, existing standards offer an ample

margin of safety to protect public health and the environment. 42 U.S.C.

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§ 7412(f)(2). It also directs EPA to require that margin within eight years of

promulgating the original standards. Id.

In contrast, the technology review asks—on a recurring basis—whether

advances in emission controls warrant stricter standards. Id. § 7412(d)(6). It

applies to all standards, including those that provide ample margins of safety.

Congress, in other words, wanted EPA to consider tightening standards based on

developments in controls even after safety margins are in place. Otherwise, it

would not have required the technology review to recur once the risk review was

complete. Nor does Section 7412(d)(6) require technology reviews to account for

safety margins or health and environmental risks. See Ass’n of Battery Recyclers v.

EPA, 716 F.3d 667, 672 (D.C. Cir. 2013) (per curiam) (“[N]othing in section

[74]12(d)(6)’s text suggests that EPA must consider” public-health factors); 89

Fed. Reg. at 38525/2-3. 3 Rather, technology reviews consider factors like

feasibility and costs. See 89 Fed. Reg. at 38531/1.

This setup reflects Congress’s decision that technological progress should

drive the regulation of air toxics independent of EPA’s risk assessment. Id. at

EPA often tightens Section 7412 standards with ample margins of safety. See 89

Fed. Reg. at 38525 n.29 (giving examples). So what it did here was not a “change

of position.” Rural Mot. 18. Granted, EPA has, in its discretion, considered risk

during technology reviews. States Mot. 4 (citing 69 Fed. Reg. 48338 (Aug. 9,

2004); 71 Fed. Reg. 76603 (Dec. 21, 2006)); Westmoreland Mot. 13. But as the

agency noted on one such occasion, an ample margin of safety does not bar

tightening standards under Section 7412(d)(6). 71 Fed. Reg. at 76609/2.

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38525/3. After all, in revamping Section 7412, Congress made clear that air-toxics

emissions are inherently dangerous and sought to reduce those emissions as much

as achievable using technology. Id. at 38513/3-14/3. And the reality is that

scientific advances and newly available data sometimes show that things we had

thought “safe” are in fact risky. See, e.g., 73 Fed. Reg. 66964, 66975/2 (Nov. 12,

2008) (updating air-quality standards for lead based on new evidence of

neurotoxicity at low doses). In choosing technology-based standards, Congress

declined to tether the air-toxics program to risk assessments that could become

outdated.

Further, an “ample margin of safety” determination does not mean zero risk.

Contra States Mot. 1, 6, 10; Rural Mot. 17-18; Talen Mot. 14-15; Westmoreland

Mot. 12-13. Coal-fired units emit air toxics that cause serious health problems.

Though risks are now much lower, they still exist—and these risks mattered to

Congress. 89 Fed. Reg. at 38556/3, 38541/3; see id. at 38524/3 (noting disparity in

exposure to nearby communities from well-controlled sources versus other

sources); Reg. Impact Analysis 4-5, 4-7. That is why Congress directed EPA to

continue to require achievable reductions in air-toxics emissions as much as

possible, even when standards offer an ample margin of safety.

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The technology review is sound.

EPA reasonably considered feasibility and costs.

EPA considers “costs, technical feasibility, and other factors when

evaluating whether it is necessary to revise existing emission standards under

[Section 7412](d)(6) to ensure the standards ‘require the maximum degree of

emission reductions…achievable.’” 89 Fed. Reg. at 38531/1 (quoting 42 U.S.C.

§ 7412(d)(2)). Here, deference is due EPA’s reasonable conclusion that the two

challenged standards are achievable given its consideration of those factors.

Surrogate standard.

The rule lowered the surrogate standard for non-mercury metals from 0.030

lb/MMBtu to 0.010 lb/MMBtu, measured on a rolling-average basis. Id. at

38510/2 & n.4, 38566/1. This new standard is achievable because it is feasible and

its costs are reasonable. See id. at 38531/1. At a minimum, EPA acted reasonably

in so concluding.

The standard is feasible because almost all coal-fired units showed that they

could already meet it. Id. at 38530/1-3. In this analysis, EPA considered the units’

ability to emit at or below 0.010 lb/MMBtu, and to do so over time.

First, quarterly emissions data showed that even before EPA proposed 0.010

lb/MMBtu as a standard, most coal-fired units could achieve that level. The data

covers 275 out of 314 coal-fired units. 2023 Technology Memo 2; 2024 Technical

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Memo 8; 89 Fed. Reg. at 38553/3. Because electricity demand—and thus

emissions—peaks in winter and summer, EPA focused on data from those quarters.

2024 Technical Memo 3; Resp. to Comments 24; cf. Rural Mot. 14-15 (quoting

White Stallion, 748 F.3d at 1251, to argue that “achievable” means “capable of

being met under most adverse conditions which can reasonably be expected to

recur”); contra id. at 12 (misstating that EPA reviewed data “from quarters with

the lowest emission rates”); Am. Power Mot. 9-10. The winter and summer data

showed that 91 percent of the units achieved emission rates of 0.010 lb/MMBtu or

less. 89 Fed. Reg. at 38530/2; 2023 Technology Memo 4-8.

Then, in response to comments, EPA also considered data from other

quarters. 89 Fed. Reg. at 38530/2. It reviewed all quarterly emissions data it had

for 62 coal-fired units. Id. This review, which accounts for the lower-emitting

seasons of spring and autumn, found that an even greater percentage of units—93

percent—achieved 0.010 lb/MMBtu or less. Id.

Second, EPA considered average emission rates at 296 coal-fired units.

2024 Technical Memo 9. Because emission rates can vary, it is important to

consider average rates, which show a unit’s ability to emit at 0.010 lb/MMBtu on a

sustained basis. See Resp. to Comments 30-31 (noting that average rates account

for unit variability); cf. Am. Power Mot. 9-17 (sidestepping this analysis); Rural

Mot. 12-13 (same). The data showed that 263 units (or 89 percent) can

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consistently achieve that level of control. 89 Fed. Reg. at 38530/3, 38533/3; see id.

at 38522/1 (noting that Movant National Rural Electric Cooperative Association’s

estimate came close); 2024 Technical Memo 17 & Att. 2; contra Am. Power Mot.

15-16. Indeed, the median of the average rates was only 0.004 lb/MMBtu. 89 Fed.

Reg. at 38522/1. Even among the 33 units (11 percent) that did not average 0.010

lb/MMBtu or less, more than half achieved that level at some point. See 2024

Technical Memo Att. 1 at 50-51 (column F).

Given that almost all regulated units could, with existing technology,

consistently emit at or below 0.010 lb/MMBtu, EPA reasonably set the surrogate

standard at that level. Of course, among units that averaged 0.010 lb/MMBtu or

less, emissions at times exceeded that level. See Am. Power Mot. at 12-15

(spotlighting Coronado facility); Resp. to Comments 25 (noting that Coronado’s

rolling-average emissions were at or below 0.010 lb/MMBtu about 70 percent of

the time). Those higher levels are unsurprising because they happened when the

standard was still 0.030 lb/MMBtu. There was nothing special about 0.010

lb/MMBtu then, and one would not expect regulated units to try to keep their

emissions below that level. See Resp. to Comments 36; 89 Fed. Reg. at 38510/1

n.3. So the sporadic higher levels do not alter either the fact that regulated units

could, using existing controls, average 0.010 lb/MMBtu, or the conclusion that the

0.010 lb/MMBtu standard is feasible. Contra Am. Power Mot. 15-16.

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EPA also explained why the standard’s compliance costs are reasonable. 89

Fed. Reg. at 38533/1-34/1. First, even before EPA adopted the new standard,

almost all coal-fired units had invested in the necessary emission controls to meet

it. Id. at 38533/3. Had costs been unreasonable, those investments would not have

happened. Second, compliance costs are only 0.03 percent of coal-fired units’

revenue. Id. at 38533/2. Third, EPA accounted for factors that skewed its cost

estimate: Two units at the Colstrip facility in Montana are the only coal-fired units

in the country without modern emission controls. Id. at 38533/3. To meet the

standard, those two would have to install better controls. Id. The cost of their

upgrades accounts for over 40 percent of total annual costs. Id.4 At the same time,

of the 33 units that would incur compliance costs, 20 account for only 1 percent of

total annual costs. Id. at 38533/3-34/1; see Resp. to Comments 31, 37; 2024

Technical Memo 15; contra Am. Power Mot. 11-12. So for most of the affected

units, EPA’s annual-cost estimates greatly overstate their actual costs.

Some Movants focus on the surrogate standard’s cost-effectiveness

(meaning the cost per ton or pound of pollution reduction). E.g., States Mot. 10.

That figure, they say, far exceeds what EPA had rejected for other air-toxics

standards in industries as disparate as petroleum refining, iron-ore processing, and

EPA assumed that Colstrip would install fabric filters. 2023 Technology Memo

9. Filter-bag vendors have “historically offered…guarantees [of emission rates] at

0.010 lb/MMBtu.” Sargent & Lundy Report 2, 9; contra Talen Mot. 18.

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portland-cement manufacturing. Id.; Westmoreland Mot. 10-12; see 89 Fed. Reg.

at 38522/2-3. Yet what it reasonably costs to reduce a pound of pollutants in one

industry may be unreasonable in a very different industry. 89 Fed. Reg. at

38523/3-24/3.5 Cost-effectiveness is also just one metric that EPA considers

alongside many others. Id. at 38523/3-24/1. Those other metrics here—the broad

adoption of necessary controls, the modest cost-to-revenue ratio, and the skewed

cost estimate toward one high-emitting facility—show that EPA reasonably

imposed costs on a small group of coal-fired units so they can catch up to everyone

else. Id. at 38530/3.

In calculating cost-effectiveness, EPA also properly declined to assume that

most coal-fired units would retire soon. Contra Am. Power Mot. 22-26. Though

Movants predict that EPA’s recently finalized greenhouse-gas rule (a separate

action not at issue here) would lead coal-fired units to retire in five years, id. at 2324, nothing in that rule compels retirement. See Respondents’ Opp. to Mots. to

Stay Final Rule, West Virginia v. EPA, Case No. 24-1120 and consolidated cases

There is no inconsistency in how EPA distinguished petroleum refineries from

power plants. Contra Westmoreland Mot. 16. In the petroleum-refineries review,

two high-performing sources used existing technologies. After considering the

cost-effectiveness of tightening the applicable standard, EPA decided against

setting a standard for the industry based on only two high performers. 80 Fed.

Reg. 75178, 75201/1-2 (Dec. 1, 2015); 89 Fed. Reg. at 38524/1-2. By contrast,

here almost the entire industry performed well. EPA did not claim, as Movants

seem to imply, to use different approaches in estimating cost-effectiveness in the

two rules. The difference follows from different context in the two industries.

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(D.C. Cir. June 11, 2024), Argument § I.B. It instead requires states to develop

plans that establish feasible technology-based greenhouse-gas emission standards

for coal-fired power plants that do not intend to retire by January 1, 2032. See 89

Fed. Reg. 39798, 39840/2-902/3 (May 9, 2024).

To support their retirement argument, Movants cite proposed guidelines that

address the Clean Air Act’s regional-haze program. See Am. Power Mot. 23

(citing 66 Fed. Reg. 38108, 38126 (July 20, 2001)); 66 Fed. Reg. at 38108/1; 42

U.S.C. § 7491. Those guidelines do not apply to this air-toxics dispute. In any

event, they do not require accounting for hypothetical retirement dates when

calculating costs. See 66 Fed. Reg. at 38126/2 (basing “remaining useful life”

assessment on closing date that “must be assured by a federally-enforceable

restriction preventing further operation”); 40 C.F.R. Part 51, App. Y.

§ IV.D.4.k (final guidelines). So that document is not evidence of arbitrary action.

Nor did EPA err in calculating cost-effectiveness for Colstrip. Contra Talen

Mot. 18. EPA estimated that fabric filters can slash Colstrip’s emissions by 90

percent, to just above 0.002 lb/MMBtu. 2023 Technology Memo 10. That

reduction amount was used to calculate cost-effectiveness. Id. at 9-10. Movants,

however, act as if fabric filters can reduce Colstrip’s emissions to 0.010 lb/MMBtu

and no more. Talen Mot. 18. But fabric filters cannot be easily fine-tuned to

reduce pollutants by a specified amount and stop there. So Movants’ method, in

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undercounting the amount of reduced pollution, distorts cost-effectiveness (and

omits the compliance margin they urge elsewhere). See Am. Power Mot. 17-20;

Rural Mot. 13. EPA also reasonably declined to assume that Colstrip would retire

soon when Colstrip itself had not—and apparently still has not—decided to retire.

Contra Talen Mot. 18-19; see Lebsack Decl.

Movants’ other arguments are easily refuted. First, in the feasibility

analysis, EPA properly considered units that use both coal and natural gas. Contra

Rural Mot. 12-13. EPA’s goal is to evaluate the performance of units that would

be subject to the surrogate standard. That includes coal-fired units that also burn

natural gas. See 2023 Technology Memo 5-6 (table 1). Indeed, one control

strategy for coal-fired units is to use some natural gas. Cf. 89 Fed. Reg. at 38538/3

(explaining this in context of mercury standard). Because EPA considered

emissions data from units that use emission controls, for consistency it was

reasonable to consider emissions from coal-fired units that also use natural gas. Id.

Second, citing a report they commissioned, Movants decry EPA’s supposed

underestimate of control-retrofit costs by 50 percent and say that annual costs are

$1.96 billion. See Rural Mot. at 13 (citing Cichanowicz Report at 21). In reality,

the report estimated those costs for a standard of 0.006 lb/MMBtu—much lower

than what EPA finalized. See Cichanowicz Report at 21 (“To meet the alternative

PM rate of 0.006 lb/MMBtu, this study projects 50% more units (87 versus 65)

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must be retrofit with fabric filters or implement enhanced O&M to an existing

fabric filter, incurring an annual cost of $1.96 B”).

Finally, the surrogate standard accounts for compliance margins. Contra

Am. Power Mot. 17-20; Rural Mot. 13. Power plants often target emission levels

below what standards require. 89 Fed. Reg. at 38521/3. Doing so creates a margin

for error in case their equipment malfunctions or breaks down. Id. That margin is

baked into the standard in two ways.

One is by setting the emission limit above what most coal-fired units were

emitting on average. Recall that EPA considered average emission rates of 296

coal-fired units. 2024 Technical Memo 9. Averages account for operational

variability and degradation of emission controls over time. Resp. to Comments 31.

In this way, averages capture the kind of equipment problems and variabilities that

regulated units must normally contend with. In fact, most of the 296 units in

EPA’s analysis averaged well below 0.010 lb/MMBtu: The median emission rate

was only 0.004 lb/MMBtu, 60 percent below the new standard. 89 Fed. Reg. at

38522/1. This difference—between what most regulated units can do and what the

standard requires them to do—serves as a built-in compliance margin that accounts

for most causes of emission spikes.

The other place that the standard builds in a margin is on the compliance

side. It assesses a given facility’s compliance using 30-day rolling averages:

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Compliance on any day is based on the facility’s average emissions over the last 30

days when fuel was combusted. See id. at 38566/1. Rolling averages dampen

isolated emission spikes. Cf. id. at 38544 (Figure 1) (illustrating this effect for

mercury standards). That in turn gives regulated entities a flexibility that allows

for normal hiccups in operations.

Movants are thus wrong that EPA ignored compliance margins. Am. Power

Mot. 17-20. The surrogate standard accounts for those margins along the same

lines that EPA did in Movants’ examples, by factoring in variability and allowing

compliance flexibility. See id. at 18.6 And because the surrogate standard in effect

has a built-in compliance margin, that margin’s cost was necessarily part of EPA’s

cost analysis. Contra id. at 18-22; Rural Mot. 13; see 89 Fed. Reg. at 38522/1. 7

Mercury standard.

The rule also lowered the mercury standard for lignite units from 4.0 lb/TBtu

to 1.2 lb/TBtu, the limit that has applied to every other coal-fired unit since 2012.

89 Fed. Reg. at 38518/3. In the 2012 rule, EPA treated lignite units differently, but

EPA declined to pick a specific compliance margin because power plants have

different compliance strategies and thus different preferred compliance margins.

See 89 Fed. Reg. at 38521/3; Am. Power Mot. 19-20. Movants are wrong that a

specific compliance margin is mandated by an EPA memorandum about proper

instrument calibration. See Am. Power Mot. 19 (citing PM CEMS Memo).

EPA did a sensitivity analysis that considered a 20 percent compliance margin.

89 Fed. Reg. at 38521/3. But because that analysis would have not changed EPA’s

decision to tighten the surrogate standard, id., Movants’ emphasis of it misses the

point. Am. Power Mot. 20-22.

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not based on any unique property of lignite. Rather, limited data showed that

lignite-fired units were not among the best performers. 89 Fed. Reg. at 38541/1-2.

In the 2024 rule, however, EPA saw that cost-effective controls are available to

lignite units. Id. at 38537/2-49/2. The record thus supports EPA’s conclusion that

the stricter standard is feasible and its costs reasonable for lignite units. Id. at

38541/3. Again, EPA acted reasonably.

Start with feasibility. EPA considered both commercially available mercury

controls and emission levels that lignite units have actually achieved. As

background, when coal burns, it releases mercury in the elemental state. Elemental

mercury, however, cannot be captured by controls, be they fabric filters or

electrostatic precipitators. To be captured, elemental mercury must first be

oxidized, typically by halogens, a group of elements that includes chlorine and

bromine. See 89 Fed. Reg. at 38539/1; 88 Fed. Reg. 24854, 24875/1 (Apr. 24,

2023). Chemical powders (usually made of carbon and called “sorbents”) are then

injected into coal-combustion flue gas, where they bind to the oxidized mercury,

allowing it to be captured and removed. 89 Fed. Reg. at 38540/2. Controlling

mercury from coal with low halogen content, like lignite, is thus harder.

Harder, but still feasible: Subbituminous coal’s halogen content is

comparable to lignite’s, and subbituminous units have long been complying with

the 1.2 lb/TBtu limit, often emitting at “considerably lower” levels. Id. at 38539/125

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2 (noting that high alkalinity in subbituminous and lignite coals exacerbates effects

of low halogen content); see id. at 38543 (tables 5-6). They have done so by

injecting additional halogens (via brominated sorbents) into flue gas. Id. at

38545/3. Subbituminous units’ success shows it is feasible to capture mercury

from low-halogen coal like lignite. Id. at 38539/1-2, 38545/3-46/1.

Other characteristics of lignite coal—higher sulfur content, and higher and

variable mercury content—can also make it hard to control mercury emissions. Id.

at 38541/1. But as with halogen content, these characteristics are also found in

other types of coal. Id. at 38541/2. Some bituminous coals have sulfur levels

comparable to that of lignite. Id. at 38543 (tables 5-6). But all bituminous units

have been complying with the 1.2 lb/TBtu limit, thanks to a range of sulfurresistant sorbents and other controls designed for high-sulfur environments. Id. at

38546/2-47/1; see id. at 38541/3 (noting the development of these sorbents).

And though some lignite coal can have high mercury content, not all lignite

coal does. For example, North Dakota lignite has lower and less variable mercury

content than Pennsylvania bituminous coal. Id. at 38543 (tables 5-6). But again,

all bituminous units have been complying with the stricter standard for years.

To be sure, lignite has a unique set of characteristics. But each kind of coal

has its own unique set of characteristics that, for one reason or another, makes it

hard to control mercury emissions. Id. at 38549/1. Given the availability of

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controls that other coal-fired units have successfully used to comply with the 1.2

lb/TBtu limit, EPA reasonably concluded that the standard is feasible for lignite

units. See Rural Mot. 13-14 (ignoring EPA’s analysis of available controls).

Lest there be any doubt about whether lignite units can achieve 1.2 lb/TBtu,

cf. id., the record shows that two such units at the Twin Oaks facility have already

done so—even before that level became the standard. 89 Fed Reg. at 38540/1

(reporting emission levels of 0.63 to 1.1 lb/TBtu). And two lignite units at the Red

Hills facility have come reasonably close. See id. (reporting emission levels of

1.73 to 1.75 lb/TBtu). Notably, Twin Oaks uses Texas lignite and Red Hills uses

Mississippi lignite. Id. at 38539/3-40/1. And both Texas and Mississippi lignite

have much higher mercury content than North Dakota lignite. Id. at 38543 (table

5). Yet Twin Oaks and Red Hills have managed to meet or come close to the new

standard. In this way, EPA assessed feasibility by considering the toughest

scenarios for controlling lignite’s mercury emissions. Contra Rural Mot. 14-15.

Movants are wrong that Twin Oaks is an “outlier” that uses controls not

“technically feasible” at other units. Id. at 14. For a start, Movants mix up

different power plants with “Oak” in their names: They cite a comment

contending that selective catalytic reduction, used by Oak Grove’s lignite plant,

would not work at facilities burning North Dakota lignite. Id. (citing Lignite

Council Comment 8). Oak Grove, however, is not Twin Oaks. And Twin Oaks,

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which meets the stricter standard, does not use selective catalytic reduction. See 89

Fed. Reg. at 38540/1 (noting that Twin Oaks uses selective non-catalytic

reduction).

What Twin Oaks does use are sulfur controls and brominated sorbents—the

most effective sorbents. Id. That sets it apart from many lignite units that are not

using brominated or sulfur-resistant sorbents to control mercury, a fact that

Movants disregard. Id. at 38540/2; Rural Mot. 14-15. Indeed, some lignite units

could at times meet the 4.0 lb/TBtu standard without injecting any sorbents. 89

Fed. Reg. at 38540/2. 8 That further shows it is feasible for lignite units to meet the

stricter standard: They need not install new controls; they simply need to use

effective sorbents in the controls they already have. See id. at 38540/2. Doing so

would also allow lignite units to inject sorbents at lower rates, something else that

Movants disregard. Rural Mot. 15.9

This modest demand on lignite units is reflected in the cost estimate.

Control costs are expected to be a “small fraction” of their revenue. 89 Fed. Reg.

at 38549/1. And the standard’s cost-effectiveness is $10,895 to $28,176 per

These units could be burning lignite coal with low mercury levels or spraying

oxidizing chemicals onto lignite before burning it.

Even though Section 7412(d)(6) does not require EPA to identify more than one

control technology, the agency did so, considering controls like brominated

sorbents and chemicals designed for high-sulfur environments. See 89 Fed. Reg. at

38546/2-47/1; Resp. to Comments 84; contra Rural Mot. 13-14.

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additional pound of mercury removed. Id. at 38548/2-3. That is comparable to

and, if anything, less than the 2012 standard’s cost (about $27,000 per pound). Id.

at 38549/1 n.82. 10 At the same time, a disproportionate share of coal-fired units’

mercury emissions comes from lignite units. Id. at 38549/1. Given all these

factors, EPA properly concluded that costs are reasonable and the standard is

achievable. Id. at 38547/2-49/2.

Movants’ remaining contention is remarkable only for its brevity. Though

Movants say that EPA failed to give a “reasoned explanation” of its feasibility

conclusion and was put “on notice” that it is “flawed,” they do not elaborate on

what the supposed flaw was, proffering only a string cite of comments. States

Mot. 11 & n.4. Such “obscure” briefing—“merely stating [an argument], in

conclusory fashion and without visible support”—forfeited the argument. Bd. of

Regents of Univ. of Wash. v. EPA, 86 F.3d 1214, 1221 (D.C. Cir. 1996); see Davis

v. Pension Benefit Guar. Corp., 734 F.3d 1161, 1166-67 (D.C. Cir. 2013)

(disregarding argument made by incorporation, which skirts limits on brief length).

Even if lignite units need to install new equipment, EPA estimated that costs

would be relatively low. See 89 Fed. Reg. at 38549/1.

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In the end, actual performance by regulated entities shows that the standards

are feasible and will incur reasonable costs. Movants’ contrary arguments, which

ignore EPA’s extensive analyses, are unlikely to succeed.

EPA properly did not rely on an analysis of benefits and

costs, but reasonably considered them anyway.

Movants latch onto an analysis of monetized benefits and costs that EPA

conducted to comply with Executive Order 12866. 89 Fed. Reg. at 38553/2. But

in choosing the standards’ stringency, EPA did not (and did not have to) use the

monetized analysis done under the executive order. It relied instead on statutory

factors. Id.; see supra Argument § I.A-B.1. Neither Section 7412(d)(6) nor legal

precedent requires EPA to compare monetized benefits and costs in a technology

review. Cf. Michigan, 576 U.S. at 759.

Meanwhile, in the analysis required by the executive order, EPA considered

“all the costs and benefits” and concluded that the rule is a “worthwhile” exercise

of its Section 7412(d)(6) authority. 11 89 Fed. Reg. at 38553/3; cf. Michigan, 576

U.S. at 753 (“reasonable regulation ordinarily requires paying attention to the

advantages and the disadvantages of agency decisions” (emphasis omitted)).

To be clear, the relevant costs and benefits come from the delta between the

2012 rule and the 2024 rule. 89 Fed. Reg. at 38553/2-3. Their scope is thus

narrower than what EPA considered in finding that it is appropriate and necessary

to regulate coal- and oil-fired power plants, a finding that no one challenged and is

not at issue here. 42 U.S.C. § 7412(n)(1)(A); 88 Fed Reg. at 13956/1.

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Movants focus on the monetized part of this analysis as evidence of arbitrary

conduct. E.g., States Mot. 6, 8-10; Westmoreland Mot. 14; Talen 28(j) Letter 2.

The complete analysis, however, shows that EPA acted reasonably.

In benefit-cost analyses, it is easy to see a proposed action’s net benefits (or

net costs) when everything can be monetized. But when many things cannot, the

agency’s task becomes much harder. Here, EPA could not monetize the rule’s

chief benefit—reduced emissions of air toxics. 89 Fed. Reg. at 38553/2, 38515/316/2. Good epidemiological data on air toxics often does not exist: Exposure to

these pollutants is often highly concentrated, but in smaller populations than those

exposed to non-hazardous air pollutants. The small population size means that

studies lack enough statistical power to detect effects of exposure. Id. at 38511/2,

38515/3-16/2; FCC v. Prometheus Radio Project, 592 U.S. 414, 427 (2021)

(noting that it is not unusual for agencies to “not have perfect empirical or

statistical data”). Without good data, economists cannot monetize harms from

exposure or benefits from avoiding those harms. By contrast, the rule’s costs were

monetized, along with some ancillary benefits like reduced emissions of nonhazardous air pollutants. See 89 Fed. Reg. at 38515/3-16/1, 38558 (table 10).

Movants emphasize that costs exceed monetized benefits, resulting in high

“‘negative net monetized benefit.’” States Mot. 8 (quoting 89 Fed. Reg. at

38511/1); see Rural Mot. 19; Westmoreland Mot. 7, 14; Talen 28(j) Letter 2; cf.

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Talen Mot. 23; Midwest Ozone Mot. 9-11. Yet as this Court warned in another

Clean Air Act context, “simply weighing the monetizable costs against the

monetizable benefits—and thereby excluding the primary benefits for which

Congress created the [p]rogram—will yield a misleading result.” Sinclair Wyo.

Refin. Co. v. EPA, 101 F.4th 871, 889 (D.C. Cir. 2024). EPA, for its part,

cautioned that the monetized analysis is “ill-suited” to air-toxics regulation because

key benefits cannot be monetized. 89 Fed. Reg. at 38511/1, 38553/2.

EPA did, however, consider all costs and benefits, including unmonetized

ones. Id. at 38553/1-59/1.12 “That those benefits are not easily monetizable does

not mean they are less valuable.” Sinclair, 101 F.4th at 889. But without context,

simply comparing costs with unmonetized benefits was meaningless. So EPA did

what most of us do when deciding whether it is worthwhile to buy something

without monetizing its benefits, be it shopping for groceries, hiring a dogwalker, or

planning a vacation: We look to indicia of reasonableness like market price,

affordability, and the advantages of having the good or service.

Here, costs reflect the relevant market price. As EPA explained in its

technology review, almost all regulated units already have paid for the necessary

controls to meet the surrogate standard, and the mercury standard’s cost is

In its public-interest argument, one Movant notes in passing that EPA ignored

certain upstream costs and benefits. Midwest Ozone Mot. 10. That argument is

too obscure to be preserved. See Univ. of Wash. v. EPA, 86 F.3d at 1221.

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comparable to that of the 2012 standard. Supra Argument § I.B.1. Those costs are

also a small fraction of regulated entities’ revenue. Id. Meanwhile, the new

standards’ chief benefit—less air-toxics emissions—is the point of Section 7412.

Those standards, expected to cut mercury by 9,500 pounds and non-mercury

metals by 49 tons, would reduce human exposure to toxic chemicals and thus risk.

89 Fed. Reg. at 38511 (table 1), 38556/3; see Reg. Impact Analysis at 4-5 (noting

the “lack of quantifiable risks” from mercury emissions, but that reductions are

expected to affect overall mercury levels in fish (and thus the people who eat

them)); 89 Fed. Reg. at 38515/2 (noting mercury’s neurotoxic effects on children).

The standards can also “enhance ecosystem services and improve ecological

outcomes.” 89 Fed. Reg. at 38556/3.

Considering all the benefits and costs, EPA noted that the final rule is

worthwhile, though the choice of standards was based on statutory factors, not the

benefit-cost analysis. Id. at 38553/3. Even if the rule had to be based on such an

analysis, this is the sort of policy judgment that Congress instructed courts to leave

to agencies. See Ctr. for Auto Safety v. Peck, 751 F.2d 1336, 1342 (D.C. Cir.

1985). Movants, having overlooked the complete benefit-cost analysis, are

unlikely to succeed here.

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EPA reasonably concluded that the rule would not imperil

grid reliability.

EPA looked to statutory factors to choose the standards’ stringency. It then

modeled the rule’s potential effect on the power sector. Reg. Impact Analysis 3-1

to 3-28. Based on that modeling, EPA concluded that the rule is not expected to

impair reliability of the nation’s electricity grid. 89 Fed. Reg. at 38526/1-2.

Fixating on the conclusion rather than the analysis, Movants miss the point.

To begin, EPA has expertise to assess the impacts of its regulations on grid

reliability. Contra States Mot. 11-12 (citing Texas v. EPA, 829 F.3d 405, 432 (5th

Cir. 2016)). After all, Congress entrusted EPA to set standards for sources like

power plants. 42 U.S.C. § 7412(d)(2), (n)(1). And EPA has been successfully

regulating the power sector for years without causing blackouts or soaring

electricity prices. See 89 Fed. Reg. at 38519/3, 38526/2-3 (giving examples of past

rules). Movants’ contrary take would bar EPA from tightening standards for

power plants unless it consults certain energy-regulatory authorities—a condition

found nowhere in Section 7412. Anyway, EPA did consult “other Federal

agencies, reliability experts, and grid operators” here. Resp. to Comments 156

(also noting ongoing consultation with the Department of Energy, under a joint

memorandum of understanding, on grid-reliability issues); contra States Mot. 12.

To assess the rule’s potential energy impact, EPA used a state-of-the-art,

peer-reviewed model. See Reg. Impact Analysis 3-1 to 3-4 (noting that industry

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also uses the model, which reflects information about the electricity market from

utilities, industry experts, gas- and coal-market experts, financial institutions, and

governments). The model projected that the rule would not lead any coal-fired

capacity to retire. Id. at 3-18. On that basis, EPA concluded that the rule is not

expected to affect grid reliability. 89 Fed. Reg. at 38526/1-2. 13

This analysis discredits the bulk of Movants’ grid arguments, which target

EPA’s conclusion about grid reliability. States Mot. 11-14. But Movants say little

about the zero-retirement projection that undergirds that conclusion. Their only

critique of the projection is that EPA allegedly underestimated retirements in the

2012 rule. Id. at 12-13; cf. Rural Mot. 25.

That critique is both irrelevant and wrong. It is irrelevant because an

agency’s failure to accurately predict the future does not make the underlying

action—let alone a later action like the 2024 rule—unreasonable. See Pub. Utils.

Comm’n of State of Cal. v. FERC, 24 F.3d 275, 281 (D.C. Cir. 1994) (“Predictions

regarding the actions of regulated entities are precisely the type of policy

judgments that courts routinely and quite correctly leave to administrative

agencies.”). And Movants’ critique is wrong because although more coal-fired

units retired than EPA had predicted in 2012, studies show that those retirements

EPA also analyzed cumulative impacts of its recent power-plant rules, including

this one, and concluded that they are unlikely to impair the power sector’s ability

to meet demand. See Resource Adequacy Memo; contra States Mot. 13-14.

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were largely due to reduced demand for coal-fired electricity, driven by lower

electricity demand and cheaper natural gas—coal’s direct competitor. See 89 Fed.

Reg. at 38526/1-27/1; 87 Fed. Reg. 7624, 7653/1-3 (Feb. 9, 2022). Of course,

substituting natural gas for coal does not affect grid reliability.

And even though EPA projected that the rule would not cause retirements, it

took commenters’ grid concerns seriously. It explained that the kind of blackouts

feared by commenters are unlikely to happen because power plants cannot

unilaterally retire. Before they can shut down, power plants generally must

undergo extensive processes imposed by state regulators and regional transmission

organizations. 89 Fed. Reg. at 38526/2. These processes typically require

analyses of the proposed retirement’s impacts and identification of mitigation

options. Id.; see Resp. to Comments 52-53 (noting that one of Colstrip’s owners is

in a regional program that addresses reliability planning). Sometimes, regulators

offer temporary funding to keep the power plant open until longer-term measures

are in place. 89 Fed. Reg. at 38526/2. And the Department of Energy, when

facing an emergency electricity shortage, can issue orders allowing power plants to

temporarily operate above their emission standards. See id. (citing 16 U.S.C.

§ 824a(c)).

Though Movants dismiss these failsafes as “unworkable,” they do not

explain why, either for Colstrip or more generally. Talen Mot. 13, 16-17; States

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Mot. 20. An argument so skeletal is forfeited. See Univ. of Wash., 86 F.3d at

1221; Davis, 734 F.3d at 1166-67. Besides, EPA did not rely on emergency

resources in the rulemaking. It projected that the rule would not impair the grid.

And it cited these resources in response to comments. 89 Fed. Reg. at 38526/1-2.

Giving accurate responses is not arbitrary or capricious. Contra States Mot. 20.

The 2024 rule is not a pretext for regulating greenhouse gases.

EPA tightened the mercury standard and surrogate standard (for nonmercury metals) to reduce power plants’ air-toxics emissions. The standards are

not, as Movants imagine, a pretext for EPA to cut emissions of another pollutant—

greenhouse gases—by “forc[ing] a nationwide transition away from coal.” States

Mot. 14.

Courts presume that, absent clear contrary evidence, agencies properly

discharged their duties. See United States v. Chem. Found., 272 U.S. 1, 14-15

(1926); USPS v. Gregory, 534 U.S. 1, 10 (2001). Movants offer no contrary

evidence. Though they spin an elaborate tale of EPA’s scheming, the record shows

that it is nonsense. States Mot. at 14-16. EPA considered—and rejected—calls for

even tougher standards. 89 Fed. Reg. at 38532 (table 4), 38538/1-2. It instead

chose standards that are expected to result in zero coal-fired retirements. Reg.

Impact Analysis 3-18. EPA cannot possibly be trying to shut down coal-fired units

by not shutting them down at all.

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Nor was the 2024 rule spurred by an “Executive Order on climate change.”

States Mot. 14; see id. at 3-4. That executive order, issued by President Biden in

early 2021, broadly states his Administration’s policy goals for protecting public

health and the environment. 86 Fed. Reg. 7037, 7037 (Jan. 25, 2021). The goals

cover more than just climate change and include “ensur[ing] access to clean air”

and “limit[ing] exposure to dangerous chemicals.” Id.

As for various statements by the White House and the Administrator that

Movants assembled in service of their tale, States Mot. at 14-16, the Court cannot

consider such extra-record material. See 42 U.S.C. § 7607(d)(7)(A) (defining

scope of the record for judicial review); CTS Corp. v. EPA, 759 F.3d 52, 64 (D.C.

Cir. 2014). Anyhow, nothing in those statements alters the conclusion that EPA’s

technology review complies with Section 7412.14 Cf. Dep’t of Com. v. New York,

Movants also misread the extra-record material. Take the PowerPoint they cite

as evidence of EPA’s supposed intent to use different statutory authorities to

“implement the Administration’s climate agenda.” States Mot. 15. In reality, the

PowerPoint addresses all kinds of environmental problems created by power

plants, and the statutes (like the Clean Air Act) that direct EPA to tackle them. See

Chang Decl. Att. Likewise, the Administrator’s PBS interview discussed powerplant regulations addressing not just climate concerns but also “waste and

discharges in water” and “health-based pollution.” Transcript, PBS interview with

Michael S. Regan (June 30, 2022), available at

https://www.pbs.org/newshour/show/epa-administrator-michael-regan-discussessupreme-court-ruling-on-climate-change (last visited on July 20, 2024); Sta

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