Emergency Application — North Dakota, et al., Applicants v. Environmental Protection Agency, et al.

Supreme Court briefAug 16, 2024

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Text

NRECA Comments on Proposed EGU RTR

conclude this proposal would only result in 500MW coal capacity retirement.7 At the very least

EPA should have modeled an alternative scenario incorporating less presumptive assumptions

regarding unit retirements and considered that alternative scenario in the RIA and when

determining the costs associated with the proposal assume unit retrofits to comply with the

proposal.

In addition, EPA did not consider the reliability impacts of the proposal’s required emission

control upgrades and additions to units. It is likely that many units that would have to incur

millions of dollars to retrofit emissions controls to comply with this proposal would not do so.

We encourage EPA to be concerned with grid reliability and consider the impacts of this

proposal on it using reasonable retrofit costs as detailed in Section 5 of the Cichanowicz Report.

7 Regulatory Impact Analysis at Section 5.3.3 page 5-13

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2875 Third Street SW

Underwood, North Dakota 58576

701.207.9988

rainbowenergycenter.com

June 23, 2023

U.S. Environmental Protection Agency

Docket ID No. EPA–HQ–OAR–2018–0794

1200 Pennsylvania Avenue, NW

Washington, DC 20460

Submitted via docket

RE:

REC Comments – National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg.

24,854 (Apr. 24, 2023) (“Proposed Rule”)

Rainbow Energy Center (“REC”) appreciates the opportunity to submit comments on the Proposed Rule—

particularly the need for alignment between the Proposed Rule and the proposed Section 111(d) Guidelines—and

would welcome the opportunity to constructively engage with EPA as it considers comments on the proposal.

REC owns and operates Coal Creek Station, a lignite coal-fired power plant located approximately six

miles south of the city of Underwood, North Dakota. Coal Creek is a base load facility capable of sending 1,151

MW per hour into the Midcontinent Independent System Operator (“MISO”) system. In addition to being a

significant source of power for residents and businesses in the region, Coal Creek is responsible for more than

600 jobs in North Dakota and is a valuable contributor to the local and regional economy, providing a $1.5 billion

estimated annual impact to the state of North Dakota.

Coal Creek anticipates playing a crucial role in helping the state of North Dakota achieve its aggressive

goal of being carbon neutral by 2030, and reducing the carbon intensity of power delivered in the MISO region.

In addition to plans to install 400 MW of wind at Coal Creek, REC is actively working toward the installation of

a full-scale post-combustion CO2 capture system (“CCS”) designed to capture 95% of CO 2 emissions at the

facility. REC is collaborating with the Energy Environment and Research Center at the University of North

Dakota, and the project has been recognized as a key contributor to the carbon reduction goals established by

Governor Burgum.1

REC is a member of the Class of ’85 Regulatory Response Group and the Lignite Energy Council, and

supports the comments submitted by both Groups, but submits the following comments because it is concerned

with the costly redundant controls that would be required by the Proposed Section 111(d) Guidelines and the

Proposed Rule, as well as flaws in the legal and technical underpinnings of the proposal.

N.D. Office of the Governor, Burgum, Sanford laud historic transfer of Coal Creek Station, transmission line to

Rainbow Energy, Nexus Line (May 2, 2022), https://www.governor.nd.gov/news/burgum-sanford-laud-historic-transfer-coal-creekstation-transmission-line-rainbow-energy.

2875 Third Street SW

Underwood, North Dakota 58576

701.207.9988

rainbowenergycenter.com

2. Carbon Capture is a highly effective fPM control.

For more than two years, REC and its partners have worked with Mitsubishi Heavy Industries (MHI) on

the design of a carbon capture island to be installed at Coal Creek. The carbon capture system requires the near

total elimination of fPM emissions from the flue gas stream before it enters the island—otherwise, the system is

exposed to amine-based solvent degradation. 7

While not of Coal Creek, the diagram below illustrates the flow of flue gas through a carbon capture

system and why removal of fPM is critical for effective operation of the system. When the flue gas enters “Step

2” at the Coal Creek Station CCS island, sulfur dioxide and fPM will be removed prior to entering “Step 3,”

where the flue gas is treated with amine solvent to absorb the carbon dioxide.

The highly effective fPM control of CCS is confirmed by EPA’s own Proposed 111(d) technical support

documents. The documents recognize that “flue gas from coal-fired facilities typically must be treated (e.g., must

pass through a flue-gas desulfurization (FGD) scrubber and often a secondary polishing column prior to entering

the absorption column).”8 EPA further states that, because of the importance of removing fPM from the flue gas

stream, in some instances an FGD column and a polishing column may also be necessary.

3. Nearly consecutive outages will strain system reliability at a critical point.

Eliminating duplicative control requirements between the Proposed Rule and the Proposed Section 111(d)

Guidelines will help maintain system reliability. The confluence of three separate EPA regulatory programs in

Energy & Environmental Research Center, “EERC Topical Report: Subtask 2.6 –Optimization of Aerosol Mitigation Technology for

Postcombustion CO2 Capture; Cooperative Agreement No. DE-FE0024233 EERC Fund 24412” (Feb. 12, 2021).

EPA, Greenhouse Gas Mitigation Measures for Steam Generating Units Technical Support Document, at 19, 43-44, available at:

https://www.epa.gov/stationary-sources-air-pollution/greenhouse-gas-standards-and-guidelines-fossil-fuel-fired-power.

2875 Third Street SW

Underwood, North Dakota 58576

701.207.9988

rainbowenergycenter.com

the same five year compliance period—each requiring control installation (i.e., outages) or unit retirements—on

both coal- and gas-fired units will strain system reliability, absent concerted effort by EPA.

EPA Regulation

Control Requirement

Timing

Cross State Air

Pollution Rule

Requires emissions reductions commensurate with the By 2027

installation of SCR at existing coal units and highemitting gas units in 22 states, including numerous

MISO states

Proposed Rule

Potentially requires installation of fPM and mercury Est. 2027 or

controls at existing coal-fired units

2028

Proposed Section

111(d) Guidelines

Potentially requires installation of CCS controls or Est. 2030

retirement of existing coal-fired units

This clustering of extended temporary and permanent cessation of dispatchable resources exacerbates

REC concerns as resource adequacy within the MISO system. “MISO is experiencing a trending decline in reserve

margin and fewer always-on ‘baseload’ resources, which is largely the result of the retirement of significant

amounts of dispatchable generation and the retirement of thermal units.” 9 Traditional dispatchable generators like

coal-fired units are being replaced by new, mostly intermittent facilities that are not valued at the same output,

which presents significant risks to grid reliability.

Reducing unit downtime by consolidating control installation into a single outage aligns with EPA’s

recognition that “[a] reliable and resilient electric power system is indispensable to the national security and

economic well-being of the United States.” 10

B. Existing Controls Provide An Ample Margin Of Safety And EPA Has Not Provided Sufficient

Justification For The Proposed Rule.

As proposed, the Proposed Rule plainly exceeds EPA’s authority under the Clean Air Act. EPA is

authorized to update Section 112 standards “if needed to provide an ample margin of safety to protect public

health” and “as necessary” to address technological developments. 11 Here, EPA’s own analysis confirms that

existing controls provide an ample margin of safety and that there are no new developments in hazardous air

pollutants (HAP) emission controls—only that EPA now has more information about the cost and performance

of existing technology.12 Accordingly, REC asks EPA to reconsider proceeding with the final rule.

Comments from the Midcontinent Independent System Operator, Inc. (MISO) Regarding the United States Environmental Protection

Agency’s Request for Comment re Docket ID Nos. EPA-HQ-OLEM-2021-0283, EPA-HQ-OLEM-2021-0282, EPA-HQ-OLEM-20210280, at 3 (Apr. 10, 2023) (attached hereto as Attachment A).

EPA, DOE, Joint Memorandum on Interagency Communication and Consultation on Electric Reliability (Mar. 9, 2023), available at:

https://www.epa.gov/power-sector/electric-reliability-mou.

88 Fed. Reg. at 24,859 (explaining CAA Section 112(f)(2) (called the residual risk review) and CAA Section 112(d)(6) (called the

technology review)).

88 Fed. Reg. at 24,863, fn 15.

PGEN COMMENTS ON EPA’S PROPOSED RULE: NESHAP COAL- AND OIL- FIRED

ELECTRIC UTILITY STEAM GENERATING UNITS REVIEW OF THE RESIDUAL

RISK AND TECHNOLOGY REVIEW

Docket ID No. EPA-HQ-OAR-2018-0794

The Power Generators Air Coalition (“PGen”) appreciates the opportunity to submit these

comments on the U.S. Environmental Protection Agency’s (“EPA” or the “Agency”) proposed

rule entitled “National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired

Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review”

(“Proposed Rule” or “Proposal”).1 The Proposed Rule proposes to amend the Mercury and Air

Toxics Standards (“MATS”) regulations.2 Particularly, EPA proposes to amend the surrogate

standard for non-mercury metal HAP—i.e., for filterable particulate matter (fPM)—for existing

coal-fired EGUs; eliminate the individual non-Hg metal HAP standards; require the use of a

Particulate Matter Continuous Emissions Monitoring System (“PM CEMS”) for compliance for

all units, thus eliminating the stack testing option; amend the mercury (“Hg”) standard for

lignite-fired EGUs; and eliminate one of two definitions of startup currently in the regulations.

EPA proposes to keep the remaining standards unchanged.

PGen is an incorporated nonprofit 501(c)(6) organization whose members are diverse electric

generating companies—public power, rural electric cooperatives, and investor-owned utilities—

with a mix of solar, wind, hydroelectric, nuclear, and fossil generation. PGen is a collaborative

effort of electric generators to share information and expertise in the interest of constructively

evaluating and effectively managing air emissions to meet and exceed environmental laws and

regulations and in the interest of informing sound regulation and public policy.3 Our members

include leaders in the ongoing transition to cleaner energy in the United States. PGen and its

members work to ensure that environmental regulations support a clean, safe, reliable, and

affordable electric system for the nation.

PGen members own and operate EGUs that are regulated under the MATS rule. Indeed, PGen

members have committed substantial resources to meet and maintain compliance with MATS.

Accordingly, PGen has a substantial interest in the Proposed Rule.

SUMMARY OF COMMENTS

Section I – The MATS Rule Significantly Reduced HAPs and Require No Further Revision.

•

MATS has resulted in substantial decreases in HAP emissions from affected EGUs.

These emissions are continuing their rapid and steady decline because of regulatory and

economic pressure that are inexorably leading to additional shutdowns of coal-fired

National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam

Generating Units Review of the Residual Risk and Technology Review, 88 Fed. Reg. 24,854 (proposed

Apr. 24, 2023) (to be codified at 40 C.F.R. pr. 63).

40 C.F.R. Part 63, Subpart UUUUU.

Additional information on PGen and its members can be found at PGen.org.

637a

practices.43 Remarkably, however, EPA did not lower the standard for formaldehyde, despite

data demonstrating these developments would result in lower actual emissions, because EPA saw

a continuing downward trend in formaldehyde emissions from that industry and concluded that

revising the standard merely to accelerate that trend slightly for some sources was not

necessary.44

In short, in each of the RTRs EPA cites, EPA in fact found developments in practices, processes,

or control technologies that warranted revisions of the respective standards. Here, EPA found no

new developments in practices, processes, and control technologies. EPA merely found that fPM

actual emissions were generally lower than the current emission limits. Without identifying any

“development” as required in section 112(d)(6), EPA is not authorized to lower the emission

standard of fPM in MATS. Moreover, even if EPA has such authority, EPA should treat EGU

affected facilities as it treated Wool Fiberglass Manufacturing facilities in that RTR. EPA is fully

aware that other regulatory programs, legislation, and the economics of power generation are

leading inexorably to substantial retirements of coal-fired EGUs in the next decade or so. The

reductions in HAPS (as well as all pollutants) from these retirements will dwarf any reductions

that the Proposed Rule would mandate. In these circumstances, it makes no sense for EPA to pile

on yet another costly, unnecessary mandate.

III.

EPA’S ANALYSIS OF NON-HG METAL HAP SURROGATE, fPM, EMISSIONS

DATA IS DEEPLY FLAWED AND DOES NOT SUPPORT A REVISED fPM

STANDARD OF 0.010 lb/MMBtu, MUCH LESS A STANDARD AS LOW AS 0.006

lb/MMBtu.

EPA’s proposal to revise the fPM standard for coal-fired EGUs to 0.010 lb/MMBtu is based on

an “analysis” that is so deeply flawed that finalizing it would be plainly arbitrary and capricious.

EPA analysis suffers from the following flaws:

•

EPA relied on a very small set of quarterly data (either CEMS or quarterly stack tests) to

characterize the emissions rates that EGUs can meet readily, even though EPA has in its

possession data for all EGUs subject to MATS for every quarter since at least the start of

2017.

•

The selection criteria for the very few quarters EPA chose to consider are unexplained

and arbitrary.

•

EPA’s extremely truncated data set is not–indeed, it cannot–be representative of the

units’ long-term performance, quarter after quarter. This truncated data set allowed EPA

to turn a blind eye to the variability in emissions rates that EGUs experience.

•

Of two out of at least 20 quarters of available data for each EGU, EPA selected the

quarter exhibiting the least emission rate (arbitrarily, at least for PM CEMS units, on the

last day of the quarter) as indicative of the emission rate the unit must be capable of

82 Fed. Reg. at 40,975.

Id.

638a

achieving consistently. EPA’s “explanation” as to why it selected the lowest of these two

quarters is supported by no evidence and is contradicted by real-world data.

•

In identifying EGUs that would have to upgrade their controls to meet the proposed

revised rate of 0.010 lb/MMBtu, EPA completely ignored the need for a compliance

margin. If the standard were lowered to 0.010 lb/MMBtu, EGU owners would have to

target 0.005 lb/MMBtu to, at most, 0.008 lb/MMBtu, to have an adequate compliance

margin that ensures they would be able to meet the proposed standard.

•

EPA underestimates the cost of the main type of control equipment upgrades that EPA

predicts would be required to meet the proposed standard of 0.010 lb/MMBtu. EPA

estimates an ESP rebuild would cost $75-$100/kW. The Industry Study looked at four

real-world ESP rebuild projects. The costs of three out of the four projects exceed the

high end of EPA’s range, with two at almost twice that amount (i.e., about $200/kW).

Based on the four real-world ESP rebuilds, the mean cost is $133/kW. As a result, the

proposed revision of the fPM standard is even less cost-effective than EPA says.

•

Control upgrade capital costs EPA assumes would be required to meet the 0.010

lb/MMBtu standard (at units EPA’s analysis determined would require such upgrades)

range, based on EPA’s own $100/kW cost for ESP rebuilds, from $52 million to $148

million per unit. Such high costs, in the current highly uncertain regulatory and

economic climate (no pun intended) for coal-fired EGUs, would almost certainly cause

the owners of these units to shut them down prematurely (i.e., by the effective date of the

proposed rule – likely mid-2027, if EPA adopts a three years compliance deadline). This

would raise the Proposed Rule’s cost even more and would make it substantially less

cost-effective. The premature retirement of these units would also pose a significant

threat to the reliability of the power grid.

•

EPA’s own estimated $/ton of fPM removed for the proposed fPM standard of 0.010

lb/MMBtu is about the same and, in the majority of cases, vastly exceed previous $/ton

amounts that EPA had found to be not cost-effective. Similarly, EPA’s 0.006 lb/MMBtu

cost-effectiveness estimates far exceed past analogous $/ton estimates EPA found to be

not cost-effective.

EPA’s Conclusion are Based on a Truncated and Unrepresentative Set of

Data, Even Though EPA has in its Possession Data for Every Quarter for

Every Unit Since MATS Took Effect.

EPA’s rationale for revising the MATS fPM standard hinges on an analysis replete with errors

and unexplained and arbitrary selections. As an initial matter, it is a mystery why EPA excluded

from its database (i.e., the inventory of EGUs it analyzed) units that “will shut or no longer burn

coal/oil by December 31, 2028.” Assuming EPA adopts a three-year compliance deadline for a

revised standard, that deadline would likely be about mid-2027, which means units that will shut

down by the end of 2028 would have to meet the revised standard for a year and half. If these

units can readily meet the revised standard (and some units can), they will presumably continue

to do so between mid-2027 and the end of 2028. But what are the units that currently do not meet

639a

Rebecca McGrew, RPG

Director, Environmental and Regulatory Affairs

Telephone: 972-448-5470

Email: rebecca.mcgrew@nacco.com

June 23, 2023

U.S. Environmental Protection Agency

EPA Docket Center ID No. EPA-HQ

HQ-OAR-2018-0794

Mail Code 28221T

1200 Pennsylvania Avenue NEW

Washington, D.C.

ATTENTION Docket ID No. EPA-HQ

HQ-OAR-2018-0794

Re:

National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric

Utility Steam Generating Units Review of the Residual Risk and Technology Review;

Notice of Proposed Rulemaking (88 Fed. Reg. 24854 (April 24, 2023)).

Dear Administrator Reagan,

The North American Coal Corporation (“NA Coal”) submits these comments in response to

the United States Environmental Protection Agency’s (“EPA”) proposed rule, National Emission

Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units

Review of the Residual Risk and Technology Review; Notice of Proposed Rulemaking (the

“Proposed Rule”).1 NA Coal owns and/or operates surface coal mines in Mississippi and North

Dakota that supply approximately 25 million tons per year of coal, on a long-term contractual basis,

to lignite-fired electric generating units (“EGUs”) in those states, as well as a lignite mine that

provides lignite as feedstock for carbon activation operations in Louisiana. In addition to providing

a reliable, onsite power fuel supply, NA Coal facilities have more than 1,500 highly paid personnel

in the mining sector. NA Coal contributes to the communities in which it operates and is an industry

leader in environmental responsibility.

The Proposed Rule in its current form will not survive legal challenge and would have the

effect of degrading U.S. energy security. EPA has not adequately demonstrated that hazardous

air pollutant (“HAP”) emissions, including mercury (“Hg”) emissions, from coal- and oil-fired EGUs,

especially lignite-fired EGUs, pose an unacceptable risk under the applicable regulatory

requirements. Rather, the Proposed Rule is the product of a deeply flawed and unlawful

“appropriate and necessary” finding in EPA’s National Emission Standards for Hazardous Air

Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating United Revocation of 2020

88 Fed. Reg. 24854 (April 24, 2023)

North American Coal

5340 Legacy Drive, Suite #300

Plano, TX 75024

972.448.5400

NACoal.com

social cost of greenhouse gas metric.57 Baseload power is a critical component of the utility grid

and the grid must maintain a certain level of baseload power for stability purposes. Because the

Proposed Rule incentivizes switching to less carbon intensive fuels – either coal to natural gas or

fossil fired generation to nuclear – fuel switching is expected to occur as a result of the Proposed

Rule. By weighing the benefits of a reduction in CO 2 emissions arising from projected EGU

closures, EPA acknowledges that its Proposed Rule would command or force such fuel switching.

Such generation-shifting considerations are impermissible. EPA attempts to hide the fact

that the rule promotes “generation shifting” by focusing on CO 2 reductions without acknowledging

fundamental aspects of the United States utility grid. Indeed, this type of forced “generation

shifting” has already been considered and rejected by the Supreme Court in West Virginia v. EPA,

where the Court explained that the CAA does not vest the EPA with sweeping authority to

“substantially restructure the American energy market.” 58 Considering the benefits of CO 2

emissions reductions associated with EGU closures in MATS is effectively considering the

restructuring of the American energy market as a benefit of the rule. This is a fatal flaw in EPA’s

benefits analysis in the 2023 Revocation, and in the Proposed Rule.

II.

Lignite-Fired EGUs Do Not Present Unacceptable Risks.

EPA has no authority to issue risk and technology review rules in the absence

of unacceptable risk, and lignite-fired EGUs pose no unacceptable risks.

EPA periodically conducts Risk and Technology Reviews (“RTR(s)”) pursuant to CAA

Sections 112(d)(6)59 and (f)(2). Section 112(f)(2) requires an unacceptable risk to exist for the

agency to promulgate revised emissions standards. If no unacceptable risk exists, CAA Section

112 does not grant EPA authority to promulgate revised standards. Here, EPA has not plausibly

demonstrated that lignite-fired EGUs create an unacceptable risk, thereby calling into question

EPA’s authority to promulgate revised emissions standards.

Lignite-fired EGUs do not pose an unacceptable risk under the most stringent

criteria utilized by EPA.

Even if it were appropriate and necessary to regulate EGUs under CAA Section 112, the

CAA does not require additional HAP standards for lignite-fired EGUs because HAPs from lignitefired EGUs do not cause a lifetime risk of cancer greater than 1-in

in-1 million to any individual in the

57 RIA at Section 4.4.

58 142 S.Ct. at 2610.

59 EPA does not consider any new practices, processes, and control technologies for MATS, thus additional

regulation under CAA 112(d)(6) is prohibited.

North American Coal

5340 Legacy Drive, Suite #300

Plano, TX 75024

972.448.5400

NACoal.com

population who is most exposed to emissions of such pollutants from any lignite-fired EGU.60 As

noted above, the 2020 Reconsideration determined that only four oil-fired facilities in Puerto Rico

caused a cancer risk above 1-in

in-1 million.61 As only oil-fired EGUs present cancer risk above the

1-in

in-1 million threshold, lignite-fired EGUs do not.

Coal-fired EGUs present risk far lower than 1-in

in-1 million cancer threshold described above.

Based on EPA’s RTR analysis in the 2020 Reconsideration, the highest risk currently presented by

any coal-fired EGU is actually just 0.344-in

in-1 million, which is well below the low risk level assigned

to the source category in its RTR.

And most lignite-fired EGUs present a considerably lower

risk than all coal-fired EGUs.

The “lignite-fired” units have predicted maximum individual cancer risks are shown in the

table below:64

Lignite-Fired EGU

Antelope Valley #1

Antelope Valley #2

Coal Creek #1

Coal Creek #2

Coyote

Leland Olds #1

Leland Olds #2

Milton R. Young #1

Milton R. Young #2

Spiritwood

Limestone #1

Limestone #2

Major Oak #1

Cancer MIR65 (-in

in-1 million)

0.0121

0.0131

0.00512

0.00309

0.0807

0.00351

0.0396

0.0446

60 See 42 U.S.C. §7412(f)(2)(A) (noting the 1-in

in-1 million standard).

61 See 85 Fed. Reg at 31319; see also Proposed Rule at 24863, FN 16.

62 EPA’s conclusion with respect to other health risks in the 2020 RTR is similar.

EPA states that “the highest chronic

noncancer [target organ-specific hazard index] and the highest acute non-cancer [hazard quotient] were below 1,

indicated low likelihood of adverse noncancer effects from inhalation exposures. There were also low risks

associated with ingestion, with the higher cancer risk being less than 50-in

in-1 million based on a conservative

screening assessment, and the highest non-cancer risk being less than 1 based on a site-specific multipathway

assessment.” 88 Fed. Reg. at 24,865.

63 See e.g., Residual Risk Assessment for the Coal- and Oil-Fired EGU Source Category in Support of the 2020 Risk

and Technology Review Final Review, at Appendix 10, Tables 1 & 2a (Facility NEI ID 540336271711).

64 See id. at Appendix 10, Tables 1 and 2a. Combined lignite-fired EGU average is depicted for facilities with more

than one lignite-fired EGU.

65 MIR stands for Maximum Individual Risk.

North American Coal

5340 Legacy Drive, Suite #300

Plano, TX 75024

972.448.5400

NACoal.com

Lignite-Fired EGU

Major Oak #2

Martin Lake #1

Martin Lake #2

Martin Lake #3

Oak Grove #1

Oak Grove #2

Red Hills #1

Red Hills #2

San Miguel

Cancer MIR65 (-in

in-1 million)

0.0446

0.137

0.0352

0.0863

0.191

Indeed, EPA’s RIA for the Proposed Rule reinforces the data demonstrating that the risk

associated with Hg and other HAP emissions from all EGUs—including the lignite-fired EGUs—is

low:

•

“[E]stimated risks from exposure to non-mercury metal HAP were not expected to exceed

acceptable levels….”66

•

“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

…. [T]hese results suggest that the residual risks from HAP exposure are low[.]” 67

•

“U.S. EGU source category emissions of non-mercury HAP are not expected to exceed 1 in

a million for inhalation cancer risk for those facilities impacted by the proposed controls.

Further, cancer risk was determined to fall within the acceptable range for multipathway

exposure to the persistent and bioaccumulative non-mercury metal HAP, such as arsenic,

cadmium, and lead.”68

•

“As HAP exposure results generated as part of the 2020 Residual Risk analysis were below

both the presumptive acceptable cancer risk threshold and the noncancer health

benchmarks, and this proposed regulation should further reduce exposure to HAP, there are

no ‘disproportionate and adverse effects’ of potential EJ concern.” 69

In any event, additional regulation of lignite-fired EGUs is inappropriate and inconsistent with

EPA’s congressional mandate. Moreover, EPA has the authority to establish subcategories within

source categories and distinguish among classes, types and sizes when promulgating standards. 70

Here, any additional regulation should be limited to a new subcategory of facilities that of the class

66 RIA at 4-2.

67 Id. at 4-4.

68 Id. at 4-7.

69 Id.

at 6-4.

70 42 U.S.C. §§ 7412(c)(1), (d)(1).

North American Coal

5340 Legacy Drive, Suite #300

Plano, TX 75024

972.448.5400

NACoal.com

and type that pose risk in excess of 1-in

in-1 million—the threshold for deregulation—which are all oil71

fired EGUs. In fact, the significant differences between the liquid-fueled (such as oil) EGUs and

solid-fueled (such as coal) EGUs justifying regulating them as entirely different source categories.

The absence of documented health risks suggest that EPA has an ulterior

motive for the more-stringent standards for lignite-fired EGUs set forth in the

Proposed Rule.

As described above, the evidence cited by EPA for the Proposed Rule demonstrates that

the health and environmental impacts of HAP emissions from lignite-fired EGUs are minimal. This

lack of compelling evidence, coupled with contemporaneous EPA proposals targeting coal-fired

EGUs and their operators, suggests EPA is taking another bite at the “generation shifting” apple

after the Supreme Court in West Virginia v. EPA stymied EPA’s efforts to that end last year. 72 In

other words, EPA is attempting to use the weight of numerous, exceptionally burdensome rules to

effect results the Supreme Court has already rejected—namely, the reduction of CO 2 emissions

through the effective forced retirement of coal-fired EGUs in favor of energy sources that may have

less CO2 emissions.

The Biden Administration has been candid about its desire to close coal plants and reduce

greenhouse gas emissions. In fact, President Biden made a pledge to world leaders to cut

greenhouse gas emissions in half by 2030 and be net zero by 2050 73. A 2021 executive order

builds on his “whole-of

of-government” effort to tackle the “climate crisis” by transitioning federal

infrastructure to zero-emission vehicles and buildings powered by carbon free electricity by 2030

and be net-zero by 205074. The only way the administration can meet these targets is for the energy

grid to transition away from coal-fired generation, install carbon capture and storage (“CCS”)

technology on the coal fleet, or a combination of both. Since CCS is not yet adequately

71 Despite presenting greater health risks than coal-fired EGUs, EPA is not proposing more stringent emissions

standards for oil-fired EGUs.

72 See, e.g., New Source Performance Standards for Greenhouse Gas Emissions From New, Modified, and

Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission Guidelines for Greenhouse Gas Emissions

From Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of the Affordable Clean Energy Rule, 88 Fed.

Reg. 33240 (May 23, 2023) (requiring coal-fired EGUs to shut down or implement carbon capture and

sequestration/storage control); Supplemental Effluent Limitations Guidelines and Standards for the Steam Electric

Power Generating Point Source Category, 88 Fed. Reg. 18824 (Mar. 29, 2023) (imposing substantially more

restrictive wastewater discharge effluent limitations); Hazardous and Solid Waste Management System: Disposal of

Coal Combustion Residuals From Electric Utilities; Legacy CCR Surface Impoundments, 88 Fed. Reg. 31982 (May

18, 2023) (expanding regulation of areas containing coal combustion residuals).

73 Biden commits to cutting U.S. emissions in half by 2030 as part of Paris climate pact (nbcnews.com) (last

accessed June 2021)

74 FACT SHEET: President Biden Signs Executive Order Catalyzing America’s Clean Energy Economy Through

Federal Sustainability | The White House (last accessed June 2023)

North American Coal

5340 Legacy Drive, Suite #300

Plano, TX 75024

972.448.5400

NACoal.com

MEMORANDUM

DATE:

July 2018

TO:

Docket ID No: EPA-HQ-OAR-2018-0794

FROM:

Nick Hutson, Melanie King, and Mary Johnson

U.S. EPA/OAQPS/SPPD/ESG

Steven McLeod and Mike Laney, RTI International

SUBJECT:

Technology Review for the Coal- and Oil-Fired EGU Source Category

This memorandum summarizes the results of an analysis the U.S. Environmental Protection

Agency (EPA) conducted in accordance with section 112(d)(6) of the Clean Air Act (CAA) to

identify developments in practices, processes, and control technologies applicable to sources

subject to the National Emission Standards for Hazardous Air Pollutants (NESHAP) for coaland oil-fired electric utility steam generating units (EGUs) (40 CFR 63, subpart UUUUU).

Specifically, the analysis focused on developments that have occurred since the original

promulgation of subpart UUUUU. This memorandum is organized as follows:

1.0

2.0

3.0

4.0

Background

Developments in Practices, Processes, and Control Technologies

Summary

References

1.0

BACKGROUND

1.1

Requirements of Section 112(d)(6) of the CAA

Section 112 of the CAA requires the EPA to establish technology-based standards for listed

source categories that are sources of hazardous air pollutants (HAP). These technology-based

standards are often referred to as maximum achievable control technology, or MACT, standards.

Section 112 also contains provisions requiring the EPA to periodically review these standards.

Specifically, paragraph 112(d)(6) states:

(6) REVIEW AND REVISION. – The Administrator shall review, and revise as

necessary (taking into account developments in practices, processes, and control

technologies), emissions standards promulgated under this section no less often than

every 8 years.

1.2

Description of the Coal- and Oil-fired Electric Utility Steam Generating Source

Category and Requirements of the Current NESHAP

The current NESHAP for the Coal- and Oil-Fired EGUs source category were promulgated on

February 16, 2012 (77 FR 9303) and are codified at 40 CFR part 63, subpart UUUUU

(commonly referred to as the Mercury and Air Toxics Standards (MATS)). The MATS rule was

645a

2.3

Mercury (Hg)

Subpart UUUUU regulates emissions of Hg from coal- and oil-fired EGUs. During combustion

Hg in the resulting flue gas is speciated into elemental mercury vapor (Hg0), gaseous oxidized

mercury compounds (Hg2+), and particle-bound (Hg-p). Finely powdered sorbent (usually

activated carbon) injected upstream of a PM collection device can be used to capture Hg present

in the flue gas. Also, existing air pollution control devices installed for reducing emissions of

nitrogen oxide (NOX), PM and sulfur oxides (SOX) can have a co-beneficial effect on Hg control.

For example, fabric filters or ESPs for PM control capture particle-bound Hg.

2.3.1

Hg Reduction – Current Implementation

Activated carbon injection (ACI) is the most commonly used mercury-specific control

technology being implemented at coal-fired EGUs. An ACI system is an add-on air

pollution control system in which sorbent is injected into the flue gas upstream of a PM

control device to bind the gas phase Hg in the exhaust stream. The gaseous Hg is bound

to the powdered activated carbon and then removed by the downstream PM control

device

From a review of CAMD databases, we compiled a list of control technologies being

used on EGUs currently in operation. The number of each Hg control or control

combination by primary fuel type as reported to CAMD is summarized in Table 3 below.

Table 3 - Counts of Each Hg Control / Control Combinations by Primary Fuel Type

Subbituminous

Coal

Lignite

Coal

Refuse

Petroleum

Coke

Residual

Oil

Diesel

Oil

Other

Oil

Total

---

-2

214

-97

-1

-6

--3

------3

-----------19

---1

-------5

-----------25

-----------1

-----------30

109

397

610

Control Type(s)a, b

Bituminous

Coal

APAC

APAC, HPAC

APAC, SORB,

UPAC

APAC, UPAC

CAT

CAT, HPAC

HPAC

HPAC, REAC

HPAC, SB

REAC

SORB

SORB, UPAC

UPAC

(N/A or None)

646a

Control Type(s)a, b

Bituminous

Coal

Subbituminous

Coal

Lignite

Coal

Refuse

Petroleum

Coke

Residual

Oil

Diesel

Oil

Other

Oil

Total

APAC = Additives to enhance powdered activated carbon (PAC) and existing equipment performance,

CAT = Catalyst (e.g., gold, palladium, other) used to oxidize Hg,

HPAC = Halogenated PAC sorbent injection, REAC = Regenerative activated coke technology

SB = Sodium based, SDA = Spray dryer absorber, SORB = Injection of other (non-PAC) sorbents,

UPAC = Untreated PAC sorbent injection, N/A = not available

APAC, HPAC, and UPAC are types of ACI

The reported Hg-specific air pollution control devices and control device combinations

for solid fuels are primarily sorbent injection technologies. Specifically, activated carbon

injection technologies such as APAC (additives to enhance powdered activated carbon

and existing equipment performance) and HPAC (halogenated b powdered activated

carbon sorbent injection) are reported to be installed most frequently. However, most of

the facilities reported no Hg-specific control devices and are assumed to be meeting the

MATS rule with co-beneficial Hg capture coming as a result of air pollution control

devices that are installed for other pollutants.

2.3.2

Hg Reduction – Developments

This review identified no developments (as defined in Section 2.0 above) in practices,

processes, or control technologies for Hg that have been implemented in this source

category since promulgation of the current MATS rule.

The existing Hg air pollution control technologies that are currently in use are wellestablished and provide the capture efficiencies necessary for compliance with the

subpart UUUUU Hg limits. Hg is being removed by activated carbon control

technologies and by air pollution control devices such as wet FGD, ESP, and SCR that

are installed at EGUs to control criteria pollutants.5

Based on the effectiveness and proven reliability of these Hg control technologies, and

the relatively short period of time (~six years) since the promulgation of the MATS rule,

no developments in practices, processes, or control technologies nor any new

technologies or practices were identified.

2.4

Organic HAP

Subpart UUUUU contains work practice standards for the control of organic HAP emissions,

including emissions of dioxins and furans, for all subcategories of EGUs. These work practice

standards require periodic burner tune-ups to ensure good combustion. The standard requires

maintaining and inspecting the boiler burners and associated combustion controls, tuning the

specific burner type to optimize combustion, obtaining and recording carbon monoxide (CO) and

NOX values before and after the burner adjustments, keeping records of activity and

measurements, and submitting a report, if requested, for each tune-up conducted.

Halogenated PAC is most of often PAC that has been treated with bromine or a bromine compound (i.e.,

“brominated PAC”).

647a

Residual Risk Assessment for the Coal- and Oil-Fired EGU Source Category in Support of the Risk

and Technology Review 2020 Final Rule

Residual Risk Assessment for the

Coal- and Oil-Fired EGU Source Category in Support of the 2020

Risk and Technology Review Final Rule

EPA's Office of Air Quality Planning and Standards

Office of Air and Radiation

September 2019

648a

Appendix 10

Detailed Risk Modeling Results

649a

Table 1 - Facility Identification Information

Facility NEI ID

010731003111

010971056111

01117949211

011277917311

01 129102861 1

0206812662311

Facility Name

James H Miller Jr

Barry

E C Gaston

Gorgas

Charles R Lowman

Healy Power Plant

040017735011

Coronado Generating Station

040017735111

04003862811

0400513606211

04017863011

050071015511

0505716584111

050631083411

05069893911

0509315259811

08001355581 1

08013778211

080414391711

080414392711

080694364011

080811839711

080853457111

08087897211

081014367811

081074458511

09001 75431 1

09007715711

09009643411

09011552611

10005640911

12001535011

12017640611

12031640211_1

12031640211_2

12033752711

12057538611

12085717611

12095845411

Springerville Generating Station

Apache Station

Navajo Generating Station

Cholla

Flint Creek Power Plant

John W. Turk Jr. Power Plant

Independence

White Bluff

Plum Point Energy Station

Cherokee

Valmont

Martin Drake

Ray D Nixon

Rawhide Energy Station

Craig

Nucla

Pawnee

Comanche (470)

Hayden

Bridgeport Harbor Station

Middletown

New Haven Harbor

Montville

Indian River

Deerhaven

Crystal River

Northside

St. Johns River Power

Grist Electric Generating Plant

Big Bend

lndiantown Cogeneration, LP

Curtis H. Stanton Energy Center

12105643111

12105751911

121072474411

130152813011

131033711211

131153713211

131497415011

132078354711

C D McIntosh Jr Power Plant

Polk

Seminole (136)

Bowen

McIntosh (6124)

Hammond

Wansley (6052)

Scherer

Address

4250 Porter RD

Hwy 43

Hwy 25

460 Gorgas Rd

Larson Rd

Mile 2.5 Healy Spur Rd

6M1/NE ST JOHNSHWY191/131018

OFF RTE 191, APP 15 MI NE

SPRI

3525 NORTH HIGHWAY 191

5 MI E OF PAGE ON HWY 98

4801 CHOLLA LAKE ROAD

21797 SWEPCO PLANT RD

3711 Highway 355 South

555 POINT FERRY RD

1100 WHITE BLUFF ROAD

2732 SOUTH COUNTY RD 623

6198 FRANKLIN STREET

1800 N 63RD ST

700 S CONEJOS ST

14020 RAY NIXON RD.

2700 E COUNTY ROAD 82

2101 S RANNEY

30739 DD 31 RD

14940 COUNTY ROAD 24

2005 LIME RD

13125 US HWY 40

1 ATLANTIC ST

1866 RIVER RD

1 WATERFRONT ST

74 LATHROP RD

29416 POWER PLANT ROAD

10001 NW 13th St

15760 West Power Line Street

4377 Heckscher Drive

11999 Pate Street

13031 WYANDOTTE ROAD

13303 SW SILVER FOX LANE

5100 Alafaya Trail

3030 EAST LAKE PARKER

DRIVE

9995 STATE ROUTE 37 SOUTH

890 NORTH U.S. HIGHWAY 17

317 Covered Bridge Rd

981 Old Augusta Road

5963 Alabama Hwy SW

1371 Liberty Church Road

10986 Highway 87

1 of 7

City

Quinton

Bucks

Wilsonville

Parrish

Leroy

Healy

State County

Jefferson County

Mobile County

Shelby County

Walker County

Washington County

Denali Borough

ST JOHNS

Apache County

SPRINGERVILLE, A AZ

COCHISE

PAGE

JOSEPH CITY

GENTRY

FULTON

NEWARK

REDFIELD

OSCEOLA

COMMERCE CITY F CO

BOULDER AREA

COLORADO SPRIM CO

FOUNTAIN AREA

WELLINGTON 9.3 N CO

CRAIG 2.9 MI. SW C CO

NUCLA 2.2 MI. SE C CO

BRUSH, 2.6 MI SW 1CO

PUEBLO

HAYDEN

BRIDGEPORT

MIDDLETOWN

NEW HAVEN

UNCASVILLE

DAGSBORO

GAINESVILLE

CRYSTAL RIVER

JACKSONVILLE

PENSACOLA

APOLLO BEACH

INDIANTOWN

ORLANDO

Apache County

Cochise County

Coconino County

Navajo County

Benton County

Hempstead County

Independence County

Jefferson County

Mississippi County

Adams County

Boulder County

El Paso County

Larimer County

Moffat County

Montrose County

Morgan County

Pueblo County

Routt County

Fairfield County

Middlesex County

New Haven County

New London County

Sussex County

Alachua County

Citrus County

Duval County

Escambia County

Hillsborough County

Martin County

Orange County

LAKELAND

MULBERRY

PALATKA

Cartersville

Rincon

Coosa

Carrollton

Juliette

Polk County

Putnam County

Bartow County

Effingham County

Floyd County

Heard County

Monroe County

650a

Table 1 - Facility Identification Information

Facility NEI ID

1 5003732091 1

150037429511

15003835401 1

170211929211

17057320651 1

1 7079258701 1

170977792311

171257337411

171277808911

171357340311

17143542271 1

1 71 55468531 1

17157795461 1

171677377311

171798199411

1718910857911

171978018111

17199816451 1

180437742411

180517363111

1 8073795701 1

1 8077774421 1

180834478911

180918011511

181257362411

181277376611

181298166111

181478017211

18153839621 1

18165724851 1

1 81 7381 8301 1

181738183111

181775506011

1 9005550931 1

1 901 31 280621 1

190575511811

19113394021 1

191153942411

19139789281 1

19155299261 1

1 91 79373221 1

1 91 93294341 1

1 91 93294351 1

200454827111

200553167611

201075367811

201495406811

201 77382301 1

202094633811

210156040811

Facility Name

Waiau Generating Station

Kahe Generating Station

AES Hawaii

Kincaid Generating Station

Duck Creek

Newton

Waukegan

Havana

Joppa Steam

Coffeen

E D Edwards

Hennepin Power Station

Baldwin Energy Complex

Dallman

Powerton

Prairie State Generating Station

Will County

Marion

R Gallagher

Gibson

R M Schahfer Generating Station

Clifty Creek

Edwardsport Generating Station

Michigan City Generating Station

IPL - Petersburg Generating Station

Bailly Generating Station

A B Brown Generating Station

Rockport

Merom

Cayuga

F B Gulley Generating Station

Alcoa Allowance Management Inc

Whitewater Valley

Lansing

Streeter Station

Burlington (IA)

Prairie Creek

Louisa

Muscatine

Walter Scott Jr. Energy Center

Ottumwa

George Neal North

George Neal South

Lawrence Energy Center

Holcomb

La Cygne

Jeffrey Energy Center

Tecumseh Energy Center

Nearman Creek

East Bend

Address

475 Kamehameha Hwy.

92-200 Farrington Highway

91-086 Kaomi Loop

4 Mi W Of Kincaid Rte 104

17751 N Cilco Rd

6725 N 500th St

401 E Greenwood Ave

15260 N Rte 78

2100 Portland Rd

134 CIPS Ln

7800 S Cilco Ln

13498 E 800 St

10901 Baldwin Rd

3100 Stevenson Dr

13082 E Manito Rd

3872 County Hwy 12

529 E 135th St

10825 Lake of Egypt Rd

30 Jackson St

1097 N CR 950 W

2723 E CR 1500 N

1335 Clifty Hollow Rd

15424 E SR 358

101 Wabash St

6925 N SR 57

246 Bailly Station Rd

8511 Welborn Rd

2791 N US Hwy 231

5500 W Old SR 54

3300 N SR 63

3711 Darlington Rd

4700 Darlington Rd

2000 US Hwy 27 S

2320 POWER PLANT DR

UTILITY PKWY

4282 SULLIVAN SLOUGH RD

3300 C ST SW

8602 172ND ST

1700 DICK DRAKE WAY

7215 NAVAJO ST

20775 POWER PLANT RD

1151 260TH ST

2761 PORT NEAL CIR

1250 N 1800 RD

2440 HOLCOMB LANE

25166 E 2200 RD

25905 JEFFREY RD

2ND & DUPONT RD

4240 N 55TH

6293 Beaver Rd

2 of 7

City

State County

Pearl City

Honolulu County

Kapolei

Honolulu County

Christian County

Kincaid

Canton

Fulton County

Newton

Jasper County

Waukegan

Lake County

Mason County

Havana

Massac County

Joppa

Coffeen

Montgomery County

Bartonville

Peoria County

Hennepin

Putnam County

Baldwin

Randolph County

Springfield

Sangamon County

Pekin

Tazewell County

Marissa

Washington County

Romeoville

Will County

Marion

Williamson County

New Albany

Floyd County

Owensville

Gibson County

Wheatfield

Jasper County

Madison

Jefferson County

Edwardsport

Knox County

Michigan City

La Porte County

Petersburg

Pike County

Chesterton

Porter County

Mount Vernon

Posey County

Rockport

Spencer County

Sullivan

Sullivan County

Cayuga

Vermillion County

Newburgh

Warrick County

Newburgh

Warrick County

Richmond

Wayne County

LANSING

Allamakee County

CEDAR FALLS

Black Hawk County

BURLINGTON

Des Moines County

CEDAR RAPIDS

Linn County

MUSCATINE

Louisa County

MUSCATINE

Muscatine County

COUNCIL BLUFFS IA

Pottawattamie County

OTTUMWA

Wapello County

SERGEANT BLUFF IA

Woodbury County

SALIX

Woodbury County

LAWRENCE

Douglas County

HOLCOMB

Finney County

LA CYGNE

Linn County

ST. MARYS

Pottawatomie County

TECUMSEH

Shawnee County

KANSAS CITY

Wyandotte County

Union

Boone County

651a

Table 1 - Facility Identification Information

Facility NEI ID

210415198511

21 0595891 71 1

211016067211

211117353711

211456037011

211617335511

211675933111

211775196711

21 183556161 1

211995787711

212235742811

21233609861 1

220198361211

22031 735441 1

220778020711

220797446811

230055823511

240017717711

240036084311_1

240036084311_2

240055155011

240176011511

240197945511

24031599801 1

240336011911

25001771851 1

250055058811

250136028411

26017817281 1

2604541 7481 1

260655985211

261014856911

Facility Name

Ghent

Elmer Smith

HMP&L Station 2

Mill Creek

Shawnee

H L Spurlock

E W Brown

Paradise

D B Wilson

John S. Cooper

Trimble County

R D Green

R S Nelson

Dolet Hills Power Station

Big Cajun 2

Brame Energy Center

William F Wyman

AES Warrior Run

Brandon Shores

Herbert A Wagner

C P Crane

Morgantown

Vienna

Dickerson

Chalk Point

Canal Station

Cleary Flood

West Springfield

Dan E Karn

Erickson

Eckert Station

TES Filer City Station

261037778411

261037779711

261157888311

261396336811

261398125511

261477239111_1

261477239111_2

261637422511

261638229311

270317039811

270616173211

271117072311

271416990811

271636772111

280197053011

280596251011

Presque Isle

Shiras

Monroe

J B Sims

J H Campbell

Belle River

St. Clair

Trenton Channel

River Rouge

Taconite Harbor Energy Center

Boswell Energy Center

Hoot Lake

Sherburne County

Allen S King

Red Hills Generation Facility

Daniel Electric Generating Plant

Address

9485 US 42 E

4301 US 60 E

9000 KY 2096

14660 DIXIE HWY

7900 Metropolis Lake Rd

KY 8

815 Dix Dam Rd

13246 KY 176 Ste 10

5663 KY 85 W

7130 KY 1247 S

487 Corn Creek Rd

Jct of KY 2097 & KY 2096

3500 Houston River Rd

963 Power Plant Rd

10431 Cajun 2 Rd (Hwy 981)

275 Rodemacher Rd

677 COUSINS ST

1 1600 Mexico Farms Rd, SE

1005 Brandon Shores Rd

1001 Carroll Island Road

12620 Crain Hwy

PO Box 128

21200 Martinsburg Rd

8711 Westphalia Rd

9 FREEZER RD

1314 SOMERSET AVE

15 AGAWAM AVE

2742 N. Weadock Hwy.

3725 South Canal Road

601 Island Ave

700 Mee Street

2701 N LAKESHORE

BOULEVARD

400 E HAMPTON

3500 E FRONT ST

1231 N. Third St.

17000 Croswell

4901 POINTE DR.

4695 W JEFFERSON AVE

1 BELANGER PARK DR

8124 W Highway 61

1210 NW 3rd St

water plant road

13999 Industrial Blvd

1103 King Plant Rd

2391 Pensacola Road

13201 Highway 63 North

3 of 7

City

State County

Ghent

Carroll County

Owensboro

Daviess County

Robards

Henderson County

LOUISVILLE

Jefferson County

West Paducah

McCracken County

Maysville

Mason County

Mercer County

Harrodsburg

Drakesboro

Muhlenberg County

Centertown

Ohio County

Somerset

Pulaski County

Trimble County

Bedford

Webster County

Sebree

Westlake

Calcasieu Parish

Mansfield

De Soto Parish

New Roads

Pointe Coupee Parish

Rapides Parish

Lena

YARMOUTH

Cumberland County

Cumberland

Allegany County

Baltimore

Anne Arundel County

Baltimore

Anne Arundel County

Middle River

Baltimore County

Newburg

Charles County

Vienna

Dorchester County

Dickerson

Montgomery County

Aquasco

Prince George's Coun.

SANDWICH

Barnstable County

TAUNTON

Bristol County

WEST SPRINGFIEL MA

Hampden County

ESSEXVILLE

Bay County

LANSING

Eaton County

LANSING

Ingham County

FILER CITY

Manistee County

MARQUETTE

MONROE

GRAND HAVEN

WEST OLIVE

SAINT CLAIR

TRENTON

RIVER ROUGE

Schroeder

Cohasset

Fergus Falls

Becker

Bayport

Ackerman

Moss Point

Marquette County

Monroe County

Ottawa County

St. Clair County

Wayne County

Cook County

Itasca County

Otter Tail County

Sherburne County

Washington County

Choctaw County

Jackson County

652a

Table 1 - Facility Identification Information

Facility NEI ID

Facility Name

2807371 5441 1

290716032111

290777496411

290837529611

290957663711

290957664111

290975321511

R D Morrow Senior Generating Plant

Labadie

John Twitty Energy Center

Montrose

Hawthorn

Sibley

Asbury

290995258811

291435363811

291656795111

291 75668841 1

291836783411

291896816611

29201759541 1

30003785151 1

300837618511

300877765611

300877854911

301115270711

310018399211

310537766111

310556732411

310798212011

311095281111

311117766511

311317303711

3201112758911

32013730201 1

33013817891 1

330157287811

330157288011

3400951 3301 1

340158093811

340337989011

350315597111

3504571 9771 1

350457991 91 1

360637417811

36071 842781 1

360757980511

36081 830901 1

361098542611

370218392811

370358370411

Rush Island

New Madrid Power Plant

latan

Thomas Hill Energy Center

Sioux

Meramec

Sikeston

Hardin Generating Station

Lewis & Clark

Colstrip

Colstrip Energy Limited Partnership

Yellowstone Energy Limited Partnership

Gerald Whelan Energy Center

Lon D Wright Power Plant

North Omaha Station

Platte

Sheldon

Gerald Gentleman Station

Nebraska City Station

TS Power Plant

North Valmy

Merrimack

Schiller

Newington

B L England

Logan Generating Plant

Carneys Point

Escalante

Four Corners Steam Elec Station

San Juan

Somerset Operating Company (Kintigh)

Roseton Generating LLC

Oswego Harbor Power

Ravenswood Generating Station

Cayuga Operating Company, LLC

Asheville

Marshall

Address

304 Old Okahola Schoolhouse

Road

LABADIE BOTTOM ROAD

5100 WEST FARM ROAD 164

400 SW HIGHWAY P

8700 HAWTHORN ROAD

33200 EAST JOHNSON RD

21133 UPHILL LANE

HWY 61 AT AA VIA BIG

HOLLOW RD

41 ST. JUDE ROAD

20250 HIGHWAY 45 NORTH

5693 HWY F

HWY 94

8200 FINE RD

1551 W WAKEFIELD ST

SUGAR FACTORY RD

MT HWY 23

WILLOW AVENUE

ROSEBUD PLANT

2215 N FRONTAGE RD

4520 E South St

2701 E 1st St

7475 Pershing Drive

1035 W Wildwood Dr

4500 W Pella Rd

6089 S Highway 25

7264 L Rd

3 mi North of Dunphy

North of 180 Stonehouse Int 212

431 RIVER ROAD

400 GOSLING ROAD

165 GOSLING ROAD

900 NORTH SHR RD

76 RT 130

500 SHELL RD

County Road 19

US 550

6800 N County Road

7725 LAKE RD

992 RIVER RD

261 WASHINGTON BLVD

38-54 VERNON BLVD

228 CAYUGA DR

200 CP&L Drive

8320 East NC Hwy 150

370458300611

370658124311

37071813751 1

Cliffside

Edgecombe Genco, LLC

G G Allen

573 Duke Power Road (SR 1002) Mooresboro

6358 Old Battleboro Road

Battleboro

253 Plant Allen Rd.

Belmont

4 of 7

City

State County

Purvis

LABADIE

SPRINGFIELD

CLINTON

KANSAS CITY

SIBLEY

ASBURY

Lamar County

Franklin County

Greene County

Henry County

Jackson County

Jasper County

FESTUS

MARSTON

WESTON

CLIFTON HILL

WEST ALTON

ST. LOUIS

SIKESTON

HARDIN

SIDNEY

COLSTRIP

BILLINGS

Hastings

Fremont

Omaha

Grand Island

Hallam

Sutherland

Nebraska City

DUNPHY

VALMY

BOW

PORTSMOUTH

NEWINGTON

BEESLEY'S POINT

SWEDESBORO

CARNEYS POINT

Prewitt

Fruitland

Waterflow

BARKER

NEWBURGH

OSWEGO

QUEENS

LANSING

Arden

Terrell

Jefferson County

New Madrid County

Platte County

Randolph County

St. Charles County

St. Louis County

Scott County

Big Horn County

Richland County

Rosebud County

Yellowstone County

Adams County

Dodge County

Douglas County

Hall County

Lancaster County

Lincoln County

Otoe County

Eureka County

Humboldt County

Merrimack County

Rockingham County

Cape May County

Gloucester County

Salem County

McKinley County

San Juan County

Niagara County

Orange County

Oswego County

Queens County

Tompkins County

Buncombe County

Catawba County

Cleveland County

Edgecombe County

Gaston County

653a

Table 1 - Facility Identification Information

Facility NEI ID

370838048111 1

370838048111_2

371457826011

371457826111

371698514011

380558011011

380578086311

380578086511

380578086611

380598087011

380658087911

3809316937511

390018101311

390018101411

390258294311

390318010811

390537983011

390538148511

390617738711

390818115711

390818190811

3909381 3081 1

390958302011

400238449511

400798148711

400978522311

401018506011

401038519411

401318212411

Facility Name

Westmoreland Partners Roanoke Valley I

Westmoreland Partners Roanoke Valley II

Roxboro

Mayo

Belews Creek

Coal Creek

Leland Olds

Antelope Valley

Coyote

R M Heskett

Milton R Young

Spiritwood Station

J M Stuart

Killen Station

W H Zimmer Generating Station

Conesville

Kyger Creek

Gen J M Gavin

Miami Fort Power Station

Cardinal

W H Sammis

Avon Lake Power Plant

Bay Shore

Hugo

AES Shady Point, LLC

Grand River Dam Authority

Muskogee

Sooner

Northeastern

410498171111

420038404811

420053866111

420073853711

420216594311

420216594411

420216594511

420257889011

420456662011

420632905911

420633005111

420633005211

420933881111

420953881711

420956558911

420973762011

421074105111

421074105211

421074735811

421078331411

Boardman

Cheswick

Keystone

Bruce Mansfield

Ebensburg Power Company

Colver Power Project

Cambria Cogen

Panther Creek Energy Facility

Eddystone Generating Station

Conemaugh

Seward

Homer City

Montour, LLC

Martins Creek, LLC

Northampton Generating Plant

Mt. Carmel Cogeneration

Gilberton Power Company

Northeastern Power Company

WPS Westwood Generation, LLC

Wheelabrator - Frackville

Address

290 Power Place

1700 Dunnaway Road

10660 Boston Road

3195 Pine Hall Road

2875 3rd St SW

3901 Hwy 200A

294 County Road 15

6240 13th St SW

T139 R81 Sct10

3401 24th St SW

93rd Ave SE

745 U.S. Route 52

14869 U.S. Route 52

1781 US Route 52

47201 County Road 273

5758 State Route 7 North

7397 N. St Rt #7

11021 Brower Road

306 County Road 7 East

29503 State Rte 7

33570 Lake Road

4701 Bay Shore Road

970N 4335 Rd

3 MILES E OF HWY 31/59 JCT

8142 HWY 412B

5501 Three Forks Road

10800 COUNTY RD 230

SE OF HWY169 & HWY88

CARTY RESERVOIR POWER

SITE, TOWER ROAD

100 PITTSBURGH ST

313 KEYSTONE DR

128 FERRY HILL RD

CAMBRIA CNTY IND PARK

141 INTERPOWER DR

243 RUBISCH RD

4 DENNISON RD

1 INDUSTRIAL HWY

1442 POWER PLANT RD

595 PLANT RD

1750 POWER PLANT RD

18 MCMICHAEL RD

FOUL RIFT RD

1 HORWITH DR

MARION HEIGHTS RD

50 ELEANOR DR

ROUTE 309

490 W MAIN ST

475 MOREA RD

5 of 7

City

Weldon

Semora

Roxboro

Walnut Cove

Underwood

Stanton

Beulah

Mandan

Center

Spritwood

Aberdeen

Manchester

Moscow

Conesville

Cheshire

North Bend

Brilliant

Stratton

Avon Lake

Oregon

FORT TOWSON

PANAMA

CHOUTEAU

FORT GIBSON

RED ROCK

OOLOGAH

State County

Halifax County

Person County

Stokes County

McLean County

Mercer County

Morton County

Oliver County

Stutsman County

Adams County

Clermont County

Coshocton County

Gallia County

Hamilton County

Jefferson County

Lorain County

Lucas County

Choctaw County

Le Flore County

Mayes County

Muskogee County

Noble County

Rogers County

BOARDMAN

SPRINGDALE

SHELOCTA

SHIPPINGPORT

REVLOC

COLVER

EBENSBURG

NESQUEHONING PA

EDDYSTONE

NEW FLORENCE

HOMER CITY

WASHINGTONVILLE PA

MARTINS CREEK PA

NORTHAMPTON

MARION HEIGHTS PA

FRACKVILLE

MCADOO

TREMONT

FRACKVILLE

Morrow County

Allegheny County

Armstrong County

Beaver County

Cambria County

Carbon County

Delaware County

Indiana County

Montour County

Northampton County

Northumberland Coun

Schuylkill County

654a

Table 1 - Facility Identification Information

Facility NEI ID

421078406511

421214760211

42133319391 1

450154120411

450158306711

450436652811

450757870811

450797126411

460514962811

470016196011

470855720911

471454979111

471575720111

Facility Name

St. Nicholas Cogeneration Project

Scrubgrass Generating Plant

Brunner Island, LLC

Cross

Williams

Winyah

Cope Station

Wateree

Big Stone

Bull Run

Johnsonville

Kingston

Allen

Address

120 YATESVILLE RD

2151 LISBON RD

1400 WAGO RD

553 CROSS STATION RD

2242 BUSHY PARK RD

661 STEAM PLANT DR

405 TEAMWORK RD

RTE 2 HWY 601

Northwest Of Big Stone City

1265 EDGEMOOR ROAD

535 STEAM PLANT ROAD

714 SWAN POND ROAD

2474 Plant Road

471614979311

471655610411

Cumberland

Gallatin

815 CUMBERLAND CITY ROAD CUMBERLAND

1499 STEAM PLANT ROAD

GALLATIN

Stewart County

Sumner County

480134898511

480295617211_1

480295617211_2

San Miguel

J T Deely

J K Spruce

CHRISTINE

SAN ANTONIO

Atascosa County

Bexar County

481494144811

481 57396841 1

481754018411

Sam Seymour

W A Parish

Coleto Creek

LA GRANGE

THOMPSONS

FANNIN

Fayette County

Fort Bend County

Goliad County

481856436311

482034845611

Gibbons Creek Steam Electric Station

H W Pirkey Power Plant

BRYAN

HALLSVILLE

Grimes County

Harrison County

482794930011

482935650511

Tolk Station

Limestone

11 MI S, SH 16; 6 MI E FM 3387

12940 S US HWY 181

7 M E OF LA GRANG ON HWY

2500 Y U JONES RD

45 FM 2987

FM 244 2.5 MI N OF HWY 30;

NEAR CARLOS

RT 2 BOX 165

ON HWY 70 9 MIL EAST OF

MULESHOE TX THEN 3 MI S

FROM FM 2910

9 MI N OF JEWETT ON FM 39

MULESHOE

JEWETT

Lamb County

Limestone County

RIESEL

McLennan County

AMARILLO

FRANKLIN

CALVERT

TATUM

MOUNT PLEASANT TX

Potter County

Robertson County

Rusk County

Titus County

OKLAUNION

Carbon County

Castle Dale

Huntington

Delta

Vernal

Chester

Wilbarger County

Carbon County

Emery County

Millard County

Uintah County

Chesterfield County

4830915628511

Sandy Creek Energy Station

483755745311

4839513385811

483957552911

484014207311

484494164411

Harrington Station

Oak Grove

Twin Oaks

Martin Lake

Welsh Power Plant

484877927311

490075066411

490155050511

490155050611

490277558311

490476281811

510414181011

Oklaunion Power Station

Sunnyside Cogeneration Associates

Hunter

Huntington

Intermountain

Bonanza

Chesterfield Power Station

APPX 2 MI W OF RIESEL;

FROM FM 1860 TURN N AT

THE 2ND ENTRANCE TO

RATTLESNAKE RD; GO 1/2 MI;

TURN R

2.7 M N ON LAKESIDE DR

FROM SH 136

11 MI E OF TOWN

8 M N OF CALVERT ON HWY 6

8850 FM 2658 N

1 187 CR 4865

3.5 MI SSW OF OKLAUNION

ON FM 3430

State Road 123

P.O. Box 569

P. O. Box 680

850 West Brush Wellman Road

12500 East 25500 South

500 Coxendale Rd

6 of 7

City

State County

SHENANDOAH

Schuylkill County

KENNERDELL

Venango County

YORK HAVEN

York County

PINEVILLE

Berkeley County

GOOSE CREEK

Berkeley County

GEORGETOWN

Georgetown County

COPE

Orangeburg County

EASTOVER

Richland County

Big Stone City

Grant County

CLINTON

Anderson County

NEW JOHNSONVILI TN

Humphreys County

HARRIMAN

Roane County

Memphis

Shelby County

655a

Table 1 - Facility Identification Information

Facility NEI ID

510836160611

510996148811

511175748311

511537520511

5119516530111

511994565211

517604039911

53041628131 1

540236257011

540336271 71 1

540494864511

540516902311

540536760811

5406116320111

540616773611

540616773811

540734782811

540796789111

550095295111

550114958511

550217673611

550597509411

55071 71 7961 1

550737078511

550796330411_1

550796330411_2

551177692911

551237711211

5600512810911

5600512811111

5600515064111

5600515659411

560057844911

560058041911

560096418211

560238419211

560314207711

560373962711

720577128511

720597129111

721236958711

Facility Name

Clover Power Station

Birchwood Power Facility

Mecklenburg Power Station

Possum Point Power Station

Virginia City Hybrid Energy Center

Yorktown Power Station

Spruance Genco, LLC

Centralia

Mount Storm Power Station

Harrison Power Station

Grant Town Power Plant

Mitchell (WV)

Mountaineer (1301)

Longview Power

Fort Martin Power Station

Morgantown Energy Facility

Pleasants Power Station

John E Amos

Pulliam

J P Madgett

Columbia

Pleasant Prairie

Manitowoc

Weston

South Oak Creek

Elm Road Generating Station

Edgewater (4050)

Genoa

Wygen I

Wygen II

Wygen III

Dry Fork Station

Neil Simpson II

Wyodak

Dave Johnston

Naughton

Laramie River

Jim Bridger

AES Puerto Rico, LP

Costa Sur Steam Power Plant

Aguirre Steam Power Plant

721276878311

721377438511

San Juan Steam Power Plant

Palo Seco Steam Power Plant

Address

4091 Clover Road

10900 Birchwood Dr

204 Cogen Drive

19000 Possum Point Rd

3425 Russell Creek Road

1600 Waterview Rd

5001 Commerce Rd

913 Big Hanaford Road

436 DOMINION BLVD

STATE ROUTE 20

Route 17

STATE ROUTE 2

STATE ROUTE 62

1375 FORT MARTIN ROAD

STATE ROUTE 53

555 BEECHURST AVENUE

No.1 Power Station Boulevard

STATE ROUTE 817

1501 Bylsby Ave

500 Old State Road 35

W8375 Murray Rd

8000 95th St

701 Columbus St

2501 Morrison Ave

1 1060 S Chicago Rd

3739 Lakeshore Dr

Rr 1 Box 276

27,50N,71W

22,50N,71W

27,50N,71W

24,51N,72W

27,50N,71W

7,33N,74W

32,21N,116W

30,25N,66W

3,20N,101W

PR 3, Km 142, Jobos Ward

Road 127

Road PR-3, Km 152.3

Mercado Central Ave, Zona

Central Ave, PR-28

Road 165, Km 3.8, Toa Baja

7 of 7

City

Clover

King George

Clarksville

Dumfries

St Paul

Yorktown

Richmond

Centralia

MOUNT STORM

HAYWOOD

Grant Town

CRESAP

NEW HAVEN

MAIDSVILLE

MORGANTOWN

WILLOW ISLAND

ST. ALBANS

Green Bay

Alma

Pardeeville

Pleasant Prairie

Manitowoc

Rothschild

Oak Creek

Sheboygan

Genoa

Campbell

Converse

Lincoln

Platte

Sweetwater

Guayama

Guayanilla

Salinas

State County

Halifax County

King George County

Mecklenburg County

Prince William County

Wise County

York County

Richmond city

WA Lewis County

Grant County

WV Harrison County

WV Marion County

WV Marshall County

WV Mason County

WV Monongalia County

WV Pleasants County

WV Putnam County

Brown County

Buffalo County

Columbia County

Kenosha County

Manitowoc County

Marathon County

Milwaukee County

Sheboygan County

Vernon County

Campbell County

Converse County

WY Lincoln County

WY Platte County

Sweetwater County

Guayama Municipio

Guayanilla Municipio

Salinas Municipio

San Juan

Toa Baja

San Juan Municipio

Toa Baja Municipio

656a

657a

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MEMORANDUM

FROM:

TO:

DATE:

SUBJECT:

 



 



  



  

 

  







 



















1. Background

 



 





  

   



  

 









 

 

  







  





  



   











 

 



2. Filterable Particulate Matter (fPM) Emission Limit

a) Baseline fPM Rates

    

  



 

 

 

 

   

 

     

   

  

 

   



 

 

  

   







National Emission Standards for Hazardous Air Pollutants: Coaland Oil-Fired Electric Utility Steam Generating Units

Review of the Residual Risk and Technology Review

Summary of Public Comments and Responses on Proposed Rule

(88 FR 24854 April 24, 2023)

April 2024

664a



Commenters further noted that the EPA employed a different data selection methodology

for each of those years and based on type of compliance measure used (CEMS vs. stack

test).



Commenters suggested that the EPA analyze more comprehensive historical data sets

across a longer timeframe rather than using a snapshot of EGUs demonstrating

compliance with the proposed limit during selected quarters prior to concluding that

continuous compliance with the proposed limit is achievable.



Comment: They also suggested if the EPA eliminates performance testing as a

compliance option, then the EPA should rely exclusively on a robust set of PM CEMS

data in terms of the number of units and datapoints used.

Commenters also provided unit-specific comments and observations:

 Commenters stated the Coronado PM CEMS data that the EPA’s referenced for the

proposal are not representative of the unit operations or capabilities, stating 10 of 20

quarters reported 90th percentile fPM rates higher than the proposed 0.010 lb/MMBtu

fPM standard and 16 of 20 quarters exceeded the baseline fPM rate of 0.0086 lb/MMBtu

estimated at proposal. The Coronado operator reports that quarter three of 2019, which is

used in the EPA’s dataset, reflects normal operation without any maintenance or

optimization activities that could have impacted emissions during that quarter.



Commenters requested correction of what they said are two errors in the EPA's January

2023 Memorandum re: the 2023 Technology Review for the Coal- and Oil-Fired EGU

Source Category. They said in Appendix C, Nearman Creek facility (ID 6064_B_N1) is

listed as having a capacity of 240 MW. They said the correct capacity for Nearman Creek

is 268 MW. The commenters also said that Nearman Creek is identified as having both an

ESP and a baghouse as PM controls. They said this is incorrect as Nearman Creek does

not have an ESP.

Commenters recommended that the EPA correct the deficiencies, as well as make the Agency’s

statistical analysis or Python code used for the fPM evaluation available for public review to

ensure that the proposed fPM limit is not deemed arbitrary and capricious.

Response 1: EPA appreciates the commenters’ observations regarding issues about the fPM

data. The rationale for the final standards is discussed in section IV.D of the preamble.

For the proposal, the Agency selected quarterly data during the time of year where electricity

demand is typically higher (winter and summer) and when EGUs tend to operate more with

higher loads, as described in the 2023 Technical Memo (Docket ID No. EPA-HQ-OAR-20180794-5789). The Agency did not intentionally exclude quarters with higher emissions, however,

the review focused on evaluating the lowest fPM rates EGUs had historically achieved with

existing PM controls. However, if the Agency were able to pull data for every quarter for every

EGU in this analysis, it would only lower the lowest achieved fPM rate, therefore potentially

decreasing PM upgrade costs to meet a lower fPM limit. The Agency disagrees that the data set

should remove potential periods when coal units were co-firing with natural gas, as the Agency

is not responsible or controls how particular EGUs decide to operate.

665a

In revising the analysis, the Agency reviewed the impacted facility list and made changes based

on commenters feedback, such as removing EGUs that have converted to natural gas. EGU

retirement plans were updated based on the comments received and the most recent NEEDS

database. Many commenters did not provide specific EGUs to include or remove from the

analysis, so we were unable to ensure these updates were included. Regarding unit-specific

comments, EPA’s analysis is based on net summer generating capacity, which has been reported

to EIA as 240 MW for Nearman Creek. EPA will update our control information to reflect the

absence of a cold-side ESP at this unit.

In response to concerns about the use of limited quarterly compliance data, EPA expanded the

analysis to include all available fPM compliance data for 60 EGUs at 18 facilities, including

EGUs that the 2023 Proposal indicated would be impacted by the 0.010 lb/MMBtu fPM limit.

The EPA acknowledges commenters requested a review of compliance data spanning longer

time periods (e.g., 2017-2021 or all available compliance data since promulgation of MATS).

Obtaining quarterly compliance data for nearly 300 coal-fired EGUs even for a shorter period of

2017-2021 would require 6,000 separate downloads from CEDRI (5 years of quarterly data for

300 EGUs), producing pdf files unable to be directly evaluated through programming languages

and requiring translation of either 3 stack runs and averages or daily 30-day rolling averages for

the quarter into Excel. Electronic reporting requirements taking effect in 2024 will enable the

Agency to review compliance data in a more time-effective manner. In addition, reviewing all

available compliance data for all EGUs would only potentially lower the lowest achieved fPM

rate used in the PM upgrade and cost assumptions. Thus, review of additional data could

potentially lower costs.

The Agency focused its additional data review on the highest-emitting EGUs, spanning a variety

of PM controls, locations, and capacities, and include the Coronado units that the commenters

reference above (see Case Study 15 in Attachment 2 to the 2024 Technical Memo, available in

the docket), as well as the Gallatin (Case Study 20), Trimble (Case Study 22), and Mill Creek

(Case Study 23) facilities that commenters discuss in their comments (Docket ID No. EPA-HQOAR-2018-0794-5910). The review of a more comprehensive historical data set reveals the vast

majority of EGUs analyzed have long-term records consistently meeting fPM rates of 0.010

lb/MMBtu or lower. For instance, 22 of 30 quarters, (spanning from 2015 to the end of quarter 1

2023, which is more data than the commenters evaluated) assessed for the Coronado facility

indicate an average fPM rate equal or less than 0.010 lb/MMBtu. Similarly, the 30-boiler

operating day average PM CEMS data from Coronado are greater than 0.010 lb/MMBtu only

approximately 30 percent of the time. The review of a more comprehensive data set also revealed

the top 20 fPM emitting EGUs discussed in the 2023 Proposal have larger variations in fPM

quarter to quarter. As a result of the additional data review, the Agency determined the lowest

quarter’s 99th percentile is effective to identify EGUs that have historically achieved lower fPM

rates despite not being required to do so and without additional capital investments. In order to

account for the unit-specific variability, the EPA also assesses the average fPM rate when

estimating whether additional improvements may be needed. The details of this expanded

analysis, including code plotting historical fPM rates, is included in the 2024 Technical Memo

entitled “2024 Update to the 2023 Proposed Technology Review for the Coal- and Oil-Fired

EGU Source Category,” available in the docket.

666a

operating scenarios. Commenters expressed concern that the EPA’s reliance on existing data

does not appear to have adequately considered the impact of the degradation in the effectiveness

of emission control devices and may have overestimated affected units’ ability to comply with

the proposed limit. Commenters specifically mentioned units with the same flue gas path and air

pollution control equipment in series, yet the units result in significant differences in fPM

reduction capabilities. Commenters indicated that some PM control technologies, such as,

hotside ESPs, inherently have higher PM emissions. Commenters noted that depending on the

coal combusted, units that utilize hydrated lime as a control technology for minimizing HAP,

like Hg and sulfuric acid, inherently have higher PM emissions. Commenters noted that wet

FGD may also result in higher PM emissions in particular, higher variability in fPM emission

rates because wet FGD can either add particulate from mist eliminators or remove additional

particulate. Commenters recognized that because control devices perform at their optimum when

operating at full-load, steady state conditions, and additional transient operation will negatively

affect their removal rates. Commenters stated that while PM emissions may be lower during lowload periods, there generally is particulate layout in the duct work during such periods and, as

units ramp to higher loads, the particulate re-entrains, potentially leading to higher emissions, in

addition at low loads, wet FGD mist eliminators operate at reduced efficiency and wet FGD

slurry carryover can increase PM emissions at reduced loads. Commenters requested that the

EPA factor in specific types of control configurations. Commenters noted that if the fPM limit

were lowered to 0.006 lb/MMBtu instead of 0.010 lb/MMBtu, units with ESPs may be required

to add FFs. They also stated this will leave virtually no margin to maintain compliance in the

absence of significant upgrades to the emission control device(s) performance, which would not

be cost effective for units with a remaining service life of less than six years.

Commenters noted that the highest emitting units have the oldest equipment, particularly those

with scrubbers and ESPs, and that replacement or improvements to degraded controls should

allow these units to meet the proposed 0.010 lb/MMBtu fPM standard.

Response 1: The EPA acknowledges these comments submitted about the variation of PM

removal efficiencies based on control configuration. The EPA evaluated different control

configurations for the proposal in Table 3 in the 2023 Technical Memo (Docket ID No. EPAHQ-OAR-2018-0794-5789). This review found that EGUs with wet scrubbers only are

associated with the largest fPM rates, and that other control configurations have lower fPM rates

on average. The EPA also acknowledges that some control configurations have inherently higher

PM emissions and that some downstream control devices (dry sorbent injection, activated carbon

injects, etc.) can add particulate loading to the flue gas stream. But, as the EPA has noted several

times, 93 percent of sources operating by the compliance period have demonstrated an ability to

comply with the more stringent fPM limit of 0.010 lb/MMBtu. Those EGUs include units with a

variety of downstream control configurations, including hotside ESPs, dry sorbent injection, and

activated carbon injection, etc.

The Agency disagrees with commenters that the reliance on historical fPM compliance data does

not consider the impact of degradation of the effectiveness of emission control devices that may

overestimate unit’s ability to comply with the proposed limit. However, the Agency recognizes

that EGUs that may have demonstrated an ability to meet a lower fPM rate in the past may not

do so consistently. For this reason, the fPM analysis assumptions have been updated to assess

667a

both the lowest achieved fPM rate (defined as the lowest quarter’s 99th percentile) and average of

all evaluated fPM data when estimating PM upgrades. The average fPM rate will account for unit

variability as well as some degradation of emission control effectiveness. In cases where the

EGU has demonstrated an ability to meet a lower rate but does not do so on average, the Agency

has updated PM assumptions based on the PM controls at the facility. If the EGU already has a

fabric filter, we assume increased bag frequency change-out (unit specific) or an O&M cost of

$100,000/year for EGUs without fabric filters. These assumptions are described in the 2024

Technical Memo entitled “2024 Update to the 2023 Proposed Technology Review for the Coaland Oil-Fired EGU Source Category,” and unit-specific cost assumptions are provided as an

excel attachment to the memo.

Related to the comment about EGUs with ESPs needing to install FFs to meet a more stringent

limit of 0.006 lb/MMBtu, this comment is not relevant as the Agency did not finalize this

standard and therefore does not require a response.

Lastly, the Agency agrees with commenters that usually the highest emitting EGUs have the

oldest equipment, and that improvements found to be cheaper than assumed at the original

MATS rulemaking will allow EGUs to meet a limit of 0.010 lb/MMBtu.

2.4 Compliance Demonstration

2.4.1 Removal of PM LEE

Comment 1: Commenters stated that if there are to be changes to the numerical emission limit,

then there should not be a change to the compliance demonstration method or to the frequency of

testing to meet a numerical limit that is only two-thirds of the fPM emission rate that defined a

LEE under the previous rule.

The commenters said that sources that are not “low-emitting sources” and required to install a

PM CEMS are subject to more stringent requirements associated with the development of the

PM CEMS correlation curve (see Performance Standard 11, Section 13.2), which are

exceptionally challenging to develop irrespective of the source emitting status.

Commenters stated that this is especially true for EGUs that are equipped with FF PM control

devices (baghouses) or equipped with an ESP and a FGD. Baghouses are the most effective fPM

control devices available and typically an FGD will control an additional 70% of the fPM

remaining after the exhaust gas passes through the ESP, which alone removes 98% - 99% of the

fPM. The commenters said that so long as there is not a physical or permitted capability to allow

discretionary bypass of the baghouse or ESP/FGD combination, there is no need to require

continuous fPM monitoring. With these control equipment devices, which result in extremely

low fPM emissions, in place, a requirement to site, procure, install, certify, operate and maintain,

quality assure and maintain a data acquisition and handling system to record and maintain

records is unnecessary and only serves to increase the cost of the demonstration of compliance

with no demonstrated monetized benefit.

Commenters stated that there is no need to either require emissions measurement more

frequently than the current fPM LEE schedule or require the use emissions measurement

668a

shutdown, and malfunction periods) for Case Study 1 range from near-zero to 1.33 lb/MMBtu

from one unit at the facility. The 30-boiler operating day averages for this unit range from 0.001

to 0.015 lb/MMBtu, considerably smoothing out the variable hourly averages. As mentioned

above, there was no regulatory reason for this EGU to operate and report emissions less than the

limit. In addition, in response to concerns about operational factors, as described in

63.10010(i)(4), data from PM CEMS during any scheduled maintenance are excluded when

determining compliance. The EPA agrees with commenters that plantwide averaging is another

compliance flexibility available to owners and operators.

Comment 2: Commenters suggested the Agency take into consideration the many variables

affecting fuel characteristics. Commenters stated the availability of coal is limited to certain

regions and, as a result, the characteristics of coal vary depending on location and may impact

the unit’s ability to demonstrate continuous compliance with the proposed fPM standard.

Commenters noted that the ash content of the coal being fired may impact the ability of units to

comply with the proposed limit, regardless of the effectiveness of the control technologies in

place. Commenters conveyed that using fuel oil for startup and stabilization may impact the

ability of units to comply with the proposed limit due to decreases in the removal effectiveness

of the ESPs for a short period of time until enough coal is introduced so that the amount of coal

ash in the combustion process has scoured the coating of the collecting plates and wires. They

expressed concern that the costs associated with adding an FF to well-controlled units cannot be

justified simply to address issues which arise rarely and for a short period of time.

Response 2: The Agency thanks commenters for providing these comments and agrees fuel

characteristics can impact fPM emissions. Using fuel oil during periods of startup for short

durations will likely raise fPM emissions for a short period of time, and the 30-day rolling

average period will lessen its impact. The Agency previously evaluated the impact of fuel

characteristics on fPM emission rates in the 2023 Technical Memo (Docket ID No. EPA-HQOAR-2018-0794-5789). This review found for the majority of EGUs burning either bituminous

or subbituminous on average have lowest achieved fPM rates below the most stringent standard

considered, with larger 95th percentiles of approximately 0.0106 and 0.0155 lb/MMBtu,

respectively. These larger fPM values are found for only a few EGUs and are not surprising as

there was little incentive towards reducing fPM rates already 50-65% below the standard (and

outside the industry compliance margin).

Comment 3: Commenters suggested that the age and retirement date of affected units with ESPs

should be considered. If an affected unit is planning to retire soon after the effective date of the

proposal, installation of FFs would not be a cost-effective choice for the plant owner, who might

choose to shut down the plant early and unnecessarily stress electricity generation supply or

capacity. The commenters said that to maximize the flexibility of existing coal-fired units,

maintain grid flexibility and to provide flexibility in the electric transmission system, the 0.010

lb/MMBtu standard should be preferred.

Response 3: The Agency agrees that age and retirement date of affected EGUs should be

considered. Of EGUs not meeting the 0.010 lb/MMBtu proposed standard, 14 have announced

retirement dates spanning from 2030 to 2042, half of which only have an ESP for controlling

fPM (Labadie, Roxboro, Mayo, and Jim Bridger). To meet a 0.010 lb/MMBtu limit, the EPA

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estimates ESP upgrades would be required for Labadie, Roxboro, and Mayo, while Jim Bridger

only requires O&M at $100,000/year. Therefore, installation of FF would not be required at

these EGUs to meet a 0.010 lb/MMBtu standard.

Comment 4: Commenters stated that the EPA must also investigate whether there are sufficient

vendors to perform fPM upgrade projects or install new fPM controls. The commenters said that

NRECA’s Technical Report estimates that 26 units will be required to upgrade ESPs if the EPA

sets the fPM emissions limit at 0.010 lb/MMBtu. This number grows substantially to 52 ESPcontrolled units that would need to retrofit to a FF if the limit falls to 0.006 lb/MMBtu.

Commenters said they believe there are only about 4 active vendors in the United States market.

Response 4: The EPA thanks commenters for providing these comments. In this final rule, the

EPA estimates 2 EGUs may require a FF install, 11 may require ESP upgrades, 10 need either a

bag type upgrade or increased changeout frequency, and 10 need O&M to meet the final fPM

limit of 0.010 lb/MMBtu. The compliance deadline is three years after publication in the Federal

necessary.

2.5.2 Intersection with Other Power Sector Rules

Comment 1: Commenters identified future regulations such as the Interstate Transport Rules

and Regional Haze SIPS that may result in installation of DSI or SDA technologies to reduce

SO2 emissions are expected to increase inlet PM loading to the FFs due to more hydrated lime

and reaction byproducts placing those units at risk of not being able to meet the proposed fPM

standard of 0.010 lb/MMBtu. Commenters indicated that some units may inject sodium or

calcium-based products upstream of the PM collection equipment which increases PM loading.

Commenters also requested that the EPA maximize all regulatory flexibilities at the Agency’s

disposal to align the requirements of the 2023 Proposal and the Proposed CAA section 111(d)

Guidelines. The Proposed CAA section 111(d) Guidelines are part of an unprecedented

rulemaking package that will transform the electric sector and will come at a similarly

unprecedented cost that will be borne by individual residents and businesses. Commenters

suggested, rather than exacerbate these costs and strain system reliability by imposing serial

outages, the EPA should utilize its substantial discretion under CAA section 112 and decline to

revise fPM standards for “long-term” coal units.

Commenters stated that CAA section 111(d)(6) affords the EPA significant discretion in

determining whether to revise standards for sources within a source category: “The

Administrator shall review, and revise as necessary…” (42 U.S.C. § 7412(d)(6)). Commenters

urged the EPA to exercise this discretion and decline to establish fPM requirements for units

designated as “long term” units in CAA section 111(d) state plans. Commenters stated that the

2023 Proposal itself acknowledges the breadth of the EPA’s discretion. They said the EPA has

proposed not to revise multiple standards established by the MATS—the acid gas standards for

coal-fired units, the standards for continental and non-continental liquid oil-fired units, and the

standards for existing IGCC units. The commenters said, notably, this demonstrates that the EPA

is able to parse the need to revise standards for some pollutants and not others, within a single

category of sources.

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Commenters stated that likewise, it is well within the EPA’s discretion to recognize coal-fired

electric generating units designated as long-term units in CAA section 111(d) state plans and

decline to revise fPM standards for these units—similar to its recognition of “non-continental

units.” They said, importantly, the EPA intends for states to designate units as long-term units no

later than 2026 and that this timeline ensures that existing coal units that are not designated as

long-term units would be subject to compliance with any revised fPM standard by the applicable

statutory deadline.

Response 1: The EPA acknowledges and thanks commenters for these comments. Regarding

aligning requirements of this rulemaking with the 111(d) Proposed Emission Guidelines, CAA

section 112 specifies different requirements for compliance. Specifically, as defined in CAA

section 112(i)(3)(A) “…the Administrator shall establish a compliance date or dates for each

category or subcategory of existing sources, which shall provide for compliance as expeditiously

as practicable, but in no event later than 3 years after the effective date of the standard.” The

Agency has not previously subcategorized based on retirements under CAA section 112, and do

not find it appropriate to do so at this time.

2.6 Costs

2.6.1 General

Comment 1: Commenters suggested that the EPA’s justification relies heavily on the Agency’s

estimation of lower than anticipated costs of control technology, significantly underestimating

the 2023 Proposal’s feasibility and cost of compliance. Commenters advocated that lower costs

are neither developments in practices, processes, or control technologies as referenced in CAA

section 112(d)(6), nor do lower costs equate to being cost-effective. They noted that the EPA’s

cost estimates seem to be substantial underestimates. Commenters felt that the EPA provides

inaccurate cost estimates for tightening of the current fPM limitations and adequate consideration

to the cost impacts of the 2023 Proposal have not been given, particularly for small power

generation operators. They recognized that the EPA is required to factor in costs for the RTR

analysis; however, in this case, commenters provided that the 2023 Proposal's cost estimates fail

to account for all of the fPM upgrades and/or installations required for compliance with the new

proposed lower limit. Commenters stated the EPA’s cost study was deficient in terms of the

number of ESP equipped units required to retrofit improvements, the capital cost assigned for the

most significant ESP improvements, improvements in FF operation and maintenance, FF retrofit,

and estimates of $/ton cost effectiveness incurred.

Commenters also stated that the EPA’s deflated and unrepresentative fPM baseline is not

accurate and therefore it is not possible to project the number of units that will need upgrades

which lead to cost per ton underestimates that erode the EPA’s overall assumption that the 2023

Proposal is cost effective. Specifically, commenters said the EPA’s estimate that only 20 units

are likely to incur any costs to meet the new standard is incorrect. As an initial matter, it is

fatuous to conclude that a unit that happened to emit in a single quarter out of the last 20 quarters

at 0.010 lb/MMBtu or less will not be required to do anything to meet the proposed revised

standard. The commenters referred to a chart of data and said that even a unit that the EPA says

has a “baseline fPM rate” of 0.086 lb/MMBtu was actually emitting more than 0.010 lb/MMBtu

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(including controls the EPA considered during the development of the original MACT

standards).” 88 FR 24863 (April 24, 2023). The EPA responds to comments on underestimated

costs in section IV.C.1 of the preamble.

We also disagree with commenters that using the lowest demonstrated fPM rate is not useful to

estimate which EGUs may need to upgrade PM controls. We recognize that EGUs may be

capable of meeting lower emission rates, but may not consistently perform at such low emission

rates. As such, the analysis has been updated to use the average of all quarterly data reviewed or

the lowest achievable fPM rate (lowest quarter’s 99th percentile) to identify EGUs requiring

improvements to PM controls. Additional details of the revised PM analysis are discussed in the

2024 Technical Memo entitled “2024 Update to the 2023 Proposed Technology Review for the

Coal- and Oil-Fired EGU Source Category.”

Regarding comments that the proposed changes will cause inconsistency with existing permitting

authorities’ boilerplate special condition language and guidance documents, EPA routinely

revises its regulations due to statutorily required reviews.

Regarding comments that costs of annual compliance costs will fall disproportionately on a few

facilities, the EPA points out that the fleet has been able to “over comply” with the existing fPM

standard due to the very high PM control effectiveness of well-performing ESPs and FFs.

However, the performance of a few units lags well behind the vast majority of the fleet. For

instance, Colstrip is the highest emitting EGU the EPA assessed and the only facility that the

EPA is aware of not using the most modern PM controls (i.e., ESP or FF), and instead using a

venturi wet scrubber as the only means for fPM controls. In addition, to the comment that

emissions are already at a level that does not pose a danger to the environment or public health,

as well as emissions will only be incrementally reduced by this rule, the EPA’s finding that there

is an ample margin of safety under the residual risk review in no way interferes with the EPA’s

obligation to require more stringent standards under the technology review where developments

warrant such standards. Indeed, the technology review required in CAA section 112(d)(6) further

mandates that the EPA continually reassess standards to determine if additional reductions can

be obtained, without evaluating the specific risk associated with the HAP emissions that would

be reduced.

Regarding the comments that EPA overestimated costs of compliance, the Agency has reviewed

the additional information the commenters referenced and agrees with the commenters that ESPs

are able to achieve greater fPM emission reductions at lower costs than assumed at proposal. We

have lowered the costs of some ESP upgrades and increased the collection efficiencies, as shown

in Table 3 of the 2024 Technical Memo. The impact of these updates to the ESP assumptions is a

reduced need for EGUs to install a FF to meet a fPM limit of 0.006 lb/MMBtu, which lowers

annual costs to approximately $400 MM. However, as described in the final rule and throughout

this document, the EPA is finalizing a fPM limit of 0.010 lb/MMBtu as this is the lowest

possible fPM limit utilizing PM CEMS.

As stated in Chapter 1 above, the EPA requested comment on whether EGUs should be able to

continue to use quarterly emissions testing past the proposed compliance date for a certain period

of time or until EGU retirement, whichever occurs first, provided the EGU is on an enforceable

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contribution to chronic and acute health disorders, as well as adverse impacts on the

environment." (Final Rule, Revocation of the 2020 Reconsideration and Affirmation of the

Appropriate and Necessary Supplemental Finding, 88 FR13956, 13968 (Mar. 6, 2023)). They

said because of the proximity of the Northern Cheyenne tribal members to the Colstrip plantliving both on the Reservation and in the nearby community of Colstrip, where many tribal

members are employed-they are disproportionately impacted by exposure to HAP.

The commenters stated that although cost-effective pollution controls are available to reduce

toxic air emissions from Colstrip Units 3 and 4, namely baghouses and ESPs, Colstrip's owners

have refused to install them and as a result, Colstrip has the highest rate of fPM emissions (a

surrogate for non-Hg HAP) in the country and is the only plant still operating without industrystandard PM controls. They asserted that Colstrip has a history of exceeding even the current

standard for non-Hg HAP.

The commenters stated that two of Colstrip's owners-NorthWestern Energy and Talen Montanaand Rosebud mine owner Westmoreland oppose the EPA's proposal to strengthen the MATS rule

to align with CAA requirements. They said that according to the companies, compliance with

lower limits for non-Hg HAP would be too costly. The commenters said that such arguments

irresponsibly ignore the acute health effects-including premature deaths that Colstrip's toxic

emissions have on Northern Cheyenne tribal members and the many others who live in close

proximity to the plant.

The commenters urged the EPA to finalize MATS and said that under the new standards,

Colstrip Units 3 and 4 should be required to install the same controls that other plants around the

country have already installed and to operate those controls to achieve maximum emission

reductions, as the CAA requires per 42 U.S.C. § 7412(d)(2), (f).

Response 1: The EPA thanks commenters for providing additional information and fPM

compliance data for the Colstrip facility, which has been considered when establishing the final

emission standard. Setting an alternative emission limit of 0.025 lb/MMBtu through

subcategorization requires distinction among class, type, and size of sources. Given the similar

characteristics of this facility, which is not unique in its design and circumstances compared to

the rest of the fleet, the EPA disagrees with the notion that a lower standard for a subset of coalfired EGUs is warranted. In fact, the only difference in circumstances that the EPA is aware of is

the use of less-effective PM controls at Colstrip. Specifically, Colstrip is the only facility that the

EPA is aware of using a venturi wet scrubber as the only means for fPM controls. The venturi

wet scrubber has not been effective maintaining fPM rates below the current standard of 0.030

lb/MMBtu, as other commenters have pointed out previous fPM rate exceedances. As described

in the 2024 Technical Memo, Colstrip is the only facility the EPA estimates need an FF install to

comply with a 0.010 lb/MMBtu standard. Further rationale for the final emission standards is

discussed in section IV.D of the preamble.

Regarding comments about the impact of closing Colstrip on reliable electrical service, facilities

may request an additional time extension through the Department of Energy under the Federal

Power Act section 202(c), which are made on a case-by-case basis based on a substantial need

for grid reliability. In addition, as other commenters have noted, NorthWestern Energy has

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recently joined the Western Resource Adequacy Program (“WRAP”), a regional reliability

planning and compliance program in the West.

Comments supporting a lower fPM rate for the Colstrip facility are supportive of the Agency’s

position and do not require a response.

Comment 2: Commenters suggested further strengthening of the limit is essential because EGUs

have seen significant improvements in fPM emissions rates since 2011 due to wider deployment

of fPM control technologies on units projected by the EPA to be operating in 2028 which present

a variety of approaches to lower fPM emission limits with implications for upgrades and actions

required to meet a revised standard for fPM. Commenters felt an even stronger level could yield

more health benefits and prevent hospital and emergency department admissions for

cardiovascular and respiratory illnesses. Commenters in support of a lower more stringent limit

stated that a fPM standard of 0.0024 lb/MMBtu would encourage many coal-fired EGUs to

choose better-performing controls to achieve greater emission reductions using available control

technologies in various configurations. Commenters suggested that the finding and fact that

emissions performance still varies significantly not only supports revising the standards, but also

provides support for a standard significantly below the proposed level of 0.010 lb/MMBtu.

Commenters conveyed that the lagging performers in the coal fleet in particular are not even

close to achieving the maximum degree of reduction in HAP emissions that can be achieved with

proven controls and should be required to reduce their emissions further.

Response 2: We agree with commenters that further strengthening the fPM limit is essential.

The rationale for the final emission standards is discussed in section IV.D of the preamble.

Comment 3: As an additional alternative, the EPA should establish a subcategory with units

making an enforceable commitment to retire, where the fPM limit remains at 0.030 lb/MMBtu

through retirement. Commenters expressed that the EPA’s proposal to make the fPM limit more

stringent, as well as require CEMS to demonstrate compliance with that limit, has far-reaching

ramifications for EGUs, particularly given Colstrip’s unique design and circumstances.

Response 3: The EPA’s response about establishing a subcategory for EGUs making retirement

commitments is provided in Chapter 2.5.2 of this document.

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mined in North Dakota) has routinely demonstrated the ability to meet an emission limit of 1.2

lb/TBtu. The EPA also notes that, similar to many comments that were received on the 2023

Proposal suggesting that the proposed standard is unachievable, several commenters on the

original MATS proposal argued, at that time, that the final Hg limit of 4.0 lb/TBtu for low rank

(lignite) coal EGUs was “based on too little data” and was “technically and economically

unattainable.” (See 77 FR 9393).

The EPA assumed use of Gulf Coast lignite in the model plant calculation because the mean Hg

content is higher than that of Fort Union lignite and thus should be more challenging to control.

The EPA also does not “admit that brominated ACI is the only feasible option for lignite coal

EGUs” and the Agency discusses the use of other technologies such as injection of chemical

additives. However, even if use of brominated ACI was the only feasible option for lignite coal

EGUs, that would not be a reason to not finalize the more stringent Hg emission standard. There

is no requirement that the EPA identify more than one control technology to meet a final

promulgated emission standard. The EPA does not mandate the use of any particular control

technology. Rather, the EPA promulgates numerical emission standards (or, at times, work

practice standards) and affected sources may meet the standard using a variety of control

technologies or strategies.

Comment 10: Commenters stated that the EPA also overlooked key factors associated with

lignite fuel. In asserting that the proposed 1.2 lb/TBtu limit could be achieved with additional

activated carbon injection, they argued that the Agency failed to account for the impacts of the

higher sulfur content of lignite coal as compared to subbituminous coal, and that such higher

sulfur content leads to additional SO3, which is known to negatively impact the effectiveness of

activated carbon.

Response 10: The impact of coal sulfur content and SO3 is discussed in section V.D of the

preamble.

Comment 11: Commenters stated that neither the 2023 Technology Review memo nor the 2023

Proposal provide specific factual evidence to refute the 2020 Final Action or the 2018

Technology Review memo findings that there are no new developments in practice, processes, or

control technologies for reduction of Hg emissions in coal-fired power plants. They said without

providing the specific evidence that was allegedly considered, the EPA “determined that

available controls and methods of operation will allow lignite-fired EGUs to meet the same Hg

emission standard that is being met by EGUs firing on non-lignite coals, and the costs of doing

so are reasonable.” (88 FR 24880). Commenters argued that without that evidence and data, the

EPA’s alleged “determination” is arbitrary and capricious.

Response 11: The EPA did not rely exclusively (or even mostly) on information obtained from

the CAA section 114 information request. The EPA relied on a variety of data sources in

developing the proposed Hg emission standards for EGUs burning lignite. This included

historical coal analyses, results from demonstration tests (including those conducted by DOE and

others), publicly available Hg emissions data, and data and information obtained from

owners/operators of lignite-fired EGUs from EPA’s limited CAA section 114 information

survey. We have discussed the rationale for the final emission standards – including the data and

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CHAPTER 9

9. Statutory and Executive Order Reviews

9.1 Executive Order 12866: Regulatory Planning and Review and Executive Order 13563:

Improving Regulation and Regulatory Review

Comment 1: The commenters urged the EPA to convene an interagency process and complete a

cumulative impact analysis of the reliability issues associated with its entire “power sector

strategy” before finalizing this rule. The commenters stated convening an interagency process

aligns with Executive Order 13563, signed by President Obama, reaffirmed in President Biden’s

Executive Order 14094, “Modernizing Regulatory Review.”

The commenters said the EPA recently signed a memorandum of understanding (MOU) with the

U.S. Department of Energy promising “interagency cooperation and consultation on electric

sector resource adequacy and operational reliability.” The commenters stated there is no

information in the docket about how the agencies will or have worked together and with FERC,

NERC, and other stakeholders toward this goal and no public meetings have been held to further

the goals of the MOU.

The commenters further stated that as part of this interagency process, the EPA should complete

a cumulative impacts analysis of the reliability impacts of its power sector strategy that is

informed by direct expert consultation with FERC, NERC, RTOs, and other grid experts. The

commenters stated as part of its plan to remake the power sector, EPA has promulgated or

proposed six rulemakings, including the proposed MATS RTR at issue in these comments, the

Clean Water Act Effluent Limitation Guideline proposal, the recently finalized Ozone Transport

Rule, the proposed rulemaking to lower the NAAQS for PM, and most recently, the new GHG

emissions guidelines for existing coal-fired electric generating units. The commenters said the

EPA is also continuing to implement the 2015 Coal Combustion Residue rule and responding to

facility requests to continue to operate certain surface impoundments under the Part A and Part B

programs promulgated more recently. The commenters stated these decisions alone impact 55

GW of electric generating capacity in 19 states. They said because all these rules affect the

power sector, coal generation, and reliability, the impact of one rule cannot be understood

without understanding the impacts of all the others.

Response 1: In parallel with the development of various rules that cover pollution from fossil

fuel-fired electric generating units, the EPA has consulted a wide range of stakeholders,

including other Federal agencies, reliability experts, and grid operators. To deepen this

coordination, on March 9, 2023, EPA and DOE issued a Joint Memorandum of Understanding

on Interagency Communication and Consultation on Electric Reliability to provide a framework

for interagency cooperation and consultation on electric sector resource adequacy and reliability.

The MOU outlines activities to monitor and share information to support the continued reliability

of the electric system, including regular outreach and consultation with FERC, NERC, and other

reliability and electricity grid-focused entities. There have been numerous events and

engagements as part of the MOU effort, which have helped enhance linkages within the EPA and

deepen our relationship with DOE. Perhaps most importantly, the MOU framework has allowed

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a more robust and focused engagement with important stakeholders who are critical to ensuring

that the grid operate efficiently and reliably. This process is not linked to any one regulatory

effort or final action, but supports EPA’s efforts to better understand the various the diverse set

of perspectives. However, this process does not substitute for EPA’s public comment process as

part of individual regulatory efforts. Each regulatory effort includes technical support

information and data related to resource adequacy and reliability, as it relates to that action. EPA

plans release additional information on the Reliability MOU develops.

The final rule covers a small number of EGUs, and as shown in section 3.5.4 of the RIA for the

final rule, the EPA does not project incremental changes in operational capacity to occur in

response to the final rule. Because the EPA projects no incremental changes in existing

operational capacity to occur in response to the final rule, the EPA does not anticipate this rule

will have any implications for resource adequacy (see Resource Adequacy Analysis

Technical Support Document, available in the docket). As EPA develops regulations, it reflects

the cost of final actions and rules in the baseline. As such, the public has the ability to understand

the incremental and cumulative impacts of various actions over time. For example, this action

includes the costs and requirements of previously finalized efforts like the Final GNP and CCR

actions. As future actions are finalized, those will include the requirements of this final action.

While the EPA will continue to evaluate and isolate the potential impacts of final actions

individually, the EPA also provides technical support information and data where relevant and as

they relate to other regulations and the potential cumulative impacts.

For example, the EPA analyzed projected resource adequacy impacts of several recently

finalized EPA rulemakings: the LDV, HDV and MDV (collectively “Vehicle Rules), Final 111

EGU Rules, ELG and MATS (collectively “Power Sector Rules”) and found that, whether alone

or collectively, these rules are unlikely to adversely affect resource adequacy. For further

discussion, see Resource Adequacy Analysis: Vehicle Rules, Final 111 EGU Rules, ELG and

MATS Technical Memo, available in the docket. Additionally, the EPA estimated the collective

impacts of the vehicle rules, final 111 EGU rules, MATS and ELG. For further discussion of

this modeling, see IPM Sensitivity Runs Memo, available in the docket.

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FERC - NERC - Regional Entity Sta Report:

The February 2021 Cold Weather Outages

in Texas and the South Central United States

Federal Energy Regulator

ory Commission

North American Electric Reliability Corporation

Regional Entities

FERC, NERC and Regional Entity Staff Report

The February 2021 Cold Weather

Outages in Texas and the

South Central United States

November 2021

FEDERAL ENERGY REGULATORY COMMISSION

NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION

Regional Entities:

Midwest Reliability Organization, Northeast Power Coordinating Council,

ReliabilityFirst Corporation, SERC Corporation, Texas Reliability Entity and

Western Electricity Coordinating Council

The February 2021 Cold Weather Outages in Texas and the South Central United States

I. Executive Summary

This report 1 describes the severe cold weather event occurring between February 8 and 20, 2021 and

how it impacted the reliability of the bulk electric system 2 (“BES” or colloquially known as the grid)

in Texas and the South Central United States (hereafter known as “the Event”). During the Event,

extreme cold temperatures and freezing precipitation led 1,045 individual BES generating units, 3

(with a combined 192,818 MW of nameplate capacity) in Texas and the South Central United States

to experience 4,124 outages, derates or failures to start. Each individual generating unit could, and

in many cases, did, have multiple outages from the same or different causes. To provide perspective

on how significant the generating unit outages were, including generation already on planned or

unplanned outages, the Electric Reliability Council of Texas (ERCOT) averaged 34,000 MW of

generation unavailable (based on expected capacity 4) for over two consecutive days, from 7:00 a.m.

February 15 to 1:00 p.m. February 17, equivalent to nearly half of its all-time winter peak electric

load of 69,871 MW.

1 This report is written for a reader who is already familiar with principles of energy markets, electric transmission system

operations and generating unit operations. For readers who are not as familiar, the Team has linked to several resources

which may be helpful:

2 Bulk electric system generally means all transmission elements operated at 100 kV or higher and real power and

reactive power resources connected at 100 kV or higher. This does not include facilities used in the local distribution of

electric energy. See NERC Glossary of Terms at

https://www.nerc.com/pa/Stand/Glossary%20of%20Terms/Glossary_of_Terms.pdf.

3 A single generating unit can range from a 75 MW gas turbine, to a 1,000-MW-plus nuclear unit, to a wind farm with

multiple wind turbines. For purposes of the report, only BES generating units were considered, i.e., those with a

nameplate rating of 75 MW or higher.

4 Expected capacity includes any expected seasonal capacity derates, and for intermittent resources (e.g., wind, solar

resources), expected capacity is calculated based on weather conditions. For example, a 100 MW wind generation facility

may be 20 MW, based on the variability of wind during the winter peak timeframe.

The February 2021 Cold Weather Outages in Texas and the South Central United States

The Event was the fourth cold-weather-related event in the last ten years to jeopardize BES

reliability, 5 and with a combined 23,418 MW of manual firm load shed, 6 the largest controlled firm

load shed event in U.S. history. In each of the four BES events, planned and unplanned generating

unit outages caused energy emergencies, and in 2011, 2014 and 2021 they triggered the need for firm

load shed. The unplanned generation outages that escalated during the Event were more than four

times as large as the previous largest event, in 2011 (65,622 MW versus 14,702 MW).

More than 4.5 million people in Texas lost power during the Event, and some went without power

for as long as four days, while exposed to below-freezing temperatures for over six days. 7 At least

210 people died during the Event, with most of the deaths connected to the power outages, of

causes including hypothermia, carbon monoxide poisoning, and medical conditions exacerbated by

freezing conditions. 8 Among the deaths were a mother and her seven-year-old daughter, 9 and an 11year-old boy who died in his bed, 10 who all died of carbon monoxide poisoning, and a 60-year-old

disabled man who died of hypothermia. 11 A grandmother and three children trying to keep warm

5 In February 2011, an arctic cold front impacted the southwest U.S. and resulted in 29,700 MW of generation outages,

natural gas facility outages and emergency power grid conditions with need for firm customer load shed. Report on

Outages and Curtailments During the Southwest Cold Weather Event of February 1-5, 2011: Causes and

Recommendations (Aug. 2011) (https://www.ferc.gov/sites/default/files/202007/OutagesandCurtailmentsDuringtheSouthwestColdWeatherEventofFebruary1-5-2011.pdf) (hereafter, 2011 Report).

In January 2014, a polar vortex affected Texas, central and eastern U.S., triggering 19,500 MW of generation outages,

natural gas availability issues and resulted in emergency conditions including voluntary load management. NERC “Polar

Vortex Review” (Sept. 2014),

https://www.nerc.com/pa/rrm/January%202014%20Polar%20Vortex%20Review/Polar_Vortex_Review_29_Sept_20

14_Final.pdf (hereafter Polar Vortex Review). And in January 2018, an arctic high-pressure system and below average

temperatures in the South Central U.S. resulted in 15,800 MW of generation outages and the need for voluntary load

management emergency measures. See South Central United States Cold Weather Bulk Electric Systems Event of

January 17, 2018 (July 2019), https://www.ferc.gov/sites/default/files/202007/SouthCentralUnitedStatesColdWeatherBulkElectricSystemEventofJanuary17-2018.pdf (hereafter, 2018 Report).

6 Manual firm load shed, often referred to as rolling or rotating blackouts, is when BES operators order a percentage of

the demand or load to be temporarily disconnected, to avoid system instability or other system emergencies. Customers

lost electric distribution service due both to manual firm load shed, as well as to weather-related unplanned outages

(such as downed power lines). In addition to being the largest controlled firm load shed event in U.S. history, the Event

was also the third largest in quantity of outaged megawatts (MW) of load after the August 2003 northeast blackout and

the August 1996 Western Interconnection blackout.

7Paul Takashi, I lost my best friend: How Houston’s winter storm went from wonderland to deadly disaster, Houston Chronicle (May

25, 2021), https://www.houstonchronicle.com/news/investigations/article/failures-of-power-series-part-2-blackoutshouston-16189658.php.

8 Andrew Weber, Texas Winter Storm Toll Goes Up to 210, Including 43 Deaths in Harris County, Houston Public Media (July

14, 2021), https://www.houstonpublicmedia.org/articles/news/energy-environment/2021/07/14/403191/texaswinter-storm-death-toll-goes-up-to-210-including-43-deaths-in-harris-county/.

9ABC 13 Staff, Carbon Monoxide “We tried our best to save them”, ABC 13 Eyewitness News (February 17, 2021),

https://abc13.com/houston-woman-and-daughter-die-from-carbon-monoxide-poisoning-mom-after-leaving-carrunning-inside-garage-dangers-during-texas-winter-storn-storm-2021/10348847/

10 KHOU Staff, Autopsy Results Released for 11-Year-Old Who Died During the Texas Winter Freeze, KHOU 11 News Channel

(May 12, 2021) https://www.khou.com/article/news/local/conroe-police-autopsy-reveals-11-year-old-boy-died-carbonmonoxide-poisoning-houston-winter-storm/285-fbae9d3f-45cd-41bb-904733665fef8f18#:~:text=Autopsy%20results%20released%20for%2011,their%20mobile%20home%20lost%20power.

11 Paul Takashi, I lost my best friend: How Houston’s winter storm went from wonderland to deadly disaster, Houston Chronicle (May

25, 2021), https://www.houstonchronicle.com/news/investigations/article/failures-of-power-series-part-2-blackoutshouston-16189658.php.

The February 2021 Cold Weather Outages in Texas and the South Central United States

using a wood-burning fireplace died in a house fire. 12 In cities including Austin, Houston and San

Antonio, over 14 million people were ordered to boil drinking and cooking water, and multiple cities

ordered water conservation measures, due to broken pipes and power outages (which lowered water

pressure). 13 After the city of Denton, Texas, lost its gas supply, it was forced to cut power to

nursing homes and water pumping stations. 14

Analysts with the Federal Reserve Bank of Dallas estimated that the outages caused direct and

indirect losses to the Texas economy of between $80 to $130 billion. 15 A separate Federal Reserve

Bank of Dallas analysis described the effect on the petrochemical and refining sector as “hurricanelevel,” comparable to 2008’s Hurricane Ike, with a 50 percent drop in February 2021 production as

compared to January. It also predicted continuing effects on the supply chain through the end of

2021 as a result of the disruptions in February. 16

Synopsis of Event

In the early morning hours of February 15, 2021, an arctic front moving through Texas and the

South Central U.S. began to take its toll. As temperatures dropped, more and more generating units

throughout Texas failed in ERCOT. The same front led to generating units to fail to a lesser extent

in the South Central U.S. footprints of Midcontinent Independent System Operator (MISO) South

and Southwest Power Pool (SPP). 17 Responding to the loss of generation, and to keep the electrical

system from cascading outages and total blackout, the system operators at ERCOT began to issue

orders for rotating outages of electricity to customers (known as manual firm load shed). ERCOT

ultimately had to shed 20,000 MW of firm load at the worst point of the Event, with SPP and MISO

12 Anna Bauman, Grandmother, 3 Children Dead in Sugar Land Fire, Houston Chronicle (Feb. 16,

2021), https://www.houstonchronicle.com/news/houston-texas/houston/article/Sugar-Land-fire-fatalities15953492.php%20https://www.google.com/amp/s/abc13.com/amp/sugar-land-house-fire-children-killeddeadly/10352669

13 Talal Ansari, New Winter Storm Threatens Fragile Power Grids in Texas, Other Parts of U.S., The Wall Street Journal New

(Feb. 22, 2021), https://www.wsj.com/articles/new-winter-s

-storm-threatens-fragile-electrical-grids-in-texas-other-partsof-u

-u-s

-s-11613588298; Elizabeth Findell, Texas Cities Under Boil-Water Orders, The Wall Street Journal (Feb. 19,

2021), https://www.wsj.com/articles/texas-cities-under-boil-water-orders-11613671450.

14 Community Emergency Preparedness Committee, City of San Antonio Community Emergency Preparedness Committee Report:

A Response to the February 2021 Winter Storm (Jun. 24, 2021),

https://www.sanantonio.gov/Portals/5/files/CEP%20Report%20Final.pdf; Russell Gold, Inside One Texas City’s Struggle

to Keep Power and Water Going, The Wall Street Journal (Feb. 17, 2021), https://www.wsj.com/articles/texas-city-dealswith-no

no-power-no

no-water-during-big-chill-11613590412.

15 Garrett Golding et al., Cost of Texas’ 2021 Deep Freeze Justifies Weatherization, Dallas Fed Economics (Apr. 15,

2021), https://www.dallasfed.org/research/economics/2021/0415.

16 Jesse Thompson, Texas Winter Deep Freeze Broke Refining, Petrochemical Supply Chains, Southwest Economy (Second

Quarter 2021), https://www.dallasfed.org/research/swe/2021/swe2102/swe2102c (Texas holds nearly 75 percent of

“basic U.S. chemical capacity,” relied upon by global supply chains, and as much as 80 percent of this capacity was

offline after the storm).

17 See Figure 1 below for map of the Event Area: ERCOT, SPP and MISO South. Except for the figures regarding the

entire MISO footprint in section II.B. below, the Team gathered data about and focused on MISO South, because the

bulk of the manual load shed and unplanned generation outages experienced in MISO occurred in MISO South.

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 and Radiation

Office of Air Quality Planning and Standards

Research Triangle Park, NC 27711

This is a copy of a public record, reproduced as it was published. It is not legal advice, and it may not be the version a court would rely on. Check the official source before you cite it.