Emergency Application — Westmoreland Mining Holdings LLC, et al., Applicants v. Environmental Protection Agency, et al.

Supreme Court briefAug 16, 2024

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TABLE OF CONTENTS

APPENDIX A

Order Denying Stay, State of North Dakota v. EPA,

No. 24-1119 (D.C. Circuit, August 6, 2024) ………………………………… App.1

APPENDIX B

42 U.S.C. § 7412 ………………………………………………………………… App.3

APPENDIX C

National Emission Standards for Hazardous Air Pollutants:

Coal- and Oil-Fired Electric Utility Steam Generating Units

Review of the Residual Risk and Technology Review,

89 Fed. Reg. 38508 (May 7, 2024) ……………………………………….…..App.34

APPENDIX D

Comments of Westmoreland Mining Holdings LLC,

EPA-HQ-OAR-2018-0794-5935………………………………………..…… App.120

APPENDIX E

Comments of Northwestern Energy,

EPA-HQ-OAR-2018-0794-5980……………………………………………...App.226

APPENDIX F

Comments of National Mining Association,

EPA-HQ-OAR-2009-0234-20531…………………………………………….App.251

APPENDIX G

Comments of Talen Montana,

EPA-HQ-OAR-2018-0794-5987……………………………………………...App.443

APPENDIX H

Declarations:

Exhibit 1 – Declaration of Patrick Barkey ………………………. App.484

Exhibit 2 – Declaration of Jeremy Cottrell …………………...…. App.518

APPENDIX G

APPENDIX

COMMENTS OF TALEN MONTANA, LLC ON THE PROPOSAL ON NATIONAL

EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS: COAL- AND

OIL-FIRED ELECTRIC UTILITY STEAM GENERATING UNITS REVIEW OF

THE RESIDUAL RISK AND TECHNOLOGY REVIEW

Docket ID: EPA-HQ-OAR-2018-0794

INTRODUCTION

On April 24, 2023, EPA published in the Federal Register, at 88 Fed. Reg. 24,854, a

Proposal that would amend the National Emission Standards for Hazardous Air Pollutants

(“NESHAP”) for coal- and oil-fired electric utility steam generating units (“EGUs”) — i.e., the

Mercury and Air Toxics Standards (“MATS”) (“Proposal” or “Proposed Rule”). Among other

amendments, EPA is proposing to: (i) tighten the surrogate filterable particulate matter (“fPM”)

standard for demonstrating compliance with the emissions limits for non-mercury (“non-Hg”)

metal hazardous air pollutants (“HAPs”) from 0.03 lb/MMBtu to 0.010 lb/MMBtu; and (ii) require

continuous emissions monitoring systems (“CEMS”) for demonstrating compliance with the fPM

standard.1

Talen Montana, LLC (“Talen Montana”) is part-owner and operator of Units 3&4 of the

Colstrip Steam Electric Station (“Colstrip”) in Rosebud County, Montana. On behalf of itself as

an owner and with knowledge gained as the operator of Colstrip, Talen Montana has significant

concerns about the Proposed Rule, particularly with the proposed tightening of the fPM standard.

These concerns stem from the unique design and circumstances of Colstrip. Colstrip currently

uses venturi wet scrubbers to address both sulfur dioxide (“SO2”) and fPM emissions. It would be

extremely expensive — and potentially cost prohibitive — for Colstrip to comply with the 0.010

lb/MMBtu fPM limit because the venturi wet scrubbers cannot meet that limit. Colstrip would

need to undertake a massive and complex construction project to install new controls — either

new fabric filters (“FFs”) or electrostatic precipitators (“ESPs”) — when Colstrip’s remaining life

and future generation is likely limited given EPA’s other rulemakings targeting older sources like

Colstrip. The high costs associated with installing, testing, and implementing new controls,

coupled with limited time and electric generation for the recovery of such costs, may cause Colstrip

to shut down prematurely if the owners deem that it is not economically feasible to install the

necessary controls to comply with the proposed fPM standard.

A premature shutdown of Colstrip would have significant economic impacts on Montana

and beyond and raises serious concerns about grid reliability and transmission, factors that were

not considered by EPA in setting the proposed fPM standard. Moreover, Colstrip bears a hugely

disproportionate burden under the Proposed Rule, especially where EPA has not found any

unacceptable risk related to Colstrip’s (or any other affected facility’s) operation under the current

fPM standard. Indeed, by EPA’s own calculations, Colstrip is expected to bear almost 50 percent

See 88 Fed. Reg. 24,854 (Apr. 24, 2023).

App.443

of the costs of the Proposed Rule. For these reasons, as well as other legal and technical reasons

discussed below, Talen Montana asks that EPA not finalize the proposed 0.010 lb/MMBtu fPM

limit. However, should EPA ultimately finalize the proposed 0.010 lb/MMBtu fPM limit, Talen

strongly urges EPA to establish a subcategory for coal-fired units that use wet scrubbers to address

both SO2 and PM emissions and that do not presently have an ESP or FF, where the fPM limit for

those units is no lower than 0.025 lb/MMBtu fPM. Given that EPA’s rationale for the Proposed

Rule is that existing control technology is more effective and cost effective than was known at the

time of the original MATS rule, a targeted limit that is specific to the existing wet scrubber

technology is consistent and appropriate with that approach.

As an additional alternative, Talen Montana requests that EPA establish a subcategory for

near-term existing coal units electing to retire where the fPM limit remains at 0.030 lb/MMBtu

until ceasing operations. This would be consistent with the approach EPA has taken in other

rulemakings. Under such an approach, units could opt-in to the subcategory by making an

enforceable retirement commitment within a specified timeline after the Proposed Rule is finalized

and with retirement planned by a specified date. For this subcategory, Talen Montana proposes

that units opt-in within 18 months after the effective date of the final rule with a retirement date

no later than December 31, 2035 (with a “safety valve” that would allow longer operation

depending on circumstances in the future, as described below).

II.

BACKGROUND

Colstrip is one of the largest coal-fired electric generating facilities west of the Mississippi

River, supplying electricity throughout Montana and the Pacific Northwest. Talen Montana has a

15% ownership stake in Colstrip, which currently consists of two active coal-fired generating units

capable of producing up to 1,480 MW of electricity that have been operating for approximately 37

years. Each of the units has approximately 740 MW of generating capacity, and the adjacent

Rosebud coal mine supplies Colstrip’s low-sulfur subbituminous coal.

Colstrip’s Unique Design

Colstrip’s design sets it apart from other coal-fired units in the country that are currently

operating. Colstrip began construction in the 1970s and Units 3 and 4 began operations in the

1980s. Colstrip was designed to utilize low-sulfur coal and with then state-of-the-art venturi wet

scrubbers to reduce its SO2 emissions below the applicable limits. Colstrip also relies on the

venturi wet scrubbers to mitigate fPM.

Colstrip has eight wet venturi scrubbers on each of unit. Seven scrubbers are used during

normal full load operation and one scrubber is a “backup,” used only when one of the other seven

scrubbers in operation needs to be removed from service or is undergoing routine cleaning and

maintenance. Below is a diagram of the wet venturi scrubber used at Colstrip Units 3&4:

App.444

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App.445

(UPPER)

SYSTEM

The venturi wet scrubbers at Colstrip Units 3 and 4 remove approximately 99.7% of fly ash

particulate from the flue gas and 95% of the SO2 via a sequence of removal processes. The flue

gas enters the scrubber vessel and is accelerated by the converging surfaces of the plumb bob and

venturi bowl. The flue gas and slurry meet in the venturi throat where turbulence atomizes the

slurry. Acceleration of the flue gas causes the particulate to collide with and be absorbed by slurry

droplets. The majority of the fly ash particulate and most of the SO2 are removed in the venturi

section. The wet venturi scrubbers utilize the alkalinity of the fly ash particle removed to help meet

the high level of SO2 removal. The throat area of the venturi is adjusted by moving the plumb bob

up or down to obtain the desired pressure drop across the plumb bob of each scrubber. The flue

gas velocity caused by this pressure drop ensures optimum fly ash removal. The slurry and

collected fly ash are separated from the flue gas as it turns up to enter the absorption area. The flue

gas then enters the absorption spray area in the annular space between the downcomer and shell of

the scrubber vessel. The flue gas is contacted with recycle slurry for additional removal of SO2.

Above the absorption section is the wash tray which uses recirculation water to contact the flue

gas and remove entrained recycle slurry from the flue gas. The flue gas then flows through the

mist eliminator where entrained droplets are removed.

As EPA recognized, Colstrip does not have a FF or an ESP and would need to install one

to comply with the proposed 0.010 lb/MMBtu fPM limit, as the current venturi wet scrubbers will

not be able to meet the proposed limit.2 While EPA recognizes that Colstrip’s venturi wet

scrubbers would not be able to comply with the proposed limit, EPA assumes Colstrip could make

a “minimal cost ($10/kW) for [wet scrubber] maintenance or minor upgrades . . . to meet a potential

0.015 lb/MMBtu standard.”3 This assumption, however, is inaccurate. Colstrip has typically been

able to remain just below the current limit of 0.030 lb/MMBtu. However, due to occasional

variability in fuel and operating condition, Colstrip has, since 2018, hired consultants and

engineers to explore ways to further enhance the efficiencies of the venturi wet scrubbers. This

work, as described below, has made the venturi wet scrubber emissions more stable. But, as

reflected in Attachment A (Colstrip’s MATS PM CEMS compliance data from September 2018

to April 2023), the work demonstrated that 0.015 lb/MMBtu fPM is not achievable with upgrades

to the existing wet scrubbers and further that the efforts to reduce fPM emissions with the existing

control technology has reached its limits:

The original operating condition for the plumb bob delta P (pressure drop) was 17” to meet

particulate and SO2 removal requirements. In an effort to optimize the performance of the

scrubbers, the plumb bob delta P is currently operated at 27-28”, the maximum delta P

achievable which is limited by the capability of the induced draft (“ID”) Fans.

The original mist eliminators have been upgraded with improved performance to better

control entrained droplets in the flue gas. In 2018, the mist eliminator supplier (Munters)

See 2023 Technology Review for the Coal- and Oil-Fired EGU Source Category (“Technical Memo”), Doc. ID.

EPA-HQ-OAR-2018-0794-5789, at PDF p. 9, posted Apr. 24, 2023.

See id.

App.446

conducted a mist eliminator performance test, and the results showed dry conditions with

very little or any droplet carry over.

Scrubber slurry solids level has been controlled to 25-30% solids to minimize potential

particulate contribution from entrained droplets in the flue gas.

Flow distribution plates have been installed on each scrubber to improve the flow balance

across the scrubber, provide a more uniform flow, and improve particulate removal

performance.

Colstrip also implemented additional measures to address combustion conditions to help ensure

that combustion of the coal occurs in a manner that prevents to formation of small fly ash particles

that are difficult to remove in the wet venturi scrubbers, including:

Combustion tuning and incorporation of optimum conditions over variable operating

conditions into the Combustion Optimizer System.

Optimization of the furnace sootblower system to ensure optimum heat transfer in the

furnace and prevent elevated temperatures in the upper part of the furnace that can

contribute to formation of small particulate particles that are difficult to remove in the wet

venturi scrubbers.

Optimization of coal mill fineness by regularly performing coal mill sieve analysis to

ensure correct particle size distribution of the coal entering the furnace.

Together, these comprehensive efforts reflect all known upgrades available to be implemented to

the Colstrip scrubber/combustion process to reduce fPM, which enables Colstrip to achieve

compliance with the current 0.030 lb/MMBtu fPM limit with an adequate compliance margin.

While the majority of stack testing has shown emission rates between 0.020 lb/MMBtu and 0.025

lb/MMBtu fPM, there have been several instances where stack tests were above 0.025 lb/MMBtu

fPM.4 In 2022, based on stack tests, the two units combined achieved approximately 0.022

lb/MMBtu fPM on an annual basis.

With the extensive scrubber/combustion process reviews by consultants and engineers and

implementation of the upgrades previously identified, Talen Montana believes that these efforts

have optimized the current control technology to the maximum extent feasible. While Colstrip

remains dedicated to continued optimization to control fPM, Colstrip cannot meet a the more

stringent fPM limits in the Proposed Rule (either the 0.015 lb/MMBtu or the proposed 0.010

lb/MMBtu) without installation of a FF or ESP, which as noted previously would be a massive,

complex, and expensive construction project.

See Attachment A.

App.447

Colstrip’s Unique Circumstances

Despite the importance of Colstrip to Montana and the surrounding region, Colstrip’s

future is uncertain. Colstrip’s remaining life and future generation may be limited by the Inflation

Reduction Act (“IRA”), which EPA’s IPM runs suggest will cause Colstrip to significantly reduce

generation as more renewables come online and other EPA rulemakings targeting older sources

such as Colstrip are implemented. These rulemakings, excluding forthcoming ones, impacting

Colstrip include: (i) the proposed rule on the Hazardous Solid Waste Management System:

Disposal of Coal Combustion Residuals (“CCR”) from Electric Utilities; Legacy CCR Surface

Impoundments (88 Fed. Reg. 31,982 (May 18, 2023)) (“Proposed CCR Rule”); and (ii) the

proposed rule on New Source Performance Standards for Greenhouse Gas (“GHG”) Emissions

from New, Modified, and Reconstructed Fossil Fuel-Fired EGUs; Emission Guidelines for GHG

Emissions from Existing Fossil Fuel-Fired EGUs; and Repeal of the Affordable Clean Energy Rule

(88 Fed. Reg. 33,240 (May 23, 2023)) (“Proposed GHG Rule”).

The costs associated with complying with the proposed fPM limit, compounded with the

proposed requirements in these other rulemakings, are massive. Given the reduced lifespan and

generation that may be on the horizon for Colstrip, it will be extremely difficult to justify installing

new controls to meet such the fPM limit in the Proposed Rule. At a certain point, it is likely that

the owners will determine that it is no longer economically feasible to continue operating Colstrip,

as they will not be able to recoup the cost of installing controls.

Furthermore, any closure plans necessitate intensive engagement and coordination among

stakeholders because Colstrip is vital to Montana and the surrounding region. As concluded in a

2017 study by University of Montana’s Bureau of Business and Economic Research, “[t]he early

retirement of Colstrip Units 3 and 4 would ultimately produce:

[A]n economy with, on average, almost 3,300 fewer jobs than would have been present

if the units continued to operate through the 2028-43 period[.]

[A] loss of income received by Montana households varying between $250 and $350

million per year, adding up to a total of about $5.2 billion over the full 16-year period

2028-43. Losses in after-tax income . . . for Montana households would total almost

$4.6 billion over the same period.

[D]eclines in annual gross sales by businesses and other organization, or economic

output, between $700 and $800 million, cumulating to $12.5 billion over the full

sixteen period.

App.448

[A] decline in population which occurs as works and families migrate to other

economic opportunities, growing to more than 7,000 people by year 2043.”5

Colstrip also is vital to ensuring that Montanans have affordable and reliability electricity,

especially during peak winter and summer months. Colstrip is one of Montana’s most important

energy assets, especially as demand for reliable baseload power in the western U.S. continues to

grow. As Montana state Governor Gianforte has recognized, Montana needs Colstrip.6

Thus, 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 given Colstrip’s unique

design and circumstances. Talen Montana strongly recommends that EPA reconsider its proposed

amendments or to provide the relief requested by Talen Montana herein.

III.

COMMENTS

Talen Montana understands that EPA conducted the MATS Residual Risk and Technology

Review (“RTR”) pursuant to President Biden’s Executive Order 13990.7 The order required EPA

to review certain actions undertaken by the prior administration, including the MATS RTR

finalized in May 2020.8 The 2020 MATS RTR indicated that HAP emissions from the source

category are acceptable and also did not identify any cost-effective controls that would achieve

further HAP emission reductions.9 While EPA acknowledges in the Proposal that the 2020

Residual Risk Review was sound and is not proposing to modify it, EPA is proposing to determine

that the 2020 Technology Review was flawed because it “did not consider developments in the

cost and effectiveness of . . . proven technologies, nor did EPA evaluate the current performance

of emission reduction control equipment and strategies at existing MATS-affected EGUs.”10

Following the consideration of such factors, EPA is proposing that the updated technology review

requires certain changes to MATS.11 These changes include the fPM limit and the use of PM

CEMS.12

Barkey, Patrick M. “The Economic Impact of the Early Retirement of Colstrip Units 3 and 4 Final Report,” June

2018 at 6.

“Governor Gianforte: ‘Montana Needs Colstrip,’” State of Montana Newsroom, Jan. 17, 2023,

https://news.mt.gov/Governors-Office/Governor_Gianforte_Montana_Needs_Colstrip.

88 Fed. Reg. at 24,856.

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

Units-Reconsideration of Supplemental Finding and Residual Risk and Technology Review, 85 Fed. Reg. 31,286

(May 22, 2020).

See id.

88 Fed. Reg. at 24,865.

See id. at 24,856.

See id. at 24,857-58.

App.449

EPA Has Not Established a Sufficient Basis for Tightening the fPM Limit.

Existing coal-fired EGUs currently can demonstrate compliance with the emission limits

for non-Hg metal HAPs by meeting: (i) the individual emission limits for each of the 10 non-Hg

metals; (ii) an emission standard for total non-Hg metals; or (iii) a surrogate fPM emission standard

of 0.030 lb/MMBtu.13 EPA is proposing to eliminate the non-Hg HAP metals standards, leaving

only the surrogate fPM standard. Further, EPA is proposing to tighten the surrogate fPM standard

to 0.010 lb/MMBtu, which is comparable to the MATS new source standard of 0.09 lb/MWh fPM

(equivalent to a new coal-fired EGU with a heat rate of 9.0 MMBtu/MWh).14 EPA also is soliciting

comment on whether to revise the fPM standard to an even more stringent level of 0.006

lbs/MMBtu.15

EPA’s proposal to tighten the fPM limit is based on its evaluation that “most-existing coalfired EGUs are reporting fPM well below the current fPM emission limit of 3.0E-02 lb/MMBtu”

and that “the fleet is achieving these performance levels at lower costs than assumed during

promulgation of the original MATS fPM emission limit.”16 EPA acknowledged that it did not

identify any new practices, processes, or control technologies for non-Hg metal HAPs.17 For the

reasons discussed below, this rationale is not a sufficient basis for tightening the fPM limit.

EPA exceeds its statutory authority in 42 U.S.C. § 7412(d)(6).

42 U.S.C. § 7412(d)(6) requires EPA to “review, and revise as necessary (taking into

account developments in practices, processes, and control technologies) emission standards . . .

every eight years.”18 Among other considerations, EPA deems “[a]ny improvements in add-on

control technology or other equipment (that were identified and considered during development of

the original MACT [Maximum Achievable Control Technology] standards) that could result in

additional emission reductions” as such “development” under § 7412(d).19 But EPA has identified

no such “developments” or “improvements.” Rather, EPA is revising the fPM limit because the

Agency says it now has more information about the cost and performance of existing technology

than it did when promulgating the original MATS rule.20 According to EPA’s evaluation of such

information, existing controls are cheaper and perform better than anticipated, and as discussed

below, EPA’s evaluation is flawed.21

See Table 1, Emission Limits for New or Reconstructed EGUs, Subpart UUUUU, 40 C.F.R. Part 63.

88 Fed. Reg. at 24,856.

Id. at 24,857.

Id. at 24,868.

Id. at 24,867-68.

42 U.S.C. § 7412(d)(6) (emphasis added).

88 Fed. Reg. at 24,863.

See id. at 24,863 fn. 15. See also National Emission Standards for Hazardous Air Pollutants From Coal- and OilFired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility,

Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, 77 Fed.

Reg. 9304 (Feb. 16, 2012).

See 88 Fed. Reg. at 24,867-68.

App.450

The statute places guardrails on EPA’s discretion to revise the existing standards. EPA

does recognize that § 7412(d)(6) provides the Agency with authority to revise emission standards

but only on specific grounds. This is most evidently reflected in a mere footnote that EPA inserted

in the Proposed Rule, where EPA explains that the term “developments” could encompass “getting

new or better information about the performance of an add-on or existing control technology (e.g.,

emissions data from affected sources showing an add-on control technology performs better than

anticipated during development of the rule).”22 Such an interpretation of the term “developments,”

however, impermissibly stretches the statutory authority EPA has in revising emission standards.23

Nowhere does the statute provide EPA the discretion to make such revisions for any other reason

not enumerated in the statute. To establish a sufficient basis for tightening the fPM limit, EPA

needs to point to a change in practices, processes, or control technologies and equipment that

justifies the corresponding change to the fPM limit. EPA has not done so. As such, EPA does not

have authority to promulgate the revised fPM standards.

EPA’s proposal to tighten the fPM limit is arbitrary and capricious.

EPA’s evaluation of current fPM emission levels is flawed.

EPA’s proposal to tighten the fPM limit is arbitrary and capricious because its evaluation

justifying the proposed tightening of the fPM limit relies on questionable methods of analysis and

is flawed. EPA states that its proposal to tighten the fPM standard is based on its review of

“developments in the current emission levels of fPM from existing coal-fired EGUs, the costs of

control technologies, and the effectiveness of those technologies, as well as the costs of meeting a

standard that is more stringent than 3.0 E-02 lb/MMBtu and the other statutory factors.”24

According to EPA:

Currently, 96 percent of existing coal-fired capacity without known retirement

plans before the proposed compliance period already have demonstrated an

emission rate of 1.5E-02 lb/MMBtu or lower, 91 percent of existing coal-fired

capacity have demonstrated an emission rate of 1.0E-02 lb/MMBtu or lower, and

72 precent of existing coal-fired capacity have demonstrated an emission rate of

6.0E-03 lb/MMBtu or lower.”25

The statistics above appear to be based on the evaluation summarized in the 2023 Technology

Review for the Coal- and Oil-Fired EGU Source Category (“Technical Memo”). EPA should not

rely on the 96% threshold as justification for setting the proposed fPM limit at 0.010 lb/MMBtu.

EPA’s reliance on that evaluation is problematic for several reasons and likely overstates the

universe of units that will be able to meet the proposed standard.

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

See e.g., Utility Air Regulatory Group v. EPA, 573 U.S. 302, 328 (2014) (“We reaffirm the core administrative-law

principle that an agency may not rewrite clear statutory terms to suit its own sense of how the statute should operate.”).

See 88 Fed. Reg. at 24,857.

Id. at 24,868 (emphases added).

App.451

First, the evaluation summarized in the Technical Memo excludes units that have shut

down, will shut down, or will no longer burn coal/oil by December 31, 2028, or reported data in

lbs/MWh.26 By failing to include units that will shut down or no longer burn coal/oil by December

31, 2028, EPA is not appropriately accounting for units that are likely emitting fPM at levels closer

to the current standard than the more stringent proposed fPM limit. EPA should have accounted

for such units given that affected EGUs will have up to three years after the effective date of the

final rule to demonstrate compliance with the revised limit, and some of the excluded units may

not have retired or ceased burning coal or oil by the compliance deadline.27 These units should be

included when evaluating what fPM levels current technologies are capable of achieving.

If the final rule is issued before December 31, 2025, or if the announced retirements are

delayed, these excluded units might become subject to a tighter standard that they cannot meet

without large capital outlays to install PM control technology despite near-term projected fuel

switches or retirement dates that would render such investments not cost-effective. Units that are

retiring in the near-term and cannot meet the fPM limit without the installation of controls could

be forced to shut down early, which could destabilize electric reliability in their service areas and

could have long-lasting effects. Significant dollars would need to be spent to restart certain

generating facilities if it is later determined that the decision to shut down early was detrimental

to reliable grid operations. A compliance date based on three years after the final rule’s effective

date is inconsistent with other recent EPA rulemakings, which recognize that significant

investments in emissions controls should not be required for EGUs that will retire in the near-term.

Second, the evaluation is based on selected quarterly data from 2017, 2019, and 2021.28

The Agency fails to explain how and why it selected the specific quarterly data for those years for

its evaluation when EPA has all quarterly tests and PM CEMS for the entire fleet since the effective

date of the original MATS rule.29 The Agency also fails to explain why it used a single quarter of

data to present the unit’s “baseline” and why “[t]he 99th percentile of the lowest quarter was chosen

to describe the baseline fPM rate for each EGU.”30 This results in a questionable dataset comprised

of an extremely small industry sample size and where a single data point is narrowed down for

each EGU. For example, for Colstrip, EPA utilized a baseline of 0.018 lb/MMBtu fPM for Unit 3

and 0.021 lb/MMBtu fPM for Unit 4.31 These numbers do not reflect what is consistently

achievable for Colstrip, as Colstrip has already optimized its existing controls to the greatest extent

See Technical Memo at PDF p. 2.

88 Fed. Reg. at 24,868, fn. 20. EPA excluded units that have announced that they will shut down by the end of

2028 based on the National Electric Energy Data System (“NEEDS”) database, but such retirement plans are not

legally binding and thus such units should not be excluded from the Agency’s evaluation.

Technical Memo at PDF p. 2. (“Quarterly data from 2017 (variable quarters) and 2019 (quarters three and

occasionally four) were first reviewed because data for all affected EGUs subject to numeric emissions limits had

been previously extracted from CEDRI. In addition, the EPA obtained first and third quarter data for calendar year

2021 for a subset of EGUs with larger fPM rates (generally greater than 1.0E-02 lb/MMBtu for either 2017 or 2019).”)

The fact that this information had previously been extracted from CEDRI is no explanation at all. See id.

Technical Memo at PDF p. 4. (emphasis added).

See id. at PDF p. 4; Appendix C, id. at PDF p. 46.

App.452

practicable and cannot sustain emissions this low. In 2022, Colstrip achieved approximately 0.022

lb/MMBtu on an annual basis, far above EPA’s assumption of the 99th percentile of the lowest

quarter.

EPA should use all data available from coal-fired EGUs — except as noted below with

respect to units co-firing natural gas and units with an early retirement date — to provide a full

picture of achieved fPM emission rates. At the least, EPA should provide justification for its

selection of the data, why reliance on the selected data is appropriate, and why certain quarterly

data from 2017, 2019, and 2021 were excluded, so that interested stakeholders can verify the

accuracy and representativeness of the underlying unit-specific data.32

Among other issues in the evaluation, EPA:

Included some units that will be converted to gas in 2025.

Did not include data for all quarters but instead selected only quarters with the lowest

emissions for some units and excluded other quarters with higher emissions (peaking for

some units, ramping for others).

Excluded some units with no current plans to retire or switch to gas.

Included some units that have a federally enforceable requirement to cease coal combustion

by December 31, 2028 (despite stating that the evaluation excluded coal-fired EGUs that

will retire by that date).

Used the last day of a quarter in some cases and the average of 30-day averages for others.

Included only certain test runs in conducting its distribution analysis.33

As to the last point above, EPA should use a historical data pool that encompasses data from

different times of year and operating conditions. EPA should include all affected units and all

operating quarters in its analysis. Without a more comprehensive data pool, it is difficult to see

how EPA could conduct a proper statistical analysis to justify the proposed fPM limit. Talen

Montana strongly recommends that EPA correct the deficiencies identified above, as well as make

its 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.

It is confusing as to which units EPA included/excluded, and as to which quarterly data sets were included/excluded.

EPA failed to explain its rationale for determining which units and data sets should be included or excluded. The lack

of explanation, coupled with the large number of supporting documents in the docket, makes it extremely difficult to

identify the unit-specific data compiled, analyzed, and ultimately relied upon by EPA and, more importantly, to

meaningfully review EPA’s evaluation.

For the same reasons articulated in fn. 32, it is confusing as to which test runs EPA included/excluded in its

distribution analysis, and EPA’s lack of rationale for how it determined which test runs to use.

App.453

Third, the evaluation fails to properly address differences in typical unit operating

variability by combining stack test data with PM CEMS data. Stack test data represent unit

performance at a discrete point in time under full load conditions, whereas PM CEMS data provide

a more comprehensive assessment of unit operating variability under all load and process

conditions. These are two different data sets and should be treated independently. This is reflected

in EPA’s performance specification for PM CEMS, which only requires the readings to be within

+/-25% of actual stack testing values two-thirds of the time (with the other one-third of the time

not having any accuracy constraint) to be considered as valid readings.34 EPA fails to explain how

using such an error prone data set is justified for establishing an emissions standard. The

evaluation fails to recognize that PM CEMS is not constrained to a linear correlation with direct

emissions. In cases where non-linear correlations are used, an allowable +/-25% error from the

correlated value could have a much larger deviation from the actual measured emissions compared

to when a linear correlation is used.35 Any emissions analysis based upon PM CEMS readings

must attempt to compare unit performance in the allowable error band.

Further, any unit using a PM CEMS to demonstrate compliance with the emissions limit

also must conduct annual emissions measurements under steady-state conditions, which are

utilized in either a Response Correlation Audit (“RCA”) or Relative Response Audit (“RRA”).

The tested unit must show compliance in the short-term via stack testing measurement values and

in the long-term via PM CEMS 30-day average values. For these purposes, PM CEMS data and

the PM testing measurements should be treated separately and not merged as a data set. Failing to

address these differences is especially problematic because EPA is proposing to require PM CEMS

as the sole compliance demonstration method, as discussed further below. EPA should thus revise

its current “apples-to-oranges” comparison to establish consistently achievable baseline emissions

for each unit by using all available data and by accounting for any bias related to operating

variability.

Fourth, the evaluation fails to take into consideration different control configurations —

specifically, the variation in PM removal efficiencies. Some PM control technology, such as hotside electrostatic precipitators (“ESPs”), inherently have higher particulate emissions. Similarly,

depending on the coal combusted, units that utilize hydrated lime as a control technology for

minimizing SO2 and acid gases inherently have higher variability in particulate emissions. Wet

flue gas desulfurization (“WFGD”) controls, like Colstrip’s venturi wet scrubbers, also may result

in higher variability in particulate emissions. EPA should factor in these specific control

configurations. EPA also should analyze more comprehensive data sets across a longer time frame

— rather than using a snapshot of EGUs “demonstrating” the proposed limit during selected

quarters — prior to concluding that continuous compliance with the proposed limit is achievable.

Fifth, the evaluation fails to recognize that some units have converted to natural gas cofiring. Since these units continue to have the capability to combust coal, all of their emissions data

is reported as subject to MATS. However, co-firing natural gas inherently results in significantly

See Appendix F, 40 C.F.R. Part 60, Procedure 2.

See Appendix B, 40 C.F.R. Part 60, Performance Specification 11.

App.454

reduced fPM emissions, which could bias the data set low. EPA should exclude data from units

that co-fire natural gas in evaluating what a revised fPM standard should be. Any proposed fPM

limit that EPA establishes should be based on fPM from affected units that only combust coal.

Lastly, EPA’s evaluation is replete with questionable assumptions and statements. For

instance, in the technical reports developed by Sargent & Lundy (“S&L”), on which EPA relies

for cost and emissions reductions assumptions, S&L acknowledges that “[b]ased on S&L’s recent

industry experience, the lowest filterable PM emission rates that an ESP supplier has been willing

to guarantee is 0.030 lb/MMBtu for a new and/or completely rebuilt ESP.”36 Yet, the study states

that “it is clear that emission levels down to 0.010 lb/MMBtu and below are achievable in most

ESP applications based on the reported emissions data” despite acknowledging that the authors

are unable to tie a specific performance improvement to a specific set of ESP upgrades. 37 EPA

should not rely on such unsupported statements to justify a fPM limit of 0.010 lb/MMBtu.

EPA’s fPM proposal disproportionately impacts Colstrip.

EPA’s proposal to tighten the fPM limit also is arbitrary and capricious because it

disproportionately impacts Colstrip. Even if EPA were correct that most units subject to the

Proposed Rule would have to do nothing and that the remainder would only need to upgrade

existing control technology, the same is not true for Colstrip.38 As EPA acknowledges in the

proposal, Colstrip would need to install new ESPs or FFs — and the Colstrip units, based on EPA’s

analysis, would be the only two units that would need to do so to comply with the proposed 0.010

lb/MMBtu fPM limit.39

Given that EPA’s rationale for the Proposed Rule is that existing control technology is

more effective and cost effective than was known at the time of the original MATS rule — that

91% of units already have either a FF or ESP and are meeting the proposed standard and that the

rest would only need to upgrade existing control technology at relatively low cost — it simply

does not follow that Colstrip should be required to install new, complex, and prohibitively

expensive control technology to meet a significantly lower standard.40 The logical conclusion that

should flow from EPA’s rationale (assuming that it is not flawed), is that Colstrip should upgrade

its existing venturi wet scrubber technology to the greatest extent possible.

Instead, EPA proposed that Colstrip should meet the proposed standard by installing new

FFs or ESPs at Colstrip. Below is a table summarizing the total annualized cost and the annualized

Sargent & Lundy. PM Incremental Improvement Memo, Doc. ID. EPA-HQ-OAR-2018-0794-5836 at 2 (Mar.

2023). See also Technical Memo at PDF p. 8.

PM Incremental Improvement Memo at 2.

See Technical Memo at PDF p. 9-10.

See id. at PDF p. 10 (“For the one facility with existing venturi-type WS (and without an existing ESP or FF), EPA

assumes that ESP upgrades will reduce fPM emission to 1.5E-02 lb/MMBtu. To achieve the lower potential fPM

standards, EPA assumes that these EGUs would require FF installation, reducing baseline fPM rates by 90% subject

to a floor of 2.0 E-03 lb/MMBtu.” (emphasis added)).

See 88 Fed. Reg. at 24,868; Technical Memo at PDF p. 9-10.

App.455

cost EPA attributes for Colstrip to comply with 0.015 lb/MMBtu, 0.010 lb/MMBtu, and 0.006

lb/MMBtu fPM limits:

Table 1: Annual Costs by Potential fPM Standard

Annualized Costs

Total of All Facilities41

Colstrip42

0.015 lb/MMBtu

$13-9-$19.3M

Unit 3: $843,600

Unit 4: $843,600

Total: $1,687,200

Potential fPM Standard

0.010 lb/MMBtu

0.006 lb/MMBtu

$77.3-$93.2M

$633M

Unit 3: $18,992,866

Unit 4: $19,058,306

Total: $38,051,172

As reflected by EPA’s own numbers, the annualized cost for Colstrip to comply with the proposed

0.010 lb/MMBtu fPM limit is approximately $38M, which represents 41-49% of the total

annualized cost of the Proposed Rule. This means that EPA is asking the owners of one facility

— representing 0.7% of EGUs subject to the Proposed Rule — to bear nearly 50% of the costs

associated with the proposed amendment.43 This result is grossly unreasonable, unwarranted, and

inconsistent with EPA’s rationale for the Proposed Rule and should not be finalized.

EPA’s cost effectiveness analysis is flawed.

Additionally, EPA’s proposal to tighten the fPM standard is arbitrary and capricious

because the Agency’s cost-benefit analysis is flawed. First, EPA overestimated the benefits

attributed to Colstrip if Colstrip were to comply with the 0.010 lb/MMBtu fPM limit. Below is a

table summarizing the total fPM emission reductions calculated by EPA and the fPM emission

reduction from Colstrip (as calculated by EPA) if Colstrip were to comply with a 0.015 lb/MMBtu,

0.010 lb/MMBtu, and 0.006 lb/MMBtu fPM limits.

Table 7, Technical Memo at PDF p. 12.

Appendix D, id. at PDF p. 80 (total annualized costs for Colstrip is calculated by summing the annualized costs for

Units 3 and 4).

See id. at PDF p. 2 (evaluating fPM rates from a total of 275 individuals EGUs with Colstrip representing two of

those EGUs)

App.456

Table 2: fPM Emission Reductions by Potential fPM Standard

fPM Emission

Reduction

Total of All

Facilities44

Colstrip45

0.015 lb/MMBtu

Potential fPM Standard

0.010 lb/MMBtu

0.006 lb/MMBtu

463 tons/yr

2074 tons/yr

6163 tons/yr

Unit 3: 82.3 tons/yr

Unit 4: 166.6 tons/yr

Total: 248.9 tons/yr

Unit 3: 442.1 tons/yr

Unit 4: 528.3 tons/yr

Total: 970.4 tons/yr

Unit 3: 442.1 tons/yr

Unit 4: 528.3 tons/yr

Total: 970.4 tons/yr

As reflected above, EPA associated nearly 47% of the total fPM emission reduction for the

proposed 0.010 lb/MMBtu fPM limit to Colstrip. However, that result relies on questionable

assumptions. For instance, to achieve the 0.015 lb/MMBtu fPM limit, EPA assumed that Colstrip

would conduct maintenance of its venturi wet scrubbers. But maintenance alone (or any other

optimization measures) will not further improve the performance of Colstrip’s wet scrubbers, as

they are already performing at maximum optimization, as discussed above in Section II.A.46

Similarly, to achieve both the 0.010 lb/MMBtu and 0.006 lb/MMBtu fPM limits, EPA

assumes that Colstrip will install a new FF that would “reduce[] baseline fPM rates by 90% subject

to a floor of 2.0E-03 lb/MMBtu.”47 In taking the 99th percentile of the lowest quarter to describe

the baseline fPM rate for each EGU, EPA assumes for Colstrip a baseline of 0.018 lb/MMBtu fPM

for Unit 3 and 0.021 lb/MMBtu fPM for Unit 4.48 With a 90% reduction, this means that EPA

is assuming that Unit 3 would achieve 0.0018 lb/MMBtu fPM (subject to the 0.0020 lb/MMBtu

fPM floor caveat) and Unit 4 would achieve 0.0021 lb/MMBtu fPM with a FF. But such

emission rates are significantly below either the proposed 0.010 lb/MMBtu fPM limit or the more

stringent 0.006 lb/MMBtu fPM limit EPA is considering.

Moreover, EPA has provided zero engineering justification for its assumption that any

EGU could achieve such emission rates with FFs/baghouses, much less Colstrip’s units with their

unique configuration. S&L’s technical reports in fact states that FF vendors would not be able to

guarantee rates as low as EPA’s 0.0020 lb/MMBtu fPM floor assumption. For instance, S&L state

that “[w]ith the usage of more expensive fiberglass bags with a PTFE [polytetrafluroethylene]

membrane coating, it is expected that 0.00375 lb/MMBtu of filterable PM emission could be

achieved but would not be guaranteed by vendors” and “[a]s such, a best-case scenario would be

Table 6, id. at PDF p. 11.

Appendix D, id. at PDF p. 80 (total fPM emission reductions for Colstrip are calculated by summing the annualized

costs for Units 3 and 4).

See id.; Table 5, id. at PDF p. 10-12.

See id. at PDF p. 10.

See id. at PDF p. 4; Appendix C, id. at PDF p. 46.

App.457

achieving 0.005 lb/MMBtu.”49 Indeed, based on Talen Montana's discussions with consultants

and vendors, it may not be possible to guarantee anything under 0.010 lb/MMBtu depending on

the configuration. As a result, EPA has grossly overestimated the emission reductions from

Colstrip that, coupled with EPA’s unjustified assumptions, renders its cost-benefit analysis flawed.

For example, EPA estimates fPM emission reductions of 970.4 tons/yr from Colstrip assuming

that Colstrip will achieve emission rates of 0.0020 lb/MMBtu fPM for Unit 3 and 0.0021

lb/MMBtu fPM for Unit 4 once controls are installed. However, as discussed below, Colstrip may

only attain an emission rate of 0.010 lb/MMBtu fPM, which corresponds to a reduction of 538

tons/yr using EPA’s “baseline.”

Second, EPA also underestimated the cost per ton of fPM reduced for Colstrip because

EPA’s cost effectiveness analysis fails to account for the impacts of the IRA. As EPA states in

the Proposal, the Agency’s estimates in the analysis “do not account for any future changes in the

composition of the operational coal-fired EGU fleet that are likely to occur by 2028 as a result of

other factors affecting the power sector, such as the Inflation Reduction Act (IRA), future

regulatory actions, or changes in economic conditions.”50 This is problematic because it means

that EPA is assuming that Colstrip Units 3 and 4 will continue to operate as baseload units for the

foreseeable future.51 But such an assumption is contrary to EPA’s post-IRA IPM model, which

predicts that Colstrip will shift away from operating as baseload units and its utilization will

decrease. Specifically, the post-IRA IPM model — which accounts for future changes that are

likely to occur only as a result of the IRA and not other factors (e.g., Proposed Rule, Proposed

GHG Rule) — assumes that Colstrip will:

Through 2030, continue to operate as baseload units with an estimated combined heat

input of 113 TBtu/year.52

By 2040, reduce its utilization by 25% so that it is estimated to operate at a combined

heat input of 85 TBtu/year.53

By 2050, reduce its utilization by 88% so that it is estimated to operate at a combined

heat input of 13 TBtu/year.54

As reflected in Attachment B, the cost effectiveness of installing new baghouses at Colstrip

significantly decreases over time because of reduced utilization. Utilizing EPA’s cost numbers

(and presumed emission reductions), the cost effectiveness is estimated to be $39,192/ton fPM

reduction in 2030 assuming baseload operation (i.e., 113 TBtu/year). However, the cost

PM Incremental Improvement Memo at 9 (original underline omitted, italicized emphasis added). See also id. at

10 (“[S]uppliers may be willing to provide a filterable PM guarantee of 0.005 lb/MMBtu for new baghouses with

PTFE bags.” (original underline omitted, italicized emphasis added)).

88 Fed. Reg. at 24,869-70.

See Technical Memo at PDF p. 11.

Post-IRA 2022 Reference Case, https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.

Id.

App.458

effectiveness would be $51,071/ton fPM by 2040 assuming 75% of baseload utilization and

$330,026/ton fPM by 2050 assuming 12% of baseload utilization. The post-IRA IPM model

predicts an 88% reduction in fPM emissions from Colstrip by 2050, as a result of the IRA only and

without reductions from the Proposed Rule. Thus, by not incorporating the post-IRA IPM model

into the analysis, EPA’s cost effectiveness estimate for Colstrip is severely underestimated because

it is premised on the Colstrip units operating at baseload utilization across a fifteen-year time

horizon and fails to account for the change in utilization that Colstrip is projected to undergo by

the latter part of that horizon.55 In other words, Colstrip is projected to operate and emit less, and

thus the same costs will be borne to generate fewer tons of reductions.

Third, EPA fails to account for the reduction in remaining useful life and utilization that

also may result from EPA’s other rulemakings targeting Colstrip, including the Proposed CCR

Rule and the Proposed GHG Rule. For instance, EPA’s Proposed GHG Rule, if finalized, would

make it challenging for Colstrip to meaningfully operate past 2034, or even 2031, given the

proposed 20% capacity factor limit for near-term units in the Proposed GHG Rule (assuming that

units would need to adopt that limit from 2031 to 2034). But the Proposed Rule would require the

Colstrip owners to spend hundreds of millions of dollars to install FFs or ESPs by 2027 or 2028,

only to potentially shut down or seriously curtail operations by 2031 due to the Proposed GHG

Rule. In considering the cost effectiveness of the rule, EPA should have considered that the costs

to upgrade Colstrip may only be spread over three to four years. This would yield astronomically

high annualized costs. Moreover, it is highly improbable that the Colstrip owners would shell out

those huge sums of money to operate for three or four more years, as the owners would not be able

to recoup those costs. Colstrip shutting down prematurely would have far-reaching ramifications

on Montana’s economy and the surrounding region and grid stability and transmission, as

discussed in Section II.B. — none of which EPA considered.

The Cost for Colstrip to Comply with the Proposed 0.010 lb/MMBtu fPM

Limit is Exorbitant and Requires Significant Time to Install, Test, and

Implement the Controls.

Talen Montana retained Burns and McDonell (“B&M”), an engineering consulting firm,

to evaluate the cost and feasibility of control technologies available to Colstrip to comply with the

proposed 0.01 lb/MMBtu fPM limit. Working with equipment vendors, B&M evaluated the cost

and feasibility of a number of controls, including an ESP or a FF upstream of Colstrip’s existing

wet scrubbers, a wet ESP, and an ESP or a FF downstream of Colstrip’s existing wet scrubbers.

For the purposes of these comments, B&M conducted a high-level feasibility and cost review that

would need to be refined with additional engineering. Actual costs when compared to this level

of estimate could be as much as 50% higher than those projected here. Sufficient time was not

See Technical Memo at PDF p. 10.

App.459

available during the comment period to further refine the feasibility and costs, and EPA rejected

Talen Montana’s request for more time to undertake additional efforts.56

B&M’s estimates for the two units combined are summarized below (see Attachment C for

the memorandum from B&M which contains a detailed summary of estimates). The first table is

how B&M estimates costs, including cost escalation during construction. The second table is

meant to be more aligned with how EPA estimates costs, which leads to underestimates:

See Talen Montana’s Request for Extension of the Comment Period on the National Emissions Standards for

Hazardous Air Pollutants: Coal- and Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk

and Technology Review, Doc. ID. EPA-HQ-OAR-2018-0794-5880, submitted May 25, 2023 (denied on June 12,

2023).

App.460

Table 3: Annual Costs of Control Options at Colstrip to

Meet the Proposed 0.010 lb/MMBtu fPM Limit

(B&M Class 5 Feasibility Estimates)

Colstrip58

Installed

Capital Cost

Total (EPA)57

Baghouse (EPA)59

Upstream ESP (B&M)

Upstream FF (B&M)

Wet ESP (B&M)

Reheat ESP (B&M)

Reheat FF (B&M)

$486.0M

$404.9M

$744.5M

$263.5M

$351.2M

Annualized

Cost of Controls

$77.3-$93.2M

$38,051,172

$87.4M

$78.0M

$104.9M

$41.8M

$56.5M

Table 4: Annual Costs of Control Options at Colstrip to

Meet the Proposed 0.010 lb/MMBtu fPM Limit

(B&M Estimates Using EPA Cost Approach)

Colstrip61

Installed

Capital Cost

Total (EPA)60

Baghouse (EPA)62

Upstream ESP (B&M)

Upstream FF (B&M)

Wet ESP (B&M)

Reheat ESP (B&M)

Reheat FF (B&M)

$406.1M

$338.3M

$622.2M

$220.2M

$293.4M

Annualized

Cost of Controls

$77.3-$93.2M

$38,051,172

$77.8M

$70.1M

$90.4M

$36.6M

$49.7M

Table 7, Technical Memo at PDF p. 12 (for all EGUs subject to the Proposed Rule).

Cost estimates are based on the following assumptions, scope, and other cost factors. Assumptions include: 85%

capacity factor, $15/ton disposal, $200/ton lime, $45/MW power, 15-year life, and 8.25% prime rate. Scope includes:

ductwork, foundations, control device, electrical (percent based), no fans, no stack modifications, and ash and lime

silos and slurring/feed for upstream control options. Other cost factors include: 5% indirect costs, 8% engineering

cost, 5% escalation during construction, 15% contingency costs, and 0% owners’ cost.

Appendix D, id. at PDF p. 80 (total annualized costs for Colstrip is calculated by summing the annualized costs for

Units 3 and 4).

Table 7, Technical Memo at PDF p. 12 (for all EGUs subject to the Proposed Rule).

Cost estimates are based on the following assumptions, scope, and other cost factors. Assumptions include: 85%

capacity factor, $15/ton disposal, $200/ton lime, $45/MW power, 15-year life, and 8.25% prime rate. Scope includes:

ductwork, foundations, control device, electrical (percent based), no fans, no stack modifications, and ash and lime

silos and slurring/feed for upstream control options. Other cost factors include: 0% indirect costs, 8% engineering

cost, 0% escalation during construction, 10% contingency costs, and 0% owners’ cost.

Appendix D, id. at PDF p. 80 (total annualized costs for Colstrip is calculated by summing the annualized costs for

Units 3 and 4).

App.461

As reflected above, B&M’s estimates of annualized costs are significantly higher than EPA’s

$38M estimate63 for a new FF at Colstrip, ranging from $41.7M to $104.9M (using B&M’s Class

5 Estimate) and $36.6M to $90.3M (using EPA’s approach), assuming that Colstrip is just able to

meet the proposed 0.010 lb/MMBtu fPM limit.

Further, the cost effectiveness of each of the control options that B&M evaluated are below,

where the first B&M column is based on a fPM baseline of 0.022 lb/MMBtu, which represents

Colstrip’s average fPM emission rate in 2022, and the second B&M column is based on a fPM

baseline of 0.0195 lb/MMBtu, which represents the average of the EPA’s fPM baselines for

Colstrip’s Units 3 and 4. The B&M estimates are calculated using EPA’s cost approach.64

Table 5: Cost Effectiveness of Control Options at Colstrip

Colstrip

EPA65

Baghouse

Upstream ESP

Upstream FF

Wet ESP

Reheat ESP

Reheat FF

B&M

0.022 lb/MMBtu

fPM baseline

B&M

0.0195 lb/MMBtu

fPM baseline

$114,900/ton

$103,200/ton

$133,100/ton

$53,900/ton

$73,200/ton

$145,000/ton

$130,300/ton

$168,000/ton

$68,000/ton

$92,400/ton

$39,192/ton

As reflected above, the cost effectiveness for Colstrip to install the various controls are

significantly higher than EPA’s estimate of $39,192/ton (see Section III.A.2.c, assuming baseload

operation), ranging from $73,156/ton to $133,104/ton (using the actual 0.022 lb/MMBtu fPM

baseline) and from $68,114/ton to $168,132/ton (using an average of EPA’s fPM baseline for the

units). In the B&M scenarios, the cost per ton is calculated assuming that the units will just be

able to achieve 0.010 lb/MMBtu after controls based on the technical review to date, as opposed

to EPA’s unrealistic assumptions of a 90% reduction in fPM down to 0.002 lb/MMBtu.

At this preliminary stage, the downstream (“Reheat”) options are the most cost-effective.

The upstream options, and wet ESP option, are even more costly, and come with additional

technical challenges, as outlined in the B&M memorandum attached as Attachment C. Despite

the lower cost of the Reheat ESP compared to the Reheat FF, the Reheat ESP comes with more

technical challenges in meeting the 0.010 lb/MMBtu standard.66 The Reheat FF has fewer

technological challenges and could be the preferred alternative should Colstrip retrofit to comply

with the Proposal. However, with an annualized cost of $56.5 M (using B&M’s Class 5 estimates)

Note that EPA fails to provide meaningful information as to how annualized control costs were estimated, how

capital costs were specifically calculated for Colstrip, or what specific control configurations were accounted for in

the estimates. This has made it difficult for Talen Montana to fully comment on EPA’s cost estimates.

Supra fn. 61.

See Attachment B.

See Attachment C.

App.462

or $49.7M (B&M’s estimates using EPA’s cost approach), and with a limited lifespan and limited

generation to recoup the costs, it is far more likely that Colstrip would suffer a premature

retirement with the potential for serious economic disruption and impacts on grid reliability and

transmission.

Should EPA Finalize the Proposed 0.010 lb/MMBtu fPM Limit, EPA Should

Create Additional Subcategories.

EPA should not finalize the 0.010 lb/MMBtu fPM limit. But should EPA do so, the Agency

should establish subcategories so that it accounts for Colstrip’s unique design and circumstances.

Specifically, EPA should establish a subcategory for coal-fired units that use wet scrubbers to

address both SO2 and PM, and that do not have ESPs or FFs, where the fPM limit for those units

is no lower than 0.025 lb/MMBtu pursuant to its authority under 42 U.S.C. § 7412(c)(5). As

discussed above, application of the 0.010 lb/MMBtu fPM standard to Colstrip is not appropriate

or warranted. At most, EPA should require Colstrip to optimize its existing control technology,

consistent with the burden borne by other EGUs, as evaluated by the Agency. While Talen

Montana believes that its efforts to reduce fPM have already been optimized, a limit of 0.025

lb/MMBtu fPM may be more achievable, especially as compared to the 0.010 lb/MMBtu fPM

limit, as it would at least provide Colstrip an opportunity to try to meet the limit without new

control technology. It also would provide for a more stringent limit for Colstrip, with additional

emission reductions, and would be more appropriate for Colstrip given its unique circumstances.

As an additional alternative, EPA should establish a subcategory with units making an

enforceable commitment to retire, where the fPM limit remains at 0.03 lb/MMBtu through

retirement.67 This would be in line with how EPA is providing lead time for older sources in other

rulemakings.68 Creating a subcategory in the MATS rule for units committing to retire would

greatly assist companies with moving forward on retirement plans without running the risk of

being forced to retire early, which could create reliability concerns or, in the alternative,

deliberating whether to install controls and continue operation longer than planned to recoup

investments in the controls.

Here, EPA should create a retirement subcategory allowing units to continue to meet the

existing 0.03 lb/MMBtu fPM standard so long as they opt-in to the retirement subcategory within

18 months after finalization of the rule, with a retirement date no later than December 31, 2035

(and where continued operation after 2035 would later be permitted if (i) the unit is essential to

maintain regional grid reliability, as determined by the Western Regional Adequacy Program,

Regional Transmission Organizations, Independent System Operators, North American Electric

Reliability Corporation, or other similar system reliability authorities; or (ii) or if EPA determines

A unit should qualify for the retirement subcategory as long as it commits to cease burning coal by the proposed

deadline of December 31, 2035.

See e.g., Proposed GHG Rule, 88 Fed. Reg. 33,240, 33,245 (May 23, 2023) (near-term retirement units); Federal

“Good Neighbor Plan” for the 2015 Ozone National Ambient Air Quality Standards, 88 Fed. Reg. 36,654 (June 5,

2023).

App.463

that additional time is required for transition to renewable or clean energy generation).69 This

would provide units another compliance option and needed flexibility.

EPA Should Retain the fPM Emission Monitoring Options.

EGUs that do not qualify for the low emitting EGU program currently demonstrate

compliance with the fPM standard by conducting quarterly performance testing (i.e., quarterly

stack testing), using a PM continuous parameter monitoring system (“CPMS”), or using a PM

CEMS.70 EPA is proposing to eliminate the quarterly stack testing and CPMS options for all coalfired EGUs — specifically, requiring all coal-fired EGUs to use PM CEMS “[a]fter considering

updated information on the costs for quarterly performance testing compared to the costs of PM

CEMS and on the measurement capabilities of PM CEMS, as well as other benefits of using PM

CEMS, which include increased transparency and accelerated identification of anomalous

emissions.”71 According to EPA, PM CEMS data “supply real-time, quality-assured feedback that

can lead to improved control device and power plant operation, which, in turn, can lead to fPM

emission reductions.”72

Talen Montana disagrees with EPA’s conclusions and strongly believes that sound

engineering approaches using control device operating parameters, such as those found in EPA’s

required compliance assurance monitoring (“CAM”) plans achieve the same ultimate objective of

fPM emission reductions. It is unclear how adding another measurement system, particularly

given the challenges with PM CEMS as described below, would be cost-effective. Talen Montana

urges EPA to retain the option for quarterly stack testing (without any changes to testing

frequency) and the CPMS option for all coal-fired EGUs.

General Challenges with PM CEMS

EPA should retain the quarterly stack testing and PM CPMS options — particularly if the

Agency intends to finalize the proposed 0.010 lb/MMBtu fPM emission limit — to afford entities

flexibility in demonstrating compliance with the more stringent limit. Currently, two-thirds of

existing EGUs have chosen to demonstrate compliance via the quarterly stack testing approach,

and EPA should continue to retain that option in light of the difficulties with using PM CEMS.

EPA justifies the proposed requirement to use PM CEMS based on cost, but the Agency

understates the costs of PM CEMS and significantly overstates stack testing costs.73 The costs

associated with installing, maintaining, and operating a PM CEMS far outweigh the costs of

demonstrating compliance through stack testing, as discussed below.

It makes sense for units retiring in this time frame to be allowed to continue operations without installation of new

controls because the annualized costs for an eight-year period (i.e., installation in the 2027-2028 time period and

retirement by the end of 2035) would be excessive. For example, the annualized costs for the reheat FF with an eightyear life would be $76.6M versus $56.5M with a 15-year life.

See 40 C.F.R. § 63.10011(b).

See 88 Fed. Reg. at 24,857.

Id. at 24,872.

Id.

App.464

In addition, use of PM CEMS may not be appropriate for all coal-fired units given the

challenges associated with: (i) meeting the Quality Assurance-Quality Control (“QA-QC”) criteria

required under Procedure 2; and (ii) establishing the correlation curve using Performance

Specification 11 (“PS-11”). First, when a PM CEMS fails to meet the QA-QC criteria required

under Procedure 2, the collected data is considered out-of-control and is no longer considered

valid.74 Because the measured emissions values are dependent upon laboratory analysis, an

owner/operator has no real time indication that its EGU might have failed the required QA-QC

criteria until several weeks after the testing has been completed. This can result in hundreds of

hours of monitor downtime being created retroactively after the QA-QC criteria failure has been

identified. Monitor downtime is required to be reported as a deviation under the MATS rule, and

most states have minimum data availability requirements that could result in enforcement actions.

At the more stringent fPM criteria of 0.010 lb/MMBtu (or 0.006 lb/MMBtu), the likelihood of outof-control periods increases. This downtime is not reflective of poor maintenance or operation but

rather the difficulties associated with the required calibration procedure at such low emission

levels. Thus, in conjunction with this rulemaking, EPA should include additional provisions in

Appendix C of 40 C.F.R. Part 63, Subpart UUUUU to mitigate the effects of this downtime, such

as provisional data periods following a failed RRA or RCA. Moreover, there currently is no

calibration procedure available that can accurately verify continuous measuring of fPM at levels

as low as 0.010 lb/MMBtu, much less 0.006 lb/MMBtu.75

EPA attempts to address these issues by proposing to amend Table 2 of 40 C.F.R. Part 63

Subpart UUUUU to require sample volumes of at least 4 dscm per run, rather than at least 1 dscm

per run.76 While the additional sample volume will reduce measurement uncertainty, it does not

address the unit and control device operating variability that occurs during correlation testing that

would make it difficult to achieve the distinct PM test conditions required under PS-11 and

Procedure 2. In addition, when developing the initial correlation curve or conducting ongoing

RCAs, emissions controls are de-tuned to simulate upset conditions and to achieve dust loadings

at mid- (25-75% of the maximum expected concentration) and high- (50-100% of the maximum

expected concentrations) levels.77 For units equipped with WFGD systems, expanding the test

runs to collect 4 dcsm of sample volume significantly increases the flyash carryover to the

scrubber.78 This off-spec material is then required to be landfilled instead of beneficially reused.

See Appendix F, 40 C.F.R. Part 60, Procedure 2.

See Nicklin, D. et. al., “Techniques to measure particulate matter emissions from stationary sources: A critical

technology review using Multi Criteria Decision Analysis (MCDA),” Journal of Environmental Management, 296:1820 (2021).

See MATS RTR Rule Text Redline Strikeout document (final) (“Redline Final”), posted on Apr. 25, 2023, at PDF

p. 86, 89, 91, 96, 98, Doc. ID. EPA-HQ-OAR-2018-0794-5831. See also 88 Fed. Reg. at 24,873-74.

Trying to simulate different ranges of particulates created for test activities often has unintended consequences on

the FGD’s performance that can take days to normalize and clean up so that the equipment resumes performing as

designed. Any additional ash carryover into the FGD increases the opportunity to blind the FGD such that the only

recovery is to shut the unit down to add lime or to dump the ash into a storage tank because the material can no longer

be stored in the onsite landfill as the chloride content of the sludge, at that point, has become too high.

Ash reinjection may be not feasible for some sources due to stratification issues or ash drop-out effects.

App.465

Furthermore, it can take days to weeks for the scrubber chemistry to again reach optimal, steadystate conditions; and maintaining optimal scrubber chemistry is needed to ensure effective removal

of mercury emissions. The increased particulate loading will physically impact the equipment and

degrade the scrubber’s performance, such as: scaling inside the scrubber vessel; plugging spray

headers; causing buildup on mist eliminators; and eroding booster and ID fan blades and absorber

recirculating pumps.

Second, PM CEMS require the use of PS-11 to establish a correlation curve.79 For the PS11 PM CEMS correlation test, a minimum of 15 sets of reference method testing must be

conducted that are evenly spaced over three different levels of PM mass concentration by varying

process operating conditions, by varying PM control device conditions, or by means of PM

spiking.80 If it is not possible to obtain three distinct levels of PM concentration, zero point testing

may be used to perform correlation testing over the maximum range of PM concentration that is

practical for the PM CEMS.81 Each run requires roughly three to four hours, and most sources

conduct 18 to 20 test runs for a robust correlation.82 Barring unpredictable circumstances, based

on the proposed sampling time, PS-11 may require seven to ten days to complete. Additional time

likely will be needed to maintain the distinct PM test conditions that are required. Sources also

will require accurate, preliminary test results to evaluate each test condition and may even need to

obtain final results before concluding the test program, which further extend the length and cost of

the tests. These activities increase the cost of MATS compliance and overall EGU operation, as

well as disrupt the normal operation of the EGU. Ongoing PM CEMS correlation testing with

injection of media in the effluent to artificially raise emission levels costs at least $250,000 per

test evolution at one source, and testing is required by MATS once every three years. For

Colstrip’s Units 3 and 4, PM CEMS would cost approximately $136,000/year, whereas quarterly

MATS PM stack testing costs approximately $24,000/year. Thus, EPA may have significantly

underestimated annual costs associated with a PM CEMS (from $18,111 to $95,397 depending on

type) and overestimated annual costs associated with stack testing ($85,127), particularly when

specific control configurations are taken into account.83 Furthermore, the excessive costs of

installing and maintaining PM CEMS become even more onerous if required on a unit with limited

remaining life (see earlier discussion on how other rules may force retirement, cessation of coal,

or decreased capacity factors, or if an early retirement subcategory is created).

More importantly, EPA has failed to show how correlations can be developed on data sets

where the upper end of the emissions testing is capped at 0.010 lb/MMBtu fPM following PS-11

requirements. Emissions levels are supposed to be evenly distributed between the low, mid, and

high PM emission levels. Even when allowing for a low-emitting unit to use a zero point in the

correlation, a correlation still needs data variation to be a valid regression model. By limiting the

See Appendix B, 40 C.F.R. Part 60, Performance Specification 11.

See id.

88 Fed. Reg. 24,872-73.

App.466

dataset — pursuant to the proposed 0.010 lb/MMBtu fPM limit — EPA needs to establish that the

PS-11 correlation will still be valid at such low levels.

Colstrip’s Challenges with PM CEMS

Colstrip has utilized PM CEMS as a particulate control performance indicator in its PM

CAM Plan since 2014. The initial PM CEMS were a light scattering technology that encountered

times when they did not accurately indicate particulate emissions from the wet venturi scrubber at

Colstrip Units 3&4. In September 2020, the PM CEMS were changed to the MSI BetaGuard 3.0

PM CEMS. The BetaGuard PM CEMS has performed better than the light scattering technology

at Colstrip; however, it still exhibits variability that would not be acceptable to be used as a

continuous compliance monitor. When compared to the quarterly MATS PM compliance test

results, the BetaGuard PM CEMS has provided mg/m3 values that varied from the RM5 mg/m3

value by -24% to +31%. Talen Montana believes this range of variability with the PM CEMS is

not acceptable for use as a compliance monitor, but its use as part of a PM CAM Plan like Colstrip

utilizes, is reasonable.

The PM CAM Plan is a requirement under Colstrip’s Title V Operating Permit to help

ensure compliance to the particulate standard utilizing performance indicators and an operational

parameter. The performance indicators include opacity monitoring and PM CEMS, and the

operational parameter is scrubber plumb bob delta P.

PM CEMS requirements under Colstrip’s PM CAM Plan are robust and include:

Installation per manufacturer’s standards.

Daily zero and span checks using manufacturer’s standards.

Initial correlation based on three levels (zero, normal operations, and at scrubber

operations that increase PM but not at a level that puts Colstrip’s Title V

requirements at risk). This initial correlation used three RM5 runs at normal

operations and two RM5 runs at the higher PM level. This correlation relates PM

CEMS mg/m3 to RM5 mg/m3.

A PM CEMS CAM Plan excursion limit in terms of mg/m3 is established.

A PM CEMS CAM Plan excursion requires a prompt investigation to identify and

correct the condition, followed by a RM5 test to confirm compliance with the

particulate standard.

On a quarterly basis, one RM5 test (comprised of three runs) will be conducted to

update the initial correlation. If the result from the average of the three runs differs

App.467

from the initial correlation by 25% or more of the CAM Plan excursion limit, then

the initial correlation will be repeated.

An on-going PM CEMS correlation adjustment will be made quarterly based on the

correlation from all RM5 test data.

PM CEMS daily averages are submitted to MDEQ on a quarterly basis.

Given Colstrip’s experience with the use of PM CEMS as a performance indicator, which

shows that the CEMS results are highly variable and not reliable, EPA should not finalize the

CEMS requirement in the Proposed Rule. If EPA does finalize the CEMS requirement, EPA

should: (i) carve out units like Colstrip Units 3 and 4 that already have a CAMS plan that utilizes

performance indicators and operational parameters to ensure compliance with the particulate

standard; and (ii) not require PM CEMS for units that would only be subject to MATS for a limited

time after the effective date of the final rule.

IV.

CONCLUSION

Talen Montana appreciates the opportunity to submit comments on the Proposed Rule.

Talen Montana respectfully requests that EPA consider the recommendations above to ensure that

the Agency accounts for Colstrip’s unique design and circumstances, as well as to account for the

prohibitive costs that Colstrip faces if it were forced to comply with the proposed fPM limit.

Colstrip is vital to Montana, and premature retirement could jeopardize Montanans’ access to

affordable and reliable electricity, especially during extreme weather conditions.

Dated: June 23, 2023

Respectfully submitted,

Thomas Weissinger

Sr. Director – Environmental

Talen Energy

thomas.weissinger@talenenergy.com

App.468

ATTACHMENT

ATTACHMENT A

Please

Please see

see native

native Excel

Excel file

file “ATTACHMENT

“ATTACHMENT A”

A” accompanying

accompanying Talen

Talen

Montana’s

Montana’s comments.

comments.

App.469

0.021

0.018

0.021

0.018

0.021

0.018

128.8

69.7

59.0

832.1

450.7

381.4

1084.3

587.0

497.3

FPM

Emissions

(tpy)

88%

23%

Reduction

in FPM

without

Proposed

Rule

38,051,172

19,058,306

18,992,866

38,051,172

19,058,306

18,992,866

38,051,172

19,058,306

18,992,866

New

Baghouse

Cost

($/yr)

0.0021

0.0020

0.0021

0.0020

0.0021

FPM

Emission

Factor with

New

Baghouse

(lb/MMBtu)

0.0020

13.5

6.97

6.5

87.0

45.07

42.0

113.4

58.7

54.7

FPM

Emissions

with New

Baghouse

(tpy)

115.3

62.8

52.5

745.1

405.6

339.4

970.9

528.3

FPM

Emissions

Reduction

from New

Baghouse

(tpy)

442.6

330,026

303,606

361,602

51,071

46,982

55,957

39,192

36,075

42,912

New

Baghouse

Cost

Effectiveness

($/ton)

App.470

Final Version of the RIA [Regulatory Impact Analysis] for the Proposed EGU MATS RTR, Doc ID. EPA-HQ-OAR-2018-0794-5837; Post-IRA 2022 Reference Case,

https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.

Scenarios. The scenarios presented for calculating the cost effectiveness of installing a baghouse at Colstrip are: (i) based on the utilization and heat input

predicted EPA’s post-IRA IPM model from present to 2050;84 (ii) based on EPA’s “baseline” for Colstrip, which represents the 99th percentile of the lowest

13,200,000

Total

85,300,000

Total

6,642,662

42,925,688

42,374,312

6,557,338

111,160,317

Total

55,904,762

Emission

Reductions

Using 2050

Base Case

55,255,556

EPA

Proposed

Emission

Reductions

(Baseload

Operation)

Emission

Reductions

Using 2040

Base Case

Heat Input

(MMBtu/yr)

Unit

Scenario

Current

FPM

Emission

Factor

(lb/MMBtu)

Colstrip New Baghouse Cost Effectiveness

The following table summarizes how the cost effectiveness of installing a new baghouse at Colstrip was calculated using EPA’s post-IRA IPM

model. The table was prepared by Trinity Consultants, which Talen Montana retained for the purposes of preparing comments on the Proposed Rule.

ATTACHMENT B

App.471

See Technical Memo at PDF p. 4.

See id. at PDF p. 10.

Post-IRA 2022 Reference Case, https://www.epa.gov/power-sector-modeling/post-ira-2022-reference-case.

See id. at PDF p. 4.

Appendix D, id. at PDF p. 80.

See id. at PDF p. 10.

New baghouse cost effectiveness ($/ton). New baghouse cost effectiveness is calculated by dividing new baghouse cost ($/yr) by fPM emissions reduction

from new baghouse (tpy).

FPM Emissions Reduction from New Baghouse (tpy). fPM emission reduction from new baghouse is calculated by subtracting fPM emissions with new

baghouse (tpy) and fPM emissions (tpy).

FPM Emissions with New Baghouse (tpy). fPM emissions with new baghouse are calculated by multiplying the Heat Input (MMBtu/yr) by the fPM New

Baghouse Emissions factor (lb/MMBtu) and then diving by 2000 lb/ton.

FPM Emission Factor with New Baghouse (lb/MMBtu). fPM emission factor with new baghouse is based on EPA’s assumption that installing a baghouse

would “reduc[e] baseline fPM rates by 90% subject to a floor of 2.0E-03 lb/MMBtu.90

New Baghouse Cost ($/yr). New baghouse cost is EPA’s annualized cost estimate for Colstrip to achieve compliance with the proposed 0.010 lb/MMBtu

fPM limit via a new baghouse.89

FPM Emissions (tpy). fPM emissions are calculated by multiplying the Heat Input (MMBtu/yr) by the Current FPM Emission Factor (lb/MMBtu) and diving

by 2000 lb/ton.

Current FPM Emission Factor (lb/MMBtu). Current fPM emission factor is EPA’s “baseline” for Colstrip, which represents the 99th percentile of the lowest

quarter among the 2017, 2019, and 2021 data EPA evaluated.88

Heat Input (MMBtu/yr). Heat input is calculated by EPA’s Post-IRA 2022 Reference Case.87

quarter among the 2017, 2019, and 2021 data EPA evaluated;85 and (iii) based on EPA’s assumption that installing a baghouse would “reduc[e] baseline fPM

rates by 90% subject to a floor of 2.0E-03 lb/MMBtu.86

ATTACHMENT

ATTACHMENT C

App.472

June 23, 2023

Mr. Gordon Criswell

Talen Montana

580 Willow Ave, PO Box 38

Colstrip, MT 59323

Re: Talen Energy Colstrip/ Mercury and Air Toxics Standards (MATS) Analysis

Dear Mr. Criswell:

Talen Montana, LLC (Talen) engaged Burns & McDonnell Engineering Company, Inc.

(BMcD) to assist it in evaluating the potential cost impacts of complying with the

potential particulate limits in EPA’s proposed MATS rule. The scope of work included

the following:

Evaluate the proposed filterable particulate matter limit of 0.01 lb fPM/mmBtu

and evaluate what particulate control technologies could maintain the limit at

Colstrip.

Provide an AACE Class 5 estimate of the necessary capital improvements and

operations/maintenance costs.

Background Information

The Colstrip units being evaluated are two approximately 740 MW units (net) that

fire PRB coal and utilize a plumb bob wet scrubber to simultaneously remove

filterable particulate and sulfur dioxide (SO2) from the flue gas. This approach has

the advantage of using the alkalinity inherent to PRB fly ash as reagent to help

remove SO2. However, this control technology is not as effective at removing fine

particulate matter (fPM) as more modern particulate control technologies. The

system was originally designed to achieve an emission rate of 0.05 lb fPM/mmBtu at

a plumb bob pressure drop of 17”.

Over the years the Colstrip plant has worked with scrubber consultants and

engineers to improve the fPM removal ability of the scrubber. Changes and

upgrades have increased the pressure drop to the system maximum across the

scrubber’s plumb bob, optimized mist eliminators, and installed flow distribution

plates to optimize scrubber performance. Beyond the scrubber, Colstrip has made

operational changes to improve the fPM removal including improving boiler wall

cleaning to impact the size of the fPM and increase removal across the scrubber,

implemented a combustion optimization system, and performed preventative

maintenance on the coal mills to maintain the coal grind size and thus the resulting

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App.473

Mr. Criswell

June 23, 2023

Page 2

fPM size. However, even with these previous scrubber upgrades, operational

changes and maintenance practices focused on fPM removal, the best single

quarterly fPM compliance test the unit has achieved (not maintained) is 0.017

lb/mmBtu.

The upgraded system typically operates between 0.020 and 0.027 lb fPM/mmBtu.

The average quarterly fPM compliance tests for 2022 was 0.022 lb/mmBtu. These

rates are in compliance with the current limit of 0.030 lb fPM/mmBtu but would not

be in compliance with the proposed MATS rule. The proposed MATS rule would

reduce the fPM limit to 0.010 lb fPM/mmBtu.

Particulate Control Technology Discussion

Potential Particulate Control Options to Achieve New MATS fPM Limit

BMcD evaluated several options to reduce fPM at Colstrip. These options include

dry/wet electrostatic precipitators (ESP) and baghouses/fabric filters (FF). The

traditional location for a dry ESP or FF is between the air heater outlet and the

scrubber. A wet ESP would be located after the scrubber systems while the flue gas

is saturated. Colstrip Units have a feature that is uncommon at wet scrubbed United

States power plants. After each scrubber vessel there is a reheat system that warms

the flue gas approximately 60°F which results in a ‘dry’ (non-saturated) flue gas.

This situation creates the opportunity to utilize an ESP or FF downstream of the

scrubber provided that the reheat system is operational.

Burns & McDonnell (BMcD) discussed these different conditions with Southern

Environmental Inc. (SEI) – an equipment supplier – and requested budgetary pricing

for each option as SEI can supply all of these technologies. SEI indicated they believe

that all of these options can achieve the proposed 0.010 lb fPM/mmBtu emission

rate. However, guaranteeing that these rates can be continuously maintained at the

stack is not certain for all technologies. We identify a few technological challenges to

consider when evaluating these technologies below:

ESP/FF Located Upstream of Scrubber

If the fPM control device is installed upstream of the scrubbers, there is a question of

whether the scrubbers will remove or re-introduce fPM into the flue gas. An ESP or

FF upstream of the scrubber can be guaranteed to maintain 0.010 lb fPM/mmBtu at

the particulate control device outlet. Nearly all of the fPM passing through the

scrubber is particulate smaller than 2.5 microns (PM2.5) as the scrubber is excellent at

9400 Ward Parkway \ Kansas City, MO 64114

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App.474

Mr. Criswell

June 23, 2023

Page 3

removing larger particulates but not great at removing smaller particulates. If an ESP

or FF is installed upstream of the scrubber, all of the PM entering the scrubber will be

PM2.5and the scrubber will do little to reduce the PM2.5 concentrations. Also, since the

existing scrubbers use the alkalinity inherent to PRB fly ash as reagent to help

remove SO2, fly ash that is collected in the ESP/FF would have to be reintroduced to

the scrubber for SO2 removal and this fly ash could be re-emitted as particulate after

the scrubber. Therefore, this evaluation has assumed that additional lime will be

used in lieu of fly ash to control SO2 emissions. This does not eliminate the risk the

scrubbers could re-emit fPM but does reduce the risk.

Wet ESP

A wet ESP downstream of the scrubber can be guaranteed to maintain

0.010 lb fPM/mmBtu at the particulate control device outlet/stack inlet. However,

the flue gas entering the scrubber must be saturated and the stack is not designed

for wet flue gas. The flue gas would need to be captured prior to the existing reheat

system, routed to the wet ESP and then either routed back to the existing reheat

system or through a new reheat system and fan. Because of the complexity of the

tie in and the fact the wet ESP and reheat system would need to be made out of high

alloy to address corrosion; the cost estimate demonstrates this is the most expensive

option.

ESP/FF Located Downstream of Scrubber

An ESP or FF downstream of the scrubber is expected to maintain 0.010 lb

fPM/mmBtu. A FF can be guaranteed to maintain 0.010 lb fPM/mmBtu if the flue gas

is maintained at least 30° above the dew point. This is critical because if the bags in

the fabric filter become wetted for even a short period, the bags could be damaged

catastrophically and fail to perform. This requirement could be challenging if there is

an upset in the reheat system or any time steam may not be available.

An ESP can likely be guaranteed to maintain 0.010 lb fPM/mmBtu; however, there is

some concern due to the fPM particle size in this location. ESP systems can remove

PM2.5 and smaller particles. However, it is more difficult to remove the smaller

particles than the larger particles. Further evaluation or testing maybe required for a

guarantee to be provided. The advantage of a dry ESP in this location is a dry ESP is

not as susceptible as a FF to wet flue gas conditions. The dry ESP cannot operate in

saturated flue gas, and continuous operation in saturated conditions would damage

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App.475

Mr. Criswell

June 23, 2023

Page 4

the ESP, but short-lived incidents with exposure to saturated flue gas are not

expected to catastrophically damage the ESP.

Cost Estimate for Particulate Control Technology

Burns & McDonnell produced AACE Class 5 estimates for these control technologies

based on the ‘flange to flange’ budgetary price information SEI shared and BMcD’s

previous experience in building up the fully-installed cost of such projects. The

estimated costs are intended to include new ductwork, foundations, support steel,

insulation, ash piping, electrical upgrades, new ash silos, new carbon injection

systems, and (as applicable) new lime silos and feed systems. The costs do not

include new fans, stack modifications, taxes, water treatment, or significant

demolition. The Class 5 estimates presented here include: indirects, engineering,

escalation during the project, and contingency. The cost estimating method favored

by the EPA differs from typical industry cost estimates. Key differences of the EPA

cost estimating method include removal of indirect costs and all escalation, and

reducing the contingency to 10%. The Class 5 estimates we prepared, and the EPA

cost estimates do not include Owners costs or an EPC fee.

The capital cost estimates provided are considered AACE Class 5 feasibility

estimates and are provided in 2023 dollars unless indicated otherwise. The estimates

were built up using heavy construction cost data from RSMeans, vendor input for

major equipment, and in-house information from other projects. Engineering,

Construction Management, Start-Up, and Contingency are based on percentages of

the total direct cost for these Class 5 estimates. All sales taxes are excluded from the

estimates. Talen should not use these estimates to establish the project budget as

they are only intended to assist in selecting the preferred solution(s) at the site. The

selected alternative(s) should be investigated further, with additional design and

more detailed quantity buildup completed along with soliciting local contractors for

labor pricing prior to establishing the project budget.

BMcD’s estimates, analyses, and recommendations contained in this email are based

on professional experience, qualifications, and judgment. BMcD has no control over

weather; cost and availability of labor, material, and equipment; labor productivity;

energy or commodity pricing; demand or usage; population demographics; market

conditions; changes in technology; and other economic or political factors affecting

such estimates, analyses, and recommendations. Therefore, BMcD makes no

guarantee or warranty (actual, expressed, or implied) that actual results will not vary,

9400 Ward Parkway \ Kansas City, MO 64114

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App.476

Mr. Criswell

June 23, 2023

Page 5

perhaps significantly, from the estimates, analyses, and recommendations contained

herein.

In the preparation of this, information provided by Talen was used by BMcD to make

certain assumptions with respect to conditions that may exist in the future. While

BMcD believes the assumptions made are reasonable for the purposes of this study,

BMcD makes no representation that the conditions assumed will, in fact, occur. In

addition, while BMcD has no reason to believe that the information provided by

Talen, and on which this report is based, is inaccurate in any material respect, BMcD

has not independently verified such information and cannot guarantee its accuracy

or completeness.

Cost Summary

We prepared the following cost summary of the various options. Table 1 is a

summary of key assumptions while Tables 2-5 are the costs summarized and

levelized to dollars per ton. Tables 2 and 4 assume the baseline is the 2022 average

emission rate of 0.022 lb fPM/mmBtu while Tables 3 and 5 assume the average

emission rate the EPA used in the MATS evaluation of Colstrip (0.0195 lb

fPM/mmBtu).

Table 1: Summary of Capital and O&M Costs

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We appreciate the opportunity to assist in this evaluation. Should you have any

questions or wish to schedule a follow-up meeting, please contact Doug Randall at

(816) 822-3455.

Sincerely,

Burns & McDonnell Engineering Company, Inc.

Douglas Randall

Associate Controls Specialist

9400 Ward Parkway \ Kansas City, MO 64114

O 816-333-9400 \ burnsmcd.com

App.482

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