Emergency Application — North Dakota, et al., Applicants v. Environmental Protection Agency, et al.
Supreme Court briefAug 16, 2024
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USCA Case #24-1119
Document #2058570
Filed: 06/07/2024
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IN THE UNITED STATES COURT OF APPEALS
FOR THE DISTRICT OF COLUMBIA CIRCUIT
STATE OF NORTH DAKOTA, STATE
OF WEST VIRGINIA, STATE OF
ALASKA, STATE OF ARKANSAS,
STATE OF GEORGIA, STATE OF
IDAHO, STATE OF INDIANA, STATE
OF IOWA, STATE OF KANSAS,
COMMONWEALTH OF KENTUCKY,
STATE OF LOUISIANA, STATE OF
MISSISSIPPI, STATE OF MISSOURI,
STATE OF MONTANA, STATE OF
NEBRASKA, STATE OF OKLAHOMA,
STATE OF SOUTH CAROLINA,
STATE OF SOUTH DAKOTA, STATE
OF TENNESSEE, STATE OF TEXAS,
STATE OF UTAH, COMMONWEALTH
OF VIRGINIA, AND STATE OF
WYOMING,
Case No. 24-1119
Petitioners,
v.
U.S. ENVIRONMENTAL PROTECTION
AGENCY,
Respondent.
DECLARATION OF CLAIRE VIGESAA
IN SUPPORT OF PETITIONERS’ MOTION TO STAY FINAL RULE
I, Claire Vigesaa, hereby declare and state under penalty of perjury that the following is
true and correct to the best of my knowledge and is based on my personal knowledge or
information available to me in the performance of my official duties:
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My name is Claire Vigesaa, and my business address is 600 East Boulevard Ave Dept 405
Bismarck, ND 58505-0840. I am over the age of 18, have personal knowledge of the subject
matter, and am competent to testify concerning the matters in this declaration.
2.
I have served as Executive Director of the North Dakota Transmission Authority (NDTA)
since July 2023. I have a Bachelor of Science degree in engineering from North Dakota
State University and held leadership roles in the electric utility industry for 39.5 years, my
last 10 years as General Manager/CEO of an electric transmission cooperative utility. As
Executive Director of the NDTA, my responsibilities include working with the North
Dakota Industrial Commission (NDIC) to facilitate the development and maintenance of
electric transmission infrastructure in North Dakota and coordinating with regional
transmission organizations to provide for a reliable and resilient electrical grid.
3.
The NDTA was created by the North Dakota legislature in 2005. The NDTA was
established to serve as a catalyst for new investment in transmission by facilitating,
financing, developing, or acquiring transmission to accommodate energy production.
NDTA is actively engaged in seeking ways to improve North Dakota’s energy export and
transmission capabilities within the state. NDTA is also involved with planning and
studying grid reliability, resilience, and congestion issues. To that end, NDTA has funded
several studies that examine the likely impacts of EPA’s proposed air quality regulations
on electric grid reliability and resilience in North Dakota and surrounding regions.
4.
I am submitting this declaration in support of Petitioners’ Motion to Stay the Final Rule
published by the U.S. Environmental Protection Agency (EPA) on May 7, 2024, entitled
“National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-Fired Electric
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Utility Steam Generating Units Review of the Residual Risk and Technology Review,” 89
Fed. Reg. 38508 (Final Rule).
5.
As Director of the NDTA, I have significant concerns that the Final Rule will
fundamentally undermine the reliability and resiliency of the electric grids upon which the
State of North Dakota and its people rely.
North Dakota’s Power Generation Environment
6.
North Dakota has a diverse portfolio of power generation resources, including wind, coal,
hydroelectric, and natural gas. The combined total capacity of all types of utility-scale
generation in North Dakota is approximately 8,863 MW, and almost half of that (4,048
MW) comes from 10 coal-firing power plants operating within the State.
7.
Over thirty percent of the electricity generated in North Dakota is exported out of the State
through the two Regional Transmission Organizations that service the State and
surrounding regions—the Midcontinent Independent System Operator (MISO) and the
Southwest Power Protocol (SPP).
8.
Studies commissioned by the NDTA project a 10,000 GWhr increase in energy demand in
North Dakota over the next two decades, requiring approximately 2200 to 2500 MW of
additional capacity to meet the anticipated growth in demand.
9.
The projected growth in renewable resources over the next two decades will not be enough
to meet the projected demand in growth, especially if existing dispatchable fossil
generation is forced into early retirement by this Final Rule or other federal rules.
10.
Dispatchable energy is energy that is available on demand. Energy sources such as wind
and solar are considered non-dispatchable. When demand for electricity exceeds the
dispatchable supply, the foreseeable result will be blackouts or energy rationing.
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The Final Rule Threatens an Already Vulnerable Power Grid
11.
The power grids providing electricity to North Dakota (and much of the country) are
already stretched dangerously thin, and they do not have the resiliency or the buffer of
excess dispatchable generation that they had ten or even five years ago.
12.
Prior to 2016, MISO had no instances requiring the use of emergency procedures, but since
then, there have been 48 Maximum Generation events. 1 Maximum Generation events are
a multi-tiered process to respond to generation resource shortages. A graphic from MISO
shows this tiered process. 2
1
North Dakota Industrial Commission and North Dakota Transmission Authority, “Analysis of Proposed EPA MATS
Residual Risk and Technology Review and Potential Effects on Grid Reliability in North Dakota,” at 9 (Apr. 2, 2024)
(MATS
Study),
available
at
https://www.ndic.nd.gov/sites/www/files/documents/TransmissionAuthority/Publications/MATS_Analysis_Report.pdf.
2
Midcontinent Independent System Operator, “Overview of June 10, 2021 Maximum Generation Event,” (July 8,
2021) available at https://cdn.misoenergy.org/20210708%20MSC%20Item%2006%20Review%20of%20Max%20
Gen%20Event%20-%20June%2010567565.pdf
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Since 2022, MISO has been operating near the level of minimum reserve margin
requirements. 3 This means that there is little to no excess capacity in the grid.
14.
In 2023, both the MISO and SPP grid operators issued warnings about the adequacy of
generation resources to meet peak demand situations. 4
15.
National organizations charged with monitoring the nation’s regional power grids are
reporting the same thing. The North American Electric Reliability Corporation (NERC)’s
2023 Long-Term Reliability Assessment, identified MISO as one of the two regions in the
country most at risk of capacity shortfalls due to the retirement of thermal resources with
inadequate reliable generation coming online to replace them. 5
16.
As soon as 2028, the MISO grid is projected to have capacity shortfalls even during normal
weather. And much of the rest of the country is projected to have capacity shortfalls during
severe weather events, when it is needed the most (and when renewable energy is at its
least reliable). These are not historically normal projections and are a significant source of
concern. And that is without this Final Rule and other federal rules forcing even more
reliable, dispatchable, fossil fuel generation sources to retire.
17.
A graphic from NERC’s 2023 Long-Term Reliability Assessment illustrates the gravity of
current projections for our national power grids. 6 Areas in red are not projected to have
sufficient capacity during normal weather events. As described above, MISO, which
3
Midcontinent Independent System Operator, “MISO’S Response to the Reliability Imperative,” at 6 (Feb. 2024),
available at https://cdn.misoenergy.org/2024%20Reliability%20Imperative%20report%20Feb.%2021%20Final
504018.pdf?v=20240221104216.
4
MATS Study at 9.
5
North American Electric Reliability Corporation, “2023 Long-Term Reliability Assessment,” (Dec. 2023),
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf.
6
North American Electric Reliability Corporation, “2023 Long-Term Reliability Assessment,” Dec. 2023, available
at https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2023.pdf.
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includes much of North Dakota, is in red. Areas in orange are not projected to have
sufficient capacity in severe weather events.
18.
On February 26, 2024, MISO released “MISO’s Response to the Reliability Imperative,”
a report that addresses the disturbing outlook for electric reliability in its footprint. The
main reasons for this warning are the pace of premature retirements of dispatchable fossil
generation and the resulting loss of accredited capacity and reliable energy production
sources. 7 In that report, MISO states that “[w]idespread retirements of dispatchable
resources, lower reserve margins, more frequent and severe weather events and increased
reliance on weather-dependent renewables and emergency-only resources have altered the
7
Midcontinent Independent System Operator, “MISO’S Response to the Reliability Imperative” (Feb. 2024), https:
//cdn.misoenergy.org/2024%20Reliability%20Imperative%20report%20Feb.%2021%20Final504018.pdf?v=202402
21104216.
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region’s historic risk profile, creating risks in non-summer months that rarely posed
challenges in the past.”
19.
That February 2024 Report from MISO contains a section titled, “EPA Regulations Could
Accelerate Retirements of Dispatchable Resources,” which states:
While MISO is fuel- and technology-neutral, MISO does have a
responsibility to inform state and federal regulations that could
jeopardize electric reliability. In the view of MISO, several other
grid operators, and numerous utilities and states, the U.S.
Environmental Protection Agency (EPA) has issued a number of
regulations that could threaten reliability in the MISO region and
beyond.
20.
If the Final Rule forces even more coal generation sources to shut down, there can be little
doubt that it will significantly impact grid reliability and the provision of reliable electricity
to the people of North Dakota and surrounding regions.
21.
Even if the Final Rule does not cause plants do not shut down, implementation of the Rule’s
low emissions standards will necessitate operational modifications within lignite power
plants. Such operational changes can compromise the inherent flexibility of lignite power
plants to respond effectively to fluctuating load conditions and grid demands. The need
for continuous operation of emission control systems, coupled with potential limitations in
responsiveness, may impede the plant’s ability to ramp up or down quickly in response to
changes in electricity demand or supply. Consequently, the reliability of lignite power
plants to maintain grid stability and meet grid operator requirements may be compromised,
raising concerns about their ability to ensure consistent and secure electricity supply.
Potential Impact of the MATS Rule to the MISO Grid and North Dakota
22.
Due to its very serious concerns about the impact the MATS Rule will have on power grid
reliability for the people of North Dakota, NDTA engaged the Center of the American
Experiment to model the reliability and cost impacts of the Rule in the MISO subregions
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as it relates to eliminating the subcategory for lignite-fired power plants. That report is
available at: https://www.ndic.nd.gov/sites/www/files/documents/Transmission-Authority
/Publications/MATS_Analysis_Report.pdf (“NDTA MATS Study”).
23.
The NDTA MATS Study applied EPA’s own capacity factor assumptions to the projected
future demand growth for electricity in the MISO region, but also accounted for seasonality
and timing of generation and demand based on historical use in the MISO region. See
NDTA MATS Study at 49-50, 58-59.
24.
After applying EPA’s own capacity factor assumptions to projected future demand, and
accounting for seasonality and timing of generation and demand, the NDTA MATS Study
concluded that if lignite-fired facilities in North Dakota that serve the MISO market are
forced to retire in the near future as a result of the Rule (or otherwise), it will increase the
severity of future projected capacity shortfalls in the MISO region, resulting in economic
damages from the ensuing blackouts ranging from $29 million to $1.05 billion over the
next decade, and imposing replacement generation costs that will be passed onto ratepayers
of approximately $1.9 billion to $3.8 billion. See NDTA MATS Study at 1, 31-32, 48.
25.
Moreover, NDTA’s MATS Study notes that in exchange for those projected capacity
shortfalls in the MISO Region, the Final Rule will not provide any meaningful or
quantifiable benefit to public health or the environment from the reductions in mercury and
other air toxins that are mandated by the Rule. EPA acknowledges those levels of emission
are already well below any level that would meaningfully affect public health. Indeed, as
the Study notes, there is substantially more mercury emitted annually from the cremation
of people with dental fillings than is emitted from all coal-fired power plants in the U.S.
combined. EPA’s decision to risk the reliability of our nation’s power grids by imposing
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a Final Rule that will not provide any meaningful public health benefit should be a cause
for concern. See NDTA MATS Study at 16-18.
26.
In summary, the long-term reliability of the power grids serving North Dakota and the
surrounding regions are already in a precarious position, with demand projected to exceed
supply for significant amounts of time, even under normal weather conditions. And the
reason is not a mystery. Reliable, dispatchable generation sources are being pushed into
premature retirement before replacement sources are projected to be online with sufficient
capacity to meet demand projections. A reliable power grid is important for meeting the
basic needs of modern society, therefore alarm bells should be going off. Grid reliability
is vital for ensuring continuous access to essential services, such as food production and
military operations. Dispatchable, reliable generation forms the backbone of grid stability,
enabling the balancing of supply and demand fluctuations. Now is not the time to be
forcing even more dispatchable sources onto retirement tracks for a Final Rule that will not
even create any meaningful or quantifiable public health benefit.
Executed in Bismarck, North Dakota, on May 25, 2024.
Claire Vigesaa
Executive Director
North Dakota Transmission Authority
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IN THE UNITED STATES COURT OF APPEALS
FOR THE DISTRICT OF COLUMBIA CIRCUIT
STATE OF NORTH DAKOTA, STATE
OF WEST VIRGINIA, STATE OF
ALASKA, STATE OF ARKANSAS,
STATE OF GEORGIA, STATE OF
IDAHO, STATE OF INDIANA, STATE
OF IOWA, STATE OF KANSAS,
COMMONWEALTH OF KENTUCKY,
STATE OF LOUISIANA, STATE OF
MISSISSIPPI, STATE OF MISSOURI,
STATE OF MONTANA, STATE OF
NEBRASKA, STATE OF OKLAHOMA,
STATE OF SOUTH CAROLINA,
STATE OF SOUTH DAKOTA, STATE
OF TENNESSEE, STATE OF TEXAS,
STATE OF UTAH, COMMONWEALTH
OF VIRGINIA, AND STATE OF
WYOMING,
Case No. 24-1119
Petitioners,
v.
U.S. ENVIRONMENTAL PROTECTION
AGENCY,
Respondent.
DECLARATION OF DOYLE WEBB
IN SUPPORT OF PETITIONERS’ MOTION TO STAY FINAL RULE
I, Doyle Webb, hereby declare pursuant to 28 U.S.C. § 1746 and state under penalty of
perjury that the following is true and correct to the best of my knowledge and is based on my
personal knowledge or information available to me in the performance of my official duties:
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I am the Chairman of the Arkansas State Public Service Commission (Commission
or PSC). I have held this position since January 17, 2023. I am over the age of 18 and am
competent to testify concerning the matters in this declaration based on my personal knowledge,
my experience with the PSC, and information provided to me by PSC personnel.
2.
The PSC is responsible for regulating the service and rates of utilities, including
electric and gas utilities serving retail customers in Arkansas. As Chairman of the PSC, I am
charged with the responsibility for appraising and balancing the interests of current and future
utility service customers, the general interests of the State economy and the interests of the utilities
subject to Commission jurisdiction in its deliberations and decisions. The Commission actively
participates in the governance of two Regional Transmission Organizations: the Midcontinent
Independent System Operator (MISO), through the Organization of MISO States, and Southwest
Power Pool (SPP), through the Regional State Committee.
3.
I am submitting this declaration in support of Petitioners’ Motion to Stay the Final
Rule, published by the U.S. Environmental Protection Agency (EPA) on May 7, 2024, 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,” 89 Fed. Reg.
38508 (Final Rule).
4.
I am aware that the EPA published the Final Rule following EPA’s proposed Rule
issued on April 24, 2023. See 89 Fed. Reg. 24854.
5.
The Final Rule will negatively impact Arkansas, its ratepayers, and its utilities that
own and operate generation facilities.
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The Final Rule will make electricity less reliable in Arkansas and throughout the
grid by forcing the retirement of base load resources, only serving to exacerbate the threat of
brownouts and blackouts, as well as long-term negative cost impacts.
7.
The Federal Energy Regulatory Commission, the North American Electric
Reliability Corporation (NERC), and entities charged with overseeing the reliability of our power
grids have warned about the long-term reliability of our nation’s power grids. NERC recently
stated that the bulk power system has reached an “inflection point” in which the risk profile to
customers is steadily deteriorating due to the retirement of valuable generation resources outpacing
the addition of new dispatchable generation. 1
8.
In its 2023 Long Term Reliability Assessment, NERC identified that the SPP region
will be at an “elevated risk” of shortfall in extreme conditions.
9.
NERC has also identified risk in MISO, projecting a “high risk” level indicating
insufficient resource adequacy for the majority of Arkansas. 2 This indicates that the electricity
supply for these areas is more likely to be insufficient in the forecast period and more firm
resources are needed. While MISO has seen an upward trend in installed capacity, accredited
capacity to meet system needs is moving in the opposite direction. MISO’s recent accreditation
reforms around direct loss of load indicate that this trend is likely to worsen. 3
10.
MISO released the following statement:
1
The Reliability and Resiliency of Electric Service in the United States in Light of
Recent Reliability Assessments and Alerts: Hearing Before the Committee on Energy and
Natural Resources (June 1, 2023) (Statement of James B. Robb, North American Electric
Reliability Corporation).
2
Id.
3
Midcontinent Independent System Operator (MISO), Managing Reliability Risk in the
MISO Footprint (June 16, 2022), available at https://cdn.misoenergy.org/20220616%20
Board%20of%20Directors%20Item%2008a%20Reliability%20Imperative625168.pdf.
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There are urgent and complex challenges to electric system
reliability in the MISO region and elsewhere. This is not just
MISO’s view; it is a well-documented conclusion throughout the
electric industry. …
Many dispatchable resources that provide critical reliability
attributes are retiring prematurely due to environmental regulations
and clean-energy policies. …
The new weather-dependent resources that are being built, such as
wind and solar, do not provide the same critical reliability attributes
as the conventional dispatchable coal and natural gas resources that
are being retired. While emerging technologies such as long
duration battery storage, small modular reactors and hydrogen
systems may someday offer solutions to this issue, they are not yet
viable at grid scale 4
11.
In summary, the Final Rule will likely have lasting negative impacts. Unless a stay
is immediately granted, the Final Rule will impose significant and irreparable harm on Arkansas
and its citizens.
I declare under penalty of perjury that the foregoing is true and correct to the best of my
knowledge. Executed in Little Rock, Arkansas, on May 22, 2024.
Doyle Webb
Chairman
Arkansas Public Service Commission
4
Midcontinent Independent System Operator, “MISO’s Response to the Reliability
Imperative,” at 2 (Feb. 2024), available at https://cdn.misoenergy.org/2024%20Reliability%20
Imperative%20report%20Feb.%2021%20Final504018.pdf?v=20240221104216.
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DECLARATION OF JASON BOHRER
I, Jason Bohrer, declare as follows:
1.
I am over eighteen years of age, suffer from no disability that would
preclude me from giving this declaration, and make this declaration based upon
personal knowledge or information available to me in the performance of my
professional duties.
2.
I am President and Chief Executive Officer of the Lignite Energy
Council (LEC).
3.
I have been employed by the LEC for 11 years and held my current title
for that entire time. My responsibilities include directing and coordinating the policy
work and research and development priorities of the LEC.
4.
The LEC is a trade association that represents various lignite mines,
lignite-fired power plants and conversion facilities, as well as the businesses that
contribute goods and services to the industry. Its members produce electricity and
also gasify lignite coal, which is then turned into synthetic natural gas and other
valuable byproducts.
5.
LEC members provide electricity to two Regional Transmission
Organizations: the Midcontinent Independent Systems Operator and the Southwest
Power Pool.
6.
I am providing this declaration in support of the motion to stay the rule
promulgated by the U.S. Environmental Protection Agency (“EPA”) entitled National
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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. 38,508 (May 7, 2024) (“MATS RTR”).
7.
The MATS RTR threatens the viability of North Dakota’s lignite-fired
power plants and coal mines. The MATS RTR also endangers the reliability and
resilience of the power grids in North Dakota and the surrounding regions.
8.
LEC members have extensive experience in operating electric
generating units (EGUs) powered by lignite coal while using a variety of emission
control technologies.
9.
North Dakota contains the world’s largest deposit of lignite coal.
Lignite coal is a geologically young form of coal and lacks the homogeneity found
in older types of coal.
10.
In North Dakota, lignite coal is mined adjacent to the EGUs and
conversion facilities where it is used in a “mine-to-mouth” operation. Each EGU
contracts with an individual lignite mine for its supply of lignite, and these EGUs
have been geographically sited based on the availability of lignite coal. Neither
market economics nor coal transportation logistics allow for fuel switching or coal
blending. Should an associated lignite EGU close, the mine providing coal for it
would have no reasonable or viable market alternative.
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The total number of EGU employees in North Dakota is 7,725, and the
total number of mining jobs is 3,250. This ratio suggests that for each employee at a
mine there are two employees at a power plant.
12.
Emission control solutions are not interchangeable and are crafted on
an EGU-by-EGU basis due to the differences in coal composition, power plant
technology and operational needs at each facility.
13.
Particularly for lignite-firing EGUs, the variability in chemical
composition of lignite coal, along with mine-to-mouth operations, requires that
EGUs maintain an emission control compliance margin that accounts for variability
in coal composition and required operational conditions.
14.
The lignite subcategory created by the EPA in the 2012 MATS rule
reflected the reality that the chemical makeup and characteristics of lignite not only
cause different emissions profiles than bituminous or sub-bituminous coals, but also
reflect the lower homogeneity of lignite coal compared to other types of coal.
15.
The lignite subcategory therefore reflected basic chemical truths, such
as the mechanism by which the higher sulfur content of lignite reduces the
effectiveness of sorbent mercury reduction solutions and the interplay between the
formation of SO3 and potential mercury reduction technologies.
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LEC is not currently aware of any verified or demonstrated technology
that will consistently allow all of North Dakota’s lignite-firing EGUs to comply with
the MATS RTR’s newly lowered Hg requirement of 1.2 lb/TBtu.
17.
Illustrating that point, testing performed by LEC member Minnkota
Power Cooperative verified that the increased utilization of sorbents, even at
significantly elevated levels, would not result in consistent compliance with the
newly reduced Hg limit.
The new limit will cause immediate and irreparable harm to LEC Members.
18.
LEC’s members are actively trying to determine if they will be able to
comply with the MATS RTR’s reduced emission requirements and still remain
commercially viable. Testing alone to accurately quantify the requirements specific
to each unique EGU is estimated at more than $1,000,000.00 per unit.
19.
Even if such further testing indicated the new emission limitations
could be met (and it is not currently clear that they could be), the construction costs
necessary to update or replace existing technologies and optimize operation would
be expensive and time consuming.
20.
New expenses would be added to those one-time construction
expenditures (estimated at a minimum of $5,000,000.00 by Minnkota Power
Cooperative for a single facility to between $55,000,000 and $500,000,000 for Basin
Electric Cooperatives’ generating fleet) by requiring additional sorbents or other
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control materials. These new expenses would continue in perpetuity along with
increased operating costs.
21.
Each EGU in North Dakota is unique, but they share in the difficulty of
establishing the feasibility of a path to compliance, and, if one is achievable, the
expenses incurred in implementation, as well as the continual ongoing costs. For
example, a baghouse is estimated to cost $282,715 per fPM ton removed while an
ESP retrofit is estimated at $67,262 per fPM ton removed. Operators will be forced
to pass along those costs to ratepayers or other end users to continue to operate.
22.
Moreover, should feasibility testing indicate compliance is possible, the
substantial modifications required by the MATS RTR would need to be
implemented immediately.
23.
For example, electrostatic precipitator upgrades carry a three-year
timeline from start of construction to implementation. For the EPA’s assessment to
be accurate that no facilities will close due to the MATS RTR, at least 26 impacted
EGUs in the country would be competing for the 4 vendors capable of performing
the work. And based on historical performance, it is unlikely the four contractors
could perform the work needed for all 26 plants in that 3-year period.
24.
The alternative to compliance is to shut down or operate at such a
reduced level that end of life will occur prematurely for the EGU. For every two jobs
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lost at a power plant due to premature shut down, a worker in a lignite mine who
will also lose their job.
The MATS RTR Rule will harm North Dakotans
25.
The elimination of the lignite subcategory will impact North Dakota
and North Dakotans in multiple ways. Lignite provides most of the electricity
consumed in North Dakota, and it provides the backbone of reliability and resilience.
26.
Should testing indicate compliance with the MATS RTR’s new
emission limits is possible for every EGU in North Dakota, the implementation of
new control technologies at each EGU would require multiple EGUs be taken offline
for extended periods of time, concentrating the danger of an unstable, unreliable grid
on North Dakota and its residents.
27.
As a recent study commissioned by the North Dakota Transmission
Authority confirmed, the power grids serving the people of North Dakota are already
operating on dangerously thin margins of dispatchable power. Available at
https://www.ndic.nd.gov/sites/www/files/documents/Transmission-Authority/
Publications/MATS_Analysis_Report.pdf. Consequently, even if Noth Dakota
plants are capable of complying with the MATS RTR’s new standards (which, as
noted above, remains entirely uncertain), complying with the Rule would require
taking multiple units offline for an extended duration to make necessary upgrades,
removing load from power grids that are not projected to have capacity to spare.
(Page 125 of Total)
610a
USCA Case #24-1119
28.
Document #2058570
Filed: 06/07/2024
Page 8 of 8
Winters in North Dakota require consistently available power for
homes, hospitals and businesses to provide care and services for families. Previous
blackouts in other parts of the country associated with Winter Storm Uri have
demonstrated that death and health impacts can follow blackouts even in relatively
mild weather.
29.
Consequently, the MATS RTR will impose significant regulatory
burdens and cost on coal-fired EGUs in North Dakota and create serious risks to the
health and welfare of people in the region.
30.
I declare under penalty of perjury that the foregoing is true and correct
to the best of my knowledge.
Executed this 3rd day of June 2024.
Jason Bohrer
President and Chief Executive Officer
Lignite Energy Council
(Page 126 of Total)
611a
Kristina Tridico
Deputy General Counsel -Regulatory
Direct Dial: 317-618-0151
Email: ktridico@misoenergy.org
April 10, 2023
VIA ELECTRONIC Submission and Email
Attn: Michelle Lloyd
Office of Resource Conservation and Recovery, Materials Recovery and Waste Management
Division, Environmental Protection Agency,
1200 Pennsylvania Avenue NW, MC: 5304T, Washington, DC 20460
Lloyd.Michelle@epa.gov
Re: 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-HQOLEM-2021-0280.
The Midcontinent Independent System Operator (“MISO”) offers these comments on the
proposal by the United States Environmental Protection Agency (“EPA”) to deny applications by
DTE Electric Company’s (“DTE”) 1.3-GW Belle River 1 and 3.3-GW Monroe Power 2 Plants in
Michigan and Rainbow Energy Center, LLC’s (“Rainbow”) 1.2-GW Coal Creek Station in North
Dakota 3 (collectively the “Plants”) for an alternate liner demonstration (ALD) to allow coal
combustion residuals (“CCR”) surface impoundments to continue to receive CCR and non-CCR
waste streams after the current April 11, 2021, deadline to cease receipt of wastes. EPA has
proposed to deny these requests4 and require the Plants to: 1) submit an application for a sitespecific alternative deadline to initiation closure of its CCR surface impoundment(s) or 2) cease
receipt of waste no later than 135 days after EPA issues its final determination on the proposed
denial of the ALD application (or a later date as EPA determines is necessary to address grid
reliability). 5 EPA has requested comment on its denials of the Plants’ alternate liner
demonstrations and its proposed date for the Plants to cease receipt of waste. See EPA-HQOLEM-2021-0280-0001 at p. 2; EPA-HQ-OLEM-2021-0282-0001 at p. 2; EPA-HQ-OLEM1
See https://www.regulations.gov/document/EPA-HQ-OLEM-2021-0282-0001.
See https://www.regulations.gov/document/EPA-HQ-OLEM-2021-0283-0001.
3
See https://www.regulations.gov/document/EPA-HQ-OLEM-2021-0280-0001.
4
The bases for EPA’s proposed decisions are explained in the following memos and proposed determinations: 1)
Proposed Denial of the CCR Part B Alternate Liner Demonstration Application Great River Energy Coal Creek
Station, Upstream Raise 91, Underwood, North Dakota, EPA-HQ-OLEM-2021-0280-0001 at p. 2; Proposed Denial
of the CCR Part B Alternate Liner Demonstration Application, DTE Electric Belle River Power Plant Bottom Ash
Ponds and Diversion Basin, China Township, Michigan , EPA-HQ-OLEM-2021-0282-0001 at p. 2; Proposed Denial
of the CCR Part B Alternate Liner Demonstration Application, DTE Energy Monroe, Fly Ash Basin, Monroe,
Michigan, EPA-HQ-OLEM-2021-0283-0001 at p. 2.
5
See EPA-HQ-OLEM-2021-0280-0001 at p. 2; EPA-HQ-OLEM-2021-0282-0001 at p. 2; EPA-HQ-OLEM-20210283-0001 at p. 2.
2
Midcontinent Independent
System Operator, Inc.
317.249-5400
www.misoenergy.org
720 City Center Drive
Carmel, Indiana 46032
2985 Ames Crossing Road
Eagan, Minnesota 55121
1700 Centerview Drive
Little Rock, AR 72211
612a
April 10, 2023
Page 2
2021-0283-0001 at p. 2. The comment period on these proposals extends to April 10, 2023. See
EPA-HQ-OLEM-2021-0280-0014; EPA-HQ-OLEM-2021-0282-0013; EPA-HQ-OLEM-20210283-0011. MISO’s comments will focus on issues surrounding the potential date for cessation
of operations at these facilities, including receipt of wastes, relevant to the electrical grid and
resource availability.
By way of background, MISO 6 delivers power from the high-voltage transmission grid to
local distribution utilities, which then are responsible for delivery to end-use customers. MISO is
authorized by the Federal Energy Regulatory Commission (“FERC”) to exercise “functional
control” over the high voltage transmission system and otherwise administer the bulk electric
system in its region. One of MISO’s critical functions is to facilitate and maintain the reliable
delivery of electricity. MISO acknowledges and appreciates the role that EPA and other
governmental agencies play in addressing environmental matters, including grid reliability issues.
• EPA MUST CONSIDER RESOURCE ADEQUACY AND GRID RELIABILITY ISSUES
IN ITS DECISIONS REGARDING ANY DATE FOR CESSATION OF WASTE RECEIPT
AT THE PLANTS.
The electric grid is undergoing significant fleet changes that creates an immediate need for
stakeholders to work together to address and maintain electric reliability. MISO’s studies indicate
that its region needs a certain level of dispatchable and flexible resources to reliably manage the
transition to a decarbonized energy future. MISO faces increasing challenges to system reliability
and the ability to commit sufficient resources to supply electricity to customers within the
Midcontinent region.7 Even with the recognized growth of alternative and renewable energy
6
MISO is an independent, not-for-profit, member-based organization responsible for managing the power grid across
15 U.S. states and the Canadian province of Manitoba. MISO is both fuel- and technology-neutral. Today, 45 million
people depend on MISO to coordinate the generation and transmission of the right amount of electricity every minute
of every day. MISO is committed to delivering electricity reliably, dependably and cost effectively. In addition to
managing the power grid within its region, MISO administers the buying and selling of electricity at the wholesale
level, and partners with members and stakeholders to plan the grid of the future.
7
Studies conducted by MISO and other Regional Transmission Organizations (RTOs) have verified that their
transmission systems are at their capacity and there are financial and other impairments currently impacting the ability
to address this lack of capacity issue. MISO’s Long Range Transmission Plan details interconnection issues7 and its
Planning Resource Auction (PRA) process shows strains in the availability of sufficient generating capacity to meet
the region’s needs. See MISO’s 2022/2023 PRA resulted in a capacity shortfall for the MISO North/Central Regions
despite the fact that MISO was able to import over 3,000 MW from neighboring regions. See, e.g., MISO 2022/2023
Planning
Resource
Auction
(PRA)
Results,
April
14,
2022,
available
at
https://cdn.misoenergy.org/2022%20PRA%20Results624053.pdf. See also MISO 2022/2023 Planning Resource
Auction
(PRA)
Results,
Revised
May
3,
2022,
available
at
https://cdn.misoenergy.org/20220420%20RASC%20Item%2004b%20PRA%20Results%20Supplemental624128.pd
f.
See
MISO
2022
Regional
Resource
Assessment
(Nov.
2022),
available
at
https://cdn.misoenergy.org/2022%20Regional%20Resource%20Assessment%20Report627163.pdf noting an overall
decline in accredited capacity in 2022 and near term capacity risk as well as increased complexity of reliability
operating and planning the electric system due to changes in generator sources); MISO’s Response to the Reliability
Imperative
(Jan.
2023),
available
at
https://cdn.misoenergy.org/MISO%20Response%20to%20the%20Reliability%20Imperative504018.pdf (addressing
the shared responsibility of shareholders to address the urgent and complex challenges to electric system reliability
and noting that the MISO region has been inching ever closer to experiencing a shortfall in electricity-generating
613a
April 10, 2023
Page 3
sources, MISO continues to be concerned about the looming shortfall of generation needed to
ensure grid reliability in the region. Within the MISO region, the retirement of generation plants
is occurring far faster than new energy sources with equivalent attributes, whatever the fuel source,
can be developed, constructed, and brought online. While MISO is both fuel- and technologyneutral, it needs to preserve the best options to provide these needed resource capabilities and
attributes to bridge the gap between retirements and replacement capabilities and attributes.
MISO has concerns as to grid reliability and resource adequacy. Resource adequacy, in
general terms, is achieved when the accredited megawatt capacity of the generators in a particular
region meets or exceeds the forecasted load, plus reserves, for that region. 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. Different types of resources are accredited, or count, for different amounts capacity
depending on how reliable they are to be able to generate at the time they are needed. The
traditional dispatchable generators like Coal, impacted by the CCR rules, tend to have much higher
accredited capacity than the replacement capacity that has been brought online in recent years.
Replacement of retiring generation with new, mostly intermittent facilities that are not installed at
the same time or valued at the same output presents its own risks. Moreover, new capacity from
these resources (i.e., non-thermal) is not always available to provide energy during times of need.
For instance, MISO has previously expressed concern to EPA regarding issues related to
withdrawal of service by the Dalman, Erickson, Meramec, Ottumwa, and Sioux power plants and
potential impacts from the loss of generation from these five generators.8 In particular, MISO
commented that “[b]ased on the most currently available information . . . there is very little excess
generating capacity (or none at all) to cover demand for electricity, plus the required reserve
margin, in the immediate future.” 9 It takes time to obtain the required regulatory approvals to
construct new generation and especially any needed transmission facilities to connect that
generation to the grid. In the interim, resource adequacy must be maintained, and reliability
standards met during this period. Accordingly, the future of the electric grid and associated
electric markets depend upon resource availability, flexibility, and visibility.
While resource adequacy is generally the responsibility of the state regulatory authorities
within the Midcontinent region, MISO is in a unique position as the grid operator to inform state
and environmental regulators on the regional impact of actions on grid reliability and customer
impacts. Given the changes to the generating fleet, and the potential shortfalls in generating
capacity, it is imperative that EPA consider the need for reliable generating resources for the
regional reliability value provided to the region’s customers. Given the existing regional supply
capacity due to widespread retirements of conventional resources, not enough replacement capacity coming online,
and other factors). FERC also notes backlogs of more than three years in the interconnection queue. See FERC
Proposes Interconnection Reforms to Address Queue Backlogs, available at, https://www.ferc.gov/newsevents/news/ferc-proposes-interconnection-reforms-address-queue-backlogs (noting significant current backlogs in
the interconnection queues of more than three years).
8
See Comments of Midcontinent Independent System Operator (MISO) related to EPA-HQ-OLEM-2021-0588, EPAHQ-OLEM-2021-0589, EPA-HQ-OLEM-2021-0592, EPA-HQ-OLEM-2021-0593, and EPA-HQ-OLEM-20210594, available at https://www.regulations.gov/comment/EPA-HQ-OLEM-2021-0588-0010.
9
Id. at p. 6, available at https://www.regulations.gov/comment/EPA-HQ-OLEM-2021-0588-0010
614a
April 10, 2023
Page 4
situation, resources need to remain online and available to provide capacity and transmission grid
stability to meet the system’s needs until sufficient replacement capability is brought online.
MISO would note that it has multiple facilities potentially impacted by proposed EPA
denials of ALD determinations for CCR wastes. Accordingly, retirement/suspension requests as
well as planned outages will require particular attention to ensure continued grid reliability and
resource adequacy. The Plants at issue in this particular comment serve crucial power corridors
and provide a combined 5.9 GW to the grid.
•
MISO HAS MADE MODIFICATIONS TO ITS TIMING REQUIREMENTS FOR GENERATOR
SUSPENSIONS AND RETIREMENTS THAT EPA WILL NEED TO CONSIDER IN ITS
DETERMINATION OF WHEN PLANTS WILL NEED TO CEASE RECEIVING WASTES AND
OPERATE.
With regard to potential timing for the Plants to cease receiving wastes and operation, EPA
has requested comments on its proposed dates for the Plant to cease receipt of waste. EPA noted
that the Plants would have “four months from the date of the ineligibility determination to apply
for an alternative closure deadline, during which time the facility’s deadline to cease receipt of
waste to be tolled.” See EPA-HQ-OLEM-2021-0280-0001 at p. 52; EPA-HQ-OLEM-2021-02820001 at p. 51; EPA-HQ-OLEM-2021-0283-0001 at p. 46. Should a plant be unable to submit a
demonstration requesting an alternative closure deadline, EPA has proposed that the plant cease
receipt of waste within 135 days of the date of the Agency’s final decision (i.e., the date on which
the decision is signed) as this would time period would provide the same amount of time that would
have been available to the Plants had EPA issued a denial immediately upon receipt of their applications
(i.e., from November 30, 2020, when EPA received the submission, to April 11, 2021, the regulatory
deadline to cease receipt of waste). See EPA-HQ-OLEM-2021-0280-0001 at pp. 52-53; EPA-HQ-
OLEM-2021-0282-0001 at pp. 51-53; EPA-HQ-OLEM-2021-0283-0001 at pp. 46-47. EPA has
proposed that it may authorize additional time for continued use of the impoundments to the extent
necessary to address demonstrated grid reliability issues, provided that a planned outage request is
submitted to MISO “within 15 days of the date of EPA’s final decision” and “a MISO
determination disapproving the planned outage and the formal reliability assessment upon which
it is based” is provided to EPA within 10 days of receipt by the submitting party. See EPA-HQOLEM-2021-0280-0001 at pp. 53; EPA-HQ-OLEM-2021-0282-0001 at pp. 52; EPA-HQ-OLEM2021-0283-0001 at pp. 46-47.
EPA has stated that it is sensitive to the importance of maintaining enough electricity
generating capacity to meet the Midcontinent region’s energy needs, including meeting specific,
localized issues. See EPA-HQ-OLEM-2021-0280-0001 at p. 55; EPA-HQ-OLEM-2021-02820001 at p. 54; EPA-HQ-OLEM-2021-0283-0001 at p. 48. EPA is proposing to rely on MISO’s
procedures for reviewing planned maintenance outage and similar requests to determine the
appropriate date for the Plants to cease taking waste. See EPA-HQ-OLEM-2021-0280-0001 at pp.
56-57; EPA-HQ-OLEM-2021-0282-0001 at pp. 55-56; EPA-HQ-OLEM-2021-0283-0001 at pp.
49-50. EPA further stated that in MISO’s region “power plants are normally required to submit a
request at 26 weeks in advance of a planned outage to allow MISO to evaluate whether the resource
is needed to maintain grid reliability, among other scheduling considerations” and that MISO
would be able to “to provide an initial assessment of reliability within 135 days.” See EPA-HQ-
615a
5301 32nd Ave S
Grand Forks, ND 58201-3312
Phone 701.795.4000
www.minnkota.com
June 23, 2023
Administrator Michael S. Regan
U.S. Environmental Protection Agency
1200 Pennsylvania Avenue, NW
Washington, DC 20460
RE: Comments from Minnkota Power Cooperative, Inc. on 88 Fed. Reg. 24854 (April 24,
2023), Docket ID No. EPA–HQ–OAR–2018–0794
Dear Administrator Regan,
Minnkota Power Cooperative, Inc.(Minnkota) appreciates the opportunity to provide comments
on EPA’s proposed rule entitled “National Emission Standards for Hazardous Air Pollutants: Coaland Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and
Technology Review” (the Proposed Rule). This Proposed Rule concerns the Mercury and Air
Toxics Standards (the MATS Rule) under Clean Air Act (CAA) Section 112.
Minnkota is a not-for-profit electric generation and transmission cooperative headquartered in
Grand Forks, North Dakota. We are comprised of 11 member-owner distribution cooperatives
located in eastern North Dakota and northwestern Minnesota, and serve some 160,000 cooperative
members, rate-payers. Minnkota also serves as the operating agent for the Northern Municipal
Power Agency (NMPA), headquartered in Thief River Falls, MN. Since our formation in 1940,
Minnkota has been committed to delivering safe, reliable, affordable and environmentallyresponsible energy to its member cooperatives.
Minnkota operates the Milton R. Young Station (the Young Station), a two-unit, cyclone lignite
coal-fired power plant located near the town of Center, North Dakota, that currently complies with
the MATS rule. Consequently, as the operator of the Young Station, Minnkota has a strong interest
in commenting on the proposed revisions in this rulemaking.
We believe EPA’s decision to affirm the robust and technically sound residual risk analysis
concluded in 2020 is well supported. However, our comments further address our serious concerns
that the EPA (1) lacks a legal basis for this proposed rulemaking; (2) used a flawed methodology,
resulting in erroneous filterable particulate matter and mercury baselines; and (3) relied upon
technical conclusions that suffer from several significant technical errors. EPA must modify the
Docket ID No. EPA–HQ–OAR–2018–0794
COMMENTS OF MINNKOTA POWER COOPERATIVE ON THE 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
88 Fed. Reg. 24854 (April 24, 2023)
Docket ID No. EPA–HQ–OAR–2018–0794
Minnkota appreciates the opportunity to provide comments on EPA’s proposed
rule entitled “National Emission Standards for Hazardous Air Pollutants: Coal- and OilFired Electric Utility Steam Generating Units Review of the Residual Risk and
Technology Review” (the Proposed Rule).1 This Proposed Rule concerns the Mercury
and Air Toxics Standards (the MATS Rule) under Clean Air Act (CAA) Section 112.
Minnkota operates the Milton R. Young Station (the Young Station) that currently
complies with the MATS rule. Consequently, Minnkota has a strong interest in
commenting on the proposed revisions in this rulemaking.
I.
Introduction.
In June, EPA recognized dramatic air quality improvements since 1990.2 All
major air pollutants have fallen, including hazardous air pollutants (HAPs), which are the
topic of this rulemaking. Concurrently, our nation is facing an energy reliability crisis.
The North American Electric Reliability Corporation (NERC) recognizes the
unprecedented, rapid evolution of the electricity grid due to retirements of fossil
generation and renewable generation coming on-line.3 NERC predicts electricity
shortfalls in the MISO portion of the electricity grid that Minnkota serves. S&P Global
reports that: “Utilities in MISO are retiring fossil capacity in exchange for investments in
renewable energy resources either contracted or added to their rate base; however,
those exchanges are not happening fast enough to replace all the generation coming
offline.”4
Despite air quality improvements and reliability fears, EPA presses the power
sector further in the 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” (the Proposed Rule).5 The rulemaking comes
at a time when fossil fuel-fired electric generating units (EGUs) are contending with
significant rulemakings that will create a sizeable cumulative cost burden on the industry
in a short time period, most by 2028. For example, in addition to the Proposed Rule,
there currently are open comment periods on other complex proposed rules directly
affecting electric cooperatives:
1
88 Fed. Reg. 24854 (Apr. 24, 2023).
Our Nation’s Air, June 2023,
https://gispub.epa.gov/air/trendsreport/2023/documentation/AirTrends_Flyer.pdf
3
NERC, Long-Term Reliability Assessment, December 2022 at 5,
https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_2022.pdf
4
Bennett, “Outlook 2023: MISO expects net addition of 8.9 GW, may face capacity strain” S&P Global
(May 3, 2023)
5
88 Fed. Reg. 24854 (Apr. 24, 2023).
2
Docket ID No. EPA–HQ–OAR–2018–0794
Nine states experienced rolling blackouts last December as the demand for
electricity exceeded the available supply. Those situations will become even
more frequent if EPA continues to craft rules without any apparent consideration
of impacts on electric grid reliability. American families and businesses rightfully
expect the lights to stay on at a price they can afford. EPA needs to recognize
the impact this proposal will have on the future of reliable energy before it’s too
late.6
The reliability and the costs of this Proposed Rule should be considered as
required by CAA Section 112. It is crucial for EPA to evaluate the overall regulatory
context. The burden of environmental compliance on electric cooperatives and their
end users is cumulatively affected by the compliance timelines of these concurrent
rulemakings.
Minnkota appreciates EPA’s recognition and consideration of these overarching
impacts on electric cooperatives and on the nation’s grid. Minnkota advocates for
adjustment of the fPM emissions limit to 0.020 lb/mmBtu or greater, which would
account for a compliance margin to accommodate variability in unit operation. Minnkota
asks EPA to revise the mercury (Hg) analysis to correct critical errors, which is
necessary to determine whether a Hg emissions limit can be consistently met by lignite
units, as further discussed infra. Minnkota supports the following specific changes to
the proposal:
• Correct the flawed fPM baseline to accurately account for current EGU emissions
and fPM control device capabilities.
• Recognize that EGUs vary in different seasonal and operational conditions as
well as on a unit-by-unit basis due to size, unit-type, fuel and climate. A
compliance margin is necessary to account for these differences.
• Correct the fPM cost analysis to quantify the appropriate number of fPM
upgrades and cost values, such that the cost is not underestimated.
• Consider the time frames in which certain fPM control upgrades and installations
can realistically occur.
• Retain the option to stack test for fPM and non-metal HAPs.
• Reconsider the substantial Hg reductions proposed for lignite-fired units that rely
on flawed technical assumptions as to the capabilities of lignite units.
• Adopt reasonable revisions or keep the current PM CEMS correlation test
requirements that apply to units that elect to use PM CEMS for MATS
compliance.
• Revise the IPM model to refrain from overvaluing the impacts of the Inflation
Reduction Act of 2022 (IRA) as the basis for the regulatory impacts analysis for
this Proposed Rule.
6
Matheson, Electric Co-ops: EPA’s Power Plant Proposal Would Further Jeopardize Reliability, May 11,
2023, https://www.electric.coop/electric-co-ops-epas-power-plant-proposal-would-further-jeopardizereliability (discussing Section 111 greenhouse gas regulations as the latest problematic EPA rule to
jeopardize reliability).
3
January 15, 2016
VIA ELECTRONIC MAIL TO: a-and-r-docket@epa.gov
Dr. Nick Hudson
Energy Strategies Group, Sector Policies &
Programs Division (D243-01)
U.S. Environmental Protection Agency
Research Triangle Park, NC 27711
Attention: Docket ID No. EPA–HQ–OAR–2009–0234
Re:
Comments of the National Mining Association on Supplemental Finding That It Is
Appropriate and Necessary To Regulate Hazardous Air Pollutants From Coaland Oil-Fired Electric Utility Steam Generating Units, 80 Fed. Reg. 75,025 (Dec.
1, 2015)
Dear Dr. Hudson:
The National Mining Association (NMA)1 submits these comments in response to
the proposed supplemental finding that it is appropriate and necessary to regulate
hazardous air pollutants (HAPs) from coal and oil-fired electric utility steam generating
units (EGUs), 80 Fed. Reg. 75,025 (Dec. 1, 2015). In addition to submitting these
comments NMA incorporates by reference the comments of the Utility Air Regulatory
Group of which NMA is a member.
NMA urges EPA to rescind and re-propose its “appropriate and necessary”
finding for electric generating units. EPA’s proposed finding is based on an arbitrarily
limited view of the information the agency should examine in assessing the costs and
benefits of regulation. EPA seems more interested in quickly reaffirming the flawed
appropriate and necessary finding it made when it issued the MATS rule rather than
conducting the type of searching analysis the Supreme Court called for in Michigan v.
EPA, 135 S. Ct. 2699 (2015), where the Court directed the agency to “consider costincluding, and most importantly, cost of compliance before deciding whether regulation
is appropriate and necessary.” (Emphasis added.) Despite this rebuke from the Court,
1
NMA’s membership includes the producers, transporters and consumers of coal. Our member
companies mines over 75 percent of the coal produced annually from operations located in 26 states.
Most of the coal produced by NMA members is used by coal-fired EGUs subject to this rulemaking.
National Mining Association 101 Constitution Avenue, NW | Suite 500 East | Washington, DC 20001 | (202) 463-2600
Jan. 15, 2016
Page Two
our analysis of the Supplemental Finding demonstrates that it, like the agency’s prior
determination, is wrong in reaching the conclusion that it is appropriate and necessary
to regulate HAP emissions from EGUs.2
1.
EPA has completely failed to consider the effect of its rule on coal.
Four years after MATS was issued, with the damage the rule caused in the coal
industry all but complete, EPA maintains its preposterous view reached in the MATS
Regulatory Impact Analysis (RIA) that the rule will have little effect on coal. EPA has no
new analysis to support this assertion as no such analysis can be constructed. It simply
proposes to limit its consideration of costs to the information it included in the RIA,
including the RIA forecast that the rule would result in the retirement of less than 5 GW
of coal capacity.3 By limiting its cost consideration in this fashion, the agency believes it
can erase the actual experience of the last four years and the hardship the agency has
wrought on our nation’s coal communities and ratepayers who were previously the
beneficiaries of affordable, reliable coal-based electricity.
As numerous commenters, including NMA, told EPA during the MATS
rulemaking, the rule would cause a wave of coal unit retirements. Unfortunately, events
have confirmed the accuracy of these forecasts and disproved EPA’s. Between 2012
when the rule went into effect and 2016 when the rule’s compliance period ends, almost
60 GW of coal capacity will have retired, including units that have already retired or, for
2016, have announced their retirement.
Coal-Fired Generating Unit Retirements by Year – Actual and Announced (MW)
Year
2012
2013
2014
2015
2016
Annual
12,601
8,220
5,568
20,728
12,065
Cumulative
12,601
20,821
26,389
47,116
59,181
Source: Energy Ventures Analysis
According to statements made by the utilities announcing the retirements,
virtually all of these closures are either fully or partially attributable to MATS and other
EPA regulations.4
2
To ensure a complete record here, NMA attaches and resubmits its MATS comments.
EPA Regulatory Impact Analysis for the Final Mercury and Air Toxics Standards, page 3-17.
4
See attached compilation from the American Coalition of Clean Coal Electricity.
3
National Mining Association 101 Constitution Avenue, NW | Suite 500 East | Washington, DC 20001 | (202) 463-2600
C O A L UN I T R E T I R E M EN T S 1
As of December 30, 2015
Since 2010, utilities have announced the retirement of a very large number
of coal-fired electric generating units. 2 In addition to these retirements,
some coal units are converting to natural gas, and a small number are
converting to biomass or another fuel. Most of these retirements and
conversions have been attributed to EPA policies, although other factors
may play a role too. 3
Table 1 lists 37 states with coal retirements and conversions that have been
attributed to EPA policies. These retirements and conversions total 410
units and represent nearly 67,000 megawatts (MW
MW) of electric generating
capacity. Approximately 12,000 MW (one-fifth of the total) are converting
to natural gas, biomass, or another fuel. By the end of 2016, 51,481 MW
will retire or convert due to EPA policies.
Table 2 lists all announced coal retirements and conversions, regardless of
cause, through 2030
30. (Table 2 includes the units in Table 1 plus additional
retirements and conversions that have not been attributed to EPA policies.)
Table 2 shows that 499
99 units totaling over 81
81,000 MW are slated
ed for
retirement or conversion. These units are located in 42 states and represent
26% of the U.S. coal fleet that existed in 2010. Approximately 14,0
,000 MW
(slightly less than one-fifth of the total) are converting to natural gas,
biomass, or another fuel.
By the end of 2015, approximately 50,000 MW will have retired or
converted. Between 2016 and 2019, an additional 22
22,000 MW are expected
4
to retire or convert.
1 This list of retirements and conversions is based primarily on public announcements by the owners of
the
coal units. We also use other information sources that are highly reliable. These retirements and conversions
are not based on modeling projections.
2 In 2010, according to EIA, the U.S. coal fleet was comprised of 1,396 electric generating units at 580 power
plants that represented a total electric generating capacity of more than 315,000 MW.
3
Review enforcement activities. Other factors contributing to the shutdowns in Table 1 include low natural
gas prices.
4 4,831 MW are slated to retire or convert after 2025.
1
TABLE 1. Coal Units Retiring or Converting Because of EPA Policies 5
STATE
1. Ohio
2. Pennsylvania
3. Alabama
4. Indiana
5. Kentucky
6. Georgia
7. Illinois
8. North Carolina
9. West Virginia
10. Virginia
11. Tennessee
12. Minnesota
13. South Carolina
14. Missouri
15. Arkansas
16. Florida
17. Iowa
18. Oklahoma
19. Massachusetts
20. Texas
21. New Mexico
22. Michigan
23. Maryland
24. Wisconsin
25. Colorado
26. Arizona
27. Mississippi
28. Nebraska
29. Oregon
30. Louisiana
31. New York
32. New Jersey
33. Utah
34. Montana
35. Kansas
36. Wyoming
37. South Dakota
MW CLOSING OR
CONVERTING
6,421
5,548
5,166
4,308
3,471
3,249
2,996
2,783
2,737
2,354
2,299
2,014
1,759
1,738
1,659
1,568
1,564
1,464
1,408
1,399
1,375
1,352
1,319
1,287
1,172
822
706
637
585
575
475
268
172
154
92
49
22
UNITS CLOSING OR
CONVERTING
40
30
26
25
16
15
13
20
18
16
15
13
14
17
2
7
28
3
6
3
5
16
7
16
11
4
2
5
1
1
3
2
2
1
2
4
1
66,967 MW
410 UNITS
5 Most of the coal units listed in the table are
retiring; 74 units representing 12,440 MW are converting to
natural gas, biomass, or another fuel.
2
TABLE 2. All Coal Units Retiring or Converting 6
STATE
1. Ohio
2. Pennsylvania
3. Alabama
4. Indiana
5. North Carolina
6. Illinois
7. Georgia
8. Kentucky
9. Virginia
10. West Virginia
11. Nevada
12. Tennessee
13. Minnesota
14. Utah
15. Iowa
16. South Carolina
17. Missouri
18. Arkansas
19. New York
20. Florida
21. Wisconsin
22. Massachusetts
23. Oklahoma
24. Michigan
25. Texas
26. Washington
27. New Mexico
28. Maryland
29. Colorado
30. Arizona
31. Nebraska
32. Mississippi
33. Oregon
34. Louisiana
35. Delaware
36. New Jersey
37. Connecticut
38. Montana
39. California
40. Kansas
41. Wyoming
42. South Dakota
MW CLOSING OR
CONVERTING
7,751
5,737
5,166
4,748
4,288
4,261
3,752
3,471
2,836
2,737
2,689
2,299
2,152
2,072
1,832
1,759
1,755
1,659
1,588
1,568
1,525
1,517
1,464
1,433
1,399
1,376
1,375
1,319
1,172
822
757
706
585
575
360
291
181
154
129
92
49
22
UNITS CLOSING OR
CONVERTING
43
33
26
30
33
18
17
16
21
18
8
15
15
7
32
14
18
2
13
7
23
7
3
19
3
2
5
7
11
4
6
2
1
1
4
3
1
1
3
2
4
1
81,423 MW
499 UNITS
6 Most of the coal units in the table are retiring; 93 units representing 13,890 MW are converting to natural
gas, biomass, or another fuel.
3
The National Rural Electric
Cooperative Association
Comments on
Proposed National Emission Standards for Hazardous Air Pollution: Coal-and OilFired Electric Utility Steam Generating Units Review of the Residual Risk and
Technology Review
Submitted Electronically to:
The Environmental Protection Agency
Air Docket
Attention Docket ID NO. EPA-HQ-OAR-2018-0794
June 23, 2023
by
Rae E. Cronmiller
Environmental Counsel
4301 Wilson Boulevard, EU 11-249
Arlington, VA. 22203-1860
(703) 907-5791 / rae.cronmiller@nreca.coop
NRECA Comments on Proposed EGU RTR
correlation requirements are next to impossible to achieve for the proposed fPM limit of
0.010lbs./MMBtu and even more unworkable with the alternative 0.006 lbs./MMBtu proposal.
The EPA cites earlier rulemakings and research projects that in fact reasonably lead to the
opposite of EPA’ s conclusion of CEMS viability to accurately measure fPM at 0.010
lbs./MMBtu. EPA maintains that the 2012 Portland Cement rulemaking bolsters EPA’s
contention that CEMS can operate with required accuracy and precision within the proposed
fPM range EPA proposes. Roberson, however, points out that in the final Portland Cement rule
EPA decided not to require CEMS because of correlation issues. EPA next claims the CEMS
requirement for new EGUs validates the proposed requirement here. But again, as Roberson
point out since there are no new EGUs, there is no actual required use to validate the CEMS
workability for the fPM levels at issue here. Lastly, EPA references an Electric Power Research
Institute (EPRI) project whose objective was to perfect a CEMS that would directly measure PM.
EPA cites the EPRI effort to somehow show this technology was developed and would allow
accurate measurement of fPM at the level proposed here. Roberson, who participated in this
earlier effort, recounts that the research effort was terminated without success at least partially
because EPA showed no interest in furthering the effort to perfect CEMS.
EPA has failed to consider the electric reliability impacts of this rulemaking
As detailed in the Cichanowicz Report, EPA IPM model base case for this proposal prematurely
retired 59 coal-fired units. Many of these units have not, as of the time of this rulemaking,
indicated retirement dates near the date when this proposal may become final. Thus, if EPA
prediction is wrong, they would be affected by the date this proposal would become final.6 EPA
modeling principally relies on the Inflation Reduction Act associated financial incentives along
with the implementation of the 2015 Ozone Transport Federal Implementation Plan (FIP) as the
main drivers forcing the retirements of most of the 59 units. EPA’ s specific modeling
assumptions leading to these units prematurely retiring do not appear anywhere in the docket and
yet EPA’s Regulatory Impact Analysis (RIA) for this proposal incorporates these assumptions to
6 Cichanowicz Report at pages 40-43. Table 8-1 listing units retiring in 2030 should read 27 not 23
making the total in Table 8-1 59 units. Tables 8-2 and 8-3 are correct in listing EPA IPM retired units.
5
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.