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

USCA Case #24-1119 | Document #2058570 Filed: 06/07/2024 Page 45 of 96

scenario and $3.8 billion in the Full scenario through 2035, compared to operating the current

lignite facilities under status quo conditions.

MISO residents would also suffer economic damages from the increased severity of rolling

blackouts, which can result in food spoilage, property damage, lost labor productivity, and loss of

life. American Experiment calculated the economic damages associated with the increase in

unserved electricity demand using a metric called the Value of Lost Load (VoLL) criteria, which

can be thought of as the Social Cost of Blackouts.

Our analysis found that the MATS rule would cause an additional 73,699 additional megawatt

hours (MWh) of unserved load in the in the Full MATS Retirement scenario in 2035 using 2019

hourly electricity demand and wind and solar capacity factors. Using a conservative value for the

VoLL of $14,250 per MWh, we conclude the MATS rule would produce economic damages of

$1.05 billion under these conditions.

Therefore, the incremental costs stemming from the closure of the 2,264 MW of lignite fired

capacity in MISO under the Full scenario exceeds the projected net present value benefits of $3

billion from 2028 through 2037 using a 3 percent discount rate modeled by EPA in its Regulatory

Impact Analysis.

Modeling the Reliability and Cost of the MISO Generating Fleet Under

Three Scenarios

Our analysis examined the impact of the proposed MATS rules on the reliability of the MISO

system through 2035 by comparing two lignite retirement scenarios to a “Status Quo” scenario

that represents “business as usual” that assumes no changes to the generating fleet occur due to the

MATS rule, or any other of EPA’s pending regulations.~°

Status Quo scenario: Installed generator capacity assumptions for MISO in the Status Quo

scenario are based on announced retirements from U.S. Energy Information Administration (EIA)

database and utility Integrated Resource Plans (IRPs) through 2035 compiled by Energy Ventures

Analysis on behalf America’s Power, a trade association whose sole mission is to advocate at the

federal and state levels on behalf of the U.S. coal fleet.°’ This database is also used by the NERC

LTRA suggesting it is among the most credible databases available for this analysis.°° It should be

noted that this database leaves considerably more coal and natural gas on its system than the MISO

grid EPA assumes will be in service in the coming years in its Proposed Rule Supply Resource

56 See Appendix 2: Capacity Retirements and Additions in Each Scenario.

57 America’s Power, “Proprietary data base maintained by Energy Ventures Analysis, an energy

consultancy with expertise in electric power, natural gas, oil, coal, renewable energy, and

environmental policies” Personal Communication, November 3, 2023.

58 North American Electric Reliability Corporation, “2023 Long-Term Reliability Assessment,” December, 2023,

https://www.nerc.com/pa/RAPA/ra/Reliability%20Assessments%20DL/NERC_LTRA_ 2023.pdf.

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Utilization file, meaning our reliability assessment will be more conservative than if we used EPA’s

capacity projections.

Retired thermal resources in the Status Quo scenario are replaced by solar, wind, battery storage,

and natural gas in accordance with the current MISO interconnection queue to maintain resource

adequacy based on capacity values given to these generators in EPA’s Proposed Rule Supply

Resource Utilization file.°? These capacity values are described in greater detail in the section

labeled Replacement Capacity Based on EPA Methodology for Resource Adequacy.

Partial MATS Retirement scenario: The Partial MATS retirement scenario assumes 1,150

megawatts (MW) of lignite fired capacity in North Dakota is retired in addition to incorporating

all of the announced retirements in the Status Quo. This value was chosen because it represents

the retirement of one lignite facility in North Dakota that serves the MISO market. These resources

are replaced with wind, solar, battery storage, and natural gas capacity using the methodology

described greater detail in the section labeled Replacement Capacity Based on EPA Methodology

for Resource Adequacy.”

Full MATS scenario: The Full MATS retirement scenario assumes the MATS regulations will

cause all 2,264 MW of lignite-fired generators in the MISO system to retire, in addition to

incorporating the retirements in the Status Quo scenario will occur.°! These resources are replaced

with wind, solar, battery storage, and natural gas capacity using the methodology described greater

detail in the section labeled Replacement Capacity Based on EPA Methodology for Resource

Adequacy.

Reliability in each scenario

The EPA did not conduct a reliability analysis for its proposed MATS rules or its Post IRA base

case. Instead, it conducted a Resource Adequacy analysis of its proposed rule, compared to the

Post IRA base case.

Resource Adequacy and reserve margin analyses can be useful tools for determining resource

adequacy and reliability, but the shift away from dispatchable thermal resources (fossil fuel)

toward intermittent resources (wind and solar) increases the complexity and uncertainty in these

analyses and makes them increasingly dependent on the quality of the assumptions used to

construct capacity accreditations. ©

°° U.S. Environmental Protect Agency, “Proposed Regulatory Option,” Zip File,

https://www.epa.gov/system/files/other-files/2023-04/Proposed%20Regulatory%20Option.zip

6° See Appendix 3: Replacement Capacity Based on EPA Methodology for Resource Adequacy.

6! These figures represent the rated summer capacity as indicated by the U.S. Energy Information Administration.

62 See Appendix 3: Replacement Capacity Based on EPA Methodology for Resource Adequacy.

3 See Appendix 4: Resource Adequacy in Each Scenario.

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This is likely a key reason why EPA has distinguished between resource adequacy and resource

reliability in its Resource Adequacy Technical Support Document for its proposed carbon

dioxide regulations on new and existing power plants.°® EPA stated:

“As used here, the term resource adequacy is defined as the provision of adequate

generating resources to meet projected load and generating reserve requirements in each

power region, while reliability includes the ability to deliver the resources to the loads,

such that the overall power grid remains stable.” [emphasis added].” EPA goes on to say

that “resource adequacy ... is necessary (but not sufficient) for grid reliability.©

As the grid becomes more reliant upon non-dispatchable generators with lower reliability values,

it is crucial to “stress test” the reliability outcomes of systems that use the EPA’s capacity value

assumptions in their Resource Adequacy analyses by comparing historic hourly electricity demand

and wind and solar capacity factors against installed capacity assumptions in the Status Quo,

Partial, and Full scenarios.

We conducted such an analysis by comparing EPA’s modeled MISO generation portfolio to the

historic hourly electricity demand and hourly capacity factors for wind and solar in 2019, 2020,

2021, and 2022. These data were obtained from the U.S. Energy Information Administration (EIA)

Hourly Grid Monitor to assess whether the installed resources would be able to serve load for all

hours in each Historic Comparison Year (HCY).°’

For our analysis, hourly demand and wind and solar capacity factors were adjusted upward to

meet EPA’s peak load, annual generation, and capacity factor assumptions. These assumptions

are generous to the EPA because they increase the annual output of wind and solar generators to

levels that are not generally observed in MISO.

Extent of the Capacity Shortfalls

While our modeling determined that the retirement of lignite facilities had a minimal impact on

the number of hours of capacity shortfalls observed in the Partial and Full scenarios, retiring the

lignite facilities makes the extent of capacity shortfalls worse.

64 EPA did not produce a Resource Adequacy Technical Support Document for the MATS rules.

65 U.S. Environmental Protection Agency, “National Emission Standards for Hazardous Air Pollutants: Coal- and Oil-

Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review,” 88 FR 24854,

April 24, 2023, https://www.federalregister.gov/documents/2023/04/24/2023-07383/national-emission-standards-forhazardous-air-pollutants-coal--and-oil-fired-electric-utility-steam.

6 Resource Adequacy Analysis Technical Support Document, New Source Performance Standards for Greenhouse

Gas Emissions from New, Modified, and Reconstructed Fossil Fuel-Fired Electric Generating Units; Emission

Guidelines for Greenhouse Gas Emissions from Existing Fossil Fuel-Fired Electric Generating Units; and Repeal of

the Affordable Clean Energy Rule Proposal Docket ID No. EPA-HQ-OAR-2023-0072 U.S. Environmental Protection

Agency Office of Air and Radiation April 2023.

67 USS. Energy Information Administration, “Hourly Grid Monitor,”

https://www.eia.gov/electricity/gridmonitor/dashboard/electric_overview/US48/US48.

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For example, Figure D-1 shows largest capacity shortfalls in the Status Quo scenario, which occur

in 2035 using the 2021 Historical Comparison Year for hourly electricity demand and wind and

solar capacity factors.

Each resource’s hourly performance is charted in the graph below. Thermal units are assumed to

be 100 percent available, which is consistent with EPA’s capacity accreditation for these resources,

and wind and solar are dispatched as available based on 2021 fluctuations in generation. Blue

sections reflect the use of “Load Modifying Resources,” which are reductions in electricity

consumption by participants in the MISO market.

Purple areas show time periods where the batteries are discharged. These batteries are recharged

on January 8" and 9 using the available natural gas and oil-fired generators. Red areas represent

periods where all of the resources on the grid are unable to serve load due to low wind and solar

output and drained battery storage systems. At its peak, the largest capacity shortfall is 15,731

MW.

Status Quo Scenario Capacity Shortfalls in 2035 Using 2021

Demand and Wind and Solar Capacity Factors

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me Coal m= Other mas Hydroelectric ==s' Nuclear

maa Biomass Wind mas Solar ma Gas CC

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Figure D-1. This figure shows the generation of resources on the MISO grid in the Status Quo

during a theoretical week in 2035. The purple portions of the graph show the battery storage

discharging to provide electricity during periods of low wind and solar generation. Unfortunately,

the battery storage does not last long enough to avoid blackouts during a wind drought.

These capacity shortfalls become more pronounced in the Partial and Full scenarios as less

dispatchable capacity exists on the grid to serve load. Figure D-2 shows the three capacity shortfall

events in Figure D-1. It depicts the blackouts observed in the Status Quo scenario in green, and

35

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the additional MW of unserved load in the Partial and Full scenarios in yellow and red,

respectively.

Capacity Shortfalls In 2035 by Scenario Using 2021 Demand and Hourly Wind

and Solar Capacity Factors

17,229 MW

16,493 MW

15,731 MW

a

2% Hm Hm Hm HHO H%HH%HMHZ

C626, €, 6, CEC, C6. CE, 8, 10%.

22.

7

a

—

AMERICAN

=FMR =PMR Reference ANENIEUN

Figure D-2. Capacity shortfalls increase during a hypothetical January 9", 2035 from 15,731 MW

at their peak in the Status Quo to 16,493 MW in the Partial scenario and 17,229 MW in the Full

scenario.

Table D-1 shows the largest capacity shortfall, in terms of MW, for each scenario in each of the

four Historical Comparison Years studied and the incremental increase in the largest shortfall due

to the lignite closures stemming from the MATS rule for the Partial and Full scenarios.

The largest incremental increase in capacity shortfalls would occur in the 2020 HCY in the Full

scenario as the blackouts would increase from 552 MW in the Status Quo scenario to 3,295 in the

Full scenario, a difference of 2,743 MW.

Data Year] Status Quo| Partial | Partial Difference | Full | Full Difference

2019 15,130 15,842 712 16,530 1,400

2020 552 2,587 2,034 3,295 2,743

2021 15,/31 16,493 762 17,229 1,498

2022 10,615 11,409 794 12,177 1,562

Table D-1. This table shows the largest capacity shortfall, in terms of MW, for each scenario in

each of the four Historical Comparison Years studied and the incremental increase in the largest

shortfalls due to the lignite closures stemming from the MATS rule for the Partial and Full

scenarios.

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It is important to note that this difference is larger than the amount of lignite-fired capacity that is

retired in the Full scenario (2,264 MW) because the retirement of these facilities reduces the

amount of capacity available to charge battery storage resources.

Unserved MWh in Each Scenario

The amount of unserved load in each scenario can also be measured in megawatt hours (MWh).

This metric is a product of the number of hours with insufficient energy resources multiplied by

the hourly energy shortfall, measured in MW. This metric may be a more tangible way to

understand the impact that the unserved load will have on families, businesses, and the broader

economy. Each MWh reflects an increment of time where electric consumers in the MISO grid

will not have access to power.

Table D-2 shows the number of MWhs of unserved load in each scenario for the four HCYs

studied. In some HCYs, the incremental number of unserved MWhs is fairly small, but in other

years they are substantial. In the 2020 HCY, the Partial scenario had 2,042 more MWhs of unserved

load than the Status Quo scenario, and the Full scenario had 4,265 MWh of additional unserved

load, compared to the Status Quo Scenario.

Data Year| Status Quo| Partial | Partial Difference Full Full Difference

2019 168,723 | 204,050 So2r 242,393 73,669

2020 582 2,624 2,042 4,847 4,265

2021 244,743 | 273,927 29,184 304,021 59,278

2022 53,458 62,223 8,765 71,304 17,846

Table D-2. The incremental MWh of unserved load ranges from 2,042 to 35,327 in the Partial

scenario, and from 4,265 to 73,669 in the Full scenario.

In the 2019 HCY, the Partial scenario experienced an additional 35,327 MWh of unserved load

and the Full scenario experienced 73,669 MWh of unserved load. These additional MWh of

unserved load will impose hardships on families, businesses, and the broader economy.

The Social Cost of Blackouts Using the Value of Lost Load (VoLL)

Blackouts are costly. They frequently result in food spoilage, lost economic activity, and they can

also be deadly. Regional grid planners attempt to quantify the cost of blackouts with a metric called

the Value of Lost Load (VoLL). The VoLL is a monetary indicator expressing the costs associated

with an interruption of electricity supply, expressed in dollars per megawatt hour (MWh) of

unserved electricity.

MISO currently assigns a Value of Lost Load (VOLL) of $3,500 per megawatt hour of unserved

load. However, Potomac Economics, the Independent Market Monitor for MISO, recommended

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a value of $25,000 per MWh for the region. °* For this study, we used a midpoint value of

$14,250 per MWh of unserved load to calculate the social cost of the blackouts under each

modeled scenario.

Table D-3 shows the economic damage of blackouts in each scenario in model year 2035 and

shows the incremental increase in the VOLL in the Partial and Full scenarios. Incremental VOLL

costs are highest using the 2019 HCY where MISO experiences an additional $503.4 million in

economic damages due to blackouts in the Partial scenario, and an additional $1.05 billion in the

Full scenario.

Data Year Status Quo Partial Partial Difference Full Full Difference

2019 $2,404,309,657| $2,907,716,665| $503,407,008 | $3,454,098,6921$1,049,789,035

2020 $8,296,505 $37,389,117 $29,092,612 $69,074,216 $60,777,712

2021 $3,487,594,170| $3,903,464,847| $415,870,677 |$4,332,301,464| $844,707,294

2022 $761,782,023 | $886,680,023 $124,898,001 |$1,016,083,680] $254,301,657

Table D-3. MISO would experience millions of dollars in additional economic damage if the

lignite fired power plants in its footprint are shut down in response to the MATS regulations.

It is important to note that these VOLL figures are not the total estimated cost impacts of blackouts

for the MATS regulations. Rather, they are a snapshot of a range of possible outcomes for the year

2035 based on variations in electricity demand and wind and solar productivity.

The VOLL demonstrates harm of the economy in a multitude of ways. For the

industrial/commercial sector, direct costs from losing power (and therefore benefits from avoiding

power outages) can be (1) opportunity cost of idle resources, (2) production shortfalls / delays, (3)

damage to equipment and capital, and (4) any health or safety impacts to employees. There are

also indirect or macroeconomic costs to downstream businesses/consumers who might depend on

the products from a company who experiences a power outage. °”

For the residential sector, the direct costs are different. They can include (1) restrictions on

activities (e.g. lost leisure time, lost work time, and associated stress), (2) financial costs through

property damage (e.g. damage to real estate via bursting pipes, food spoilage), and (3) health and

safety issues (e.g. reliance on breathing machines, air filters). ”°

68 David B. Patton, “Summary of the 2022 MISO State of the Market Report,” Potomac Economics, July 13, 2023,

https://cdn.misoenergy.org/20230713%20MSC%20Item%2006%20IMM%20State%200f%20the%20Market%20Re

commendations629500.pdf.

6 Will Gorman, “The Quest to Quantify the Value of Lost Load: A Critical Review of the Economics of Power

Outages,” The Electricity Journal Volume 35, Issue 8, October 2022,

https://www.sciencedirect.com/science/article/pii/S 10406 19022001130.

7 Will Gorman, “The Quest to Quantify the Value of Lost Load: A Critical Review of the Economics of Power

Outages,” The Electricity Journal Volume 35, Issue 8, October 2022,

https://www.sciencedirect.com/science/article/pii/S 1040619022001130.

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Hours of Capacity Shortfalls

Comparing hourly historic electricity demand and wind and solar output to MISO grid in the Status

Quo scenario, our modeling found that MISO would have capacity shortfalls in the 2019, 2021,

and 2022 HCYs which can be seen in Table D-4 below.

There would be additional capacity shortfalls in all of the HCYs modeled in the Partial and Full

scenarios, where the Partial scenario would experience four additional hours of blackouts in 2019

HCY, one additional hour of blackouts in the 2020 HCY, four additional hours of blackouts in 2021

HCY, and one additional hour of blackouts in the 2022 HCY. In the Full scenario, there would be

five additional hours of blackouts in the 2019 HCY, one additional hour of blackouts in the 2020

HCY, eight additional hours in the 2021 HCY, and two additional hours in the 2022 HCY,

compared to the Status Quo Scenario.

Data Year| Status Quo] Partial | Partial Difference Full Full Difference

2019 28 32 4 33 5

2020 2 3 1 3 1

2021 24 28 4 32 8

2022 13 14 1 15 2

Table D-4. Capacity shortfalls occur in three of the four HCYs in the Status Quo scenario and all

four HCYs for the Partial and Full scenarios.

Cost of replacement generation

Our VOLL analysis demonstrates that the MATS rules will cause significant economic harm in

MISO by reducing the amount of dispatchable capacity on the grid due to lignite plant closures

stemming from the removal of the lignite subcategory.

However, load serving entities (LSEs) will also begin to incur costs as they build replacement

generation to maintain resource adequacy if lignite resources are forced to retire in response to the

proposed MATS rules. These costs will be passed on to electricity consumers and must be

calculated to produce accurate estimates of the true cost of the MATS regulations.

We modeled the cost of the replacement generation under the Status Quoe, Partial and Full

scenarios. The cost of the Partial and Full scenarios, when compared to the Status Quo scenario,

is used to determine the additional economic burden that the MATS regulations will impose onto

MISO electricity customers.

Our modeling determined the total cost of replacement generation capacity in the Status Quo,

Partial, and Full scenarios will cost $12.93 billion, $14.88 billion, and $16.76 billion, respectively,

from 2024 through 2035 (see Figure D-3).

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Total Additional Expenses from 2024 to 2035

iS)

Y*

S os aS

& 5

Total Expenses

Figure D-3. The Partial scenario will cost $1.95 billion more than the Status Quo scenario from

2024 through 2035 and the Full scenario will cost $3.8 billion more than the Status Quo scenario

in this timeframe.

Figure D-4 shows the incremental cost of the Partial and Full scenarios from 2024 through 2030,

the period reflecting the up-front costs of complying with the regulations. From 2024 through

2028, LSEs would incur $337 million by building replacement generation in the Partial scenario,

compared to the Status Quo scenario, and $654 million in the Full scenario, relative to the Status

Quo. It should be noted that these costs are only the cost of building replacement generation and

do not factor in the cost of decommissioning or remediating existing power plants or mine sites.

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Annual Incremental Expenses Resulting from

MATS Compliance Compared to Status Quo

$496 M

$.500 B $479 M

$337-$654 million of additional expenses from 2024 to 2028

resulting from MATS compliance efforts

® $.400 B

nw

c

o

x $304 M

w $.300 B

3 $251 $243

=

S 200 B

S *- $155M $155

= $117 M

$56 M $81

$.100 B $22 M $64

Si ol Oi

$0008 == a =

2024 2025 2026 2027 2028 2029 2030

= Partial MATS Retirement = Full MATS Retirement

Figure D-4. This figure shows the annual cost of building the replacement capacity needed to

maintain resource adequacy after the retirement of the lignite plants based on EPA's capacity

accreditation values for wind, solar, storage, and thermal resources.

We describe the total costs of replacement generation capacity for each scenario in greater detail

below. The assumptions used to calculate the cost of replacement generation can be found in

Appendix 1: Modeling Assumptions.

Status Quo scenario:

The Status Quo scenario results in the retirement of 28,756.8 MW of coal resources, 7,852 MW of

natural gas capacity, and 462 MW of petroleum capacity. These retirements are already projected

to occur without imposition of the new MATS Rule or other federal regulations. This retired

capacity is replaced with 4,306 MW of natural gas, 19,436 MW of wind, 29,652 MW of solar, and

3,304 MW of storage. 7!

The total cost of replacement generation for the Status Quo scenario is $12.9 billion. The majority

of these expenses consist of additional fixed costs of building new wind, solar, and battery storage

facilities, such as fixed operational and maintenance (O&M), capital costs, and utility returns.

Compared to the current grid, the Status Quo scenario saves $32 billion in fuel costs, $11.5 billion

in variable operations and maintenance costs, and $5 billion in taxes. However, these savings are

71 See Appendix 2: Capacity Retirements and Additions in Each Scenario.

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far outweighed by $5.1 billion in additional fixed costs, $16 billion in capital costs, $2.1 billion in

transmission costs, and $38.2 billion in utility profits (see Figure D-5).

Total Additional Costs of Status Quo Scenario

from 2024 through 2035

$80.0 B

$60.0 B

n $40.0B = Total Costs

= Utility Profits

&- $20.0B m Taxes

ui

a $2.1B $12.9B aulasinauane

5 $0.0B = Variable O&M

= Fixed O&M

zo)

< $(20.0 B) = Capital Costs

= Transmission

$(40.0 B) $(5.0 B)

$(60.0 B)

Through 2035 Total

Figure D-5, The Status Quo scenario saves consumers money from lower fuel costs, fewer

variable operations and maintenance costs, and lower taxes (due to federal subsidies) but these

savings are outweighed by the additional costs. As a result, building the grid in the Status Quo

scenario would increase costs by $12.93 billion compared to today’s costs.

These additional costs will have an impact on electricity rates. Our cost modeling determined that

electricity costs for MISO ratepayers would be 9.89 cents per kWh in the Status Quo scenario, an

increase of nearly 3.5 percent relative to current costs of 9.56 cents per kWh. ”

Partial MATS Retirement scenario:

The Partial scenario results in the closure of 1,151 MW of lignite capacity and necessitates an

incremental increase in replacement capacity of 1,015 MW wind, 1,549 MW solar, and 173 MW

storage, compared to the Status Quo scenario.”

The total cost of replacement generation for the Partial scenario is $14.9 billion, and the total

incremental cost is $1.9 billion compared to the Status Quo scenario. The majority of these

72 Annual Electric Power Industry Report, Form EIA-861 detailed data files,

https://www.eia.gov/electricity/data/eia861/.

® See Appendix 2: Capacity Retirements and Additions in Each Scenario.

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expenses consist of additional fixed costs of building new wind, solar, and battery storage facilities,

such as fixed operational and maintenance (O&M), capital costs, and utility returns.

Compared to the current grid, the Partial scenario saves $32.7 billion in fuel costs, $11.6 billion in

variable operations and maintenance costs, and $5.1 billion in taxes. However, these savings are

far outweighed by $5.3 billion in additional fixed costs, $17.1 billion in capital costs, $2.2 billion

in transmission costs, and $39.7 billion in utility profits (see Figure D-6).

Total Additional Costs of Partial Scenario from

2024 through 2035

$80.0 B

$60.0 B

Ph $40.0B = Total Costs

a = Utility Profits

S $20.0B = Taxes

= $2.2B = Fuel Costs

= $0.0B = Variable O&M

= Fixed O&M

a ($20.0 B) = Capital Costs

= Transmission

($40.0 B) ($5.1 B)

($60.0 B)

Through 2035 Total

Figure D-6. The Partial scenario results in an $14.88 billion in additional costs compared to the

current grid due to additional capital costs, fixed operations and maintenance costs, additional

transmission costs, and additional utility profits.

Compared to the Status Quo scenario, the incremental savings are $664 million in fuel costs,

$119.7 million in variable operations and maintenance costs, and $102.2 million in taxes, which

are outweighed by $178.7 million in additional fixed costs, $1.1 billion in capital costs, $116.5

million in transmission costs, and $1.4 billion in utility profits (see Figure D-7).

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Total Incremental Savings and Expenses of Partail

Scenario Compared to Status Quo from 2024

$6.00 B

$5.00 B

$4.00 B

$3.00 B

$2.00 B

$1.00 B

$0.00 B

Incremental Expenses

($1.00 B)

($2.00 B)

($3.00 B)

through 2035

$0.12 B

\ ($0.12 B)

=-— ($0.10 B)

Through 2035

Total

# Total Costs

= Utility Profits

= Taxes

= Fuel Costs

= Variable O&M

=u Fixed O&M

= Capital Costs

= Transmission

Figure D-7. The Partial scenario will cost MISO ratepayers an additional $1.9 billion from 2024

through 2035.

These incremental costs mean Load Serving Entities will incur an additional $1.9 billion because

of these rules. These costs will start incurring before the compliance deadline is finalized in 2028,

totaling $337 million of additional expenses compared to the Status Quo scenario (see Figure D-

8).

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Annual Incremental Expenses Resulting from Partial Scenario

MATS Compliance Compared to Status Quo

$500 M

$450 M

m $400 M $337 million of additional expenses from 2024 to 2028

) resulting from MATS compliance efforts

% $350 M

rm)

&- $300 M $054 M

Lu

= $250 M $243 M

=

® $200 M

‘. $155 M

S $150 M

~ 81M

$100 M $61 M S

$50M gay = 820M E i

1+ _——__

2024 2025 2026 2027 2028 2029 2030

= Partial MATS Retirement

Figure D-8. This figure shows the annual incremental cost incurred by LSEs as a result of the

lignite closures in the Partial scenario.

These additional costs will have an impact on electricity rates. Our cost modeling determined that

electricity costs for MISO ratepayers would be 9.95 cents per kWh in the Partial scenario, an

increase of nearly 3.9 percent relative to current costs of 9.58.

Full MATS scenario:

Under the Full scenario, 2,264 MW of lignite capacity would be forced to retire resulting results

in an incremental increase in replacement capacity of 1,997 MW wind, 3,048 MW solar, and 304

MW storage compared to the Status Quo scenario.

The total cost of replacement generation for the Full scenario is $16.8 billion, and the total

incremental cost is $3.8 billion compared to Status Quo scenario. The majority of these expenses

consist of additional fixed costs of building new wind, solar, and battery storage facilities, such as

fixed operational and maintenance (O&M), capital costs, and utility returns.

Compared to the current grid, the Full scenario saves $33.3 billion in fuel costs, $11.7 billion in

variable operations and maintenance costs, and $5.2 billion in taxes. However, these savings are

far outweighed by $5.4 billion in additional fixed costs, $18.1 billion in capital costs, $2.4 billion

in transmission costs, and $41.1 billion in utility profits (see Figure D-9).

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Total Additional Costs of Full Scenario from 2024

through 2035

$80.0 B

$60.0B

~ $40.0B = Total Costs

wn & Utility Profits

S $20.0 B = Taxes

si ~$2.4B = Fuel Costs

S $0.0 B = Variable O&M

= = Fixed O&M

< ($20.0 B) = Capital Costs

# Transmission

($40.0 B)

— ($5.2 B)

($60.0 B)

Through 2035 Total

Figure D-9. The Full scenario results in an increase of $16.76 billion in costs compared to the

current grid.

Compared to the Status Quo scenario, the incremental savings are $1.3 million in fuel costs, $235.1

million in variable operations and maintenance costs, and $202 million in taxes, which are

outweighed by $350.8 million in additional fixed costs, $2.1 billion in capital costs, $229.1 million

in transmission costs, and $2.8 billion in utility profits (see Figure D-10).

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Total Incremental Savings and Expenses of Full

Scenario Compared to Status Quo from 2024

through 2035

$6.00 B

$5.00 B

$4.00 B

i” = Total Costs

2 $3.00 B = Utility Profits

Se $2.00 B m Taxes

= = Fuel Costs

$1.00 B $0238 = Variable O&M

/ = Fixed O&M

5 $0.00B xe

= ™ ($0.24 B) = Capital Costs

($1.00 B) = Transmission

_— ($0.20 B)

($2.00 B)

($3.00 B)

Through 2035 Total

Figure D-10. This figure itemizes the expenses incurred in the Full scenario, which will cost an

additional $3.8 billion compared to the Status Quo scenario.

These incremental costs mean Load Serving Entities will incur an additional $3.8 billion in the

Full scenario because of these rules. These costs will start incurring before the compliance deadline

is finalized in 2028, totaling $654 million of additional expenses compared to the Status Quo

scenario (see Figure D-11).

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Annual Incremental Expenses Resulting from Partial Scenario

MATS Compliance Compared to Status Quo

$496 M

$479 M

$500 M $654 million of additional expenses from 2024 to 2028

resulting from MATS compliance efforts

77)

4 $400 M

o

x $304 M

li $300 M

g

=

© 200 M

wv $ $155 M

f= $117 M

$100 M $56 M

$22 M oH

$M |

2024 2025 2026 2027 2028 2029 2030

= Full MATS Retirement

Figure D-11, LSEs would incur an additional $654 million in additional expenses, compared to

the Status Quo scenario, as a result of the proposed MATS rules.

These additional costs will have an impact on electricity rates. Our cost modeling determined that

electricity costs for MISO ratepayers would be 9.97 cents per kWh in the Full scenario, an increase

of nearly 4.1 percent relative to current costs of 9.58.

Conclusion:

By effectively eliminating the subcategory for lignite power plants and ignoring the breadth of

evidence demonstrating that these regulations are not reasonably attainable, the MATS rules will

increase the severity of capacity shortfalls in the MISO region, resulting in economic damages

from the ensuing blackouts ranging from $29 million to $1.05 billion, depending on the HCY used,

and imposing $1.9 billion to $3.8 billion in the cost of replacement generation capacity in the

Partial and Full scenarios, respectively.

Therefore, the costs stemming from the closure of the 2,264 MW of lignite fired capacity in MISO

exceeds the projected net present value benefits of $3 billion from 2028 through 2037 using a 3

percent discount rate modeled by EPA in its Regulatory Impact Analysis. “4

” Regulatory Impact Analysis for the Proposed National Emission Standards for Hazardous Air Pollutants: Coaland Oil-Fired Electric Utility Steam Generating Units Review of the Residual Risk and Technology Review (Apr.

2023), Docket ID: EPA-HQ-OAR-2018-0794-5837.

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Appendix 1: Modeling Assumptions

Electricity Consumption Assumptions

Annual electricity consumption in each model year is increased in accordance with EPA’s

assumptions in the IPM in each of the MISO subregions.

Peak Demand and Reserve Margin Assumptions

The modeled peak demand and reserve margin in each of the model years are increased in

accordance with the IPM in each of the MISO subregions.

Time Horizon Studied

This analysis studies the impact of the proposed MATS rules from 2024 through 2035 to accurately

account for the costs LSEs would incur by building replacement generation in response to the

potential shutdown of lignite capacity.

This timeline downwardly biases the cost of compliance with the regulations because power plants

are long term investments, often paid off over a 30-year time period. This means the changes to

the resource portfolio in MISO resulting from these rules will affect electricity rates for decades

beyond 2035.

Hourly Load, Capacity Factors, and Peak Demand Assumptions

Hourly load shapes and wind and solar generation were determined using data for the entire MISO

region obtained from EIA’s Hourly Grid Monitor. Load shapes were obtained for 2019, 2020, 2021,

and 2022. ”° These inputs were entered into the model to assess hourly load shapes and assess

possible capacity shortfalls in 2035 using each of the historical years.

Capacity factors used for wind and solar facilities were adjusted upward to match EPA assumptions

that new wind and solar facilities will have capacity factors as high as 42.2 percent and 24.7

percent, respectively. These are generous assumptions because the current MISO-wide capacity

factor of existing wind turbines is only 36 percent, and solar is 20 percent.

Our analysis upwardly adjusted observed capacity factors to EPA’s estimates despite the fact that

EPA’s assumptions for onshore wind are significantly higher than observed capacity factors

reported from Lawrence Berkeley National Labs, which demonstrates that new wind turbines

entering operation since 2015 have never achieved annual capacity factors of 42.2 percent (See

Figure D-12).”°

% Energy Information Administration, “Hourly Electric Grid Monitor,’ Accessed August 12, 2022,

https://www.eia.gov/ electricity/gridmonitor/dashboard/electric_overview/balancing authority/MISO

7 Lawrence Berkely National Labs, “Wind Power Performance,” Land Based Wind Report, Accessed July 27, 2023,

https://emp.lbl.gov/wind-power-performance.

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2021 Capacity Factor (National Avg. by Online Date)

M3

2021 avg. NCF

—

Figure D-12. This figure shows capacity factors for U.S. onshore wind turbines by the year they

entered service. In no year do these turbines reach EPA's assumed 42.2 percent capacity factor on

an annual basis.

Another generous assumption is that we did not hold natural gas plants accountable to other EPA

rules, such as the Carbon Rule, that may be in effect in addition to the MATS rule and would cap

natural gas generators at 49 percent capacity factors to avoid using carbon capture and

sequestration or co-firing with hydrogen. Doing so would have resulted in even more capacity

shortfalls.

Line Losses

Line losses are assumed to be 5 percent of the electricity transmitted and distributed in the United

States based on U.S. on EIA data from 2017 through 2021.7”

Value of Lost Load

The value of lost load (VoLL) is a monetary indicator expressing the costs associated with an

interruption of electricity supply, expressed in dollars per megawatt hour (MWh) of unserved

electricity.

7 Energy Information Administration, “How Much Electricity is Lost in Electricity Transmission and Distribution in

the United States,” Frequently Asked Questions, https://www.cia.gov/tools/faqs/faq.php?id=105 &t=3

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Our analysis uses a conservative midpoint estimate of $14,250 per MWh for VoLL. This value is

higher than MISO’s previous VoLL estimate of $3,500 per MWh, but significantly lower than the

Independent Market Monitor’s suggested estimate of $25,000 per MWh. ”®

Plant Retirement Schedules

Our modeling utilizes announced coal and natural gas retirement dates from U.S. EIA databases

and announced closures in utility IRPs using a dataset collected by NERA economic consulting.

Plant Construction by Type

The resource adequacy and reliability portions of this analysis use MISO Interconnection Queue

data to project into the future. EPA capacity values are applied to each newly constructed resource

until the MISO system hits its target reserve margin based on EPA’s peak demand forecast in its

IPM.

Load Modifying Resources, Demand Response, and Imports

Our model allows for the use of 7,875 MW of Load Modifying Resources (LMRs) and 3,638 MW

external resources (imports) in determining how much reliable capacity will be needed within

MISO to meet peak electricity demand under the new MATS rules.

Utility Returns

Most of the load serving entities in MISO are vertically integrated utilities operating under the

Cost-of-Service model. The amount of profit a utility makes on capital assets is called the Rate of

Return (RoR) on the Rate Base. For the purposes of our study, the assumed rate of return is 9.9

percent with debt/equity split of 48.92/51.08 based on the rate of return and debt/equity split of the

ten-largest investor-owned utilities in MISO.

Transmission

This analysis assumes the building of transmission estimated at $10.3 billion, which is consistent

with MISO tranche | for the Status Quo Scenario. For the Full and Partial scenarios, transmission

costs are estimated to be $223,913 per MW of new installed capacity to account for the increased

wind, solar, storage, and natural gas capacity additions.

Taxes and Subsidies

Additional tax payments for utilities were calculated to be of 1.3 percent of the rate base. The state

income tax rate of 7.3 percent was estimated by averaging the states within the MISO region. The

78 Potomac Economics, “2022 State of the Market Report for the MISO Electricity Markets,” Independent Market

Monitor for the Midcontinent ISO, June 15, 2023, https:/;www.potomaceconomics.com/wp-content/uploads/2023/

06/2022-MISO-SOM Report _Body-Final.pdf.

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Federal income tax rate is 21 percent. The value of the Production Tax Credit (PTC) is $27.50. The

Investment Tax Credit (ITC) 30 percent through 2032, 26 percent in 2033, and 22 percent in 2034.

Battery Storage

Battery storage assumes a 5 percent efficiency loss on both ends (charging and discharging).

Maximum discharge rates for the MISO system model runs were held at the max capacity of the

storage fleet, less efficiency losses. Battery storage is assumed to be 4-hour storage, while pumped

storage is assumed to be 8-hour storage.

Wind and Solar Degradation

According to the Lawrence Berkeley National Laboratory, output from a typical U.S. wind farm

shrinks by about 13 percent over 17 years, with most of this decline taking place after the project

turns ten years old. According to the National Renewable Energy Laboratory, solar panels lose one

percent of their generation capacity each year and last roughly 25 years, which causes the cost per

megawatt hour (MWh) of electricity to increase each year.’”? However, our study does not take

wind or solar degradation into account.

Capital Costs, and Fixed and Variable Operation and Maintenance Costs

Capital costs for all new generating units are sourced from the EIA 2023 Assumptions to the

Annual Energy Outlook (AOE) Electricity Market Module (EMM). These costs are held constant

throughout the model run. Expenses for fixed and variable O&M for new resources were also

obtained from the EMM. MISO region capital costs were used, and national fixed and variable

O&M costs were obtained from Table 3 in the EMM report. °°

Discount Rate

A discount rate of 3.76 percent is used in accordance with EPA’s assumptions in the IPM.

Unit Lifespans

Different power plant types have different useful lifespans. Our analysis takes these lifespans into

account. Wind turbines are assumed to last for 20 years, solar panels are assumed to last 25 years,

battery storage for 15 years. Natural gas plants are assumed to last for 30 years.

Repowering

Our model assumes wind turbines, solar panels, and battery storage facilities are repowered after

they reach the end of their useful lives. Our model also excludes economic repowering, a growing

7% Liam Stoker, “Built Solar Assets Are ‘Chronically Underperforming,’ and Modules Degrading Faster than

Expected, Research Finds,” PV Tech, June 8, 2021, https://www.pv-tech.org/built-solar-assets-are-chronicallyunderperforming-andmodules-degrading-faster-than-expected-research-finds/.

8° U.S. Energy Information Administration, “Electricity Market Module,” Assumptions to the Annual Energy Outlook

2022, March 2022, https://www.cia.gov/outlooks/aeo/assumptions/pdf/electricity.pdf.

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trend whereby wind turbines are repowered after just 10 to 12 years to recapture the wind

Production Tax Credit (PTC). This trend will almost certainly grow in response to IRA subsidies.

EPA does not appear to take repowering into consideration because the amount of existing wind

on its systems never changes. If our understanding of EPA’s methodology is accurate, this a large

oversight that must be corrected.

Fuel Cost Assumptions

Fuel costs for existing power facilities were estimated using FERC Form 1 filings and adjusted for

current fuel prices.*!-*? Fuel prices for new natural gas power plants were estimated by averaging

annual fuel costs within the MISO region according to EPA.*® Existing coal fuel cost assumptions

of $17.82 per MWh were based on 2020 FERC Form 1 filings.

Inflation Reduction Act (IRA) Subsidies

Our analysis assumes all wind projects will qualify for IRA subsidies and elect the Production Tax

Credit, valued at $27.50 per MWh throughout the model run. Solar facilities are assumed to select

the Investment Tax Credit in an amount of 30 percent of the capital cost of the project.

Appendix 2: Capacity Retirements and Additions in Each Scenario

This section details the capacity additions and retirements in the MISO region under each scenario.

Status Quo scenario: The Status Quo scenario results in the retirement of 28,756.8 MW of coal

resources, 7,852 MW of natural gas capacity, and 462 MW of petroleum capacity. Additions in the

Status Quo scenario consist of 4,306 MW of natural gas, 19,436 MW of wind, 29,652 MW of solar,

and 3,304 MW of storage.

Annual retirement and additions can be seen in Figure D-13 below.

81 Trading Economics, “Natural Gas,” https://tradingeconomics.com/commodity/natural-gas.

82 https://data. nasdaq.com/data/EIA/COAL-us-coal-prices-by-region

83 U.S. Energy Information Administration, “Open Data,” https://www.cia.gov/opendata/v1/qb.php?category=

40694&sdid=SEDS.NUEGD. WI.A

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