strawman proposal - misoenergy.org

Updated 2/24/20

of 30 Version 2 Midcontinent Independent System Operator, Inc.

Strawman Proposal

MISO Futures

February 13, 2020


MISO Futures Strawman Proposal – Second Version

Table of Contents Table of Contents ............................................................................................................................................................2

Table of Figures................................................................................................................................................................3

Table of Tables .................................................................................................................................................................3 Executive Summary ........................................................................................................................................................4

Proposed Futures ............................................................................................................................................................5

Future I ...........................................................................................................................................................................6

Future II..........................................................................................................................................................................6

Future III ........................................................................................................................................................................6 Carbon Emissions Goals................................................................................................................................................7

Carbon Reduction Assumptions............................................................................................................................7

Retirement & Repowering Assumptions.............................................................................................................. 10

Base Retirement Assumptions............................................................................................................................ 10

Age-Based Retirement Assumptions................................................................................................................ 10 Peak Load (MW) & Energy (GWh) Forecasts...................................................................................................... 14

Base Forecast & Load Shapes .............................................................................................................................. 14

Future-Specific Forecasts and Load Shapes................................................................................................... 14

Demand & Energy Growth Assumptions......................................................................................................... 14

Natural Gas Price Forecast ....................................................................................................................................... 16

Electrification ................................................................................................................................................................ 18 Heavy-Duty/Light-Duty Electric Vehicles ...................................................................................................... 19

Residential and C&I Electrification ................................................................................................................... 22

DERs and Demand-Side Additions ......................................................................................................................... 23

Generation Resources ................................................................................................................................................ 24

Solar.............................................................................................................................................................................. 24 Wind ............................................................................................................................................................................. 24

Hybrid: Utility-Scale PV Solar + Storage ......................................................................................................... 24

Storage: Lithium-Ion Battery (4-hour) ............................................................................................................. 25

Natural Gas: Combined Cycle ............................................................................................................................. 25

Natural Gas: Combustion Turbine..................................................................................................................... 25 Capital Cost Assumptions ......................................................................................................................................... 25

Unit Operation Adjustments .................................................................................................................................... 27

Must-Run Designation ............................................................................................................................................... 27

Unit Seasonal Operation............................................................................................................................................ 27

Global Assumptions..................................................................................................................................................... 27 Study Period ................................................................................................................................................................... 27

Financial Variables for New Generation .............................................................................................................. 27

Discount Rate ................................................................................................................................................................ 28

EGEAS Study Areas ..................................................................................................................................................... 28

Siting ................................................................................................................................................................................. 29



Table of Figures Figure 1: MISO States, Cities, and Utilities with Decarbonization or Clean Energy Goals ...................7

Figure 2: Renewable Electricity Sourced by Fortune 500 Companies with 100% Renewable

Energy Goals .....................................................................................................................................................................8 Figure 3: CO2 Modeling Assumptions per Future ................................................................................................9

Figure 4: Total Retirements per Future (Cumulative by Year), Equal to Age-Based + Base .............. 11

Figure 5: Age-Based Retirements per Future (Cumulative per Year)........................................................ 11

Figure 6: Base Retirements per Future (Cumulative per Year).................................................................... 12

Figure 7: Future I Retirements Through 2040 ................................................................................................... 12 Figure 8: Future II Retirements Through 2040.................................................................................................. 13

Figure 9: Future III Retirements Through 2040 ................................................................................................ 13

Figure 10: Forecast High Level Process Flow Chart ........................................................................................ 15

Figure 11: Adjusted Load Shape Example............................................................................................................ 15

Figure 12: Henry Hub Natural Gas Price Forecast ........................................................................................... 16 Figure 13: Future-Specific Gas Forecast Potential Variation (Henry Hub) ............................................. 17

Figure 14: MTEP19 Gas Price Spread ............................................................Error! Bookmark not defined.

Figure 14: 30% Electrification by Sector.............................................................................................................. 18

Figure 15: 60% Electrification by Sector.............................................................................................................. 19

Figure 16: EV Growth per Future (MISO footprint)......................................................................................... 20

Figure 17: Future I EV Growth per LRZ................................................................................................................ 20 Figure 18: Future II EV Growth per LRZ .............................................................................................................. 21

Figure 19: Future III EV Growth per LRZ ............................................................................................................. 21

Figure 20: Electrification Potential Map .............................................................................................................. 22

Figure 21: Solar + Storage Hybrid Profile ............................................................................................................ 24

Figure 22: Annual Capital Cost Assumptions by Fuel Type........................................................................... 25 Figure 23: Solar PV ITC .............................................................................................................................................. 26

Figure 24: Wind PTC ................................................................................................................................................... 26

Figure 25: MISO Footprint & Neighboring Systems ........................................................................................ 29

Table of Tables Table 1: MTEP21 Future Assumptions Summary ...............................................................................................5

Table 2: Selected State RPS Mandates & Goals....................................................................................................8

Table 3: Selected Announced Utility Plans.............................................................................................................9 Table 4: Age-Based Retirement Assumptions.................................................................................................... 10

Table 5: MTEP21 DER Technical Potential in MISO........................................................................................ 23

Table 6: EGEAS External Model Representation .............................................................................................. 28



Executive Summary The MISO landscape is moving forward and changing dramatically. These changes are driven by

developments in economics, energy policies, and customer preferences. Expectations reveal

continued trends toward the “3Ds” highlighted in the 2019 MISO Forward Report:

Decentralization from large stations to smaller distributed resources, Digitalization of electricity-

consuming devices and the Internet of Things, and De-marginalization of resource costs.

In light of these trends and the numerous company announcements around an evolving fleet mix, MISO initiated a public stakeholder process to “retool” the MISO MTEP Futures. MTEP Futures

are designed to accommodate uncertainty by bookending a wide range of potential scenarios.

MISO’s Value Proposition affirms its core belief that a collective, region-wide approach to grid

planning and management delivers the greatest value to our members and their customers.

This document represents the cumulative efforts of collaboration between MISO staff and stakeholders. It proposes three new Futures.

In Future I, the MISO footprint evolves as members’ plans are substantially met, carbon emissions

decline 40% from 2005 levels, and current trends of electric vehicle adoption persist.

In Future II, members’ plans are met or exceeded, carbon emissions decline 60%, an increasing

trend in electric vehicle adoption drives growth in demand and energy, and residential and commercial electrification reaches 39% of technical potential.

Future III sees members’ plans met or exceeded, carbon emissions decline 80%, a heightened

increase in electric vehicle adoption drives greater growth in demand and energy, residential and

commercial electrification reaches 77% of technical potential, and renewable penetration levels

reach a minimum of 50%.

The Futures in this document incorporate a footprint-wide perspective which includes company

announcements and plans, federal and state policies, impacts of electric vehicles and other types

of electrification, technological advancements, and more. Implementation of these Futures will

allow MISO to plan reliable, value-creating changes to the transmission system.



Proposed Futures MISO proposes three Futures: Future I, Future II, Future III; each weighted equally.

Variables / Futures

Future I Future II Future III

Percent of Goals Met

≥ 85% goals met ≥ 100% IRPs met



Carbon Emissions Reduction* (2005 baseline)

≥ 40% (currently at 22%)** ≥ 60% ≥ 80%

Retirements–Coal Retirements–Natural Gas- CC Retirements–Natural Gas-Other

46 years 50 years 46 years



Wind and Solar Penetration

No minimum No minimum ≥ 50%

EV Adoption & Charging Technology

Low-Base EV growth Uncontrolled charging

Base-High EV growth Uncontrolled 2020-2035 &

V2G 2035 and beyond

Extra-High EV growth Uncontrolled 2020-2030 &

V2G 2030 and beyond

Electrification (includes EVs and gas to electric appliances / heating / cooling)

None 39% of technical potential

realized representing a 30% energy growth

77% of technical potential realized representing a 60%

energy growth

Demand & Energy Growth

Future-dependent (based on “Merged” ILF forecast);

Awaiting Future-specific forecast from AEG





DER Technical Potential by 2040 (GW)^

DR: 5.2 EE: 13.3 DG: 14.7

DR: 5.9 EE: 14.5 DG: 14.7

DR: 5.9 EE: 14.5 DG: 21.8

Natural Gas Prices

Base starting price determined by GPCM;

Future-specific price input to PROMOD





External Modeling

Pick “more aligned” SPP Future and single PJM

Apply our assumptions to external areas (take their

sites though)

Apply our assumptions to external areas (take their

sites though)

Table 1: MTEP21 Future Assumptions Summary

* Entire footprint in aggregate

** 2005-2017; MISO calculation from EIA Form 860 data

^ Distributed Energy Resources (DER); Demand Response (DR); Energy Efficiency (EE); Distributed Generation (DG): Capacity, preliminary

approximation; final results pending AEG model-build/run and aggregation, expected March.



Future I The footprint will continue to develop in line with substantial achievement of company announcements and plans, along with state mandates, goals, or preferences, and an associated

carbon emissions reduction1 of 40%. This is applicable to both resource additions and retirements.

This Future assumes that demand and energy (D&E) growth are driven by existing economic

factors.

Coal age-based retirement2 is 46 years

Natural gas prices developed through GPCM forecasting

Wind and solar resources are built commensurate with announced plans

Demand-side management programs are included

EV growth is modeled from data from LBNL study, relative to the low rate case scenario with only uncontrolled

charging modeled in this Future

Future II Driven by a robust economy and changing federal, state, and local policies, the footprint

experiences increased D&E and an associated reduction in carbon emissions of 60%. Decreased costs, improved technology, and supportive policies drive high growth in wind, solar, hybrid, and

storage resources. Annual growth in distributed generation reaches 30% or more.

Coal age-based retirement is 36 years


EV growth is modeled from data from LBNL study, relative to the base rate case scenario with uncontrolled

charging only capabilities until V2G integration in 2035 Energy increases 30% due to Electrification

Demand-side management programs increase

Future III Driven by a booming economy, supportive policies and investment, and D&E increases, DERs,

wind, and solar resources grow to comprise at least 50% of energy served in the footprint. Commercial and passenger light-duty vehicle fleets have largely electrified. Policy supports

carbon emissions reductions of 80% or more. Investments in R&D and continuing innovation

further decrease costs, improve technology, and advance development in power infrastructure,

generation, and storage.

Coal age-based retirement is 30 years


EV growth is modeled from data from LBNL study, relative to the high rate case scenario with uncontrolled

charging only capabilities until V2G integration in 2030

Energy increases by 60% due to Electrification

Wind and solar generation and DERs are built commensurate with an 80% carbon emissions reduction

High energy demand and decarbonization policies drive DSM/DER development

DERs comprise 30% of energy served

1 Carbon emissions reduction in Futures narratives refers to power sector emissions, from 2005 baseline 2 https://www.eia.gov/todayinenergy/detail.php?id=40212

https://www.eia.gov/todayinenergy/detail.php?id=40212



Carbon Emissions Goals To ensure a reliable and economic Bulk Electric System (BES) in an ever-changing energy,

regulations, and economics environment, MISO will evaluate three different levels of carbon

reductions within the Futures. Internal analysis indicates the footprint has decarbonized 22% since 2005. Carbon-related modeling and analysis will support MISO’s preparation for a broad

range of future scenarios, enabling continual adaptation to the changing energy lan dscape while

ensuring better grid reliability.

Carbon Reduction Assumptions Goals in the Footprint Cities, states, large commercial and industrial corporations, and utilities are exploring and setting decarbonization goals that often include reaching 100% renewable energy supply by 2050.

Figure 1: MISO States, Cities, and Utilities with Decarbonization or Clean Energy Goals



Figure 2: Renewable Electricity Sourced by Fortune 500 Companies with 100% Renewable Energy Goals

State Mandates & Goals Selected state mandates and goals publicly announced as of February 2020.

Selected State

Mandates & Goals

Renewable Portfolio Standard (RPS)

(as of June 2019, sources linked) Other State Goals

Illinois 25% by 2026

IL Clean Energy Jobs Act (CEJA): 100% C-free power by 2030, 100% RE by 2050; IL General

Assembly next in session Jan thru May 2020

Indiana 10% by 2025^ Voluntary clean energy PS (no participants as of

2018); 10% by 2025 for participants

Iowa 105 MW (completed as of 2007)

Michigan 15% by 2021^* 26-28% Carbon reduction by 2025

Minnesota 31.5% by 2020 (Xcel); 26.5% by 2025

(IOUs); 25% by 2025 (other utilities)

Carbon-free power by 2050 (Governor)

Missouri 15% by 2021

North Dakota 10% by 2015

Wisconsin 10% by 2015 Carbon-free power by 2050 (Governor)

Table 2: Selected State RPS Mandates & Goals

^: Includes non-renewable energy alternative resources

*: Extra credit for solar or customer-sited renewable energy

Source: dsireusa.org

https://s3.amazonaws.com/ncsolarcen-prod/wp-content/uploads/2019/07/RPS-CES-June2019.pdf

https://s3.amazonaws.com/ncsolarcen-prod/wp-content/uploads/2019/07/RPS-CES-June2019.pdf

https://programs.dsireusa.org/system/program/detail/584





https://mn.gov/governor/news/?id=1055-412110




https://www.wpr.org/task-force-begins-work-combat-climate-change



Utility Announced Plans

Goal Cohort Members

Carbon Emissions

Reduction (CER)

Goals

Goal

Year

Percent of MISO

Load Served

(Energy)*

Percent of MISO

Capacity

Served**

28% x 2030 Entergy 28% 2030 21.49% 15.28% 40% x 2030 Minnesota Power, Alliant,

Duke, WEC Energy Group 40% 2030 17.13% 12.96%

50% x 2040 Ameren 50% 2040 11.84% 9.29% 80% x 2030 NIPSCO, Xcel 80% 2030 9.80% 7.18% 80% x 2040 DTE, Hoosier Energy 80% 2040 7.94% 6.28%

90% x 2030 SMMPA 90% 2030 0.65% 0.46%

90% x 2040 Consumers Energy 90% 2040 7.18% 5.21% Total 76.03% 56.65%

Table 3: Selected Announced Utility Plans

* Estimate as of 2019 data. Sources: Reported Annual Loads from Load Forecast Survey / 712,836,003 (MWh) MISO Load, 2018 MISO

Value Proposition,3 slide 8

** Estimate as of 2019 data. Sources: Average of Reported Peak Loads from Load Forecast Survey / 146,028 (MW) required capaci ty

with MISO, 2018 MISO Value Proposition,4 slide 22

Modeling of Carbon Reductions Assumptions This cohort proposes system limits in terms of carbon emission reductions (CER) for each of the three Futures. In 2005, MISO emitted 539 million (M) tons of CO2. The Futures propose system

limits of 40% CER for Future I, 60% CER for Future II, and 80% CER for Future III. By the end of

the study period, emission limits will be 323 M tons, 215 M tons, and 108 M tons respectively. A

straight line from 2016 emission levels to the end of the study period system limit was made to

determine the CO2 emission limit for each year. MISO will input these system limits into the EGEAS model.

Figure 3: CO2 Modeling Assumptions per Future

3 https://cdn.misoenergy.org/2018%20MISO%20Value%20Proposition%20-%2015Feb2019(Final)321318.pdf 4 Ibid.

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MIS

O C

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Emis

sio

ns

(M t

on

s)

CO2 Limits per Future Compared to MISO Historical Emissions

MISO Historical Future I 40% CER Future II 60% CER Future III 80% CER

323 M tons

203 M tons 215 M tons

108 M tons

https://cdn.misoenergy.org/2018%20MISO%20Value%20Proposition%20-%2015Feb2019(Final)321318.pdf



Retirement & Repowering Assumptions

Base Retirement Assumptions Hydro retirements will be decided by the owner. Other resource retirements will be determined

by the resource type. Publicly announced retirements will be included in base retirements.

Age-Based Retirement Assumptions Future I Future II Future III

Coal 46 36 30 Natural Gas – CC 50 45 35

Natural Gas – Other 46 36 30 Oil 45 40 35

Nuclear License Expiration License Expiration License Expiration Solar – Utility-Scale 25 25 25 Wind – Utility-Scale 25 25 25

Table 4: Age-Based Retirement Assumptions

Nuclear The relicensing and retirement of nuclear units will be assumed to be dependent upon company

announcements, age, and operational costs.

Coal & Gas The retirement age of coal units progressively decreases in every Future. It is assumed that with changing policies and emission standards, coal usage will decline. The retirement ages modeled in

the three Futures respectively are: 46, 36, and 30 years. In doing so, complete retirement of coal

can be modeled within Future III.

Wind An age-based retirement assumption will be added for utility-scale wind along with assumptions

for repowering a wind resource. Currently, wind units are being retired between 20 and 25 years,

while repowering may occur once a unit reaches 15 years of age. The repowering assumptions for wind turbines will be a repowering at the age of retirement and replaced by a hub height

technology representative of the region (e.g. 100, 120m). Repowering is heavily influenced by

Production Tax Credits (PTC) and decarbonization policies.



Figure 4: Total Retirements per Future (Cumulative by Year), Equal to Age-Based + Base

Figure 5: Age-Based Retirements per Future (Cumulative per Year)

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040


MW

Total Retirements per Future

Coal Gas Nuclear Wind Solar Oil

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040


MW

Age-Based Retirements per Future




Figure 6: Base Retirements per Future (Cumulative per Year)

Figure 7: Future I Retirements Through 2040

0

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4,000

6,000

8,000

10,000

12,000

14,000

16,000

2025 2030 2035 2040 2025 2030 2035 2040 2025 2030 2035 2040


MW

Base Retirements per Future




Figure 8: Future II Retirements Through 2040

Figure 9: Future III Retirements Through 2040



Peak Load (MW) & Energy (GWh) Forecasts MTEP21 will utilize the 2019 Merged Load Forecast for Energy Planning as well as MISO’s 2018

load shapes. These base data points will be adjusted to meet Future-specific criteria as stated in

this proposal.

Base Forecast & Load Shapes The 2019 Merged Load Forecast for Energy Planning forecast was reviewed for updates by

stakeholders December 17, 2019 through January 10, 2020 and updates received will be incorporated. To accompany the forecast, MISO evaluated its 2018 load shapes for weather

anomalies and will use these shapes for MTEP Futures and the Market Congestion Planning Study

(MCPS). MISO’s 2018 load shape also aligns with wind and solar shapes that are based on the most

current data.

As a Futures retooling process improvement, MISO will use PROMOD to adjust each Load Balancing Authority (LBA) 2018 load shape to meet the annual Peak Load (MW) and Peak Energy

(GWh) requirements set by the updated 2019 Merged Load Forecast for Energy Planning

forecast. The benefit of this improvement will be to create 20 years’ worth of unique load shapes

for EGEAS analysis as well as to establish a common load shape for the EGEAS and MCPS

analyses.

Future-Specific Forecasts and Load Shapes Applied Energy Group (AEG) will use the updated 2019 Merged Load Forecast for Energy

Planning forecast and the unique load shapes as their base input assumptions. AEG will then modify the 2018 load shapes to achieve Future-specific assumptions (electric vehicle growth and

charging assumptions, residential electrification, and commercial and industrial electrification),

ultimately creating 20 years’ worth of load shapes for each future. These Future-specific load

shapes will be used to calculate new annual Peak Load (MW) and Peak Energy (GWh) forecasts to

be used in the EGEAS analysis.

Demand & Energy Growth Assumptions Demand and energy growth values will be based on Futures assumptions. These values will be

determined once the 20-year MTEP EGEAS analysis is complete and will be developed throughout the process.



Figure 10: Forecast High Level Process Flow Chart

Figure 11: Adjusted Load Shape Example

MISO receives updated 2019 Merged Forecast

Review MISO's 2018 Market Load Shapes

Adjust 2018 Load Shapes to match 2019 Merged

Forecast (By Year)

AEG EV and Electrification

adjustments to load shapes (By Year and

Future)

AEG produces new annual Peak Load (MW) and Peak Energy (GWh)

forecast (By year and Future)

EGEAS Analysis (By Future)

Determine Demand and Energy growth rates (By

Future)

50

70

90

110

130

150

170

190

210

230

250

GW

Composite Load Shape

60% CASEComposite Load Shape (GW)

30% CASEComposite Load Shape (GW)

ReferenceComposite Load Shape (GW)



Natural Gas Price Forecast MISO will use the GPCM base price forecast across the three Futures, instead of the locked-down

Henry Hub (HH) from past cycles (illustrated in Figure 12). The base forecast will be the same for

all Futures in EGEAS. After the capacity expansion is complete, the Futures will be implemented in

PROMOD. MISO will then export the resulting new gas burn in each individual Future into GPCM,

producing Future-specific gas prices. Examples of Future-specific gas prices resulting from this

method (using MTEP19 Futures as illustration only) are shown in Figure 13 and Table 5 below. GPCM outputs the gas price at a level of monthly granularity and based on past exploration

Future-specific prices can vary by 40% or more.

Figure 12: Henry Hub Natural Gas Price Forecast



Figure 13: MTEP19 Future-Specific Gas Forecast Potential Variation (Henry Hub) Example

LFC CFC DET AFC Max 46% 42% 44% 16%

Min 0% 0% 0% -40%

Average 13% 8% 9% -10%

Table 5: MTEP19 Futures Gas Price Spread Example

1.00

2.00

3.00

4.00

5.00

6.00

7.00

8.00

1 5 9 13 17 21 25 29 33 37 41 45 49 53 57 61 65 69 73 77 81 85 89 93 97 101 105 109

Test

HH

Ba

se F

ore

cast

Monthly (1 yr Before Model Year to 1 yr After)

Future-Specific Gas Forecast Potential Variation (Henry Hub)

Base HH Potential Max (LFC) Potential Min (AFC)

Potential Avg High Potential Avg Low

5-yr model10-yr model

15-yr model



Electrification MISO has contracted Applied Energy Group (AEG) to conduct an electrification study on the

MISO footprint. Electrification is the conversion of an end-use device to be powered with

electricity, such that it displaces another fuel, such as natural gas. The technical potential of the MISO footprint was evaluated in seven different sectors:

Residential – Heating, ventilation, and air conditioning (HVAC) Residential – Domestic water heating (DWH) Residential – Appliances (APP) Residential/Commercial and Industrial – Plug-in electric vehicles (PEVs) Commercial and Industrial – Heating, ventilation, and air conditioning (HVAC) Commercial and Industrial – Domestic water heating (DWH) Commercial and Industrial – Other (process)

When incorporating results from AEG’s electrification technical potential study, MISO will be assuming current trends, 30% technical potential, and 60% technical potential respectively in the

three Futures. Percentages of technical potential reached align with the percentage of load

growth in each of the three scenarios. This growth is made up of the cumulative increases of the

seven different sectors evaluated.

Figure 14: 30% Electrification by Sector

0

50,000

100,000

150,000

200,000

250,000

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

GW

h

30% Case by End Use

Res - HVAC

RES - DHW

RES - APP

C&I - HVAC

C&I - DHW

C&I - Other

PEVs



Figure 15: 60% Electrification by Sector

Heavy-Duty/Light-Duty Electric Vehicles Information was created with collaboration from MISO and Lawrence Berkeley National

Laboratory (LBNL) and then incorporated into the electrification study conducted by AEG.

The LBNL EV study categorized the projected growth of EVs in the MISO footprint into four

categories: low, base, high, and very high. Given there are only three Future scenarios being

evaluated, MISO will be using combinations of the data forecasted within each Future to

encompass both light-duty and heavy-duty EVs, this will include both passenger and fleet light-

duty EVs as well as heavy-duty EVs. Each of these cases explored a variety of EV growth and charging scenarios within every LRZ and projected data to produce a twenty-year outlook for the

footprint.

0

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400,000

450,000

500,000

2020 2022 2024 2026 2028 2030 2032 2034 2036 2038 2040

GW

h

60% Case by End Use

Res - HVAC

RES - DHW

RES - APP

C&I - HVAC

C&I - DHW

C&I - Other

PEVs



Figure 16: EV Growth per Future (MISO footprint)

Figure 17: Future I EV Growth per LRZ

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EV

Po

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illio

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2019 2024 2029 2034 2039

Future I 0.135 0.53 1.33 2.57 4.19

Future II 0.26 1.205 3.47 7.455 12.49

Future III 0.435 2.42 8.25 20.915 36.32

EV Growth per Future (MISO Footprint)

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illio

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Future I EV Growth per LRZ

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Figure 18: Future II EV Growth per LRZ

Figure 19: Future III EV Growth per LRZ

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2019 2024 2029 2034 2039

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Residential and C&I Electrification The key elements that make up the residential electrification variables are heating, ventilation, and air conditioning systems (HVAC), domestic water heating (DWH), and appliances. Residential

appliances were assumed to be clothes dryers, dishwashers, and stoves. Dishwasher

electrification occurred when no existing dishwasher was seen to be present.

Similar to residential electrification components, commercial electrification was evaluated on

HVAC and DWH systems with the addition of industrial processes. All the variables evaluated in the study (EVs, Residential, and C&I) were then compounded upon each other with higher

adoption rates to better evaluate the footprint in a variety of electrification scenarios.

Within electrification there are three characteristics that allow a state to have a higher

electrification potential. These characteristics include latitude, gas infrastructure, and cooling.

Northern states (latitude) that have greater heating loads and states with more gas heating (gas infrastructure) have a high potential to be electrified. States with higher cooling loads (cooling)

primarily in the south, do not have high electrification potential.

Figure 20: Electrification Potential Map



DERs and Demand-Side Additions As in previous MTEP cycles, MISO has commissioned Applied Energy Group (AEG) to develop new

demand-side addition technical potential, based on previous analysis for the MTEP20 Futures,

with updated utility information and Futures narratives for thi s cycle. These resources will be modeled in three main categories: Demand Response (DR), Energy Efficiency (EE), and Distributed

Generation (DG).

As expressed in the Futures assumptions, technical potential will represent feasible potential

under each scenario. Existing DR programs will be modeled as base assumptions. Only

economically viable programs will be implemented in the MTEP21 models (each program will be offered against supply-side alternatives). The following figures are draft approximations; final

results are pending AEG’s model-build and run, and aggregation of results.

MTEP21 DERs Future I Future II Future III

Capacity (GW)

Energy (GWh)

Capacity (GW)

Energy (GWh)

Capacity (GW)

Energy (GWh)

20

-Ye

ar

Te

chn

ical

P

ote

nti

al

Demand Response

(DR) 5.2 442 5.9 498 5.9 498

Energy Efficiency

(EE) 13.3 86,886 14.5 94,313 14.5 94,313

Distributed Generation

(DG) 14.7 26,119 14.7 26,119 21.8 36,934

Table 6: MTEP21 DER Technical Potential in MISO



Generation Resources

Solar Regional Resource Forecasted (RRF) unit representation of photovoltaic (PV) will be sized at

1,200 MW (on the AC side of the inverter) of capacity, consistent with the unit sizes of the other

supply-side resources. Vibrant Clean Energy (VCE) 2018 hourly profiles will be used as the base

data. Existing units will use a representative hourly profile and all solar units will assume 50%

capacity credit at the beginning of the study period and decrease 2% each year.

Wind RRF unit representation of wind will be sized at 1,200 MW of capacity, consistent with the unit

sizes of the other supply-side resources. Vibrant Clean Energy (VCE) 2018 hourly profiles will be used as the base data and RRF units. New RRF units will be built at 100m at the beginning of the

study period and will be 120m after 2030. Existing wind units will be grouped into the following

sections: North, Central, and South. Existing units will use a representative 80m hub height hourly

profile and all wind units will assume 15.6% capacity credit.

Hybrid: Utility-Scale PV Solar + Storage Hybrid units will be modeled 1200 MW inverter capacity with 1500 MW of solar panels, thus 300

MW of over-paneling. Excess energy produced from the solar panel will be used to power a 300

MW 4-hour battery behind the inverter. Hybrid solar profiles will use VCE 2018 hourly profiles that will then be modified to create a hybrid profile. Exact methodology for the calculation of

capacity credit will be ready during the next workshop. The losses in the battery will be 8%, thus

92% of the battery charge will be available energy for discharge.

Figure 21: Solar + Storage Hybrid Profile



Storage: Lithium-Ion Battery (4-hour) RRF unit representation of lithium-ion battery storage will be sized as 100 MW to be consistent

with battery units in MISO GI queue. Batteries will be 4-hour duration batteries.

Natural Gas: Combined Cycle RRF units representing Combine Cycle units be 1200 MW of capacity.

Natural Gas: Combustion Turbine RRF units representing Combustion Turbine units be 1200 MW of capacity.

Capital Cost Assumptions NREL ATB-2019 is used to calculate the capital costs of the non-battery storage resources. For

battery storage, Lazard5 4-hour Lithium-Ion battery at Wholesale level is considered. For wind units,

Participation Tax Credits (PTC) and Investment Tax Credits (ITC) are grossed up to reflect the impacts

on capital costs.

Figure 22: Annual Capital Cost Assumptions by Fuel Type

5 Lazard’s Levelized Cost of Storage Analysis, Version 5.0: https://www.lazard.com/media/451087/lazards-levelized-cost-of-storage-version-50-vf.pdf

$-

$1,000

$2,000

$3,000

$4,000

$5,000

$6,000

$7,000

Wind Solar Utility Geothermal Hydropower Gas CC Gas CT Coal Nuclear Biopower EnergyStorage

Ca

pit

al

Co

st $

/kW

Capital Cost MTEP ComparisionMTEP19 ($2018) MTEP20 ($2019) MTEP21

https://www.lazard.com/media/451087/lazards-levelized-cost-of-storage-version-50-vf.pdf

https://www.lazard.com/media/451087/lazards-levelized-cost-of-storage-version-50-vf.pdf



Figure 23: Solar PV ITC

Figure 24: Wind PTC

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

$/k

W

Solar Capital Cost with ITC

Low 2020 w/ Grossed ITC Real 2020 w/Gross ITC Real 2020 No ITC

$300

$500

$700

$900

$1,100

$1,300

$1,500

$1,700

2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036

$/k

W

Wind Capital Cost with PTC

Low 2020 w/Gross PTC Real 2020 Mid w/Gross PTC Real 2020 No PTC



Unit Operation Adjustments

Must-Run Designation

The purpose of this is to determine which generation units will be used to provide security to the

grid under normal operating conditions. In a time where wind and solar generation is increasing, it

is critical to ensure that reliability criteria requirements are always met. The decision to use of a

unit depends on the compatibility with the system, runtime specifications, and shall be capable of

representing least-cost capacity planning with economic decisions for expansion, retirement, and

retrofits (EIA 2015).

MTEP21 Must-Run Designation Criteria Only co-generation (as identified in EIA-860), nuclear, and hydro units shall be assigned a Must-

Run designation. Coal units shall not be assigned a Must-Run designation. Future II and Future III

will have no thermal units designated as a Must-Run type so that economical units may be selected to meet high carbon reduction goals.

Unit Seasonal Operation

MISO footprint includes several of units with announced seasonal operations due to economic

conditions or operating limitations. Such units will be operated seasonally until their retirement.

Global Assumptions

Study Period

The study period of the MTEP21 EGEAS resource expansion analysis is 20 years, beginning in

2020 and ending in 2040. An extension period of 40 years is added to the of the simulation period, with no new units forecasted during this time. This additional study period ensures that the

selection of generation in the last few years of the forecasting period (i.e., years 15-20) is based on

cost of generation spread out over the total tax/book life of the new resources (i.e., beyond year

20) and does not bias to the cheapest generation in those final years.

Financial Variables for New Generation

The variables associated with financing new Regional Resource Forecasted (RRF) units, listed are averaged values sourced annually from data submitted by MISO’s Transmission Owners through

Attachment O of the MISO Tariff.



Discount Rate

The discount rate of 7.22% is based upon the after-tax weighted average cost of capital of the Transmission Owners that make up the Transmission Provider Transmission System.

EGEAS Study Areas There will be no proposed changes to MISO footprint and incremental changes to external-to-

MISO areas.

MISO Footprint The proposed study area for the retooled MTEP Futures continues to study the MISO footprint as

a single footprint.

External Areas

From an external-to-MISO (external areas) perspective, MISO proposes to increase the EGEAS

analysis granularity for external Areas/Pools represented in the MCPS by increasing the number

of representative models.

MISO to Create Regional Model with Associated Future Assumptions

EGEAS Models Future I Future II Future III

PJM No – Use PJM Model Yes Yes

SPP No – Use SPP “more aligned”

Future6 Results Yes Yes

TVA TVA Other Southeast

Yes Yes Yes

Manitoba Hydro No No No Table 7: EGEAS External Model Representation

MISO realizes system flows are dependent on external areas representations and the above

improvements are intended to help align MISO Future assumptions to MISO’s neighbors as well as provide one Future, Future I, that utilizes SPP and PJM Future assumptions. This Future will be

used to help bookmark projected external system flows as decided by external Future

assumptions.

6 https://www.spp.org/Documents/61365/2021%20ITP%20Scope%20MOPC%20Approved.docx

https://www.spp.org/Documents/61365/2021%20ITP%20Scope%20MOPC%20Approved.docx



Figure 25: MISO Footprint & Neighboring Systems

Siting MISO proposes no changes to siting methodologies that were updated for MTEP19,7 but instead is

proposing some process enhancements.

Siting Enhancements The goal of the enhancements listed below is to reduce siting rework pre-MCPS and reduce siting adjustments during MCPS robustness testing.

SPP Sites: Use resource expansion sites determined by SPP in their Integrated Transmission

Planning siting process8.

Pre-Site Screening: Same sites will be used for each Future and site and site capacity differences will be

due to Future-specific wind and solar amounts Evaluating using TARA to calculate DFAX (Distribution Factor) and Total MW

Impact to compare to Powerflow model transmission element ratings

Post-Site Screening: Evaluating possibility of using generator bus transmission (MW) post PROMOD

simulation

7 MTEP19 Future Siting Improvements: https://cdn.misoenergy.org/MTEP19%20Futures%20Summary291183.pdf 8 ITP Resource Siting Process White Paper

https://cdn.misoenergy.org/MTEP19%20Futures%20Summary291183.pdf

https://www.spp.org/Documents/60787/ITP%20Resource%20Siting%20Process%20White%20Paper.docx