PSC REF#:390854
Rebecca Cameron Valcq, Chairperson
Ellen Nowak, Commissioner
Tyler Huebner, Commissioner

4822 Madison Yards Way
P.O. Box 7854
Madison, WI 53707-7854

June 3, 2020
To the Parties:
Re:

Strategic Energy Assessment for January 1, 2020 Through
December 21, 2026

Comments Due:
Friday, August 14, 2020–Noon
This docket uses the Electronic Records Filing
(ERF) system.

5-ES-110

Address Comments To:
Docket 5-ES-110 Comments
Public Service Commission
P.O. Box 7854
Madison, WI 53707-7854

The Commission has authorized the enclosed draft Strategic Energy Assessment (SEA) to be
released for public comment. The accompanying environmental assessment will be made
available on the Commission’s website upon its completion.
The SEA is a study prepared by the Commission pursuant to Wis. Stat. § 196.491(2) and Wis.
Admin. Code § PSC 111.03 that profiles the state’s electricity system. Topics include the
adequacy and reliability of electric supply and transmission, the affordability of customer rates
and bills, and initiatives towards the environmentally responsible delivery of electric services.
Public comments on the draft SEA must be submitted by August 14, 2020.
The Commission encourages all interested persons to comment on the content of the draft SEA.
Comments will be used to prepare the final SEA.
Comments may be submitted in any of the following ways:
•

ERF System. The ERF system can be accessed through the Commission’s
website at http://psc.wi.gov. Party comments must be filed using the
Commission’s ERF system.

•

Web Comment. Go to the Commission’s website at http://psc.wi.gov, and click
on the “File a Comment” button. On the next page, select the “File a comment”
link that appears for docket number 5-ES-110.

•

Mail Comment. All comments submitted by U.S. Mail shall be received no later
than August 14, 2020. A mail comment should be entitled “5-ES-110
Comments,” and addressed using the mailing information above.

Telephone: (608) 266-5481
Home Page: http://psc.wi.gov

Fax: (608) 266-3957
E-mail: pscrecs@wisconsin.gov

Public Service Commission of Wisconsin
RECEIVED: 06/03/2020 3:05:01 PM

Public Service Commission of Wisconsin

 To the Parties
5-ES-110
Page 2
•

Oral Comment. The Commission will hold a public hearing on Wednesday,
August 5, 2020, at 1:00 p.m. The hearing shall be an audio hearing with no public
location. Members of the public may attend by telephone or listen live on the
internet. Spoken comments may be submitted during the hearing by those
attending by telephone.
To attend the hearing by telephone use the following:
Dial-in number: (872) 240-3212 (Toll)
Access Code:
903-694-349 #
To listen live on the internet, go to the Commission’s web site at
http://psc.wi.gov, and select “Live Broadcast” button. The live broadcast
webpage provides no opportunity to make a comment.

Please contact Joe Fontaine at (608) 266-0910 or joe.fontaine@wisconsin.gov to request a CD or
printed copy of the draft SEA. Questions from the media and the legislature may be directed to
Matthew Sweeney at (608) 267-3589 or matthew.sweeney@wisconsin.gov.
Sincerely,

Martin R. Day
Administrator
Division of Energy Regulation and Analysis
MRD:JF:cmb:DL: 01736481
Attachment

 PUBLIC SERVICE COMMISSION OF WISCONSIN

FINAL
STRATEGIC ENERGY
ASSESSMENT 
2020-2026

4822 MADISON YARDS WAY 
MADISON, WISCONSIN

JUNE 2020 
DOCKET 5‐ES‐110

 Strategic Energy Assessment 2026 ‒ Draft

Public Service Commission of Wisconsin
North Tower, 6th Floor
Hill Farms State Office Building
4822 Madison Yards Way
Madison, Wisconsin 53705
Phone: (608) 266-5481 ‒ General toll-free: (888) 816-3831 ‒ Fax: (608) 266-3957
Website: http://psc.wi.gov
Email: PSCSEA@wisconsin.gov
Home Page: http://psc.wi.gov

Questions from the Legislature and the media may be directed to Matthew Sweeney at (608) 266-9600.

i

 TABLE OF CONTENTS
Strategic Energy Assessment 2026 ‒ Draft..................................................................................................... i
Table of Contents .......................................................................................................................................... ii
Table of Figures ............................................................................................................................................ iv
Table of Tables.............................................................................................................................................. vi
EXECUTIVE SUMMARY.............................................................................................................................. 1
Electric Supply in Wisconsin ....................................................................................................................... 2
Electric Transmission in Wisconsin ............................................................................................................ 2
Reliability and RESILIENCE ...................................................................................................................... 3
Customer Rates and Bills .............................................................................................................................. 3
Clean Energy Programs and Policies .......................................................................................................... 4
Electric SYstem Emissions........................................................................................................................... 5
CHAPTER 1 ‒ ELECTRIC SUPPLY IN WISCONSIN .......................................................................... 6
Defining Supply Needs ................................................................................................................................. 6
Reserve Margins and Total Required Electric Supply .............................................................................. 8
Sources of Energy Supply...........................................................................................................................10
Historical Trends in Sources of Supply ................................................................................................13
Projecting Energy Supply, 2020-2026.......................................................................................................16
CHAPTER 2 ‒ ELECTRIC TRANSMISSION IN WISCONSIN ........................................................21
Transmission Planning ................................................................................................................................23
Transmission Costs .....................................................................................................................................26
CHAPTER 3 ‒ RELIABILITY AND RESILIENCE ..............................................................................28
Reliability .......................................................................................................................................................28
NEW GRID TECHNOLOGIES ............................................................................................................31
Renewable Resources and Reliability ....................................................................................................31
Other Grid Technologies .......................................................................................................................34
Resilience ..................................................................................................................................................34
Cybersecurity ............................................................................................................................................36
CHAPTER 4 ‒ CUSTOMER RATES AND BILLS ................................................................................37
Utility Cost Drivers .....................................................................................................................................37
Trends in Customer Sales .......................................................................................................................37
ii

 Sources of Utility Costs ..........................................................................................................................39
Effects of Tax Reform on Investor-Owned Utilities .........................................................................41
Determining Customer Rates.....................................................................................................................42
Components of Customer Rates ...........................................................................................................44
Current Rates and Bills ...............................................................................................................................45
Residential Customers.............................................................................................................................45
Non-Residential Customers ...................................................................................................................49
Alternative Rate Options ........................................................................................................................50
Affordability for Low-Income Customers ...............................................................................................52
CHAPTER 5 ‒ CLEAN ENERGY PROGRAMS AND POLICIES ...................................................56
ENERGY EFFICIENCY..........................................................................................................................56
Focus on Energy Programs....................................................................................................................56
Focus on Energy Outcomes ..................................................................................................................57
Future Focus on Energy Spending and Outcomes ............................................................................58
DEMAND RESPONSE ............................................................................................................................60
RENEWABLE ENERGY ........................................................................................................................63
Renewable Portfolio Standard ...............................................................................................................64
Electric Provider Solar Initiatives..........................................................................................................65
Customer-Owned Renewables ..............................................................................................................67
ELECTRIC VEHICLES............................................................................................................................69
CHAPTER 6 ‒ ELECTRIC SYSTEM EMISSIONS ...............................................................................72
Electric Providers’ Carbon Reduction Goals ..........................................................................................73
Historical Electric System Emission Trends ...........................................................................................74
Projected Emissions Reductions ...............................................................................................................75
APPENDIX A – SUPPORTING DATA, ELECTRIC SUPPLY...................................................... - 1 APPENDIX B – SUPPORTING DATA, ELECTRIC TRANSMISSION ...................................... - 4 APPENDIX C – SUPPORTING DATA, CUSTOMER RATES AND BILLS .............................. - 5 APPENDIX D – SUPPORTING DATA, CLEAN ENERGY PROGRAMS & POLICIES .....- 10 APPENDIX E – ACRONYMS ...............................................................................................................- 12 -

iii

 TABLE OF FIGURES
Figure 1-1

Historical and Forecasted Maximum Monthly Peak Demand by Year, MW .................. 6

Figure 1-2

Average Non-Coincidental Peak Demand per Month for the Period 2015-2019 .......... 7

Figure 1-3

Electric Providers’ Generation Resources in Wisconsin...................................................11

Figure 1-4

Capacity – January 2020 .........................................................................................................12

Figure 1-5

Generation - 2018 ...................................................................................................................12

Figure 1-6

Comparison of 2010 and 2018 Generation Data ...............................................................13

Figure 1-7

Henry Hub Natural Gas Average Annual Cost in $/MMBtu ..........................................14

Figure 1-8

Estimated Levelized Unsubsidized Cost of Electricity for Solar and Wind Resources
in $/MWh ................................................................................................................................15

Figure 1-9

2018 vs Forecast 2026 Generation Comparison ................................................................18

Figure 2-1

MISO Regional Transmission Map ......................................................................................21

Figure 2-2

Existing Transmission Lines .................................................................................................23

Figure 2-3

MISO Transmission Projects Identified in MTEP19 ........................................................25

Figure 3-1

Statewide Average SAIFI, SAIDI, and CAIDI Values for Major IOUs ........................29

Figure 3-2

Reliability indices by state for large utilities (>100,000 customers), 2018 ......................30

Figure 3-3

Possible Future MISO North Annual Hourly Solar Production, 30-day Averages ......32

Figure 3-4

Possible Future MISO North Annual Hourly Wind Production, 30-day Averages .....33

Figure 4-1

Retail Sales of Electricity, by Sector (MWh) .......................................................................38

Figure 4-2

Ten-year Annual Growth Rate of Revenue Requirement Components—Major
IOUs (%) .................................................................................................................................39

Figure 4-3

MISO Schedule 9 Network Transmission Charges ($/MW-Month) ..............................40

Figure 4-4

Statewide Average Purchased Power Cost ($/MWh)........................................................41

Figure 4-5

Rate Case Process ...................................................................................................................43

Figure 4-6

Average Residential Electricity Rates (1990-2018).............................................................47

Figure 4-7

Historical Comparison of Average Monthly Residential Electric Bills (2009-2018),- ...48

Figure 4-8

Monthly Residential Electricity Costs and Consumption in Wisconsin and the
Midwest....................................................................................................................................49

Figure 4-9

Time Varying Price of Electricity on an Average Summer Day in Wisconsin ..............51

Figure 5-1

Actual and Projected Annual Electric Energy Efficiency Expenditures 2018-2026 .....59

Figure 5-2

Actual and Projected First-Year Annual Energy Savings 2018-2026 ..............................60

Figure 5-3

Interruptible Service in Wisconsin .......................................................................................62
iv

 Figure 5-4

Direct Load Control in Wisconsin .......................................................................................63

Figure 5-5

Renewable Energy by Resource 2010-2018 ........................................................................64

Figure 5-6

2018 Renewable Energy by State and Resource .................................................................65

Figure 5-7

Community Solar Capacity in Wisconsin ............................................................................67

Figure 5-8

Capacity of Customer-Owned Renewables in Wisconsin, 2019 ......................................68

Figure 5-9

Number of Renewable DER Installations by Technology ...............................................69

Figure 5-10

Installed Capacity of Renewable DER Installations by Renewable Source ...................69

Figure 5-5

Areas of Interest ......................................................................................................................71

Figure 6-1

Comparison of CO 2 Emissions by End Use in Wisconsin vs. National Average ........72

Figure 6-2

Comparison of CO 2 Emissions by Fossil Fuel Type in Wisconsin vs. National
Average ....................................................................................................................................73

Figure 6-3

Wisconsin Electric CO 2 Emissions per MWh, 2005-2017 ...............................................75

Figure 6-4

Wisconsin Electric Sector CO 2 Emissions .........................................................................76

Figure A-1

MISO System-Wide Average Monthly Day-Ahead and Real-Time LMPs $/MWh.. - 2 -

Figure A-2

Forecasted Levelized Cost of Electricity in $/MWh per NREL in 2019 .................... - 2 -

Figure A-3

Wind Energy as Percent of Total Energy in MISO Region, 2014-2019...................... - 3 -

Figure B-1

MTEP19 Regional Investment by Project Category ...................................................... - 4 -

Figure C-1

Weather-Normalized Annual Use, per Residential Customer (kWh) .......................... - 5 -

Figure C-2

Energy Intensity – Non-Residential Sales ($ of GDP/MWh) ...................................... - 5 -

Figure C-3

Average Monthly Residential Bills by Census Division (2018 EIA Data)................... - 7 -

Figure C-4

Monthly Residential Electricity Bills for Wisconsin’s Largest IOUs............................ - 7 -

Figure C-5

Distribution of Monthly Residential Electricity Bills for Municipal Utilities .............. - 8 -

Figure C-6

Distribution of Commercial (CP-1) Costs in cents/kWh for Municipal Utilities ...... - 8 -

Figure C-7

Distribution of Monthly Commercial (CP-1) Bills for Municipal Utilities.................. - 9 -

Figure D-1

Number of Renewable DERs Installed by Capacity ....................................................- 10 -

Figure D-2

Number of Renewable DERs Installed by Customer Type ........................................- 10 -

Figure D-3

Installed Capacity of Renewable DERs by Capacity Range ........................................- 11 -

Figure D-4

Installed Capacity of Renewable DERs by Customer Type ........................................- 11 -

v

 TABLE OF TABLES
Table 1-1

Expected Maximum Monthly Peak Loads, with Percentage Increases from Previous
Year ............................................................................................................................................ 7

Table 1-2

Wisconsin Aggregated Supply and Demand, MW ............................................................... 9

Table 1-3

Forecasted Planning Reserve Margins from SEA (%); Forecasted Reserve in ICAP
through 2014 and UCAP through 2020................................................................................ 9

Table 1-4

New or Upgraded Utility-Owned or Leased Generation Capacity 2020-2026..............16

Table 1-5

Retired Utility-Owned or Leased Generation Capacity 2020-2026 .................................17

Table 1-6

MISO Interconnection Queue Snapshot in January 2020 for the State of Wisconsin .18

Table 2-1

MTEP19 Projects in Wisconsin ............................................................................................25

Table 4-1

Annual Growth Rates for Retail Electricity Sales (%) .......................................................38

Table 4-2

Wisconsin Electric IOU Bill Components for Residential Customers, 2019 ................46

Table 4-3

Wisconsin Municipal Electric Utility Bill Components for Residential Customers,
2019 ..........................................................................................................................................46

Table 4-4

Municipal Utility Bill Components for Cp-1 Customers, 2019........................................50

Table 4-5

Enrollment in Standard and TOU Rates .............................................................................51

Table 4-6

Enrollment in Incremental Load and Real-Time Pricing Rates .......................................52

Table 4-7

Average Residential Electricity Costs as a Percentage of Monthly Income for
Wisconsin, Adjacent Midwest States, and U.S., 2018 .......................................................53

Table 5-1

Approved Solar Additions in Wisconsin and Expected Renewable Energy Generation
and Percentage ........................................................................................................................66

Table 6-1

Carbon Dioxide Reduction Goals of Wisconsin Electric Providers ...............................74

Table A-1

Assessment of Electric Demand and Supply Conditions, Monthly Non-Coincident
Peak Demands, MW (using SEA monthly peak demand and previous SEA) ........... - 1 -

Table A-2

Wisconsin Aggregated Supply and Demand .................................................................... - 1 -

Table A-3

Data for Figure A-2 ............................................................................................................. - 3 -

Table C-1

Residential Average Rates in the Midwest and U.S. (cents/kWh) ................................ - 6 -

Table C-2

Commercial Average Rates in the Midwest and U.S. (cents/kWh).............................. - 6 -

Table C-3

Industrial Average Rates in the Midwest and U.S. (cents/kWh) .................................. - 6 -

Table C-4

Estimated Monthly Bill Data for Municipal Utility Cp-1 Customers .......................... - 9 -

vi

 DRAFT ‒ Strategic Energy Assessment 2026

EXECUTIVE SUMMARY

Under Wis. Stat. 196.491(2), the Public Service Commission of Wisconsin (Commission) prepares a
biennial Strategic Energy Assessment (SEA) to evaluate Wisconsin’s current and future electricity
supply. To address all aspects of the Commission’s mission to ensure the provision of quality utility
services in Wisconsin, this document addresses:
•

•
•
•

The adequacy of available supplies to support the generation of electricity, as well as the
adequacy of the transmission system to carry electricity supplies from generation sources to
customers;
The reliability of electric system operations to provide consistent service and avoid outages,
including through resilience against extreme events that challenge system operations;
The affordability of customers’ electric rates and bills, as regulated by the Commission’s
authority to approve rates set by regulated electric providers; and
The environmentally responsible provision of electric services, through programs and
policies related to energy efficiency, demand response, renewable energy, and electric
vehicles; as well as efforts among electric providers to reduce carbon dioxide emissions.

Under the SEA’s statutory and administrative code requirements, electric providers and transmission
owners operating in Wisconsin 1 file specified historical and forecasted information on electric
system operations. All electric providers submitted required data in November 2019, providing
forecasted information through 2026. 2 Commission staff analyzed the data submitted along with
other information sources to develop the SEA as a comprehensive resource for readers regarding
Wisconsin’s electric system. This draft SEA report summarizes staff analysis to date, and is being
distributed to interested parties for comment. Based on the comments received through public
hearings and written filings, the Commission will revise this report and issue a final SEA in late
2020.
The data used for SEA analysis was collected in advance of the global COVID-19 pandemic,
which began affecting Wisconsin on a broad scale in March 2020. Moreover, the effects of
the pandemic on Wisconsin’s electric system are rapidly evolving, and future conditions are
difficult to predict. This draft report provides the information available as of May 2020, and
identifies topics where the pandemic may have significant effects on the published findings. The
Commission will continue to monitor pandemic-related conditions and will update the final SEA
with new information.

For purposes of the SEA, electric providers required to submit data include any entity who owns, operates, manages or
controls, or who expects to own, operate, manage or control, electric generation capacity in Wisconsin greater than
5 megawatts (MW).
2 In addition, Dairyland Power Cooperative (DPC) updated its filing in January 2020 to incorporate its announced plans
to close the Genoa coal plant.
1

1

 DRAFT ‒ Strategic Energy Assessment 2026

ELECTRIC SUPPLY IN WISCONSIN
As of November 2019, Wisconsin electric providers projected limited future growth in electric
demand from customers. Statewide peak megawatt (MW) demand is projected to increase by less
than 0.4 percent annually between 2021 and 2026. While providers projected higher growth of
1.8 percent in 2020, the COVID-19 pandemic is likely to reduce peak demand as response measures
continue to significantly reduce commercial and industrial activity during the remainder of 2020.
Wisconsin electric providers plan to procure electric generation capacity sufficient to meet projected
customer demand, plus an additional “reserve margin” to ensure supplies are adequate if actual
demand exceeds projections. Wisconsin’s projected capacity meets or slightly exceeds the 8.9
percent reserve margin each year from 2021 to 2026.
While coal remains the most common source of electricity generation in Wisconsin, the share of
energy produced from coal declined from 63 percent to 48 percent between 2010 and 2018. The
share of energy produced from natural gas increased from 9 percent to 24 percent, driven by
decreases in natural gas prices. Solar and wind generation have also increased since 2010 in
connection with declining generation costs.
Electricity providers report as of May 2020 that they anticipate adding approximately 2,200 MW of
new owned or leased generation capacity through 2026, all from new natural gas combined-cycle
plants and new solar projects. Providers also report plans to retire 1,098 MW of generation capacity,
primarily coal resources and natural gas combustion turbines that operate less efficiently than new
combined-cycle plants.
If all additions and retirements are implemented as reported, coal would decline from 48 percent of
Wisconsin’s generation in 2018 to 40 percent in 2026, natural gas would increase from 27 percent to
33 percent, and solar resources would increase from less than 0.1 percent to 4.4 percent. The share
of solar resources may increase further through future procurements from independently developed
projects underway in Wisconsin.
ELECTRIC TRANSMISSION IN WISCONSIN
Wisconsin participates in the regional transmission system of the Midcontinent Independent System
Operator, Inc. (MISO), which operates an integrated electric grid across 15 states that supports
long-distance transmission of electricity supplies. Participating in MISO allows Wisconsin to access
low-cost energy resources located in nearby states, and offers access to a wholesale market with clear
and predictable energy prices that providers may use to maintain adequate electric supply.
MISO maintains primary responsibility for planning large transmission projects that cross state lines.
Commission staff participate as stakeholders within MISO’s planning process to ensure Wisconsin’s
needs and priorities are represented in final decisions.
MISO’s most recent planning process has identified 28 future transmission projects located
completely or partially in Wisconsin, with costs totaling $217.8 million. The largest share of costs
would be allocated to projects updating aging infrastructure and addressing condition issues.
2

 DRAFT ‒ Strategic Energy Assessment 2026

Commission staff have successfully advocated for improvements to MISO’s transmission planning
processes. With Wisconsin’s support, MISO has recently implemented data enhancements to more
accurately assess the benefits of proposed projects, and has proposed a framework to more precisely
allocate transmission costs to the customers receiving benefits.
RELIABILITY AND RESILIENCE
Wisconsin’s largest electric providers compare favorably to most states nationwide in minimizing the
number of outages that interrupt service to customers. The average duration of outages experienced
by Wisconsin customers falls closer to national averages.
Efforts to maintain the electric system’s resilience against extreme events such as severe weather and
cyberattacks has increased in recent years. The Commission’s Office of Energy Innovation has
partnered with state emergency management staff to develop energy-related emergency plans and
conduct exercises to identify improvements to emergency management practices. In response to the
public health emergency declared for COVID-19, the Commission is collecting information
regarding the effects of the pandemic on critical energy infrastructure, and collaborating with other
agencies to define appropriate responses.
CUSTOMER RATES AND BILLS
The Commission regulates the customer rates charged by investor-owned and municipal utilities to
allow utilities to recover their costs while maintaining the lowest feasible cost to customers. Total
costs for Wisconsin’s largest electric providers increased 1.8 percent between 2009 and 2018, with
increasing costs for electric generation and transmission accounting for the largest growth.
Continued increases in generation costs may occur in future years as providers continue to incur
construction and procurement costs from investing in new generation resources. These investments
may also be accompanied by fuel cost decreases due to the increased deployment of zero-carbon
energy resources that require no fuel. Ongoing application of savings from 2017’s federal tax
reform legislation will also support continued cost reductions.
Based on national data, Wisconsin residential customers are charged higher average rates than
Midwest or national averages, but also pay significantly less on their average monthly bills, due to
lower average levels of energy use. Comparisons between states should be made cautiously due to
differences between states in energy market conditions and regulatory frameworks.
Many Wisconsin electric providers offer innovative rate options designed to help customers exercise
control over their costs and reduce their energy bills. 1.5 percent of Wisconsin residential,
commercial, and industrial customers are enrolled in time-of-use and real-time pricing rates that can
reduce costs for both providers and customers by encouraging customers to shift their usage to
hours of the day where energy supply costs are lower. While many customers can benefit from
these rates, benefits may be limited for customers that are not able to reduce their energy
consumption during high-cost periods of the day.

3

 DRAFT ‒ Strategic Energy Assessment 2026

Low-income customers face a higher energy burden than other customers: they must pay a larger
percentage of their total income for the same amount of electric service as other customers.
Wisconsin electric providers and the Commission can seek to help low-income customers manage
their energy burden in multiple ways, including by referring customers to programs that offer energy
efficiency and bill payment assistance.
In March 2020, the Commission directed electric providers to take several steps to address increased
affordability concerns related to the COVID-19 pandemic, including prohibiting providers from
disconnecting service or charging late fees for any customer unable to pay their bill for the duration
of the public health emergency. The Commission also opened an investigation under docket 5-UI120 to conduct ongoing review of safety, reliability, and affordability issues related to the pandemic.
CLEAN ENERGY PROGRAMS AND POLICIES
Focus on Energy, Wisconsin’s statewide energy efficiency and renewable resource program,
provides a portfolio of programs to help customers throughout the state reduce their energy use.
From 2015 through 2018, Focus achieved lifetime savings sufficient to power more than two million
average Wisconsin homes for a year, and reduce carbon dioxide emissions by more than 28.5 million
tons. A recent national study found that Wisconsin ran the most cost-effective energy efficiency
program of any state in the country.
Beginning in 2020, Focus on Energy has deployed a restructured program portfolio intended to help
the program maintain savings levels and cost-effectiveness in future years. Focus on Energy will
also be conducting a potential study in 2020-2021 to review the amount of savings Focus will be
able to achieve in future years, and assess the program’s future impacts on reducing carbon
emissions and energy demand.
Wisconsin electric providers operate demand response programs designed to reduce energy demand
during peak periods and create financial savings for providers and customers. While available
response capacity reached nearly 10 percent of statewide peak demand in 2018, electric providers
have only deployed a small fraction of available resources. While some providers are discontinuing
established demand response programs due to low enrollment and technical limitations, smart
thermostats and other wi-fi technologies are presenting opportunities to establish new program
models.
The primary driver for renewable resource development during the past decade has been compliance
with Wisconsin’s Renewable Portfolio Standard law. Providers have met the Renewable Portfolio
Standard (RPS) requirement to provide at least 10 percent of electricity generation through
renewable resources each year since 2013, primarily from wind energy received through the regional
transmission system.
Declining costs, environmental benefits, and customer interest in zero-carbon energy are beginning
to drive increased renewable deployment above RPS requirements. Recently approved solar energy
projects would increase renewable energy to 13 percent of generation by 2023, and further increases
would occur if other planned projects are approved and implemented. Electric providers have also
4

 DRAFT ‒ Strategic Energy Assessment 2026

increased their total capacity offered through community solar programs by 61 percent between
2017 and 2019.
Wisconsin had more than 7,000 customer-owned renewable generation installations operating in
2019, with capacity equal to 1.66 percent of statewide capacity. Customer-owned solar installations
account for more than 90 percent of the total number of customer-owned renewable installations
and 0.64 percent of total statewide capacity.
Large-scale use of electric vehicles could have significant implications for Wisconsin’s electric
system, by increasing electric demand, modifying the timing and location of energy use, and
presenting new considerations for customer rates and service arrangements. The Commission has
opened an investigation to consider EV-related policies and conducted a collaborative, stakeholderdriven process that has identified multiple issues for continued consideration.
ELECTRIC SYSTEM EMISSIONS
Within the past two years, Wisconsin’s five largest electric providers have established goals to reduce
carbon dioxide (CO 2 ) emissions from electric generation by either 80 percent or 100 percent by
2050. Achievement of those goals would reduce statewide emissions by approximately two-thirds in
2050. Further reductions may be achieved by other providers who have not set formal goals but are
also retiring fossil fuel generation and adding zero-carbon generation resources.
Wisconsin electric providers project that their 2020 emissions will achieve reductions of
37.5 percent, driven substantially by the retirement of nearly 1,800 MW of coal generation between
2018 and 2020. Providers expect to achieve continued emissions reductions in future years through
deployment of natural gas in place of coal generation, deployment of additional solar resources,
increased zero-carbon generation on MISO’s regional grid, and continued increases in energy
efficiency.

5

 DRAFT ‒ Strategic Energy Assessment 2026

CHAPTER 1 ‒ ELECTRIC SUPPLY IN WISCONSIN

By statute, the Strategic Energy Assessment (SEA) must assess the adequacy of Wisconsin’s electric
supply: whether the state’s electric providers have procured enough total power to meet customers’
total electric demand. At present, Wisconsin electric providers are assessing supply in the midst of a
transition in electric generation sources, as declining costs and environmental considerations begin
to increase the share of electricity supplies generated from natural gas and zero-carbon sources such
as wind and solar energy.
DEFINING SUPPLY NEEDS
Wisconsin, and electric providers nationwide, define adequate supply as meeting the electricity
demand of all customers at all times of the year. In practice, sufficient energy must be available to
meet the highest, or peak, usage levels anticipated at any point during the year.
Demand for electricity fluctuates both throughout the day and throughout the year. As shown in
Figure 1-1, yearly peak demand levels in Wisconsin have varied between 13,000 and 15,000 MW of
electricity demand. Year-by-year differences are influenced by weather conditions as well as other
influences such as the addition and subtraction of significant customer loads.
Figure 1-1

Historical and Forecasted Maximum Monthly Peak Demand by Year, MW 3

Monthly Peak Demand (MW)

16,000
15,000
14,000
13,000
12,000
11,000
10,000
2000

2002

2004

2006

2008

2010

2012

2014

2016

2018

2020

2022

2024

2026

2028

Year

As shown in Figure 1-2, peak energy demand occurs in the summer months of June, July, and
August, influenced largely by the increase in air conditioner use. Smaller peaks have historically
occurred in the winter, in part due to higher heating loads and the use of holiday lighting. These
non-summer peaks have gradually been shifting closer to spring and autumn in recent years due to

3

Source: Aggregated electricity provider data responses, docket 5-ES-110.

6

 DRAFT ‒ Strategic Energy Assessment 2026

varied changes in weather, technology use, and customer demand. More detailed data on energy use
by month can be found in Appendix A, Table A-1.
Figure 1-2

Average Non-Coincidental Peak Demand per Month for the Period 2015-2019 4

16000
14000

Peak Demand (MW)

12000
10000
8000
6000
4000
2000
0

As of November 2019, Wisconsin electric providers expected peak demand to increase each year
from 2020 to 2026, but for those increases to be limited in size. Table 1-1 shows that, after a
forecasted increase of 1.8 percent between 2019 and 2020, providers collectively project growth
levels averaging 0.37 percent annually over the following six years. These forecasts predate the
onset of the COVID-19 pandemic, which may reduce monthly peak loads, particularly if significant
pandemic response measures continue to reduce commercial and industrial electric use during the
remainder of 2020.
Table 1-1
Year
2019
2020
2021
2022
2023
2024
2025
2026

4
5

Expected Maximum Monthly Peak Loads, with Percentage Increases from Previous Year 5
Maximum Monthly Peak Load (MW)
14,023
14,277
14,370
14,420
14,469
14,517
14,561
14,601

Percentage Increase from Previous Year (%)
1.81%
0.65%
0.35%
0.34%
0.33%
0.30%
0.27%

Source: Aggregated electricity provider data responses, docket 5-ES-110 and previous SEA reports.
Source: Aggregated electricity provider data responses, docket 5-ES-110.

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 DRAFT ‒ Strategic Energy Assessment 2026

RESERVE MARGINS AND TOTAL REQUIRED ELECTRIC SUPPLY
Projections of peak energy demand serve as the foundation for determining the amount of electricity
supply needed to meet customer demand. However, these projections may not match actual future
conditions, due to the inherent uncertainties in forecasting customer demand and the variability of
peak usage due to weather and other factors. To account for these uncertainties, forecasters define
adequate supply to include a “reserve margin” over and above projected peak levels to reduce the
risk of inadequate supply if actual demand exceeds projections.
Wisconsin generates and purchases energy supplies within the regional context of the Midcontinent
Independent System Operator, Inc. (MISO), which operates an integrated electric grid across
Wisconsin and several other states. (See the Sources of Electricity section and Transmission chapter
for more detail on MISO.) Wisconsin therefore assesses its energy supplies relative to MISO’s
planning reserve margin, set at 8.9 percent for the 2020-2021 planning cycle. 6 In effect, this reserve
margin establishes that electric providers in the MISO market should maintain energy supplies that
exceed projected electric demand by 8.9 percent. MISO defines the value of this margin based on
aggregate unforced capacity (UCAP), which takes into account the total energy available from
generation sources as well as the likelihood that conditions at any given time may include unit
outages and other limitations on actual operating capacity. 7
Table 1-2 shows total projected capacity for Wisconsin electric providers. The projections submitted
by providers incorporate Wisconsin-based energy sources, including planned generation additions and
retirements announced as of January 2020, as well as generation outside of the state that is owned or
purchased by a Wisconsin provider and delivered through MISO’s regional grid. (More detailed
calculations of these projections can be found in Appendix A, Table A-2.) Under these projections,
Wisconsin’s total capacity falls below MISO’s 8.9 percent planning margin in 2020, at 7.76 percent.
Annual projections from 2021 through 2026 meet or exceed the planning margin, ranging from 8.9 to
9.9 percent. These forecasts do not take into account any potential reductions in demand, particularly
in 2020, due to the COVID-19 pandemic or any associated changes in economic conditions.
Moreover, MISO’s subsequent capacity planning auction in April 2020 identified sufficient capacity
resources in Wisconsin, likely due to established arrangements for state electric providers to import
power from out of state when needed to address capacity shortfalls on high-demand days.

MISO sets updated reserve margin values on an annual basis, and the value of 8.9 percent represents an increase of one
percent from the value set for the 2019-2020 planning cycle. This increase was attributed to changes in the mix of generating
resources, aging fossil fuel generating stations, and changes to load profiles and forecasts. See
https://cdn.misoenergy.org/20191106%20RASC%20Item%2003a%20PY%20202021%20LOLE%20study%20results397078.pdf
7 The Commission has also historically set planning reserve margin guidelines for Wisconsin electric providers, to serve as a
guideline for state-level planning and a reference for annual capacity reports to the Commission under docket 5-EI-141. In its
Order of October 10, 2008 (PSC REF#: 102692), the Commission set a state level planning guideline of 14.5 percent when
considering generation needs beyond the current year. For the current year planning reserve margin, the Commission requires
that Wisconsin electric utilities meet the MISO annual capacity requirement.
6

8

 DRAFT ‒ Strategic Energy Assessment 2026
Table 1-2

Wisconsin Aggregated Supply and Demand, MW 8

Net Capacity 9
Expected Demand 10
UCAP Planning Reserve Margin 11

2020
15,842
14,700
7.76%

2021
15,853
14,485
9.45%

2022
15,692
14,381
9.12%

2023
15,804
14,375
9.94%

2024
15,648
14,371
8.89%

2025
15,836
14,450
9.59%

2026
15,878
14,511
9.42%

Historically, Wisconsin’s energy supply has exceeded required capacity by more substantial margins,
as shown in Table 1-3. Higher reserve margin values published in previous SEA reports reflected
large-scale construction of energy generation sources by Wisconsin electric providers in the 1990s
and 2000s and low rates of demand growth.
Table 1-3
Planning Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026

Forecasted Planning Reserve Margins from SEA (%); Forecasted Reserve in ICAP through 2014 and
UCAP through 2020 12
Final SEA 2010
11.7
24.1
26.1
25.8
24.9
20.1
18.7
15.1

Final SEA 2012
6.6
7.3
21.9
15.8
15.8
13.0
11.6
13.3

Final SEA 2014

20.5
18.9
17.3
15.3
13.7
14.3
13.8

Final SEA 2016

16.9
13.9
13.7
16.4
15.5
14.7
13.6

Final SEA 2018

12.0
5.9
8.2
9.0
9.2
7.8
6.4

Final SEA 2020

7.8
9.5
9.1
9.9
8.9
9.6
9.4

While relatively low demand growth has continued, sources of supply have also started to decline in
scale, in part due to recent and projected future retirements of generation facilities. While current
projections slightly exceed reserve margin standards in later years, any future changes in existing
generating capacity beyond those currently projected could impact whether Wisconsin meets those

Source: Aggregated electricity provider data responses, docket 5-ES-110. Reflects all announced generation additions and
retirements as of April 2020.
9 Net capacity numbers include projected future generation reported by utilities; whether and when those additions are
implemented may vary based on multiple factors, including federal and state regulatory approvals and construction timelines.
Specifically included in years 2025 and 2026 are the DPC-owned portion of the Nemadji Trail Energy Center (NTEC), which
was approved by the Commission in early 2020. DPC had excluded NTEC from its generating assets in those years due to
uncertainty surrounding the timing of the plant’s deployment, but in light of the Commission’s approval of the project
Commission staff felt it appropriate to include this generator for the start of its commercial operation in 2025.
10 Defined by MISO as coincident load serving entity (LSE) peak to MISO peak gross of demand response net full
responsibility transaction (FRT).
11 Equals (net capacity/expected demand) – 1.
8

12

Source: Table c and previous SEA reports

9

 DRAFT ‒ Strategic Energy Assessment 2026

standards. Further details on providers’ projected generation retirements and additions are
described in the Projecting Energy Supply section below.
SOURCES OF ENERGY SUPPLY
Wisconsin electric providers can procure energy by operating their own generation plants, entering
into long-term purchase power agreements (PPA) with other generation owners, or purchasing
electricity from the MISO’s regional wholesale market, which operates a day-ahead market and a real
time market. 13 (See Appendix A, Figure A-1 for data on MISO market prices.)
Providers traditionally also rely on multiple different sources of electric supply.
•

•

•

Baseload resources are designed to meet the minimum level of electric demand over a
lengthy duration of time. Baseload power plants use generation sources that can operate on
a consistent, ongoing basis, including coal, nuclear, and natural gas combined-cycle plants,
and therefore have high “capacity factors” that reflect the percentage of time during the year
that they operate. Nuclear plants typically have capacity factors of up to 90 percent, while
coal and natural gas plants typically have capacity factors of 60 percent or more.
Intermediate resources operate during hours of significant demand, but operate less
frequently than baseload plants during periods of low demand such as weekends and
overnight hours. Common generation sources for intermediate plants include natural gas
combined-cycle plants and hydroelectric power. Capacity factors for intermediate plants
typically range between 15 and 60 percent.
Peaking resources typically operate only during peak demand times, such as summer
afternoons in hot weather. Peaking plants generally have a capacity factor of 15 percent or
less. Examples of peaking plants are natural gas combustion turbines and diesel generators.
Solar energy may also serve as a peaking resource when it meets demand during daylight
peaking hours.

Generally, an electric provider will run those plants whose cost to produce electricity is less than the
price in MISO’s wholesale market. For resources such as solar and wind, for which availability varies
by weather conditions, electric providers must also take into account whether the resource is
available when energy is needed. (See the Reliability and Resilience Chapter for more discussion on
reliability considerations for solar and wind resources.)
Figure 1-3 depicts Wisconsin electric providers’ in-state operating resources in 2020.

13 While the day-ahead and real time markets serve as the primary platforms for providers to meet overall supply needs,
MISO also operates transmission rights and ancillary services markets to support grid operations.

10

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 1-3

Electric Providers’ Generation Resources in Wisconsin

Figure 1-4 breaks down the total capacity of Wisconsin’s in-state operating resources by generation
source as of January 2020. Coal accounts for approximately 42 percent of total generation capacity
in Wisconsin, and natural gas for approximately 38 percent. Zero-carbon energy sources account
for approximately 16 percent of capacity, including 7 percent from nuclear energy and 4 percent
from wind energy. 14

14

Zero-carbon energy sources include nuclear, wind, solar, biomass, and hydro.

11

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 1-4

Capacity – January 2020

Because different resources operate with different capacity factors, the amount of energy generated
from different fuels differs from the amount of capacity. Due to their status as baseload fuels, the
share of energy produced from coal and nuclear sources exceeded their share of in-state capacity,
accounting in 2018 for 48 percent and 16 percent of energy generation, respectively. Wind and solar
energy accounted for a slightly smaller share of energy than capacity due to comparatively low
capacity factors.
Figure 1-5

Generation - 2018

12

 DRAFT ‒ Strategic Energy Assessment 2026

While it is difficult to determine the precise share of generation sources from purchased power, PPA
data reported by electric providers suggests that Wisconsin’s purchased power may include
somewhat higher shares of zero-carbon power sources than in-state generation. In 2020, the market
purchases projected by providers are approximately 63 percent coal and natural gas, compared to
approximately 75 percent projected from Wisconsin-owned sources. One contributing factor is the
greater availability of wind power in MISO region states west of Wisconsin, including Minnesota,
Iowa, and North Dakota. Due to windier conditions in those states, wind power sources in those
states can produce energy more cost-effectively, at a higher capacity factor. As detailed in Appendix
A, Figure A-3, wind resources have steadily increased as a share of MISO’s total generation since
2014.
Historical Trends in Sources of Supply
While coal still represents the most common source of electricity generation in Wisconsin, it is
accounting for a declining share of total load. As shown in Figure 1-6, the share of energy produced
from coal has declined from approximately 63 percent to approximately 48 percent between
2010 and 2018.
Figure 1-6

Comparison of 2010 and 2018 Generation Data

Natural gas resources account for the largest increase in generation share, increasing from 9 percent
of generation in 2010 to 24 percent in 2018. This increase has been driven primarily by low natural
gas prices. As shown in Figure 1-7, natural gas prices since 2011 have generally remained lower than
previous levels, in part due to an expansion in sources of available supply.

13

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 1-7

Henry Hub Natural Gas Average Annual Cost in $/MMBtu 15

$5.000
$4.500
$4.000
$3.500
$3.000
$2.500
$2.000
$1.500
$1.000
$0.500
$0.000

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Multiple zero-carbon energy resources have also experienced significant declines in price during the
past decade. As shown in Figure 1-8, since 2010 total generation costs per kilowatt-hour (kWh)
have declined 63 percent for solar energy in the Midwest region. Although base costs for wind
energy in Wisconsin are higher than in Minnesota, costs in both states have declined at a comparable
rate of 30 percent since 2010. After factoring in available tax benefits and other accounting benefits
that further reduce prices for many individual projects, these declines have made solar and wind
resources more price-competitive with natural gas and coal resources.

15

Source: Energy Information Administration.

14

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 1-8

Estimated Levelized Unsubsidized Cost of Electricity for Solar and Wind Resources in $/MWh 16

$140

$120

$/MWh

$100

$80

Wind-WI
Wind-MN

$60

Solar

$40

$20

$0

2010

2013

2016

2019

As a result, solar and wind generation increased between 2010 and 2018. (Total zero-carbon
generation decreased from 28 percent to 25 percent due to the closure of the Kewaunee nuclear plant,
which offset the gains made by solar and wind.) No utility-scale solar resources were deployed in 2010
and they still accounted for less than 0.1 percent of generation in 2018, but are projected to grow to
slightly more than 4 percent by 2026. If the growth in solar resources meets the current projection,
solar will be the largest source of zero-carbon energy, after nuclear resources, by 2026.
Increased deployment of natural gas and zero-carbon energy resources have been influenced by
environmental considerations as well as declining prices. As the Emissions chapter outlines in
greater detail, a number of electric providers in Wisconsin have set goals to reduce carbon dioxide
emissions from their generation sources, and report that increased deployment of natural gas and
zero-carbon energy resources will be two primary approaches to pursuing those goals. The growing
emphasis on reducing emissions through shifts in generation has corresponded with a de-emphasis
on initiatives to install emissions control equipment on existing generation facilities. While
Wisconsin electricity providers have spent more than $3 billion on emissions control projects since
2000, no such projects are currently in progress or planned for future years.

16

Source: Energy Information Administration.

15

 DRAFT ‒ Strategic Energy Assessment 2026

PROJECTING ENERGY SUPPLY, 2020-2026
Electric providers’ projected additions and retirements indicate that the transition in electric
generation sources will continue. As shown in Table 1-4, Wisconsin electric providers have reported
as of April 2020 that they will add approximately 2,200 MW of new owned or leased generation
capacity between 2020 and 2026. 57 percent of this capacity will come from new natural gas
combined-cycle plants, including 1,214 MW from two Commission-approved plants, West Riverside
and Nemadji Trail Energy Center. 17 Solar projects comprise the remaining 43 percent of projected
generation additions, including Commission-approved projects as well as some proposed future
additions not yet submitted for regulatory review. Independent solar developers are also in the
process of implementing or planning multiple additional solar projects in Wisconsin that are not
included in Table 1-4 but may be leased by electric providers at a future date for additional
generation capacity.
Table 1-4

New or Upgraded Utility-Owned or Leased Generation Capacity 2020-2026

Year

Nameplate
Capacity (MW)

2020

50

2020

100

2020

50

2020

100

2020

9

2020

5

2020

664

2021

50

2021

100

2021
2022

50
150

2023

50

2023

300

2025

550 18

Name

New or
Existing Site

Owner/
Leaser

Fuel

Location

New

MGE

Solar

Iowa County

New

WPS

Solar

Iowa County

Two Creeks

New

MGE

Solar

Two Creeks

New

WPSC

Solar

New

MGE

Solar

Dane County

New

MGE

Solar

Dane County

New

WP&L

Natural
Gas

Beloit

New

MGE

Solar

Iowa County

New

WEPCO

Solar

Iowa County

New
New

WP&L
WP&L

Solar
Solar

TBD
TBD

New

MGE

Natural
Gas

Rock County

New

WP&L
DPC,
SWL&P

Solar
Natural
Gas

Badger Hollow
(phase 1)
Badger Hollow
(phase 1)

Dane County
Airport
Morey Field
Middleton
Airport
West Riverside
Badger Hollow
(phase 2)
Badger Hollow
(phase 2)
Solar 2021
Solar 2022
Riverside
Energy Center
Expansion
Solar 2023
Nemadji Trail
Energy Center

New

Manitowoc
County
Manitowoc
County

PSC Status and
Docket #
5-BS-228,
approved
5-BS-228,
approved
5-BS-228,
approved
5-BS-228,
approved
3270-CE-128,
approved

6680-CE-176,
approved
5-BS-234,
approved
5-BS-234,
approved

TBD
City of Superior

9698-CE-100

A lawsuit that petitioned for judicial review of the Commission’s conditional approval of the Nemadji Trail Energy
Center was filed in February of 2020, as Dane County Docket No. 20-CV-177, and remains pending as of the date of
this document.
18 The application in docket 9698-CE-100 for the Nemadji Trail Energy Center (NTEC) stated that the plant would have
a nameplate capacity of approximately 550 MW. Based on the record developed in that docket, the Commission’s final
decision authorizes the construction of the NTEC at a nameplate capacity of approximately 625 MW. As construction
17

16

 DRAFT ‒ Strategic Energy Assessment 2026

As shown in Table 1-5, Wisconsin electricity providers report as of April 2020 that they plan to
retire 1,098 MW of generation capacity by 2026. Approximately 52 percent of retired capacity will
come from natural gas combustion turbines used as peaking resources, which typically operate less
economically than new natural gas combined cycle units. DPC’s planned retirement of the Genoa
coal plant accounts for another 31 percent of total retired capacity.
Table 1-5

Retired Utility-Owned or Leased Generation Capacity 2020-2026

Year

Name

Owner/Leaser

2019

Bay Front 4

2019
2020
2020

Wheaton 5
Fitchburg 1, 2
Rock River 3, 4, 5,
6
Sheepskin 1
Nine Springs 1
Sycamore 1, 2
Genoa Generating
Station
Blount Street 6, 7
Rosiere Wind Farm
Wheaton 1, 2, 3, 4,
6

2020
2021
2021
2021
2024
2024
2025

Capacity (MW)

Fuel

Location

NSPW

Type of Load
Served
Peaking

20

Ashland, WI

NSPW
MGE
WP&L

Peaking
Peaking
Peaking

53
29, 29
27, 15, 51, 51

Biomass or
Biogas
Fuel Oil
Natural Gas
Natural Gas

Eau Claire, WI
Madison, WI
Beloit, WI

WP&L
MGE
MGE
DPC

Peaking
Peaking
Peaking
Base

40
16
18, 24
345

Natural Gas
Natural Gas
Natural Gas
Coal

Edgerton, WI
Madison, WI
Madison, WI
Genoa, WI

MGE
MGE
NSPW

Base
Intermittent
Peaking

50, 50
11
54, 54, 54, 54,
53

Natural Gas
Wind
Natural Gas
and Fuel Oil

Madison, WI
Casco, WI
Eau Claire, WI

As shown in Figure 1-9, if all additions and retirements are implemented as reported by electric
providers, coal would decline from 48 percent of Wisconsin’s generation to 40 percent, natural gas
would increase from 27 percent to 33 percent, and solar resources would increase from less than
0.1 percent to 4.4 percent. The share of solar resources may increase further through future
procurements from independently developed projects.

of the NTEC is not complete, and the final nameplate capacity is not known, 550 MW has been used in this SEA in
order to conservatively estimate generation resources.

17

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 1-9

2018 vs Forecast 2026 Generation Comparison

As noted above, Wisconsin’s projected total generation capacity does not meet MISO’s reserve
margin standards for 2020, and providers would likely rely on increased power purchases in the
MISO regional market to maintain efficient supplies during periods of especially high demand.
These purchases would occur in a MISO regional market also experiencing changes in its resource
mix. As shown in Table 1-6, solar resources account for more than 75 percent of capacity proposed
to be added to MISO’s regional market as of January 2020, while wind resources account for an
additional 12.5 percent. Because many individual projects posted to MISO’s interconnection queue
are not implemented, Table 1-6 should not be considered a precise quantification of the future
changes in the regional resource mix. However, the current composition of the queue does still
provide an indication that renewable resources will account for a growing share of regional market
capacity.
Table 1-6

MISO Interconnection Queue Snapshot in January 2020 for the State of Wisconsin

Type
Natural gas combined cycle
Wind
Battery storage
Solar
TOTAL

Amount (MW)
530
900
320
5400
7150

Percentage
7.5
12.5
5
75
100

Ongoing trends in generation costs could also significantly influence the timing of further changes
and the generation sources to be chosen. Some forecasts, including from the National Renewable
Energy Laboratory (NREL), suggest that solar and wind costs will continue to decline by an
additional 40 percent or more through 2049, which could continue to accelerate the increased
18

 DRAFT ‒ Strategic Energy Assessment 2026

deployment of those resources. 19 (See Appendix A, Figure A-2 and Table A-3, for detailed NREL
forecast data, including comparisons to costs for other generation sources.) On the other hand,
forecasts by the federal U.S. Energy Information Administration (EIA) project solar and wind costs
to remain relatively stable in future years, which may result in less rapid deployment.
In addition to generation from solar and wind, the changing costs of battery storage resources could
also influence future resource decisions, by providing options to store previously generated
electricity for peak periods rather than building additional peaker resources. At current cost levels,
Wisconsin electric providers have not formally proposed storage resources to the Commission.
However, by one estimate, average costs per kWh of storage resources have declined by nearly
50 percent between 2016 and 2019. 20 Forecasts again differ on the speed by which costs will decline
in future years, but multiple forecasts suggest continued cost declines of up to 40 to 60 percent, 21
which could result in more cost-effective storage opportunities in the coming years. 22
Ongoing changes in generation costs, as well as pursuit of carbon reduction goals, will also influence
electric providers’ future decisions on whether, and when, to retire additional generation units. In
addition to weighing their own internal decision factors, electric providers must also receive MISO
approval for unit retirements:
•

•

First, providers considering a retirement may submit an Attachment Y2 form requesting
MISO to evaluate the impacts on grid operations of the potential retirement. MISO
conducts modeling analysis to assess the adequacy of supplies on its regional grid in the
absence of the unit, and informs the requesting provider whether it concludes that adequate
generation supply remains available within MISO’s regional grid to meet customer needs. If
MISO concludes that adequate supply would not be available, its response indicates that
MISO would consider designating the proposed unit a System Support Resource (SSR),
which would require it to continue operating until further generation and/or transmission
additions can provide for adequate supply.
Providers who subsequently choose to pursue a unit retirement must submit an Attachment
Y form requesting MISO’s formal approval. MISO conducts additional, up-to-date
modeling analysis on the adequacy of supply. If the analysis reveals no supply adequacy
concerns, MISO authorizes the provider to proceed with retirement. 23 However, if

National Renewable Energy Laboratory (NREL) 2019 Annual Technology Baseline: Electricity. https://atb.nrel.gov/.
Bloomberg New Energy Finance 2019 Battery Price Survey
21 Ibid. and NREL Annual Technology Baseline Forecasts.
22 The cost-effectiveness to providers of deploying storage depends on available revenue streams, in addition to the
upfront costs of installation projected here. For example, storage is particularly cost-effective in markets with large
differences between wholesale electric prices at different hours of the day, which allows for larger arbitrage savings from
storing energy for use during high-cost hours. MISO has less hour-by-hour price variability than some other regional
markets, which may limit the relative cost-effectiveness of storage compared to other parts of the country.
23 To allow electric providers flexibility to make their own final determination whether to proceed with retirement,
MISO initially notifies a proposer that its Attachment Y study is complete without providing any results. The provider
may choose, at this time or any time before, to rescind its Attachment Y request. In this event, MISO will not release the
19
20

19

 DRAFT ‒ Strategic Energy Assessment 2026

retirement would result in inadequate supplies, MISO conducts further review of available
resources and proceeds with an SSR designation if no adequate alternatives are identified.
As part of the Commission’s data request for this SEA, electric providers submitted all Attachment
Y2 and Attachment Y documentation submitted to or received from MISO between 2017 and 2019.
Provider responses confirm that announced, upcoming retirements have followed the MISO
process, such as the 2020 retirements of the Rock River and Sheepskin natural gas plants. 24
However, retirements under consideration by electric providers may be foregone, or delayed, in
response to MISO findings that continued operation is needed to support adequate regional supply.

study results to the provider. If the provider does not choose to rescind its request, retirement is approved upon the
provider’s receipt of study results confirming MISO’s approval.
24 See PSC REF#: 381398.

20

 DRAFT ‒ Strategic Energy Assessment 2026

CHAPTER 2 ‒ ELECTRIC TRANSMISSION IN WISCONSIN

Wisconsin electric providers are responsible for delivering adequate and reliable service directly to
customers, through their own distribution systems. In addition, high-voltage transmission lines are
required to carry energy across long distances and deliver electricity to customers located far from
generation resources. Wisconsin participates in the regional transmission system of MISO, which
operates an integrated electric grid serving all or part of 15 states and one Canadian province,
identified in Figure 2-1.
Figure 2-1

MISO Regional Transmission Map

Participation in MISO is designed to help the state electric system access additional benefits within a
larger regional context, including:
•

Accessing less expensive wholesale energy and capacity resources available outside of
Wisconsin, including low-cost zero-carbon energy resources, such as wind produced west of
Wisconsin (see Supply chapter);
21

 DRAFT ‒ Strategic Energy Assessment 2026

•
•

•

Reducing the generation capacity reserves any single provider may need to meet peak
customer demand by taking advantage of access to more diverse suppliers;
Offering access to a wholesale market with clear and predictable energy prices, which can
allow providers access to energy resources and use price signals to guide their own
investment decisions; and
Managing the transmission grid to enhance region-wide reliability.

Wisconsin has approximately 15,700 miles of high-voltage transmission lines in service, which are
mapped in Figure 2-2. 25 Transmission lines with higher voltage ratings are designed to carry the
largest volumes of energy efficiently over longer distances. High-voltage lines are located to carry
energy from Wisconsin generation facilities to areas of high customer demand within the state, and
to connect those high-demand areas with other states in the MISO region. Figure 2-2 does not
include the Cardinal-Hickory Creek transmission line approved by the Commission in 2019, 26 which
will enhance transmission connections between La Crosse, Madison, and Dubuque, Iowa when
construction is completed.

Wisconsin defines high-voltage transmission lines as those with rated capacity of 69 kilovolts (kV) or higher.
This transmission project was approved by the Commission in docket number 5-CE-146. That approval is the subject
of several lawsuits. The state lawsuits have been consolidated in Dane County Circuit Court as case number 19-cv-3418,
and a federal action is also pending in U.S. District Court for the Western District of Wisconsin as case number
19-cv-1007.

25
26

22

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 2-2

Existing Transmission Lines

TRANSMISSION PLANNING
Wisconsin electric providers typically initiate planning for local transmission projects, including
those that remain within state lines. MISO maintains primary responsibility for planning larger
projects, including most projects that cross state lines within its region. Commission staff
participate as stakeholders within MISO’s process for developing regional plans, in order to ensure
Wisconsin’s energy needs and policy priorities are accounted for in planning decisions. The
23

 DRAFT ‒ Strategic Energy Assessment 2026

Commission also maintains jurisdiction over final decisions related to the approval and siting of
transmission lines constructed within the state.
The annual MISO Transmission Expansion Planning (MTEP) process serves as a primary
foundation for reviewing transmission needs and identifying and developing transmission projects.
MTEP focuses on ensuring infrastructure is sufficient to provide adequate energy delivery
throughout the MISO region and to meet national standards for maintaining service reliability. (See
the Reliability and Resilience chapter for more detail on reliability measurement.) Issues reviewed
and addressed through the MTEP process can include:
•

•
•
•
•

Baseline reliability initiatives to ensure adequate transmission is available throughout the
regional grid, such as increasing capacity to eliminate localized areas of transmission
congestion where available energy exceeds transmission capacity, which can increase energy
prices as well as increase the risk of service outages due to overheating or insufficient energy
availability;
Generation interconnection updates to support the addition of new generation facilities in
specific locations;
Reliability initiatives to address more localized transmission capacity needs within states;
Age and condition updates to replace or enhance existing transmission infrastructure; and
Load growth projects to update the transmission system to meet increased energy usage in
specific locations.

The most recent planning process, MTEP 2019 (MTEP19), identified a new set of proposed
projects over and above those approved in previous planning cycles. The overall MTEP19
identified 480 transmission projects to meet needs across the full MISO system, at a total cost of
$3.9 billion. 27 As shown in Figure 2-3, reliability and baseline reliability projects accounted for
slightly more than half of the total project costs. Project allocations by MISO region can be found
in Appendix B.

27

https://cdn.misoenergy.org/MTEP19%20Executive%20Summary%20and%20Report398565.pdf

24

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 2-3

MISO Transmission Projects Identified in MTEP19

MTEP19 includes 28 future projects located completely or partially in Wisconsin, with costs totaling
$217.8 million. As shown in Table 2-1, updates to address aging infrastructure and condition issues
accounts for the largest number of projects and largest share of costs. Projects for “Other Local
Needs” include installing optical cable to enhance communication and security, and improving
interconnections between transmission equipment in different regions of the state.
Table 2-1

MTEP19 Projects in Wisconsin
Transmission Project Type
Age and Condition
Other Local Needs
Load Growth
Reliability
Baseline Reliability Projects
Generation Interconnection Planning
Totals:

Number
11
5
2
7
2
1
28

Estimated Cost
$91.4 million
$46.7 million
$30.8 million
$23.1 million
$19.5 million
$6.2 million
$217.8 million

While MTEP19 identified projects that will receive further analysis and development from MISO
and participating states, not all identified projects may ultimately be implemented. A number of
projects identified in previous MTEP processes were not completed for a variety of reasons,
including changing market conditions that reduced or eliminated the reliability needs previously
established or that reduced the projected cost-effectiveness of the project.
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MISO’s upcoming MTEP21 planning process will update the modeling scenarios used to assess
transmission needs, to ensure modeling assumptions are consistent with the pace of change related
to the decreased use of coal generation and the increased use of zero-carbon energy resources,
including renewable energy. Once implemented, new projects may result in changes to the mix of
transmission projects identified through MTEP. Commission staff participate on an ongoing basis
in MISO stakeholder processes to ensure that project assumptions and analyses are consistent with
conditions and requirements in Wisconsin, and that they are likely to result in project proposals that
appropriately meet the state’s future transmission needs and policy considerations.
In addition to the annual, reliability-focused MTEP process, MISO undertakes additional planning
studies to address other issues affecting transmission. The Badger-Coulee and Cardinal-Hickory
Creek lines recently approved in Wisconsin were initially identified through MISO’s 2011
Multi-Value Project (MVP) study. The MVP study was designed to identify transmission upgrades
needed to support the efforts of several participating MISO states to meet public policy goals such
as compliance with renewable portfolio standards, as well as to increase reliability and provide
economic benefits.
Several ongoing planning studies at MISO may inform project proposals at a future date. For
example, MISO’s Renewable Integration Impact Assessment (RIIA) is assessing the grid effects of
incorporating increasing amounts of renewable energy resources in the MISO region. In addition to
assessing effects for maintaining day-to-day operational reliability (see the Reliability and Resilience
chapter), RIIA is assessing the impacts on transmission capacity, including the review of the
development of additional transmission infrastructure as well as “non-wires alternatives” such as
increased use of localized storage resources. Additional specific studies are reviewing the potential
future effects of increased electric vehicle usage in the MISO region, specific constraints affecting
efficient transmission of information among different zones within the MISO region, and
coordination of planning and operations across the “seams” between MISO and other regional
transmission operators. Commission staff continue to monitor and provide input on all studies, to
ensure they are conducted effectively and meet Wisconsin’s state-specific needs, interests and
priorities.
TRANSMISSION COSTS
Transmission costs to Wisconsin electric providers have been increasing in recent years, and account
for an increasing share of total costs to utility customers. (See the Customer Rates and Bills chapter
for more detail.) Partly for this reason, Commission staff prioritize a close review of costs during
their participation in MISO’s transmission planning processes. Two specific areas of scrutiny
include:
•
•

Ensuring clear identification and rigorous measurement of the benefits provided by each
project; and
Establishing appropriate methods for allocating the costs of transmission upgrades among
electric providers and utility customers.

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To achieve MISO approval, proposed transmission projects are typically required to achieve a
benefit-cost ratio of at least $1.25 in benefits for every $1 in costs. Historically, MISO quantified
project benefits solely in terms of reduced production costs, such as those associated with reducing
transmission system congestion. However, Commission staff have participated in MISO initiatives
to identify and implement additional benefit metrics, with the goal of providing more accurate and
detailed evaluation of project impacts, and identifying all positive value to Wisconsin associated with
transmission upgrades. In 2019, MISO, with support from Commission staff, approved two
additional benefits to be added to projects, quantifying avoided costs of transmission investments
and reduced costs of importing energy from outside the MISO region. 28 Commission staff will also
monitor implementation of newly proposed benefit metrics to ensure they are applied consistently
across the review of individual projects, and avoid any double-counting of benefits due to overlap in
metric calculations.
MISO and participating stakeholders seek to allocate transmission project costs to electric providers
and utility customers in proportion to the share of benefits they receive. Historically, MISO
implemented cost allocation methods that included a “postage stamp” approach, according to which
benefits are shared by the customers in all of the MISO states in proportion to each state’s share of
MISO’s total load. (Wisconsin’s share has historically ranged between 13 and 15 percent.)
Commission staff have advocated for modifications to the approach, due to concerns that the
postage stamp allocation does not clearly align cost allocations with local benefits, and that other
methods are available to determine with greater precision who is actually benefitting from any new
transmission investment and assign costs to those customers. With Commission staff support,
MISO has proposed to modify its approach on large transmission projects beginning in 2020 to a
direct cost allocation method, which allocates costs according to the beneficiaries on a sub-regional
basis. Formal implementation of this proposal is pending approval by the Federal Energy
Regulatory Commission (FERC). Commission staff will continue to monitor the proposal as it
proceeds through FERC review, and advocate to apply the same methods to a wider range of
project types.

28

https://cdn.misoenergy.org/20180814%20PSC%20Item%2006d%20Benefits%20Metrics%20Discussion265122.pdf

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CHAPTER 3 ‒ RELIABILITY AND RESILIENCE

In addition to obtaining an adequate total supply of energy to serve customers, Wisconsin electric
providers must also carry out their daily operations to ensure reliability: providing all customers
access to electricity at all times, and avoiding outages whenever possible. As new technologies
present opportunities for grid modernization, electric providers and the Commission are reviewing
the opportunities grid modernization presents for increased reliability as well as other benefits. In
addition, the Commission and electric providers are working with other organizations to increase the
Commission’s focus on the related concept of resilience: protecting system operations against
potential extreme events such as severe weather and cyberattacks, and establishing policies and
processes to quickly restore service after extreme events occur.
RELIABILITY
All utilities in the United States assess their reliability using three standard metrics defined by the
Institute of Electric and Electronic Engineers (IEEE).
•
•

•

System Average Interruption Duration Index (SAIDI) identifies the average number of
total minutes a customer experiences electric system outages during a year. 29
Customer Average Interruption Duration Index (CAIDI) identifies the average number
of minutes per customer outage, which reflects the average length of time required for
utilities to restore service. 30
System Average Interruption Frequency Index (SAIFI) identifies the average number of
outages a customer experiences during a year. 31

The use of multiple metrics reflects that utilities want to limit both the frequency and duration of
service outages. A utility that experiences many short outages in a year would have a high SAIFI
value, but low SAIDI and CAIDI values. By contrast, a utility with few outages that take a long
average time to restore would have high SAIDI and CAIDI values, but a low SAIFI value.
Electric utilities with more than 100,000 customers must report annually to the Commission their
reliability measures for the preceding year, including customer interruptions due to storms,
catastrophic events, or police actions. Figure 3-1 shows statewide SAIFI, SAIDI, and CAIDI for
the five major Wisconsin Investor-Owned Utilities (IOU) since 2001. In 2018, the average customer
of those utilities experienced less than one outage per year (SAIFI=0.82), with an average duration
per outage of approximately three hours (CAIDI=179 minutes). The frequency of outages has
consistently declined since reporting began in 2001, while the average duration of outages has
increased in recent years compared to average durations in the mid- to late-2000s.

SAIDI = annual sum of customer-minutes of interruption/average number of customers served during the year.
Interruptions include any event that results in customer loss of service, including weather events and technical issues.
30 CAIDI = annual sum of all customer-minutes of interruption durations/annual number of customer interruptions
31 SAIFI = total annual number of customer interruptions/average number of customers served during the year.
29

28

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 3-1

Statewide Average SAIFI, SAIDI, and CAIDI Values for Major IOUs 32

250

1.20
1.06
1.02

1.00
200

200 186

0.96

0.96

0.94

0.93

0.93

186

0.95
0.91

0.92

0.92

177

148

150

139
135

148
146

145
138

136
128

135
127

140
129

150
140

170

193
0.93
182

1.00
0.87
175

0.82
163

154

181
0.84

173
0.82

0.80

153
145
134

SAIFI

SAIDI or CAIDI (Minutes)

165
162

169
162

0.90
182

0.60

100
0.40
SAIFI 5-yr Rolling Average

50

CAIDI 5-yr Rolling Average

0.20

SAIDI 5-yr Rolling Average

0.00

0
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018

Year

Reports filed with the federal EIA allow a comparison to similar utilities nationwide. 33 As shown in
Figure 3-2, Wisconsin utilities with more than 100,000 customers compared favorably to most states
in minimizing the number of outages (SAIFI) during 2018, and fell closer to national averages on
outage duration (SAIDI and CAIDI).

Source: Reports filed with the Commission per Wis. Admin. Code PSC § 113.0604. Five-year rolling averages are
used to normalize weather conditions.
33 Source: Annual Electric Power Industry Report, EIA-861. https://www.eia.gov/electricity/data/eia861/. Although
some data is also available for utilities with fewer than 100,000 customers, comparisons are more difficult to make
because many smaller utilities in both Wisconsin and other states do not file reliability data through this report.
32

29

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 3-2

Reliability indices by state for large utilities (>100,000 customers), 2018

30

 DRAFT ‒ Strategic Energy Assessment 2026

NEW GRID TECHNOLOGIES
In recent years, a variety of new electric system technologies have emerged – including the growth
of zero-carbon energy generation sources as well as a range of other new technologies supporting
daily system operations. Electric providers nationwide are assessing the opportunities for use of
these technologies, which are sometimes grouped under the general heading of grid modernization.
To review these emerging opportunities in Wisconsin, the Commission has collaborated with energy
providers and stakeholders to inventory the activities already underway in Wisconsin and to clarify
long-term priorities for continued exploration. In 2018, the Commission conducted a survey asking
utilities and stakeholders to identify the most important grid opportunities. The five leading topics
identified by respondents were:
•
•
•
•
•

Interconnection of distributed energy resources;
Identification of customers’ changing expectations, preferences and behaviors;
Uses and benefits of advanced meters;
Safety and reliability of the distribution system; and
Increased electrification.

Respondents’ highest modernization priority was studying the integration of renewables and other
distributed energy resources (DER). (See the Renewable Policies and Programs section for data on
DERs.) Respondents also prioritized reviewing how the full range of emerging technologies can
support reliability and more effectively serve customers.
Renewable Resources and Reliability
Renewable energy sources such as solar and wind provide varying amounts of energy at different
times of the day and at different times of year. Solar energy is available only during daylight hours
and at higher levels in the summer (Figure 3-3); wind resources are highest during the winter and
spring and are often greatest during overnight hours (Figure 3-4). Due to the influence of weather
patterns, such as cloud cover for solar resources, the precise amount of available resources is also
difficult to predict in advance.

31

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 3-3

Possible Future MISO North Annual Hourly Solar Production, 30-day Averages 34

PSC REF#: 357406. MISO North refers to MISO’s operating regions in Minnesota, Iowa, North Dakota, and parts
of South Dakota and Wisconsin. The “possible future” scenario assumes operation of existing wind and solar resources
on the MISO system, plus implementation of the wind and solar projects currently listed in MISO’s interconnection
queue.
34

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 DRAFT ‒ Strategic Energy Assessment 2026
Figure 3-4

Possible Future MISO North Annual Hourly Wind Production, 30-day Averages 35

Reliable electric service requires electric system operators to balance net supply and demand on the
electric grid at all times in order to maintain system reliability. Renewable resources can present
more complications for maintaining this balance than baseload resources such as coal and nuclear
power, which are more consistently available at all times of day; and intermediate resources such as
natural gas which can be used on a more intermittent basis but at levels that can be defined in
advance. (See the Supply chapter for additional description of baseload, intermediate, and
intermittent resources.)
As of 2019, solar and wind resources currently comprise less than 10 percent of generation in
Wisconsin’s local operations and regional MISO transmission market. (See the Supply chapter.) At
these levels, the impacts from balancing those resources with baseload and intermediate resources
remain limited. However, challenges may grow as solar and wind penetration continues to increase.
One effort to study these effects is MISO’s RIIA, which is modeling the impacts of renewable
generation thresholds of 10 percent, 20 percent, 30 percent, 40 percent, and 50 percent. In addition
to identifying potential transmission needs (see Transmission chapter), study outputs will also
identify reliability challenges and potential approaches to address those challenges at each level of
penetration.
Commission staff are also monitoring research on additional operational aspects of solar and wind
impacts on reliability. Balancing supply and demand for reliability also requires that the system
maintain stable electric frequencies and voltage levels, to protect against sudden spikes or drops that
could create outages resulting from operating technology failures. Renewable energy can present
challenges for frequency control by increasing the amount of variable power on the grid that must
be controlled. On the other hand, renewable technologies could help improve voltage stability.

35

Ibid.

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 DRAFT ‒ Strategic Energy Assessment 2026

While traditional resources can only provide voltage support while they are generating power,
renewable resources can provide voltage support at all times while connected to the system, and
thereby help provide “ride-through” services that limits the impacts when voltage instabilities occur.
The National Electric Reliability Corporation’s (NERC) Essential Reliability Services (ERS)
initiative, currently in progress, is developing informational resources on these operational issues.
Other Grid Technologies
Wisconsin’s review identified advanced meters as an additional priority for obtaining further grid
benefits. Advanced meters add new technological components to the standard meters traditionally
used to quantify energy use for customer billing.
A 2017 Commission survey 36 found that, of the 2.6 million residential meters in Wisconsin at that
time, 78 percent included some form of advanced metering infrastructure (AMI). In nearly all cases,
advanced components included automated meter reading (AMR) capability that permit the electric
provider to remotely collect meter data, eliminating the need for home visits by utility staff and
reducing costs for providers and customers. Approximately half of advanced meters included
additional components to support two-way communications between the utility and the customer,
which can have a variety of benefits, including:
•
•
•

Enhancing reliability by helping the provider more quickly and efficiently identify outages
and initiate more rapid service restoration efforts;
Providing customers increased information on their energy use, which can meet the growing
interests of some customers in taking greater control of their energy use; and
Supporting the implementation of advanced rates and tariffs, such as rates that depend on
market-based pricing. (See the Rates section for more information on advanced rates).

A number of Wisconsin electric providers are also supporting these benefits through upgrades to
their customer information systems (CIS). New CIS systems allow utilities to integrate new
technologies and meters into system operations, and serve as another platform for providing
additional information to customers about their energy usage. Other benefits of system upgrades
include improved data security and cost savings through operational efficiencies.
Resilience
Nationwide focus on resilience has grown in recent years, as a result of increasing attention to “high
impact, low frequency” (HILF) events—such as severe weather and cyberattacks—that can result in
lengthy service interruptions and significant recovery costs. Resilience efforts focus on both taking
steps to prevent HILF events from occurring and developing plans and resources to support
efficient recovery after an event occurs.
The U.S. Department of Energy (DOE) initiated formal federal policy development on resilience by
issuing a Notice of Proposed Rulemaking on the issue in September 2017. National policy effort
has since shifted to the Federal Energy Regulatory Commission (FERC), which ended DOE’s
36

See PSC REF#: 296929.

34

 DRAFT ‒ Strategic Energy Assessment 2026

rulemaking in 2018 and created in its place FERC Docket AD 18-7, under which MISO and other
regional transmission organizations have been asked to review the resilience on their systems. While
FERC has not taken further action on this docket to date, the Commission has collaborated with
other organizations within Wisconsin to enhance state-level planning and policy development on
resilience issues.
State law places the primary responsibility for responding to large-scale emergencies that exceed
local capacities with the Wisconsin Division of Emergency Management (WEM) within the
Department of Military Affairs. The Commission’s Office of Energy Innovation (OEI) contains the
state’s federally designated state energy office, which serves as a lead advisory agency to WEM, and
the two agencies work together to carry out OEI’s federal requirement to develop energy emergency
plans that respond to supply disruptions. Commission personnel also play roles in energy assurance
coordination, by sharing information with the federal government and other state governments
during emergency situations.
WEM and OEI regularly participate in planning exercises at the state, regional and national level,
working with other actors to model planning and responses to HILF events. In May 2018, WEM
hosted a three-day “Dark Sky” event which modeled a long-term power outage and incorporated
considerations related to cybersecurity and fuel shortages. The exercise included over
1,600 participants from over 240 agencies and departments spanning the local, county, state, federal,
and private sector including Commission staff, four investor-owned utilities, municipal electric
utilities, water utilities, healthcare, law enforcement, and non-profit partners. The exercise identified
several specific recommendations to improve resilience planning, such as increasing the deployment
of fueling infrastructure available during outages to support vehicles involved in recovery operations.
OEI is further promoting collaborative resilience planning through its Statewide Assistance for
Energy Resilience and Reliability (SAFER2) grant, which focuses on enhancing coordinated
statewide planning with local emergency management officials at the regional, tribal, county, and
municipal levels. Grant funds have supported meetings and training exercises to gather enhanced
information on critical energy infrastructure, clarified specific roles and responsibilities within a
collaborative framework, and developed planning templates for specific types of HILF events.
The declaration of a public health emergency in response to the COVID-19 pandemic has activated
Wisconsin’s energy-related emergency response plans. The Commission is collecting information
regarding the needs of and effects on critical energy infrastructure and collaborating with WEM and
other agency partners to define appropriate responses to operational needs. (Additional actions by
the Commission to address the effects of the pandemic on customers are described in the Customer
Rates and Bills chapter.) 37

These efforts include dockets to investigate the provision of safe, reliable and affordable access to utility services
during the pandemic (docket 5-UI-120; see the Affordability for Low-Income Customers section) and to investigate the
financial accounting of costs related to the pandemic (docket 5-AF-105; see the Determining Customer Rates section).

37

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 DRAFT ‒ Strategic Energy Assessment 2026

Cybersecurity
Nationwide attention has also increased regarding the specific resilience threats associated with
cybersecurity attacks, which could create outages or diminish service through attacks on the grid
control networks used by system operators. In 2018, the U.S. DOE released a Multiyear Plan for
Energy Cybersecurity which identifies goals to strengthen cybersecurity preparedness, coordinate
event responses, and enhance research and development on cyber-resilience. 38 In the same year,
DOE also established an Office of Cybersecurity, Energy Security, and Emergency Restoration to
coordinate cybersecurity issues and provide training and support to state and local officials.
In 2015, representatives of Wisconsin electric providers worked with state and local government
officials and other owners of critical state infrastructure to add a Cyber Incident component to the
Wisconsin Emergency Response Plan. The plan includes provisions to limit the impacts of
cyberattacks and maintain critical services. The Dark Sky exercise, mentioned above, served as a test
of the Cyber Incident Response Plan by role-playing scenarios involving cyberattacks, in
combination with physical attacks, on electric utility infrastructure. Participants exercised the
provisions of the plan, including establishment of the state Cyber Response Team, to assess the
quality of communication and analysis within the team and identify opportunities for improvement.
Areas for cybersecurity improvement identified through the exercise included ongoing collaboration
with state electric providers to regularly share information on cybersecurity protections and
emerging threats, as well as the development of enhanced operating plans to further clarify roles and
responsibilities for responding to future cyberattacks.

U.S. Department of Energy. Multiyear Plan for Energy Sector Cybersecurity. March 2018.
https://www.energy.gov/sites/prod/files/2018/05/f51/DOE%20Multiyear%20Plan%20for%20Energy%20Sector%20
Cybersecurity%20_0.pdf. Accessed on March 18, 2020.
38

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 DRAFT ‒ Strategic Energy Assessment 2026

CHAPTER 4 ‒ CUSTOMER RATES AND BILLS

In addition to ensuring adequate and reliable electric supply, the Commission also seeks to ensure
that electric providers offer customers reasonably priced electric service. The Commission regulates
the rates charged by investor-owned and municipal electric utilities to identify the prices that
minimize costs for customers while still permitting providers to recover from customers the funds
needed to offset operating costs and make a reasonable profit to support future investment. Many
electric providers also work, under Commission regulation, to develop new and innovative rates and
programs to meet customers’ evolving needs and cost-effectively serve specific types of customers.
UTILITY COST DRIVERS
As the first step in the rate regulation process, electric providers propose a revenue requirement, the
total amount of money a utility needs to recover through customer rates to provide adequate and
reliable service. Revenue requirements are developed based on historical costs, as well as forecasts
of future growth in customer energy use and the future costs of providing service. The revenue
requirement also includes a return on equity on the assets used to provide service, such as generation
plants, which each provider uses to pay interest on money it borrows and to compensate investors.
Commission staff audits each provider’s proposed revenue requirement and makes adjustments as
appropriate to establish a requirement that will recover costs and provide utilities with a reasonable
return, while maintaining the lowest feasible cost to customers. (See the Determining Customer
Rates section below for more details on the rate case process.)
Three key trends have influenced revenue requirement levels for providers across Wisconsin in
recent years. First, customer sales have grown slowly. Second, electric providers are still
considering significant investments to meet electric supply needs, driven by capacity needs within
the state and the economic and environmental factors supporting the increased pursuit of new
natural gas and zero-carbon generation. Third, application of the cost savings from 2017’s federal
tax reform have reduced utility costs in recent cases.
Trends in Customer Sales
In 2008, Wisconsin electricity sales fell in response to the recession. While sales have increased
every year since 2014, annual growth rates in those years have remained low, and total electricity
sales in 2018 remained one percent lower than sales in 2007, as shown in Figure 4-1 and Table 4-1.
Energy efficiency is one key reason electric sales did not return to pre-recession levels by 2018.
After incorporating total net energy savings recorded by Focus on Energy’s statewide programs
since 2007, Figure 4-1 and Table 4-1 show that, in the absence of those reductions in energy use,
annual growth rates would have been higher in each of the past 12 years, and total electricity sales
would have exceeded pre-recession levels. Using Focus on Energy savings also serves as a
conservative estimate of energy efficiency impacts, since many customers may also be taking
additional energy-efficient actions outside of the program. Although the effects of the COVID-19

37

 DRAFT ‒ Strategic Energy Assessment 2026

pandemic remain uncertain at this time, response measures and associated slowdowns in economic
activity are likely to result in overall sales reductions from 2018 levels. 39
Figure 4-1

Retail Sales of Electricity, by Sector (MWh) 40

80,000,000
70,000,000
60,000,000
50,000,000
40,000,000
30,000,000
20,000,000
10,000,000
-

2007

2008

2009

2010

2011

Weather Normalized Residential

Table 4-1

2012

2013

Non-Residential

2014

2015

2016

2017

2018

Focus on Energy Net Savings

Annual Growth Rates for Retail Electricity Sales (%)

Residential
Non-Residential
Total
Total w/o Focus on Energy

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

-1.6%
-1.6%
-1.6%
-1.2%

-2.6%
-7.4%
-6.0%
-5.4%

5.0%
3.6%
4.1%
4.6%

-0.6%
-0.5%
-0.5%
-0.1%

-1.1%
0.4%
0.0%
0.7%

-0.1%
-0.3%
-0.2%
0.7%

-0.6%
1.4%
0.9%
1.5%

-0.1%
0.0%
0.0%
0.7%

0.2%
1.0%
0.8%
1.3%

-2.1%
1.4%
0.4%
1.0%

1.7%
1.0%
1.2%
1.7%

Average
Growth
-0.2%
-0.1%
-0.1%
0.5%

Usage by customer provides another measure of the effects of energy efficiency on overall sales.
Average electricity use per customer for residential customers declined 5 percent from 2007 through
2018. Average energy intensity per dollar of economic output, the metric commonly used to assess
the more widely varying population of non-residential customers, increased nearly 50 percent from
2007 through 2018. (See Appendix C, Figures C-1 and C-2 for illustration of these trends). The

In May 2020, Wisconsin Power and Light and WEC Energy Group (representing Wisconsin Electric Power Company
and Wisconsin Public Service) reported that they project sales declines of approximately 5 percent in 2020.
40 Source: Utility annual reports filed with the Commission; Focus on Energy. For this analysis, weather-normalized
sales for residential customers are used to remove data outliers from unusual weather events such as the polar vortex of
2014.
39

38

 DRAFT ‒ Strategic Energy Assessment 2026

effects of these per-customer trends have been partially offset by the increase in the number of total
customers served, but not at sufficient levels for total sales to reach their pre-2008 levels.
Sources of Utility Costs
Declining usage trends can benefit individual customers by helping them reduce their energy bills.
However, electric providers must still bear the costs of providing adequate and reliable service to all
customers. If costs for a given provider grow at a higher rate than electric sales, the result can be a
need for increased customer rates to absorb the higher costs.
Major Investor-Owned Utilities with Generation
Wisconsin’s five largest IOUs, 41 who serve nearly 90 percent of the state’s electric customers,
provide most of their electric supply through utility-owned generation. The majority of the revenue
requirements for each of these “Major IOUs” comes from generation, distribution, and
transmission.
As shown in Figure 4-2, total revenue requirements for Major IOUs increased 1.8 percent between
2009 and 2018. Of the revenue requirement components, the Commission has direct control over
generation, return on equity, and distribution investment for large projects. Fuel costs and
transmission rates are mostly outside the Commission’s control and represent pass-through
expenses.
Figure 4-2
7
6

Ten-year Annual Growth Rate of Revenue Requirement Components—Major IOUs (%)

5.89
4.55

5

4.44

Percent

4
3

1.81

2
1
0
-0.27

-1

-0.72

-2
Generation

Fuel

Transmission

Distribution

ROE

Revenue Requirement

Both fuel costs and return on equity for IOU assets decreased between 2009 and 2018. Return on
equity is set for each utility in their rate cases, but have generally trended down due in part to low
interest rates during this time period. Fuel costs have generally declined due to reduced natural gas

41

MGE, NSPW, WEPCO, WP&L, and WPSC.

39

 DRAFT ‒ Strategic Energy Assessment 2026

costs and the increased utilization of generating resources that incur no fuel costs, such as wind and
solar.
Total fuel costs may continue to decline in future years as providers make further investments in
wind and solar resources. By contrast, investments in new generation may result in further increases
in generation and distribution costs for new utility-owned generation, which increased by
approximately 5 percent between 2009 and 2018. The generation and distribution cost amount in
revenue requirements reflects the amount of annual depreciation value from those investments
authorized by the Commission in rate cases.
Transmission costs also increased at an annual rate of 4.5 percent between 2009 and 2018. These
expenses are not under the direct control of IOUs or the jurisdiction of the Commission. Rather,
they reflect transmission charges to each major IOU by Xcel Energy and American Transmission
Company (ATC). Transmission rates are regulated by the Federal Energy Regulatory Commission
(FERC) and charged through MISO’s regional transmission tariffs. As shown in Figure 4-3,
transmission charges have increased more than 40 percent in the last 10 years, with similar increases
from both transmission providers. As noted in the Transmission chapter, Commission staff are
participating in MISO transmission planning processes that influence transmission costs, including
efforts to improve methods for allocating transmission costs among states.
Figure 4-3

MISO Schedule 9 Network Transmission Charges ($/MW-Month) 42
$6,000.00
$5,000.00
$4,000.00
$3,000.00
$2,000.00
$1,000.00
$ATC

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

$3,403. $4,260. $4,214. $4,168. $4,430. $4,418. $4,556. $5,058. $4,792. $5,056.

Xcel (NSP System) $2,962. $2,460. $3,144. $3,744. $3,795. $3,720. $4,050. $4,555. $4,116. $4,259.1
ATC

Xcel (NSP System)

Non-Major Investor-Owned Utilities and Municipal Utilities
The other seven electric IOUs in Wisconsin, as well as the 81 municipally owned electric utilities
regulated by the Commission, maintain most of the same cost components as the major IOUs.
42

Source: MISO Open Access Tariff, Schedule 9.

40

 DRAFT ‒ Strategic Energy Assessment 2026

However, most or all of their power supply comes through purchased wholesale power, rather than
utility-owned generation. Therefore, wholesale power costs are the main driver of customer rates
for these utilities.
Statewide, the average cost of purchased power has increased between 2009 and 2018, but remained
relatively stable between 2014 and 2018 (see Figure 4-4). It should be noted that these costs do not
match MISO day-ahead market prices (Appendix A, Figure A-1), because most utilities buy power
under long-term contracts which also incorporate the embedded costs of transmission service.
Figure 4-4

Statewide Average Purchased Power Cost ($/MWh) 43

$80.00
$70.00
$60.00
$50.00
$40.00
$30.00
$20.00
$10.00
$0.00

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Effects of Tax Reform on Investor-Owned Utilities
In December 2017, the federal Tax Cuts and Jobs Act (TCJA) implemented reforms to the federal
tax code. Wisconsin IOUs are impacted by the TCJA’s reduction of the corporate income tax rate
to a flat rate of 21 percent, in place of a graduated structure with a maximum rate of 35 percent. 44
The rates the Commission approved prior to 2018 for each IOU included the previously higher tax
rate. As a result, IOUs began over-collecting tax revenue under those rates when the legislation
took effect in 2018. To address these over-collections in a timely fashion, the Commission opened
docket 5-AF-101 to review collections by all IOUs, reduce each IOUs’ 2019 rates to account for the
reform, and identify how each utility will return to customers the funds over-collected in 2018.

43
44

Source: Monthly purchased power clause (PCAC) filings with the Commission.
See Sec. 13001 at https://www.congress.gov/bill/115th-congress/house-bill/1.

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The effects of tax reform will have short-term, intermediate-term, and long-term impacts on the
costs included in revenue requirements.
•
•

•

In the short term, a total of $110.3 million was immediately refunded to customers in 2018
and 2019, reflecting savings from utilities’ 2018 tax expenses.
In the intermediate term, an estimated additional $541.7 million will be returned to
customers once each IOU files a rate case with the Commission. These funds represent
income taxes collected in previous accounting periods that will not be paid to the IRS due to
the reduction in the corporate tax rate, and can be applied to reduce customer rates in each
utility’s next rate case. In docket 5-AF-101, the Commission ordered that all IOUs must file
a rate case by 2021 to ensure customers receive these benefits in a timely fashion.
In the long term, nearly $1.5 billion additional dollars, previously collected in customer rates,
will be applied to reduce future rates based on utility assets, such as owned power plants.
Under federal tax law, these balances cannot be returned to customers any faster than the
asset depreciates over its average remaining life. Given the long-lived nature of large utility
capital investments, these balances will be gradually applied to reduce revenue requirements
in each rate case over the next several years.

DETERMINING CUSTOMER RATES
Customer rates are established by each electric provider to generate sufficient revenue to recover
their costs. Ratemaking processes are intended to simulate for monopoly utilities the conditions of a
free market; when rates are designed properly, the rate structure should signal to all different types
of customers the actual cost of providing them reliable service and electricity.
Figure 4-5 summarizes the rate case process 45 that is followed by all electric providers regulated by
the Commission, including all investor-owned and municipal electric utilities. 46

See also the Commission Proceedings webpage:
https://psc.wi.gov/Pages/Regulatory/GuideToPSCProceedings.aspx.
46 The rates of retail electric cooperatives are not regulated by the Commission. Uncontested municipal rate cases follow
a simplified process.
45

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 DRAFT ‒ Strategic Energy Assessment 2026
Figure 4-5

Rate Case Process

Before a regulated utility can raise its customer rates, it must file an application with the
Commission. The application proposes rates for a forward-looking test year, typically the first year
of service the rates are expected to be in effect. Since this test year is usually either the current year
or the year after the application is filed, the provider submits forecasts of the revenue requirement it
projects it will need to cover its expenses and return on investment in that year and subsequent
years, and proposes customer rates to allocate that revenue requirement among its customers. 47
As the first step in application review, Commission staff audit the utility’s revenue requirement by
reviewing the application’s forecasts and proposals and requesting additional information as needed.
Commission staff analysis may focus on determination of values for key cost drivers such as asset
depreciation, operations and maintenance costs, labor costs, rate of return, and sales forecasts.
Based on audit findings, Commission staff may make adjustments to the proposed revenue
requirement to more accurately reflect projected costs, and establish a final revenue requirement
that will be used to determine rates.
Commission staff then use the final revenue requirement to review the utility’s proposed rate
design. Rate design analysis begins with a cost of service study (COSS) that seeks to meet the
goal of charging actual costs to customers by estimating the allocation of utility costs among
different customer classes, such as residential, commercial, industrial, and agricultural classes. 48

In recognition of additional expenditures and reductions in revenue collections utilities may experience as a result of
the COVID-19 pandemic, the Commission opened docket 5-AF-105 in March 2020 to collect information on the
financial impacts related to the pandemic and the procedures to be used for financial accounting of those impacts.
48 The COSS model applies many assumptions about how to classify, and allocate utility costs assumed in the revenue
requirement. Utilities, Commission staff, and other rate case participants may reference best practices documented by
47

43

 DRAFT ‒ Strategic Energy Assessment 2026

Utilities may submit one or more COSS models in their application, and Commission staff may
design one or more additional models of their own. Using the COSS models, alternative rate
designs can be proposed by the utility and Commission staff to fully recover the costs allocated to
each class. (See the Components of Customer Rates section below for more detail on rate designs.)
Audit and rate design findings are then used as core evidence in a rate case proceeding that creates
a record of evidence for Commissioners to evaluate, and allows many opportunities for public input.
The proceeding includes:
•
•
•
•

submission of case evidence, including testimony and exhibits that summarize the audit
and rate design work;
opportunities for rebuttal and surrebuttal testimony to initial evidence, which may be
submitted by the utility and Commission staff as well as by other interested parties;
at least one public and party hearing to receive testimony from all interested parties,
including members of the public; and
attorney briefs to summarize the final positions of the applicant and other parties involved
in the proceeding.

Commissioners then review the full record created by the rate case proceeding and issue a final
decision approving, denying, or approving with modifications the proposed rates. As applicable, a
final approval will also select from among the alternative decision options provided by the utility,
staff, and other parties for decisions on specific components of the revenue requirement and rate
design.
Components of Customer Rates
As described above, COSS are designed to assign to different customers the total amount of costs
required to serve their customer class. Rates are designed to further link customer charges with the
costs they create by including several different types of charges designed to recover different aspects
of service costs.
All customers receive a customer charge, or fixed charge, of a flat amount per day or per month,
regardless of how much energy they use. These charges are designed to reflect the minimum service
for interconnection utilities must provide to serve customers regardless of energy usage level, such
as each customer’s energy meter, billing and customer service costs, and portions of the costs of the
infrastructure needed to connect the customer’s location with the electric grid. COSS studies seek
to estimate these costs for each customer class, and then calculate the customer charges to recover
those costs.
All customers also receive an energy charge per unit of electricity (kilowatt-hour) they use. These
charges reflect the incremental costs associated with producing the next additional unit of energy a
customer might need to use. For a customer of a utility that owns power plant generation, these

the National Association of Regulatory Utility Commissioners (NARUC) COSS Manual, as well as other external
references and the practices used by the Commission and the utility in previous rate cases.

44

 DRAFT ‒ Strategic Energy Assessment 2026

costs are informed by the fuel costs and other costs needed to operate the plant. For utilities that do
not own generating units, energy charges are informed by the per unit energy costs they use to
purchase wholesale energy.
Demand charges are typically only charged to larger non-residential customers, such as commercial
and industrial customers. Residential and small commercial customers have these demand costs
embedded in energy charges instead. Demand may be measured using one of two separate methods.
•

•

Distribution (or customer) demand reflects the distribution infrastructure costs associated with
the customer’s peak load use. The utility calculates a distribution demand charge by
measuring the customer’s highest usage level in a month, and then assigning a demand
charge informed by the costs of the infrastructure needed to provide that volume of energy
to the customer.
Coincident, or “billable”, demand reflects the costs to the utility of serving large customers
during the utility’s peak energy usage hours. Coincident demand charges reflect the service
costs associated with making the generation, transmission, and distribution investments
needed to provide adequate energy supply and transmission during system peaks.

Customer bills may also include adjustments to align customer charges with the variable costs of
certain resources. IOUs that own generation units must provide fuel credits to customers when
actual fuel costs are lower than forecasted in the utility’s previous rate case, or fuel surcharges to
recover costs higher than forecasted. IOUs submit annual fuel plans to the Commission, which
approves the amount of the fuel credit or surcharge provided to customers in the following year.
Customers of utilities receive credits or surcharges under the power cost adjustment clause (PCAC),
which accounts for deviations from the municipal utility’s forecasted costs of purchasing wholesale
power.
Finally, other charges and credits may appear on the customer’s bill if authorized by the Commission
or state law. A recent example is the refunds associated with the 2018 tax reform (see the Utility
Cost Drivers section above).
CURRENT RATES AND BILLS
Charges paid by utility customers reflect two inputs: the utility’s Commission-approved rates, and
the amount of energy used by the customer, which determines their total amount of energy and
demand charges.
Residential Customers
Residential customers of all electric providers are typically billed almost entirely through customer
and energy charges. Tables 4-2 and 4-3 summarize residential rates for investor-owned utilities and
municipal utilities, based on the Commission-approved tariffs in place during 2019. For municipal
utilities, the median customer charge is $7.50/month and the median energy charge is 10.28 cents
per kilowatt-hour (kWh). IOUs have a median customer charge of $12.00/month and a median
energy charge of 12.06 cents/kWh. On average, investor-owned utilities charge higher rates. Both
tables also demonstrate that rates can vary based on the differing cost profiles faced by individual
45

 DRAFT ‒ Strategic Energy Assessment 2026

utilities, which can differ due to a wide variety of factors such as location, amount and condition of
utility assets, and the mix of customers served.
Table 4-2

Wisconsin Electric IOU Bill Components for Residential Customers, 2019
Summary Statistics
Minimum
25th Percentile
Median
Average
75th Percentile
Maximum

Energy (cents/kWh)
8.70
11.53
11.86
11.94
13.00
13.72

* Note: Cents/kWh based on weighted average seasonal rates for MGE and NSPW.
Table 4-3

Customer Charge ($/month)*
$8.00
$9.50
$12.00
$13.29
$16.75
$21.00

Wisconsin Municipal Electric Utility Bill Components for Residential Customers, 2019
Summary Statistics
Minimum
25th Percentile
Median
Average
75th Percentile
Maximum

Energy (cents/kWh)
4.65
9.45
10.28
10.11
10.96
12.45

* Note: Customer charge data is for single-phase customers only.

Customer Charge ($/month)*
$5.00
$7.00
$7.50
$8.99
$11.50
$16.00

National data collected by the EIA permits comparison of Wisconsin rate levels to other states and
regions. While direct rate comparisons between states should be made cautiously due to differences
between energy market conditions and regulatory structures, available data indicates Wisconsin’s
residential rates are higher than Midwest and national averages. Based on an overall, sales-weighted
average of all electric utilities within each state, Wisconsin’s average 2018 residential energy charges
of approximately 14 cents/kWh exceed national and Midwest averages of approximately
13 cents/kWh. As shown in Figure 4-6, Wisconsin’s average rates have exceeded national and
Midwest averages for the past decade. Appendix C, Table C-1 provides more detailed comparisons,
including charges for each individual Midwest state.

46

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 4-6

Average Residential Electricity Rates (1990-2018) 49

EIA data also demonstrates that average monthly electric bills in Wisconsin have remained
consistently lower than other states during the past decade. Wisconsin’s average 2018 bill of
$97.09 compares to Midwest average bills of $109.16 and national average bills of $117.65. (See
Appendix C, Figure C-3 for more detailed comparisons of average bills by census region.)

U.S. Energy Information Administration, Electricity Sales, Revenue, and Average Prices (Table 5A). Issued October
1, 2019. Accessed January 3, 2020 at https://www.eia.gov/electricity/sales_revenue_price/.

49

47

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 4-7

Historical Comparison of Average Monthly Residential Electric Bills (2009-2018) 50,-51

Wisconsin’s lower bills reflect significantly lower average levels of electricity use. As shown in
Figure 4-8, Wisconsin customers used an average of 690 kWh per month in 2018, compared to
853/kWh per month across other Midwest states. This usage difference has been present at
consistent levels throughout the 2010s.

According to the U.S. Energy Information Administration, the East North Central region is comprised of Illinois,
Indiana, Michigan, Ohio, and Wisconsin.
51 See previous editions of Residential Average Monthly Bill by Census Division and State at
https://www.eia.gov/electricity/sales_revenue_price/.
50

48

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 4-8

Monthly Residential Electricity Costs and Consumption in Wisconsin and the Midwest

Bills received by individual customers will vary based on their utility and the amount of individual
energy use. At average usage levels, residential customer electric bills for different utilities in 2018
ranged from $37 to $114 per month (see Appendix C, Figure C-4).
Non-Residential Customers
Based on national EIA data, Wisconsin’s average 2018 energy rate for commercial customers of
10.67/kWh closely compares to the national average of 10.66 cents/kWh and exceeds the Midwest
regional average of 10.14 cents/kWh (additional data can be found in Appendix C, Table C-2).
However, drawing clear conclusions from rate and bill comparisons for non-residential customers is
generally more difficult than for residential customers.
Reasonable comparisons can be made for municipal utility customers served under the Cp-1 rate
schedule, which most municipal providers use to serve small and medium-sized commercial and
industrial customers under a common rate structure. As shown in Table 4-4, municipal Cp-1
customers paid average energy charges of 7 cents/kWh, average customer charges of $45/month,
and demand charges of $6.00-$8.00 per kW of demand in 2019. (More details on the analysis can be
found in Appendix C, Figures C-6 and C-7 and Table C-4.) Similar comparisons of IOU rates, and
of rates for larger municipal customers, cannot be made in simple terms due to greater variation in
definitions of customer classes, in rate structures, and in methods for calculating charges, such as
different definitions of peak periods used for demand charges.

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 DRAFT ‒ Strategic Energy Assessment 2026
Table 4-4

Municipal Utility Bill Components for Cp-1 Customers, 2019

Summary

Energy (cents/kWh)

Minimum
25th Percentile
Median
Average
75th Percentile
Maximum

3.00
6.12
7.02
6.89
7.77
9.13

Distribution Demand
$/kW)
$0.25
$1.00
$1.50
$1.36
$1.50
$2.00

Billable Demand ($/kW)
$5.00
$6.00
$7.00
$7.17
$8.00
$9.79

* Note: Summary statistics include data from 73 municipal utilities that offer Cp-1 rates with a flat energy charge.

Customer Charge
($/month)*
$20.00
$34.00
$50.00
$44.86
$50.00
$100.00

Alternative Rate Options
While the substantial majority of customers in Wisconsin receive traditional rates, many Wisconsin
electric providers offer additional, innovative rate options designed to help customers exercise
control over their costs to reduce their energy bills.
Residential Time-of-Use Rates
A total of 76 electric providers in Wisconsin offer a time-of-use (TOU) rate option to residential
customers, under which the customer’s energy charge per kWh varies at different hours of the day.
As shown in Figure 4-9, electric providers face higher costs for serving customers during peak
afternoon hours of the day for multiple reasons, including the higher costs of operating peaking
resources (see Supply chapter) and the greater availability of low-cost wind resources in the
overnight hours. 52 By setting higher energy charges during higher-cost hours, TOU rates can
encourage customers to move more of their energy usage to lower-cost hours. When TOU rates
successfully shift usage, providers are able to reduce their total energy costs and pass savings along
to customers through lower off-peak energy charges.

Wholesale energy prices on the energy market are used for general illustration. While many providers do not buy
electricity directly from this market, the price trends correspond with the prices a utility would pay to purchase from a
different wholesale provider, as well as the costs a generation-owning utility would face for operating its own plants.

52

50

 DRAFT ‒ Strategic Energy Assessment 2026
Time Varying Price of Electricity on an Average Summer Day in Wisconsin

$60

$0.14

$50

$0.12
$0.10

$40

Price per kWh

Price per MWh

Figure 4-9

$0.08

$30

$0.06

$20

$0.04

$10
$0

$0.02
1

2

3

4

5

6

7

8

9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

$0.00

Hour of Day
MISO Wholesale Market Prices

Residential TOU Rate

All utilities with TOU rates offer them as optional alternatives in which customers may choose to
enroll. This optional approach partially reflects concern over the impacts on customers with limited
ability to shift the timing of their energy use. While many customers may benefit from TOU rates,
mandatory TOU enrollment could cause bills to increase for those with high energy needs during
on-peak hours. As shown in Table 4-5, approximately 34,000 customers of investor-owned and
municipal electric utilities, or 1.5 percent of all residential customers, are currently enrolled in TOU
rates.
Table 4-5

Enrollment in Standard and TOU Rates
Residential Rate Class
Standard Rate
TOU Rate

Total Enrollment
2,161,877
34,259

Percent of Total
98.44%
1.56%

The increasing use of new technologies in future years could help increase customers’ ability to
control their energy use, and accordingly enhance the benefits of enrolling in TOU rates. For
example, installing smart thermostats and other smart appliances can make it easier for customers to
shift the timing of energy use to off-peak periods. (See the Demand Response section for more
information on the use of smart thermostats to control demand.) If electric vehicle use increases in
the future, the use of charging equipment that allows customers to control charging time for vehicles
could provide similar benefits. (See the Electric Vehicle section.)
Real-Time Pricing for Commercial and Industrial Customers
Twenty-six (26) Wisconsin electric providers offer “real-time pricing” rate options for commercial
and industrial customers. These rate options typically incorporate wholesale prices for energy and
demand, based on MISO’s next-day electricity prices and transmission charges on demand, which
serve as the primary influence on energy costs for customers with high energy use. Similar to TOU
51

 DRAFT ‒ Strategic Energy Assessment 2026

rates, these rate options are designed to account for the actual electricity prices faced by providers,
to incent customers to modify their energy use and create potential shared cost savings for providers
and customers.
Customer eligibility for real-time pricing depends on the type of rate options each provider offers.
The most common option presently offered in Wisconsin is incremental load pricing, often labeled
as a New Load Market Pricing (NLMP) rate or an Economic Development Rider (EDR).
Incremental load pricing is only available to customers opening a new facility or expanding an
existing facility. The additional electric load must also be substantial in size, typically greater than
500 kW of demand.
Incremental load enrollees are provided an incentive to control their energy use, and promote
business growth, by receiving energy charges specific to their new load that vary each day based on
day-ahead MISO market prices. Customers able to control the timing of their energy use can benefit
by shifting energy use to days with lower day-ahead prices, and minimizing energy use on
higher-priced days. New loads are typically eligible for incremental load enrollment for four years,
before being placed on the standard rates.
Real Time Market Pricing (RTMP) enrollees are provided a similar incentive to NLMP/EDR
enrollees to control their energy usage, but the pricing is applied to all consumption above a set
level, rather than to new loads. Similar to NLMP/EDR customers, those who can control the
timing of their energy use would be able to benefit the most from this type of rate. Enrollment on
this rate generally begins with a multi-year contract that requires an advanced notice to the utility if
the customer wishes to stop taking this type of service.
As shown in Table 4-6, 97 commercial and industrial customers were enrolled in real-time pricing
rates in 2019, an enrollment rate of 1.5 percent. These enrollment levels reflect, in part, the
restriction of eligibility to customers with large and (for NLMP) new loads. Moreover, eligible
customers will only receive clear benefits if they are able to exercise significant control over their
energy use; customers with less control over their load profile may not be able to achieve reduced
costs through these rates.
Table 4-6

Enrollment in Incremental Load and Real-Time Pricing Rates
Industrial
Standard Rate
Incremental Load (NLMP/EDR)
Real-Time Pricing (RTMP)

Total Enrollment
6,596
76
21

Percent of Total
98.55%
1.14%
0.31%

AFFORDABILITY FOR LOW-INCOME CUSTOMERS
Low-income residential customers can often face challenges in paying their utility bills. By paying
the same rates as all customers on more limited financial resources, low-income households often
face a higher energy burden: they must pay a larger percentage of their total income to pay for the
same amount of electric service. Customers earning the state median average household income of
$62,629 would need to pay less than 2 percent of their total income to cover Wisconsin’s average

52

 DRAFT ‒ Strategic Energy Assessment 2026

residential electric bill of $97.09 per month. 53 By contrast, the same average bill would require
higher burdens for customers meeting common definitions for low-income status:
•

•

Customers earning less than 200 percent of the federal poverty level (FPL), or less than
$40,000 per year- the eligibility threshold for federal, state, and local low-income assistance
programs- would have to pay at least 2.9 percent of their total income; and
Customers in the lowest 20 percent of state income earners- or less than $25,000 per yearwould have to pay at least 4.5 percent of their total income.

Table 4-7 compares Wisconsin’s 2018 energy burdens at these income levels to average burdens in
the U.S. and in other Midwest states. Low-income Wisconsin customers have generally faced
slightly lower energy burdens, due to lower average bills associated with lower average usage.
Burdens for individual low-income customers may vary based on the rates of their electric provider,
as well as their usage needs. While some customers may be able to limit their burden by using
below-average amounts of electricity, others may face higher burdens due to above-average energy
demand driven by personal needs such as medical equipment, or difficulty controlling their usage in
homes and apartments with low levels of energy efficiency.
Table 4-7

Average Residential Electricity Costs as a Percentage of Monthly Income for Wisconsin, Adjacent
Midwest States, and U.S., 2018
2018
United States
Illinois
Iowa
Michigan
Minnesota
Wisconsin

Median Income
2.23%
1.62%
1.91%
2.06%
1.73%
1.86%

200% FPL
3.53%
2.85%
3.28%
3.11%
3.10%
2.91%

20th Percentile
5.51%
4.45%
5.12%
4.86%
4.84%
4.55%

Wisconsin electric providers and the Commission can help low-income customers manage their
energy burden through multiple approaches, including through rate design, and by connecting
customers with programs for low-income assistance and energy efficiency.
Alternative rate designs that allow customers to reduce costs by controlling their usage may be
beneficial for some low-income customers. For example, TOU rates could reduce costs for lowincome customers who are able to shift their usage to off-peak hours with lower energy charges.
Some electric providers have also explored whether the implementation of residential demand
charges could also benefit customers who can control their energy usage to minimize peak
demand. 54 To support a successful implementation process, the implementation of demand charges

Based on a household size of 3 persons.
Wisconsin Power and Light was authorized by the Commission in docket 6680-UR-120 to implement demand charges
for residential and small commercial customers, and has implemented residential rates with a group of primarily lowincome customers. See PSC REF#: 385269, Appendix B for a March 2020 report on outcomes to date from
implementation of demand charges.
53
54

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 DRAFT ‒ Strategic Energy Assessment 2026

is commonly accompanied by marketing and education efforts designed to help customers
understand the calculation of the demand charge and their options for reducing their charges. 55
Electric providers and Commission Consumer Affairs staff also seek to refer customers facing
affordability challenges to multiple low-income assistance programs designed to meet energy needs.
•

•

•

•

Electric utilities in Wisconsin are required to offer residential customers budget billing
options that charge customers the same bill amount in all twelve months of the year, to help
avoid the seasonal increases in energy charges most customers typically experience.
Electric utilities are also required to offer Deferred Payment Agreements (DPA) to all
residential customers who are unable to pay their bill in full. DPAs allow customers to
provide a down payment on their outstanding balance and arrange an installment plan to pay
the remaining balance over a specified time period.
Households with incomes of less than 60 percent of the state median income are eligible for
federally funded energy assistance through the Wisconsin Home Energy Assistance Program
and the Public Benefits Energy Assistance Program. These programs can help customers
pay a portion of their electric bills and provide weatherization assistance that can help
customers reduce energy costs by increasing the efficiency of their home.
Additional nonprofit and local programs are available to provide energy assistance. Many
state electric providers financially support the Keep Wisconsin Warm/Cool Fund (KWWF),
a statewide, non-profit effort that provides preventative services and financial assistance in
response to energy emergencies. Heat for Heroes provides assistance to veterans facing
service disconnections or other energy challenges. Customers may be able to find assistance
through a variety of other local non-profits throughout Wisconsin, such as Aging and
Disability Resource Centers, the Salvation Army, and local churches.

One reason low-income customers may experience a higher energy burden is because they live in
older homes with less energy-efficient lighting, appliances, and heating and cooling systems.
Referring customers to energy efficiency programs can also help low-income households manage
their energy burden by increasing home efficiency and reducing their energy bills.
Focus on Energy, Wisconsin’s statewide energy efficiency and renewable resource program, offers
multiple program options that can benefit low-income customers. For example, all residential
customers may register to receive a free kit of energy-efficient products, including lighting, power
strips, and low-flow showerheads, and may purchase program-discounted lighting and appliances at
retail stores. Low-income customers are also eligible for bonus incentives to help them conduct
home energy audits and complete projects to replace heating and cooling appliances and install
insulation. Three Wisconsin electric providers—Wisconsin Electric Power Company, Wisconsin
Public Service Corporation, and Wisconsin Power and Light Company—operate additional energy

Source: “Understanding Residential Demand Charges” presented by Philip Hanser, 2016, National Energy and Utility
Affordability Coalition, http://neuac.org/wp-content/uploads/2016/06/1C-Philip-HanserUnderstandingResDmdCharges.pdf.
55

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 DRAFT ‒ Strategic Energy Assessment 2026

efficiency programs that provide further financial support to low-income customers conducting
heating, cooling and insulation projects through Focus on Energy. 56
Declining economic conditions associated with the rapid onset of the COVID-19 pandemic may
increase affordability concerns for many utility customers. Moreover, access to utility services is
essential to ensure citizens can abide by guidelines to remain in their homes. In March 2020, the
Commission directed electric utilities to take several steps to address safety and affordability
concerns for the duration of the public health emergency, including:
•
•
•

prohibiting the disconnection of service to any customer unable to pay their bill;
prohibiting the charging of late fees for failure to pay a bill; and
requiring deferred payment agreements to be offered to all interested customers, including
nonresidential customers;

The Commission also opened an investigation under docket 5-UI-120 to conduct ongoing review of
appropriate steps to address safety, reliability, and affordability issues related to the pandemic.

WEPCO and WPSC operate the Residential Assistance Program (Commission dockets 5-EE-2020 and 6690-EE2020). WP&L operates the Enhanced Low-Income Weatherization Program (Commission docket 6680-EE-2020).

56

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 DRAFT ‒ Strategic Energy Assessment 2026

CHAPTER 5 ‒ CLEAN ENERGY PROGRAMS AND POLICIES
ENERGY EFFICIENCY
Energy efficiency programs provide incentives and technical assistance to residents and businesses
to take steps to reduce energy use. Since 1999, state law has established Focus on Energy (Focus) as
Wisconsin’s statewide electric and natural gas efficiency and renewable resource program. Under
2005 Wisconsin Act 141 (Act 141), IOUs are required to fund Focus through contributions equal to
1.2 percent of annual operating revenues from retail sales. Act 141 also requires municipal utilities
and retail electric cooperatives to collect an average of $8 per meter annually for energy efficiency
programs. Municipal utilities and cooperatives have the option to contribute these funds to Focus
or administer their own programs. As of 2019, all IOUs and municipal utilities participate in Focus.
Of the 24 electric cooperatives in the state, 13 run their own programs while 11 participate in Focus.
Some investor-owned and municipal utilities run voluntary energy efficiency programs that provide
additional benefits to their customers beyond what Focus offers. 57
Act 141 requires Focus to be operated by a third-party program administrator, under a contract
established by IOUs and approved by the Commission. 58 APTIM has served as the third-party
program administrator since 2011. Program administrator contracts are established on a 4-year basis,
after the Commission completes a quadrennial planning process to determine program goals, policies,
and priorities for the upcoming contract period. Most recently, the Commission approved updated
program goals in 2018, to establish contract priorities for the 2019-2022 time period. Through a
rebidding process, APTIM was selected to continue as program administrator through 2022.
Focus on Energy Programs
Focus offers a portfolio of programs that match energy efficiency products and services to
appropriate customer segments, ensuring customers throughout the state have an equivalent
opportunity to receive the benefits of the programs.
Focus on Energy includes separate portfolios of programs to target residential and nonresidential
customers. To meet the differing needs of residential customers, separate residential programs ship
energy-efficient products directly to customers free of charge, operate an online marketplace where
customers can purchase energy efficient products which are then shipped to their home, offer retail
discounts on efficient lighting and appliances, help customers recycle their old, low-efficiency
appliances, work with contractors to support energy efficient repairs and installations, and work with
homebuilders to increase the energy efficiency of new homes. Within Focus’ non-residential
portfolio, separate programs target the differing efficiency opportunities for different types of
customers, including small businesses, commercial customers, schools and government facilities,

A voluntary energy efficiency program is run by the electricity provider with funding that is above and beyond what
the electricity provider is required to collect pursuant to Wis. Stat. § 196.374.
58 The IOUs created a nonprofit board to fulfill its duties under Act 141. The 9-member board is called the Statewide
Energy Efficiency and Renewables Administration (SEERA).
57

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agriculture customers, and large industrial facilities. As part of the 2018 Quadrennial Planning
process, the Commission also allocated $8 million in annual funding to provide enhanced program
offerings to rural residential, agricultural, and industrial customers. More specific information on
program offerings can be found at www.focusonenergy.com.
While Focus accounts for the largest share of energy efficiency activity in the state, all electric
providers in the state provide some degree of additional energy efficiency services. These services
include educational and marketing activities, which do not have quantifiable savings of their own but
can help increase Focus savings by informing customers of Focus offerings and encouraging
participation. Some electric providers also fund and operate their own energy efficiency programs, 59
although, as shown below, spending and savings from those programs remain small relative to
Focus’ statewide activities.
Focus on Energy Outcomes
Independent program evaluators, led by the Cadmus Group (Cadmus), perform research and analysis
to validate the energy savings from Focus programs. Cadmus works with program staff to manage
Focus’ Technical Reference Manual (TRM), which documents and explains the methods for
calculating savings achieved from installing energy efficient measures. Savings calculations in the TRM
take into consideration the lifecycle savings achieved as participants continue to use their efficient
products and services for many years after implementation. Evaluators also seek to validate the
amount of net savings that can be attributed to the influence of Focus programs, excluding the savings
from “free-rider” participants who would have taken the same actions without Focus’ support.
While energy-efficient products can reduce both energy use and total energy demand for customers,
the Commission’s quadrennial planning decisions have directed Focus to place primary priority on
achieving savings in energy use. Demand savings are still tracked by the program, but are a
secondary priority for Focus programs to achieve. In the 2015-2018 period, Focus achieved total
life cycle verified net savings of 210.4 million MMBtu, the equivalent of the amount of energy to
power more than two million typical Wisconsin homes for a year. Total savings exceeded the
Commission’s energy savings goals for the four-year period. These lifecycle savings will reduce CO 2
emissions by more than 28.5 million tons during the lifetime of the projects installed.
Focus’ evaluators also validate whether the program meets its Commission requirement to operate
cost-effectively, and achieve benefits in excess of costs. As directed by the Commission, Focus
measures cost-effectiveness using a Modified Total Resource Cost (TRC) test that compares the
benefits from reduced energy use and emissions to the costs of program administration, program
implementation, and the higher costs of energy-efficient products to participants. For 2018,
Cadmus’s cost-benefit analysis concluded that for every dollar spent, Focus’ full portfolio of

NPSW, WEPCO, WP&L, WPSC, and WPPI Energy all operate Commission-approved “voluntary programs”, using
utility funds that are in addition to the funds they contribute to Focus. Some cooperatives associated with DPC use the
$8.00 per meter they are required to collect for energy efficiency to operate their own programs instead of contributing
those funds to Focus.

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programs achieved $3.66 in lifecycle benefits. 60 A recent national study of energy efficiency
programs found that Wisconsin ran the most cost-effective efficiency programs of any state in the
country, achieving the highest rate of energy savings per dollar spent. 61
Future Focus on Energy Spending and Outcomes
Annual IOU contributions to Focus on Energy are based on utility revenues, and therefore can vary
based on weather conditions and other influences on revenue levels. Commission decisions on
program offerings can also impact Focus’ available funding and annual expenditures. As shown in
Figure 5-1, Focus’ actual electric energy efficiency expenditures declined from 2018 to 2019 and its
projected expenditures will decline further in 2020. The decline in 2019 reflects the Commission’s
use of previously unallocated surplus Focus funds to support programs targeting rural customers in
2017 and 2018. Most excess funds were spent in the two-year period, reducing available surplus
funds for future years.
The decline from 2019 to 2020 reflects a decrease in utility contributions. Commission staff
calculate each IOU’s required contribution based on historical revenue averages. Beginning in 2020,
the historical calculation no longer includes utility revenues from 2014, when extremely cold polar
vortex conditions led to unusually high energy use and revenues. As a result, program contributions
will decline. IOUs project generally stable contribution levels between 2021 and 2026, with only
slight increases over the five-year period. Spending on additional utility programs is also projected
to remain stable.

For informational purposes, Cadmus also conducts an “expanded TRC” test which incorporates the economic
benefits created by Focus. In 2018, the program evaluator’s expanded TRC analysis found that Focus created net
economic benefits of nearly $348 million and achieved $5.16 in benefits for every $1.00 in costs.
61 Report available at: http://www.swenergy.org/Data/Sites/1/media/lbnl-cse-report-june-2018.pdf.
60

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 DRAFT ‒ Strategic Energy Assessment 2026
Figure 5-1

Actual and Projected Annual Electric Energy Efficiency Expenditures 2018-2026 62

To inform the determination of savings goals for the 2019-2022 quadrennial period and beyond, the
Commission authorized the independent program evaluators in 2017 to conduct a potential study
projecting the amount of future energy efficiency savings Focus could achieve. The final study,
completed in 2017, used data on customers’ existing energy use practices and available efficient
technologies to assess achievable energy savings under a variety of scenarios, including a “business
as usual” scenario that maintained Focus’ existing program policies. In its 2018 quadrennial
planning decisions, the Commission approved savings goals based on the business as usual scenario,
consistent with other decisions to continue existing program policies.
The potential study concluded that Focus should be able to continue achieving energy savings
consistent with historical levels in the 2019-2022 period. These potential estimates are reflected in
Figure Y, which maintains electric savings estimates closely comparable to achieved savings in 2018.
Beginning in 2020, the Focus program deployed a restructured portfolio intended to simplify and
enhance the customer experience, reduce administrative costs, and target opportunities for increased
energy savings. The reorganization is intended to help support Focus’ ability to maintain overall
program savings levels with reduced funding, while also maintaining cost-effectiveness and

Sources: Aggregated electricity provider data responses, docket 5-ES-110; Focus on Energy 2018 Evaluation Report;
Focus on Energy 2019 to 2022 Program Administration Contract.

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improving service to rural customers. Projected energy savings from other utility programs are
projected to remain stable through 2026.
Figure 5-2

Actual and Projected First-Year Annual Energy Savings 2018-2026 63

The Commission has authorized the Focus program evaluator to perform an updated potential study
to inform the next quadrennial planning process. The study will be conducted in 2020-2021 and
focus on assessing savings potential for the 2023-2026 quadrennial period, as well as longer-term
potential in subsequent years. Along with reviewing appropriate levels for future program goals, the
study will also collect additional information to help inform the Commission’s quadrennial planning
review. For example, the study will assess in more detail Focus’ potential future impacts on reducing
carbon emissions, and assess Focus’ future potential for demand savings, to help the Commission
assess whether the program’s current primary emphasis on energy savings should be maintained or
modified.
DEMAND RESPONSE
Demand response programs provide customers with incentives to reduce energy demand during
peak periods and create financial savings for electric providers and customers. Demand response
programs are most commonly deployed in the summer months, to reduce peak energy usage during
Sources: Aggregated electricity provider data responses, docket 5-ES-110; Focus on Energy 2018 Evaluation Report;
Focus on Energy 2019 to 2022 Program Administration Contract; 2017 Focus on Energy Potential Study.

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the highest-demand periods of the year. Demand response programs may also be operated at other
times of a year to support a balance between demand and available supply, such as to reduce usage
during smaller winter peak periods or to address demand on days when available generation is
limited due to plant outages. (See the Supply chapter for more information on peak demand.)
Wisconsin electricity providers operate two types of demand response programs: 64
•

•

Interruptible service programs enable customers to receive a lower energy charge in return
for allowing their electric provider to interrupt load during periods of peak demand.
Interruptible load programs are typically targeted to industrial customers.
Direct load control programs enable electric providers to turn off or reduce the energy use
of specific customer equipment, such as residential air conditioners. Customers receive an
upfront financial incentive to encourage their participation and share in the financial savings
that can be achieved through successful demand reductions.

As shown in Figure 5-3, available interruptible service capacity reached a historic high of 1,156 MW
in 2018, nearly 8 percent of statewide peak demand. Figure 1 also shows that electric providers have
deployed no more than 24 percent of available resources in any year since 2013. Providers’ projected
amount of available interruptible resources through 2026 declines to about 700 MW per year, or
approximately 5 percent of peak demand, driven largely by recent provider decisions to cease
enrolling new customers in their interruptible tariffs due to low customer demand. At these reduced
levels, the amount of available interruptible resources statewide still significantly exceeds the amount
of interruptible service historically used.

Some definitions of demand response include other types of approaches that can help reduce demand, such as timeof-use rates and energy efficiency programs designed to achieve demand savings. This section focuses on the distinct
program models that are not already addressed elsewhere in the report.
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Figure 5-3

Interruptible Service in Wisconsin

1400
1200

Megawatts

1000
800
600
400
200
0

2013

2014

2015

2016

2017

2018

2019

Interruptible Available

2020

2021

2022

2023

2024

2025

2026

Interruptible Used

Available direct load control resources in recent years have totaled between 150-230 MW, or slightly
more than 1 percent of statewide peak demand. As shown in Figure 5-4, approximately 33 percent
of available resources were deployed annually since 2013. Providers forecasted direct load control
capacity declines below 100 MW annually, driven in part by provider decisions to close programs
due to low enrollment and increasing technical difficulties in maintaining the control equipment.
However, actual figures in future years may remain higher than projections; at least one provider
with significant program activity in recent years did not forecast any future load control due to
program uncertainty, but still may continue to operate programs. As with interruptible programs,
available capacity statewide would still exceed historical levels of direct load control under the
reduced projections.

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Figure 5-4

Direct Load Control in Wisconsin

250

Megawatts

200

150

100

50

0

2013

2014

2015

2016

2017

2018

2019

DLC Available

2020

2021

2022

2023

2024

2025

2026

DLC Used

Historically, direct load control programs have used equipment to remotely turn off participating
technologies (such as air conditioners and water heaters) on a temporary basis. Two recent
Commission-approved programs, MGE’s Smart Thermostat Demand Response Pilot 65 and NSPW’s
AC Rewards program, 66 have started using new program models that control usage through
customers’ wi-fi-enabled smart thermostats. Both programs use software to set participant
thermostats at a higher temperature setting during peak demand events, and also provide
“pre-cooling” before peak demand hours to help participants remain comfortable during the event.
As the deployment of smart thermostats continue to increase, these program models may be able to
support further development of direct load control programs, as well as provide opportunities for
integration with energy efficiency programs that support smart thermostat installation.
RENEWABLE ENERGY
The primary driver for utility-scale renewable resource development by Wisconsin electric providers
over the last decade has been compliance with Wisconsin’s Renewable Portfolio Standard (RPS) law.
However, declining costs, environmental benefits, and customer interest are driving increased
renewable deployment above RPS requirements, including through growth in provider offerings
such as community solar programs, and through individual customers’ increased use of renewables.

65
66

Commission dockets 3270-TE-121 and 3270-TE-106.
Commission docket 4220-TE-103.

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Renewable Portfolio Standard
Wisconsin’s present RPS law, established by 2005 Wisconsin Act 141, requires each electric provider
to increase the share of renewable energy resources it uses to serve retail customers, in order to
achieve a statewide goal for renewable resources to provide at least 10 percent of energy generation
by 2015. 67
Individual electric providers have met their requirements every year since 2006, and the statewide
goal of 10 percent of electricity has been achieved every year since 2013. As shown in Figure 5-5,
wind energy accounts for the largest share of renewable resources providers have deployed to
comply with the RPS, and accounts for nearly all of the increases in deployment since 2010 that
have been required to attain RPS compliance.
Figure 5-5

Renewable Energy by Resource 2010-2018
6,000,000
5,000,000

Wind

MWh

4,000,000
3,000,000
2,000,000

Hydro

1,000,000

Biomass

-

2010

2011

2012

2013

2014

2015

2016

2017

2018

As shown in Figure 5-5, wind energy accounted for nearly two-thirds of total renewable energy
generation serving Wisconsin customers. Most of that wind energy is supplied through the
transmission system from out-of-state facilities located west of Wisconsin, where more consistently
windy weather conditions support more cost-effective generation. Solar resources accounted for
approximately 1 percent of total renewable generation deployed by electric providers in 2018.
(These figures do not include solar generation used by individual customers, which is described in
the Customer-Scale Renewables section below).

To achieve the statewide 10 percent standard, the RPS requires each electric provider to increase their percentage of
renewables, relative to their 2001-2003 baseline, by 2 percent by 2010 and 6 percent by 2015.

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Figure 5-6

2018 Renewable Energy by State and Resource

WI Solar
< 1%

WI
Biomass
10%

Non WI
Wind
46%

WI Hydro
17%
WI Wind
19%

Non WI
Solar
< 1%

Non WI Biomass
2%

Non WI
Hydro
5%

Electric Provider Solar Initiatives
As outlined in the Supply chapter, significant declines in the cost of solar energy, as well as the
environmental benefits of deploying zero-carbon resources, are leading Wisconsin electric providers
to add multiple sources of solar generation in the coming years, over and above the resources
required for RPS compliance. Electric providers also cite business case reasons for investing in new
renewable resources, such as hedging against volatility in fuel prices and investing in resource
diversification. Most electric utilities have also established carbon reduction targets, which have led
them to invest more heavily in renewable energy resources, including solar energy.
As shown in Table 5-1, approved solar construction projects would result in the addition of
750 MW of in-state solar generation by 2022, and increase the total statewide share of renewable
generation by approximately 2 percent. 68

Construction of Badger Hollow, Two Creeks, Point Beach, and Badger State have been approved by the Commission.
While the Richland County solar farm falls below the 100 MW capacity threshold for Commission approval, the project
has received approvals at the county level.
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Table 5-1

Approved Solar Additions in Wisconsin and Expected Renewable Energy Generation and Percentage

Statewide Retail Sales
(MWh)
Statewide 2018:
70,938,007

Statewide 2023:
71,000,000

Solar Facility Additions

Badger Hollow
Two Creeks
Richland County Solar Farm
Point Beach
Badger State

Expected
In-Service
2020
2020
2021
2021
2022

Expected Renewable
Annual Generation (MWh)

Statewide
Renewable Energy

Statewide: 7,638,136

10.8 %

630,720
315,360
104,069
210,240
313,258
Statewide: 9,211,783

13.0%

The implementation of additional planned solar construction projects would result in further
increases. For example, Wisconsin Power and Light Company (WP&L) projects the addition of at
least 500 MW in additional solar capacity by 2023, but has not announced specific project plans to
date (see Supply chapter, Table 1-4). Independent solar developers are also in the process of
planning multiple additional solar projects in Wisconsin, and the capacity from those projects may
be leased by electric providers at a future date.
The status of the federal Investment Tax Credit (ITC) for solar development may have a significant
influence on the timing and scale of solar investment decisions. Under current law, solar facilities
must be placed into service by the end of 2023 to qualify for the ITC, and the value of the credit is
higher if construction begins in earlier years. 69 Absent future federal action to extend or modify the
current credits, the current ITC provides incentives to move forward with renewable energy
planning and construction in the near term.
Utility-scale solar construction projects will increase the share of renewable generation provided to
all customers. An increasing number of electric providers have also established community solar
programs for individual customers interested in procuring a larger share of their own energy use
from renewables. Community solar programs allow residential, and sometimes commercial
customers, to pay a subscription fee for a specific amount of energy produced by solar facilities on
the provider’s system. Most commonly, customers pay the subscription fee upfront, and then
receive monthly bill credits to reflect the solar energy production associated with their subscription.
MGE’s Shared Solar program uses an alternative program structure under which customers can
receive a guaranteed retail rate associated with the costs of the solar facilities for the duration of their
participation.
As shown in Figure 5-7, total capacity offered by Wisconsin community solar programs has
increased 61 percent from 2017 to 2019. Further additions planned for 2020 will increase total
available community solar capacity to 8.3 MW. Customer subscriptions have consistently exceeded
85 percent of available capacity.

Projects can be “safe harbored” through equipment purchases or by commencing construction. Projects which meet
these criteria in 2019 qualify for a 30 percent tax credit; projects which meet those criteria in 2020 qualify for a
26 percent tax credit; and projects which meet those criteria in 2021 qualify for a 22 percent tax credit.

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Figure 5-7

Community Solar Capacity in Wisconsin

9
8

Megwatts (MW)

7
6
5
4
3
2
1
0
2016

2017

2018

2019

Available Capacity

2020

2021

2022

Subscribed Capacity

Four electric providers also offer “renewable rider” programs for large customers to contract for a
defined amount of utility-provided renewable resources for their use. The renewable rider uses a
similar concept as Community Solar, but allows the electric provider to define larger portions of
either distribution or transmission-interconnected renewable facilities for specific customers through
individual contracts.
Customer-Owned Renewables
Customers may also procure renewable resources by installing their own sources of generation on
their property. Customer-owned generation, also commonly referred to as distributed energy
resources (DERs), can reduce the amount of electricity the customer would have otherwise needed
to purchase from their electric provider (or provide energy back to the grid). Net metering
arrangements enable eligible customers to receive bill credits for providing excess energy production
from their generation back to their electric provider. 70
Starting in 2016, each Strategic Energy Assessment has asked all electric providers in Wisconsin to
report data on the number, type, and generation capacity of all DERs used by their customers,
including historical data extending back to 2008. DER data reported by utilities include all
customer-owned generation, including from non-renewable sources such as diesel-fueled generators.
Since non-renewable sources account for only 10 percent of total DER capacity, the analysis below
focuses on renewable DERs.

Eligibility for net metering arrangements varies by electric provider, but is generally limited to small-capacity solar
installations, most commonly with capacity of less than 20 kW.

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Customer-owned renewable generation capacity in Wisconsin totaled 258 MW (DC) in 2019, which
amounts to 1.66 percent of total statewide capacity, as shown in Figure 5-8. 71 Customer-owned
solar installations account for the largest share by source. At a total capacity of slightly more than
100 MW (DC), customer-owned solar accounts for nearly 40 percent of renewable DER capacity
and 0.64 percent of total statewide electric capacity. 72
Figure 5-8

Capacity of Customer-Owned Renewables in Wisconsin, 2019

Total Statewide
Capacity less DERs
98.34%
Total Renewables
1.66%

Storage
0.00%
Wind
0.09%

Hydro
0.32%
Other
0.26%

Biogas
0.18%
Solar
0.64%

Biogas

Landfill Gas

Solar

Wind

Storage

Hydro

Landfill Gas
0.17%

Other

Statewide Capacity

As shown in Figure 5-9, the number of customer-owned renewable installations has increased
consistently over the past decade, from 528 in 2008 to 7,004 in 2019. The increase has been driven
almost entirely by increased deployment of solar resources, with an average annual growth rate of
more than 20 percent per year. The 6,646 solar installations reported in 2019 account for 95 percent
of all renewable DER installations in Wisconsin. As shown in Appendix D, more than 90 percent
of all renewable DERs are small-scale installations of less than 20 kW (Figure D-1). A majority of
DER installations are used by residential customers, and the share of installations by residential
customers has gradually increased over time, reaching 75 percent in 2019 (Figure D-2).

DER analysis in previous SEAs has reported the amount of generation (MWh) rather than the amount of capacity
(MW). However, the generation data electric providers are able to report reflects the amount of energy purchased by the
utility, which can understate the scale of DER use and deployment by excluding energy directly used by the customer.
Capacity figures are provided here with the intent to quantify the general scale of DER deployment across the state.
72 SEA data collection requirements direct providers to report solar capacity based on the Direct Current (DC) capacity
of the panels, rather than the Alternating Current (AC) capacity of the inverters. AC capacity values are lower than DC
values, so capacity reported in AC would result in lower values than reported here.
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Number of Installations

Figure 5-9

Number of Renewable DER Installations by Technology

7,500
6,750
6,000
5,250
4,500
3,750
3,000
2,250
1,500
750
-

2008

2009

Biogas

2010

Fossil Fuel

2011

2012

Hydroelectric

2013

2014

Landfill Gas

2015

Other

2016
Solar

2017

2018

Storage

Wind

2019

By contrast, the 258 MW in total installed (DC) capacity from customer-owned renewables
represents a decline from levels in the first half of the 2010s, as shown in Figure 5-10. The decline
reflects customer decisions to discontinue operation of a small number of very large DER
installations, primarily in the industrial sector. As a result, the share of renewable DER capacity
categorized as landfill gas or other renewable sources has declined, offset only partially by capacity
growth from small-scale solar installations. As shown in Appendix D, large installations with
capacity in excess of 1,000 kW continue to account for the majority of installed capacity, although
their share has decreased in recent years (Figure D-3). Although the share of residential capacity has
gradually increased due to the increased deployment of small-scale residential solar, commercial and
industrial installations still account for nearly 90 percent of Wisconsin’s total (DC) DER capacity
(Figure D-4).
Figure 5-10

Installed Capacity of Renewable DER Installations by Renewable Source

Installed Capacity (kW)

450,000
375,000
300,000
225,000
150,000
75,000
-

2008

2009

Biogas

2010

2011

Hydroelectric

2012

2013

Landfill Gas

2014

Other

2015
Solar

2016

2017

Storage

Wind

2018

2019

ELECTRIC VEHICLES
Large-scale use of electric vehicles (EV) could have significant implications for Wisconsin’s electric
system, by increasing total electric demand, modifying timing and location of energy use, and
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presenting new considerations for determining customer rates and service arrangements. Fewer
than 10,000 EVs were operated in Wisconsin in 2019, and the effects on electric system demand to
date remain limited. The speed and scale of future increases in EV use is also uncertain. However,
the Commission and electric providers have initiated research and programming to serve current
customers with EVs and to begin exploring a range of relevant issues in advance of expanded EV
use.
In February 2019, the Commission opened an investigation in docket 5-EI-156 to consider future
policies and regulations related to EVs and their associated infrastructure, including the home and
public charging stations required for customers to operate their vehicles. To establish a
collaborative, stakeholder-driven process for the investigation, the Commission has solicited written
comments from interested stakeholders on the full range of EV policy and regulatory issues, and
organized a workshop supporting expanded small-group discussion of the issues. The Commission
received substantial input and feedback through both processes, receiving 42 written comments and
input from more than 60 workshop attendees.
Several electric providers have already taken steps to address EV-related customer demand, by
establishing new electric rates for vehicle charging and offering financial incentives for the
installation of charging infrastructure. Feedback submitted from a range of stakeholders, including
electric vehicle owners, identifies a range of priorities as the Commission and electric providers
continue to consider further future activities. As shown in Figure 5-5, multiple topic areas were
identified by commenters as priorities for continued consideration.
•

•

•

•

•

The most commonly cited issue was access to charging infrastructure. Commenters
identified insufficient access as the most significant barrier to EV use, associated with the
“range anxiety” drivers may feel due to limited public charging options during travel.
Commenters also cited interest in appropriate pricing and rate design. Setting rates for
EV charging will require new analysis of how to allocate charging-specific costs to
participants, and how to design rates that are cost-effective for customers and providers.
Load management refers to the issues, associated with increased electric demand from
significant expansions in electric vehicle use. Additional demand could result in increased
costs for generation and transmission. Opportunities may also exist to manage the increased
load cost-effectively, by using time-of-use rates and “managed charging” programs that
encourage customers to shift charging use away from periods of peak demand.
While few Wisconsin providers currently offer subsidies and incentives specific to EV
infrastructure, a growing number of providers nationwide have initiated offerings to
encourage growth in electric demand and support cost-effective load management.
Many commented in the investigation that third-party ownership of public EV charging
stations should not require the owner to be regulated as a public utility. However, the
potential application of the statutory definition of a public utility to an EV charging station
has not yet been analyzed by the courts in this state, and EV charging stations present novel
legal scenarios. Further discussion by the Commission, regulated utilities, the Legislature,
and other parties active on EV issues may be appropriate to clarify these legal uncertainties.

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Figure 5-5

Areas of Interest

The Commission will continue its EV investigation during 2020. Commission staff are also
conducting additional technical research to model the potential effects of expanded EV deployment
on the electric system. Initial findings suggest that expanding electric vehicle use to 5 percent of
Wisconsin’s total vehicle mix, which is well above current levels of 0.1 percent, would still have
minimal effects on system metrics such as transmission capacity and wholesale market energy costs.
To support future planning, continuing research will assess the effects of a wider range of scenarios
by assessing system conditions at different levels of EV penetration.

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CHAPTER 6 ‒ ELECTRIC SYSTEM EMISSIONS

The burning of fossil fuels results in emissions of numerous pollutants. Wisconsin electric providers
have achieved substantial reductions in the local pollutants that cause environmental impacts in
areas near generation sources, such as nitrous oxide (NO 2 ), sulfur dioxides (SO 2 ), particulate matter,
and carbon monoxide (CO). Statewide, electric providers reduced total emissions from those
sources by more than 60 percent between 2007 and 2017, 73 largely through investments in emissions
control projects and reductions in the share of coal generation. (See Supply chapter.)
In the past two years, a number of electric providers in Wisconsin and nationwide have established
new goals to reduce emissions of carbon dioxide (CO 2 ) . CO 2 emissions occur from the use of coal
and natural gas for electricity generation, as well as from transportation fuels and from fossil fuel use
outside of the electric system, such as propane use. As shown in Figure 5-6, transportation
emissions currently represent the largest contributor to nationwide CO 2 emissions. In 2017, the
most recent year for which complete data is available, transportation accounted for 37 percent of
U.S. CO 2 emissions, compared to 33 percent from electric generation.
By contrast, electric generation accounts for the largest share of carbon emissions in Wisconsin. In
2017, electric generation represented 42 percent of CO 2 emissions in Wisconsin, while
transportation emissions represented 29 percent of emissions and industrial use represented 13
percent. 74
Figure 6-1

Comparison of CO 2 Emissions by End Use in Wisconsin vs. National Average

50%
40%
30%
20%
10%
0%

Electric Power

Transportation
Wisconsin

Industrial

Residential

Commercial

National Average

2017 Wisconsin Energy Statistics Book.
https://psc.wi.gov/Documents/OEI/WisconsinEnergyStatistics/ENVIRONMENT_AND_EMISSIONs.pdf, p. 1.
74 U.S Energy Information Administration (EIA) State Carbon Emissions Data.
https://www.eia.gov/environment/emissions/state/.
73

72

 DRAFT ‒ Strategic Energy Assessment 2026

One driver of Wisconsin’s differences from the national average is the continuing status of coal as a
leading source of electric generation (see Supply chapter.) As shown in Figure 6-2, 38 percent of
Wisconsin’s total CO 2 emissions in 2017 resulted from coal emissions, almost all of which was for
electricity generation, compared to 26 percent of emissions nationwide. 75
Figure 6-2

Comparison of CO 2 Emissions by Fossil Fuel Type in Wisconsin vs. National Average

50%

40%

30%

20%

10%

0%

Coal

Petroleum
Wisconsin

Natural Gas

National Average

ELECTRIC PROVIDERS’ CARBON REDUCTION GOALS
As part of its data request for the SEA, the Commission asked each major electric provider for
information on the definition of any CO 2 reduction goals it has set. The Commission also requested
that each provider document its current and projected emissions levels, regardless of whether the
provider has set a formal reduction goal. 76
As shown in Table 6-1, Wisconsin’s five largest electric providers have established goals to reduce
their 2050 CO 2 emissions by either 80 percent or 100 percent compared to 2005 levels. Four of the
five providers also set interim goals to reduce 2030 emissions by at least 40 percent. Providers differ
in their methods for measuring reductions. For example, WP&L’s goal applies reductions from its

Id.
Major electric providers, also termed “primary respondents,” include DPC, Great Lakes Utilities, MGE, Manitowoc
Public Utilities, NSPW, SWL&P, WEPCO, WP&L, WPSC, and WPPI Energy. Other providers, such as municipal
utilities and smaller IOUs, were not required to respond to this component of the Commission’s data request.

75
76

73

 DRAFT ‒ Strategic Energy Assessment 2026

owned generation, while NSPW measures emissions from all electricity used to serve its customers,
including owned generation as well as purchased power.
Table 6-1

Carbon Dioxide Reduction Goals of Wisconsin Electric Providers
Provider
Northern States Power Company-Wisconsin (Xcel)
Madison Gas and Electric Company
Wisconsin Electric Power Company (We Energies)
Wisconsin Power and Light Company (Alliant)
Wisconsin Public Service Corporation

2030 CO 2 Reduction Goal
80%
40%
40%
40%

2050 CO 2 Reduction Goal
100%
100%
80%
80%
80%

The five electric providers with CO 2 reduction goals provide approximately 85 percent of total
electric service in Wisconsin. 77 As a result, achievement of these goals would reduce statewide
emissions from electric generation by approximately two-thirds from the 2005 baseline. Further
reductions could be achieved from other electric providers. For example, while DPC has not set a
quantified goal, it has recently announced plans to close a coal plant in favor of lower-emission
energy sources. (See Supply chapter.)
HISTORICAL ELECTRIC SYSTEM EMISSION TRENDS
Statewide Wisconsin CO 2 emissions from electricity generation declined 16.4 percent from 2005 to
2017. In response to the Commission’s data request, the five electric providers with carbon
reduction goals reported a comparable average reduction of 18.5 percent between 2005 and 2018.
These emission reductions have occurred despite overall growth in electric generation since 2005.
As shown in Figure 6-3, these changes have instead reflected a decline in carbon emissions per unit
of electricity generated, or “carbon intensity.” As shown in Figure 6-3, total carbon intensity
declined 28.4 percent between 2005 and 2017.

77

Source: Aggregated electricity provider data responses, docket 5-ES-110.

74

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 6-3

Wisconsin Electric CO 2 Emissions per MWh, 2005-2017

1.00

(t/MWh)

0.90
0.80
0.70
0.60
0.50
2005

2007

2009

2011

2013

2015

2017

Three factors have made significant contributions to the decline in carbon intensity. First,
Wisconsin coal generators have become more carbon efficient due to a variety of changes, including
the installation of emissions controls. On average, coal facilities in Wisconsin reduced their carbon
intensity by 14 percent from 2005 to 2017.
Second, Wisconsin electric providers have increasingly used natural gas as a generation source in
place of coal. Compared to coal, natural gas emits approximately 50 percent less CO 2 per unit of
energy. As noted in the Supply chapter, declines in natural gas prices have supported a significant
increase in natural gas generation since 2010, and a corresponding reduction in the share of
generation from coal.
Third, electric providers have also increased their use of zero-carbon generation sources, including
nuclear power and renewable energy, from 2005 levels. The amount of increased generation from
zero-carbon sources equates to more than half of Wisconsin’s total increase in generation needs
between 2005 and 2017, needs that likely would have otherwise been met by additional coal or
natural gas generation.
PROJECTED EMISSIONS REDUCTIONS
The Commission’s data request asked major electric providers to identify their projected CO 2
emissions in 2020 and 2026, in addition to providing their most recently measured carbon emissions
in 2018. Figure 6-4 summarizes total emissions from all reporting utilities. As noted above, average
2018 emissions reported by providers decreased 18.5 percent from 2005 levels. Providers projected
additional emissions reduction of 22.9 percent between 2018 and 2020, resulting in 2020 emissions
levels 37.5 percent below 2005. Providers reported more limited reductions between 2020 and 2026,
projecting emissions levels 39.8 percent lower than 2005.

75

 DRAFT ‒ Strategic Energy Assessment 2026
Figure 6-4

Wisconsin Electric Sector CO 2 Emissions

Million Metric Tons of Carbon Dioxide (MMTCO2)

60

50

40

30

20

10

0

2005

2018

2020

2026

Multiple providers identified coal plant retirements as a significant driver of reduced emissions
between 2018 and 2020. Nearly 1,800 MW of coal generation capacity will be retired within the
two-year period, including the retirements of generating units at Pleasant Prairie, Pulliam, and
Edgewater (Unit 4).
Providers also consistently identified multiple additional factors driving emissions reductions in both
2020 and 2026, including:
•

•
•

•

Deployment of new natural gas plants in place of coal-fired generation, including 1,214 MW
of capacity from Commission-approved plants at West Riverside and Nemadji Trail Energy
Center;
Deployment of new utility-owned solar resources, including 964 MW of new capacity
reported by providers;
Increased zero-carbon energy deployment on MISO’s regional grid, which will reduce
emissions from the purchased power providers obtain through power purchase agreements
and wholesale purchases on the regional market; and
Continued increases in conservation and energy efficiency.

The limited amount of emissions reductions projected between 2020 and 2026 largely correspond to
specific future generation additions and retirements reported by providers. (See Supply chapter).
Total emissions reductions may exceed the projections if further additions of zero-carbon
generation or retirements of fossil fuel generation take place before 2026. Furthermore, any declines
in electric demand due to economic conditions associated with the COVID-19 pandemic may result
in decreased emissions. Although projected goal compliance varies by individual provider, the
76

 DRAFT ‒ Strategic Energy Assessment 2026

aggregate projected emissions reductions of 39.8 percent by 2026 would already closely align with
the 40 percent reduction target multiple providers have set for 2030.

77

 DRAFT ‒ Strategic Energy Assessment 2026

APPENDIX A – SUPPORTING DATA, ELECTRIC SUPPLY
Table A-1

Year
HISTORICAL:
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
FORECASTED:
2019
2020
2021
2022
2023
2024
2025
2026

Table A-2

Assessment of Electric Demand and Supply Conditions, Monthly Non-Coincident Peak Demands,
MW 78 (using SEA monthly peak demand and previous SEA)

JAN

FEB

MAR

APR

MAY

JUN

JUL

AUG

SEP

OCT

NOV

DEC

10,739
10,924
11,127
10,622
10,958
11,249
11,273
10,671
10,552
10,614
10,685
11,299
11,107
10,755
10,842
10,977
11,207

10,498
10,384
10,678
10,556
11,419
11,167
10,681
10,226
10,645
10,020
10,182
10,656
10,710
10,139
10,245
10,414
10,561

10,291
10,091
10,433
10,174
10,682
10,437
10,246
9,611
9,824
9,779
9,720
10,272
10,153
9,659
9,720
9,674
10,649

9,602
9,400
9,610
9,550
9,946
9,899
9,209
9,030
9,311
9,005
9,171
9,150
9,072
9,049
9,166
9,375
9,334

9,048
10,273
10,000
11,527
11,343
9,583
9,606
12,490
10,668
10,394
10,221
10,117
9,871
10,190
10,047
12,739
9,770

12,725
12,486
14,020
12,559
13,834
12,283
13,694
12,495
13,601
13,974
11,937
11,793
11,243
12,500
13,143
14,143
11,970

13,319
12,958
13,832
15,006
14,163
13,256
11,051
13,069
14,870
15,105
14,347
13,290
12,860
13,730
13,230
13,655
14,023

13,694
12,437
14,323
14,507
14,461
12,883
12,260
14,098
13,553
13,439
14,162
12,270
13,308
13,851
12,474
13,373
12,779

11,937
12,161
13,224
11,060
13,693
13,111
10,846
11,662
13,092
12,927
13,428
11,255
13,065
13,030
13,123
13,118
11,500

10,136
9,902
11,912
10,320
12,033
10,216
9,454
9,608
9,624
9,681
9,647
9,339
9,207
9,695
10,178
10,357

10,450
10,557
10,833
10,909
11,091
10,279
9,944
10,170
9,955
10,186
9,814
10,403
9,694
9,574
9,972
10,155

11,302
11,478
11,581
11,553
11,503
11,438
11,075
11,101
10,520
10,475
10,897
10,514
9,986
10,900
10,804
10,220

10,845
10,795
10,916
10,944
10,987
11,017
11,047

10,574
10,578
10,706
10,732
10,791
10,824
10,858

10,060
10,025
10,141
10,170
10,209
10,241
10,273

9,398
9,362
9,478
9,506
9,543
9,574
9,636

10,421
10,369
10,489
10,522
10,561
10,597
10,633

13,112
13,127
13,252
13,298
13,343
13,387
13,429

14,277
14,307
14,420
14,469
14,517
14,561
14,601

13,968
14,003
14,108
14,160
14,205
14,248
14,288

12,471
12,510
12,599
12,636
12,688
12,729
12,769

9,775
9,814
9,852
9,913
9,952
9,979
10,015
10,049

10,083
10,169
10,217
10,274
10,311
10,341
10,373
10,404

10,683
10,746
10,837
10,889
10,919
10,956
10,988
11,017

Wisconsin Aggregated Supply and Demand 79

Report Line MISO Description Capacity (MW)
High Certainty Resources
Low Certainty Resources
Behind the Meter
Demand Response Resources
New Capacity
Local Resource Zone (LRZ) Internal Transfer - In
LRZ Internal Transfer – Out
Net Imports
Retired
Net Capacity (MW)
Demand (MW)
Non-Coincident Load Serving Entities (LSE) Peak gross of DR
Full Responsibility Transactions
Zonal Coincident Factor
Coincident LSE Peak with Zonal Peak
MISO Coincident Factor
Expected Demand: Coincident LSE Peak to MISO Peak
Reserve Requirement (MW)
Local Clearing Requirement
Planning Reserve Requirement
Average UCAP Planning Reserve Margin
Resources above local clearing requirement
Resource above planning reserve requirement
UCAP Planning Reserve Margin

78
79

2020
12,736
8
353
886
644
1881
(661)
395
(401)
15,842

2021
12,719
0
315
796
783
2036
(821)
430
(404)
15,853

2022
12,389
0
315
786
956
2026
(801)
430
(408)
15,692

2023
12,389
0
315
789
1222
1611
(536)
430
(414)
15,804

2024
12,365
24
314
789
1245
1611
(514)
430
(615)
15,648

2025
12,650
0
314
792
1380
1611
(514)
297
(693)
15,836

2026
12,650
0
310
795
1473
1611
(514)
297
(742)
15,878

14,532
(672)
0.98
14,953
0.9597
14,700

14,465
(522)
0.98
14,735
0.9597
14,485

14,513
(371)
0.98
14,632
0.9597
14,381

14,559
(321)
0.98
14,626
0.9597
14,375

14,606
(271)
0.98
14,623
0.9597
14,371

14,693
(271)
0.98
14,706
0.9597
14,450

14,759
(271)
0.98
14,769
0.9597
14,511

13,878
15,518
1.07
1,964
324
7.76%

13,772
15,283
1.07
2,082
570
9.45%

13,830
15,173
1.08
1,862
519
9.12%

13,778
15,172
1.08
2,027
632
9.94%

13,826
15,141
1.08
1,823
507
8.89%

14,105
15,275
1.08
1,731
561
9.59%

14,118
15,364
1.08
1,760
514
9.42%

Source: Aggregated electricity provider data responses, docket 5-ES-110.
Source: Aggregated electricity provider data responses, docket 5-ES-110.

-1-

 DRAFT ‒ Strategic Energy Assessment 2026
Figure A-1

MISO System-Wide Average Monthly Day-Ahead and Real-Time LMPs $/MWh

Figure A-2

Forecasted Levelized Cost of Electricity in $/MWh per NREL in 2019

$120
$100
$80
$60
$40
$20
$0

2019

2024

2030

2034

2040

2044

Nuclear

Wind-WI

Wind-MN

Solar-Chicago

Coal

Coal-90% Carbon Capture

NGCC- Carbon Capture

Natural Gas Combined Cycle

-2-

2049

 DRAFT ‒ Strategic Energy Assessment 2026
Table A-3

Data for Figure A-2

Year
2019
2024
2030
2034
2040
2044
2049

Nuclear
$66
$65
$64
$63
$62
$61
$60
Change from 2019 to 2030:
-3%
Change from 2019 to 2049:
-9%

Figure A-3

Wind-WI

Wind-MN

$39
$33
$28
$27
$25
$24
$22

$34
$30
$25
$24
$22
$21
$20

SolarChicago
$44
$39
$34
$32
$30
$28
$27

$68
$68
$68
$67
$67
$66
$66

Coal-90%
Capture
$106
$103
$100
$99
$97
$96
$95

NGCC
w/ CCS
$52
$55
$57
$58
$59
$60
$63

NGCC
no CCS
$31
$34
$36
$38
$39
$40
$42

-28%

-26%

-23%

0%

-6%

10%

16%

-44%

-41%

-39%

-3%

-10%

21%

35%

Coal

Wind Energy as Percent of Total Energy in MISO Region, 2014-2019

-3-

 DRAFT ‒ Strategic Energy Assessment 2026

APPENDIX B – SUPPORTING DATA, ELECTRIC TRANSMISSION
Figure B-1

MTEP19 Regional Investment by Project Category

-4-

 DRAFT ‒ Strategic Energy Assessment 2026

APPENDIX C – SUPPORTING DATA, CUSTOMER RATES AND BILLS
Figure C-1

Weather-Normalized Annual Use, per Residential Customer (kWh) 80

8,200
8,000
7,800
7,600
7,400
7,200
7,000

Figure C-2

2007

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2015

2016

2017

2018

Energy Intensity – Non-Residential Sales ($ of GDP/MWh) 81

$9,000
$8,000
$7,000
$6,000
$5,000
$4,000
$3,000
$2,000
$1,000
$-

80
81

2007

2008

2009

2010

2011

2012

2013

2014

Utility annual reports filed with the Commission.
Utility Annual Reports filed with the Commission; U.S. Bureau of Economic Analysis.

-5-

 DRAFT ‒ Strategic Energy Assessment 2026
Appendix Table C-1

Residential Average Rates in the Midwest and U.S. (cents/kWh)

State

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Illinois

11.07

11.27

11.52

11.78

11.37

10.63

11.91

12.50

12.54

12.95

12.77

Indiana

8.87

9.50

9.56

10.06

10.53

10.99

11.46

11.57

11.79

12.29

12.26

Iowa

9.49

9.99

10.42

10.46

10.82

11.04

11.16

11.63

11.94

12.34

12.24

Michigan

10.75

11.60

12.46

13.27

14.13

14.59

14.46

14.42

15.22

15.40

15.45

Minnesota

9.74

10.04

10.59

10.96

11.35

11.81

12.01

12.12

12.67

13.04

13.14

Missouri

8.00

8.54

9.08

9.75

10.17

10.60

10.64

11.21

11.21

11.63

11.34

Ohio

10.06

10.67

11.31

11.42

11.76

12.01

12.50

12.80

12.47

12.63

12.56

Wisconsin

11.51

11.94

12.65

13.02

13.19

13.55

13.67

14.11

14.07

14.35

14.02

Midwest

9.94

10.44

10.95

11.34

11.67

11.90

12.23

12.55

12.74

13.08

12.97

U.S. Average

11.26

11.51

11.54

11.72

11.88

12.13

12.52

12.65

12.55

12.89

12.87

2016

2017

2018

Appendix Table C-2

Commercial Average Rates in the Midwest and U.S. (cents/kWh)

State

2008

2009

2010

2011

2012

2013

2014

2015

Illinois

9.25

9.04

8.88

8.64

7.99

8.14

9.26

9.02

9.02

9.09

9.12

Indiana

7.82

8.32

8.38

8.77

9.14

9.60

9.96

9.78

10.01

10.54

10.60

Iowa

7.18

7.55

7.91

7.85

8.01

8.44

8.67

8.92

9.17

9.46

9.68

Michigan

9.17

9.24

9.81

10.33

10.93

11.06

10.87

10.55

10.64

11.00

11.15

Minnesota

7.88

7.92

8.38

8.63

8.84

9.42

9.85

9.44

9.86

10.48

10.38

Missouri

6.61

6.96

7.50

8.04

8.20

8.80

8.90

9.16

9.26

9.47

9.40

Ohio

9.23

9.65

9.73

9.63

9.47

9.35

9.83

10.07

9.97

10.05

10.11

Wisconsin

9.28

9.57

9.98

10.42

10.51

10.74

10.77

10.89

10.77

10.87

10.67

Midwest

8.30

8.53

8.82

9.04

9.14

9.44

9.76

9.73

9.84

10.12

10.14

U.S. Average

10.26

10.16

10.19

10.24

10.09

10.26

10.74

10.64

10.43

10.66

10.67

Appendix Table C-3

Industrial Average Rates in the Midwest and U.S. (cents/kWh)

State

2008

2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

Illinois

7.34

7.01

6.82

6.42

5.80

5.94

6.85

6.67

6.51

6.47

6.80

Indiana

5.46

5.81

5.87

6.17

6.34

6.70

6.97

6.86

6.97

7.54

7.38

Iowa

4.81

5.27

5.36

5.21

5.30

5.62

5.71

5.90

6.05

6.21

6.45

Michigan

6.73

6.98

7.08

7.32

7.62

7.72

7.68

7.02

6.91

7.19

7.10

Minnesota

5.87

6.26

6.29

6.47

6.54

6.98

6.72

7.02

7.37

7.37

7.53

Missouri

4.92

5.42

5.50

5.85

5.89

6.29

6.36

6.44

7.12

7.33

7.22

Ohio

6.20

6.72

6.40

6.12

6.24

6.22

6.77

7.02

6.98

6.92

7.01

Wisconsin

6.51

6.73

6.85

7.33

7.34

7.40

7.52

7.58

7.49

7.49

7.33

Midwest

5.98

6.28

6.27

6.36

6.38

6.61

6.82

6.81

6.93

7.07

7.10

U.S. Average

6.96

6.83

6.77

6.82

6.67

6.89

7.10

6.91

6.76

6.88

6.92

-6-

 DRAFT ‒ Strategic Energy Assessment 2026
Figure C-3

Average Monthly Residential Bills by Census Division (2018 EIA Data) 82

Figure C-4

Monthly Residential Electricity Bills for Wisconsin’s Largest IOUs 83

U.S. Energy Information Administration. 2018 Average Monthly Bill – Residential.
https://www.eia.gov/electricity/sales_revenue_price/pdf/table5_a.pdf. Accessed 2 January 2020.
83 Source: Major utility tariffs filed with the Commission, http://apps.psc.wi.gov/vs2010/tariffs/default.aspx
82

-7-

 DRAFT ‒ Strategic Energy Assessment 2026
Figure C-5

Distribution of Monthly Residential Electricity Bills for Municipal Utilities 84

Figure C-6

Distribution of Commercial (CP-1) Costs in cents/kWh for Municipal Utilities 85

84
85

Source: Major utility tariffs filed with the Commission, http://apps.psc.wi.gov/vs2010/tariffs/default.aspx
Source: Major utility tariffs filed with the Commission, http://apps.psc.wi.gov/vs2010/tariffs/default.aspx

-8-

 DRAFT ‒ Strategic Energy Assessment 2026
Figure C-7

Distribution of Monthly Commercial (CP-1) Bills for Municipal Utilities 86

The monthly costs summarized in Figure C-6 and Figure C-7 are based on the following
assumptions for commercial customers billed under the CP-1 tariff schedule:
•
•
•
•

Monthly consumption of 50,000 kWh or 600,000 kWh/year (this represents an average load
factor of 68.5 percent based on a peak load of 100 kW)
Peak/Off-Peak split of 60 percent (peak) and 40 percent (off-peak)
Monthly peak demand of 100 kW (typically CP-1 range is 50-200 kW)
Municipal utilities with a CP-1 classification threshold below 50 kW are not included in the
distribution plot shown in Figure C-7 (only one utility has a threshold below 100 kW and
two others do not have a CP-1 schedule in their effective tariff).

Table C-4

Estimated Monthly Bill Data for Municipal Utility Cp-1 Customers
Summary
Minimum
25th Percentile
Median
Average
75th Percentile
Maximum

Total Cost (cents/kWh)*
4.19
7.75
8.89
8.74
9.69
11.38

Estimated Bill ($/month)*
$2,095
$3,873
$4,443
$4,437
$4,847
$5,690

* Note: The Total Cost (cents/kWh) is the sum of all bill components (monthly fixed charge, energy charge, distribution demand, and billable
demand) divided by monthly energy use.

86

Source: Major utility tariffs filed with the Commission, http://apps.psc.wi.gov/vs2010/tariffs/default.aspx

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 DRAFT ‒ Strategic Energy Assessment 2026

APPENDIX D – SUPPORTING DATA, CLEAN ENERGY PROGRAMS
AND POLICIES

Total Installations

Figure D-1
7,500
7,000
6,500
6,000
5,500
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
-

Number of Renewable DERs Installed by Capacity

2008

2009

≤20 kW

Number of Installations

Figure D-2
6,500
6,000
5,500
5,000
4,500
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
-

2010

2011

>20-200 kW

2012

2013

>200-1,000 kW

2014

2015

2016

>1,000-15,000 kW

2017

2018

2019

>15,000 kW

Number of Renewable DERs Installed by Customer Type 87

2008

2009

2010

2011

2012

Residential

2013
Commercial

2014

2015

2016

2017

2018

2019

Industrial

Some providers did not report DER installations by customer type. As a result, the number of total DER installations
by customer type is presented with lower values than those provided for other DER data.

87

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 DRAFT ‒ Strategic Energy Assessment 2026

Installed Capacity (kW)

Figure D-3

Installed Capacity of Renewable DERs by Capacity Range

450,000
400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
-

2008

2009

≤20 kW

Figure D-4

2010

2011

>20-200 kW

2012

2013

>200-1,000 kW

2014

2015

2016

>1,000-15,000 kW

2017

2018

2019

2018

2019

>15,000 kW

Installed Capacity of Renewable DERs by Customer Type 88

450,000
Installed Capacity (kW)

400,000
350,000
300,000
250,000
200,000
150,000
100,000
50,000
-

2008

2009

2010

2011
Residential

2012

2013

Commercial

2014

2015

2016

2017

Industrial

Some providers did not report DER installations by customer type. As a result, total DER capacity by customer type
is presented with lower values than those provided for other DER data.

88

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 DRAFT ‒ Strategic Energy Assessment 2026

APPENDIX E – ACRONYMS
§
AMI
AMR
APTIM
ATC
BRP
CAA
CAIAI
Cadmus
CB&I
CC&B
ch.
CIS
CME
Commission
CO 2
CSAPR
DER
DNR
DPC
EDR
EIA
ELG
EPA
FERC
FGD
Focus
fps
GIP
GW
ICAP
ICE
IEEE
IGCC
IMM
IOU
IPL
ITC
JOA
kV
kW
kWh
LMP
LMR

Section
Advanced metering infrastructure
Automated meter reading
formerly Chicago Bridge and Iron
American Transmission Company LLC
Baseline Reliability Project
Clean Air Act
Customer Average Interruption Duration Index
Cadmus Group
Chicago Bridge and Iron
Customer Care and Billing System
Chapter
Customer information systems
Centuria Municipal Electric Utility
Public Service Commission of Wisconsin
Carbon Dioxide
Cross State Air Pollution Rule
Distributed Energy Resources
Department of Natural Resources
Dairyland Power Cooperative
Economic Development Rate
U.S. Energy Information Administration
Effluent Limitations Guideline
U.S. Environmental Protection Agency
Federal Energy Regulatory Commission
Flue gas desulfurization
Focus on Energy
Feet per second
Generator Interconnection Project
Gigawatt
Installed Capacity
Improved Customer Experience
Institute of Electric and Electronic Engineers
Integrated Gasification Combined-Cycle
Independent market monitor
Investor-owned utility
Interstate Power and Light Company
Investment Tax Credit
Joint Operating Agreement
kilovolt
Kilowatt
Kilowatt hour
Locational Marginal Pricing
Load Modifying Resources
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 DRAFT ‒ Strategic Energy Assessment 2026

LOLE
LRZ
LSE
LTRA
MATS
MEP
MGE
MISO
MTEP
MVP
MW
MWh
NAAQS
NERC
NEV
NO X
NRC
NSPM
NSPW
NWE
OMS
PCAC
PPA
PRB
PRM
PRMR
PTC
PY
RER
RIIA
ROW
RPS
RTO
SAIDI
SAIFI
SCPC
SCR
SEA
SNCR
SO 2
SPP
SWL&P
TMEP
TOU
TRC
TRM

Loss of load expectations
Local Resource Zone
Load Serving Entity
Long-Term Resource Assessment
Mercury and Air Toxics Standard
Market Efficiency Project
Madison Gas and Electric Company
Midcontinent Independent System Operator, Inc.
MISO Transmission Expansion Plan
Multi Value Project
Megawatt
Megawatt hour
National Ambient Air Quality Standards
North American Electric Reliability Corporation
Neutral-to-earth voltage
Nitrogen oxides
Nuclear Regulatory Commission
Northern States Power Company-Minnesota
Northern States Power Company-Wisconsin
Northwestern Wisconsin Electric Company
Organization of MISO States
Power cost adjustment clause
Purchased power agreements
Power River Basin
Planning Reserve Margin
Planning Reserve Margin Requirement
Production Tax Credit
Planning Year
Renewable Energy Rider
Renewable Integration Impact Assessment
Right-of-way
Renewable Portfolio Standard
Regional Transmission Organization
System Average Interruption Duration Index
System Average Interruption Frequency Index
Supercritical pulverized coal
Selective catalytic reduction
Strategic Energy Assessment
Selective non-catalytic reduction
Sulfur dioxide
Southwest Power Pool
Superior Water, Light and Power Company
Targeted Market Efficiency Projects
Time-of-Use
Total Resource Cost
Technical Reference Manual
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 DRAFT ‒ Strategic Energy Assessment 2026

UCAP
VOC
WEC
WEM
WEPCO
WG
Wis. Admin. Code
Wis. Stat.
WP&L
WPPI
WPSC
Xcel

Unforced Capacity
Volatile organic compounds
Wisconsin Energy Corporation
Wisconsin Emergency Management
Wisconsin Electric Power Company
Wisconsin Gas LLC
Wisconsin Administrative Code
Wisconsin Statutes
Wisconsin Power and Light Company
WPPI Energy
Wisconsin Public Service Corporation
Xcel Energy, Inc.

DL: 01744729

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