PSC REF#:441648
Public Service Commission of Wisconsin
RECEIVED: 06/29/2022 5:15:00 PM

WISCONSIN OFFICE OF
ENERGY INNOVATIONSAUK PRAIRIE EMERGENCYOPERATIONS CENTER
MICROGRID FEASIBILITY
STUDY

Prepared for the Wisconsin Office of Energy Innovation (WI OEI)
June 2022

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Contents
List of Figures
List of Tables
Authors
About SEPA
Acknowledgements

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0.0 Executive Summary

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1.0 Introduction
1.1 Project Overview
Site and Customer Background
Existing Infrastructure
Rationale for Microgrid
Identification of Critical Infrastructure
Key Partners and Stakeholders
Financial and Environmental Impact Analysis
1.2 Feasibility Study Methodology and Assumptions
Stakeholder Engagement
Data Collection
System Sizing and Analysis
Financial and Environmental Impact Analysis

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2.0 Site Assessment
2.1 Site Overview
Detail infrastructure
Community vulnerability indicators
Site application and functionality
Critical services
Customer information and historical outage information
Rate schedule
2.2 Initial Load and Solar Analysis
Load Analysis
EV Charging Analysis
Solar Analysis
2.3 Site Availability
Site Assessment for Solar PV
Site Assessment for Microgrid Assets
Existing Electric Feeders

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3.0 Microgrid Scenarios Development
3.1 Stakeholder Process and Findings
Process

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Findings
3.2 Microgrid Scenarios
Overview
Preliminary Economic Analysis
Scenario Pros and Cons

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4.0 Microgrid Feasibility
4.1 Preliminary Engineering Considerations
Site Layout
Scenario A
Scenarios B and C
Scenario D
EV Scenario
Microgrid Operations
Operating Mode 1: Normal Operation/Blue Sky
Operating Mode 2: Microgrid Operation - Disconnecting from the Grid
Operating Mode 3: Microgrid Operation – Resuming Normal Operation
Interconnection
Microgrid
Solar, Diesel, and Battery Storage
4.2 Financial and Environmental Impact
Inventory of Benefits and Costs
Overview of Costs
Overview of Benefits
Summary of Results
Summary of Cost Results
Interpretation

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5.0 Conclusion

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6.0 Appendices
Appendix 1: Project Team Check-In Summaries
January 2022
February 2022
March 2022
April 2022
Appendix 2: Detailed Benefits
Value of Solar Generation
Value of Emissions Reduction
Value of Battery Savings
Implied Value of Resilience

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List of Figures
Figure 0.1 – Planned Sauk Prairie Police Station Site Plan
Figure 0.2 – Overview of Proposed Microgrid Scenarios
Figure 2.1.1 - Site Boundaries and Aerial Imagery
Figure 2.1.2 - Site Infrastructure
Figure 2.1.3 - State View: Area Deprivation Index Legend
Figure 2.1.4 - State View: Area Deprivation Index
Figure 2.1.5 - Local View: Area Deprivation Index
Figure 2.1.6 - Percentile of Population over 64
Figure 2.1.7 - Level of Community Resilience
Figure 2.1.8 - Flood Hazards Near Proposed Site
Figure 2.1.9 - Average Energy Burden Near Proposed Site
Figure 2.1.10 - Small Power TOD Service
Figure 2.2.1 - Sauk Prairie EOC Load by Month
Figure 2.2.2 - Estimated Daily EV Fleet Charging
Figure 2.2.3 - Sauk Prairie EOC and EV Fleet Charging Load
Figure 2.2.4 - Proposed Solar Generation and Energy Consumption
Figure 2.3.1 - Sauk Prairie Police Station Site Map
Figure 3.1 - Current Microgrid Installations by Technology
Figure 3.1.1 - Key Microgrid Scenario Development Questions
Figure 3.2.1 - Scenario Asset, Load Coverage, Outage Capability, etc.
Figure 4.2.1 - Overview of Benefits and Costs
Figure 4.2.2 - Summary of Benefits and Costs

List of Tables
Table 0.1 - Microgrid Scenario Summary
Table 0.2 - Summary of Costs and Benefits
Table 1.1 - Core Project Team and Responsibilities
Table 2.2.1 - Sauk Prairie EOC PEV and Charging Station Assumptions
Table 2.3.1 - Sauk Prairie Emergency Operations Center Site Map Key
Table 3.2.1 - Microgrid Scenario Components
Table 4.2.1 - Summary of Costs
Table 4.2.2 - Summary of Benefits
Table 4.2.3 - Summary of Benefits and Costs

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Authors
Jared Leader, Director, Resilience, Smart Electric Power Alliance
Mac Keller, Senior Analyst, Research, Smart Electric Power Alliance
Carolyn Dougherty, Analyst, Industry Strategy, Smart Electric Power Alliance
Weston Dengler, Analyst, Industry Strategy, Smart Electric Power Alliance
Alan Wildman, Village Administrator/Zoning Administrator, Village of Prairie Du Sac
Anna Stieve, Senior Energy Services Manager, WPPI Energy
Josh Sherman, Police Sergeant, Sauk Prairie Police Department
Troy Murphy, Director of Public Works/Utilities, Village of Prairie Du Sac
Chris Chartier, Director of Distribution Services, WPPI Energy

About SEPAThe Smart Electric Power Alliance (SEPA) is dedicated to helping electric power stakeholders
address the most pressing issues they encounter as they pursue the transformation to acarbon-free energy system. We are a trusted partner providing education, research, standards,
and collaboration to help utilities, electric customers, and other industry players across threepathways: Regulatory and Business Innovation, Grid Integration, Electrification. Througheducational activities, working groups, peer-to-peer engagements and custom projects, SEPA
convenes interested parties to facilitate information exchange and knowledge transfer to offer
the highest value for our members and partner organizations. For more information, visit
www.sepapower.org.

Acknowledgements
SEPA would like to thank the Wisconsin Office of Energy Innovation (WI OEI) for the opportunity
to conduct this study. The study was made possible by WI OEI’s Critical Infrastructure Microgrid
and Community Resilience Centers Pilot Grant Program (CIMCRC), which focuses oninnovative pre-disaster mitigation through critical infrastructure microgrids and other resilient
building strategies by studying the feasibility of the deployment of distributed energy resources(DERs) and appropriately sized storage, along with a grid-interactive controls schema. This
feasibility study was one of sixteen (16) grants awarded across the state.
SEPA would also like to thank its project partners at Sauk Prairie Police Commission, WPPIEnergy, and the Village of Prairie Du Sac.

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0.0 Executive Summary
Extreme weather events threaten damage to the electrical system and disruption to power
supply. These weather events in Wisconsin are increasing in both frequency and economic
impact, causing prolonged outages, and disproportionately affecting underserved communities.
This project presents an opportunity to collaborate with a Wisconsin police station which willhouse an emergency operations center (EOC) to assess the feasibility of deploying a microgrid
as a pre-disaster mitigation technique. An appropriately sized microgrid could insulate thefacility from the impacts of prolonged outages and build resilience for the community. This study
identifies a microgrid as a resilience solution, develops microgrid designs that incorporate
varying power supply technologies, and utilizes stakeholder input to evaluate the feasibility ofeach microgrid design. This feasibility study was funded by a grant from WI OEI and donatedfunds and working time from SEPA, Sauk Prairie Police Commission, WPPI Energy, and theVillage of Prairie Du Sac.
The feasibility study methodology included the following primary tasks:
1. Stakeholder Engagement - SEPA convened a core project team of key stakeholders to
discuss the feasibility of a microgrid project at Sauk Prairie Emergency Operations
Center.
2. Data Collection - SEPA collected community, utility, and energy consumption data
relevant to the system sizing and financial and environmental impact analysis of apotential microgrid at the emergency shelter.
3. System Sizing and Analysis - SEPA evaluated five (5) preliminary microgrid scenarios.
Based on stakeholder feedback, the project team conducted a detailed system design of
one of the modeled scenarios. The sizing and analysis considered community function
as the primary resilience objective and metric.
4. Financial and Environmental Impact Analysis - SEPA conducted a benefit-cost
analysis of the modeled scenarios to determine economic feasibility.
The project team designed the microgrid scenarios for Sauk Prairie Police Commission’s newpolice station in Prairie du Sac, WI, as seen in Figure 0.1. During emergencies, the police
station would be used by the Sauk Prairie Police Department, Prairie du Sac Fire Department,
Sauk City Fire Department, Sauk Prairie EMS, the Village of Prairie Du Sac, and the Village ofSauk City. The EOC may also be used by other area emergency government or law
enforcement agencies as needed, including Sauk County Sheriff’s Department, Sauk County
Emergency Government, and Sauk County Public Health Department. The police station wasunder construction during the time of the study.
This report provides several scenarios for the additional development and seamless integrationof a microgrid. The feasibility study partners analyzed the load profiles of a nearby fire stationand consumption/load estimates from the site plan as a proxy load profile and developed fivepotential microgrid designs, as seen in Table 0.1 and Figure 0.2, to serve the load of the police
1station, while utilizing solar photovoltaic, battery storage, diesel generator, and electric vehicle(EV) charging technologies.
Figure 0.1 – Planned Sauk Prairie Police Station Site Plan

Source: Sauk Prairie Police Station, 2022

To ensure the microgrid designs would serve the needs of the police station and community, thecore project team consisted of key project stakeholders. Each month, project team members
provided information about the purpose of the microgrid, project updates and findings, and heldan open dialogue for members to provide feedback. Project team members were given theopportunity to ask questions and ultimately chose five possible microgrid design scenarios thatthey determined would best suit the site and community.
The microgrid components in this study include:
●
●
●
●
●
●
●

Load: Sauk Prairie Police Station (+Proposed EV Fleet)
Ground-Mounted Solar PV
Battery Energy Storage System (BESS)
Diesel Generation
Microgrid Controller
Level 2 Dual Charging Stations
Distribution System

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Table 0.1 - Microgrid Scenario Summary
Scenario

Load

ScenarioA

PoliceStationScenario
B

PoliceStationScenario
C

PoliceStationScenarioD

PoliceStationEV
Scenario

PoliceStation +EV Fleet

Solar

Ground-Mounted
Solar Only

Rooftop +Ground-Mounted
Solar

Solar
kW-DC1

Battery
kW-DC

DieselkW-DC2

94.5

360

154

94.5

150

154

94.5

150

154

192

3,200

154

192

75

154

Source: SEPA, 2022

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2

Only solar PV in addition to the 94.5 kWdc of planned solar PV is included in the BCA.
The planned diesel generation is not included in the BCA.

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Figure 0.2 – Overview of Proposed Microgrid Scenarios

Source: SEPA, 2022

The benefit-cost analysis (BCA) quantifies the net present value (NPV) of the benefits and costs
associated with each proposed microgrid scenario as summarized in Table 0.2 below. The
BCAs highlighted below assume a mid-range estimate for component costs and O&M. The
benefits exceed costs over the project lifecycle if the benefit-cost ratio (BCR) is greater than 1.0.
The analysis found that the BCR of each scenario was between 0.01 and 0.74, indicating that
the NPV of costs outweigh the benefits in all scenarios. It is important to note that the value of4

resilience was implied from the BCA but was not included in the BCA itself, so BCR values
presented in this report are likely to underestimate the actual BCR in each scenario. Also notethat while the team found the costs to slightly outweigh the benefits in the five scenarios, thebenefits of solar generation and BESS operation could change depending on future analysis
around the business model and ownership structures of a microgrid project. Conversely, notethat some of the emissions reduction benefits included in the BCA may not be directly realized
by the Sauk Prairie Police Department, effectively reducing the BCR.
Table 0.2 - Summary of Costs and Benefits
Costs
●
●
●
●
●

Benefits*

Generation (Solar Photovoltaic (PV) +Diesel Generator)
Battery Energy Storage System (BESS)
Controller and Communications
Distribution Upgrades
Operations & Maintenance●●●

Solar Generation (Demand savings,
energy rate savings, and excess
generation credits)
BESS Economic Benefits (Energy
arbitrage, demand savings)
Emissions Reductions

Scenario A: BCR = 0.01
Total NPV of Costs: $829,550

Total NPV of Benefits: $4,951
Scenario B: BCR = 0.01

Total NPV of Costs: $345,646

Total NPV of Benefits: $4,973
Scenario C: BCR = 0.08

Total NPV of Costs: $345,646

Total NPV of Benefits: $26,440
Scenario D: BCR = 0.03

Total NPV of Costs: $7,570,119

Total NPV of Benefits: $214,642
EV Scenario: BCR = 0.66

Total NPV of Costs: $369,198

Total NPV of Benefits: $242,093*Note that an estimate of the value of resilience is implied from this BCA and noted in section 4 below, but it is notincluded in the BCA and is not reflected in the BCR.
Source: SEPA, 2022.

This study develops the groundwork for the Sauk Prairie Police Commission, WPPI Energy, theVillage of Prairie Du Sac, and other local stakeholders to move to a more detailed benefit-cost
analysis and ultimately to the implementation phase of microgrid development. The potential
next steps include a determination of ownership and operation structures, further construction
coordination, identification of financing and funding, and the development of a full engineering
design and construction study. The continuation of strong engagement with community
stakeholders through the implementation of the microgrid will facilitate the success of the
project.
51.0 Introduction
A resilient energy system can absorb and recover in a timely manner from unavoidable external
events, such as natural disasters. In recent years, the frequency and intensity of naturally
occurring threats has substantially increased. Wisconsin suffered 32 billion-dollar disasterevents costing over $166 billion in damages in the last 20 years. This is more than a 50%
increase from eight such events costing $104 billion from 1980 to 2000.3 Extreme weather
events threaten the stability of the grid and cause power outages with attendant economic
losses. In fact, national power outage data suggests a 67% increase in outages fromweather-related events since 2000.4
A grid without resilience measures in place may suffer prolonged outages, which may rendercritical services inaccessible, such as communications, public safety, water treatment,
healthcare, and emergency shelters. This microgrid project in Prairie Du Sac, Wisconsin would
bolster resilience for the emergency operation center’s critical functions during emergency
events, utilize renewable power sources, and provide energy savings and increase affordability
for the facility.

1.1 Project Overview
Site and Customer Background
This report assesses the feasibility of utilizing a microgrid in building resilience for the Sauk
Prairie Police Station, an EOC in Prairie du Sauk, Wisconsin.

Existing Infrastructure
The site consists of a 3.6 acre parcel containing a planned 22,000 square foot police station,parking lot, and a road that connects to the police station. Once construction is complete, thepolice station will host a 94.5 kWdc solar array, a 154kW diesel generator, and a 595 gallon fueltank. The site will host an interconnection point to the Village of Prairie Du Sac‘s electric
distribution grid system.

Rationale for MicrogridThis report was commissioned by WI OEI through the CIMCRC to study the feasibility ofincluding a critical infrastructure microgrid for the site as a means for innovative pre-disastermitigation given its shelter designation and documented failure of existing backup generation.
Such a microgrid might incorporate DERs, appropriately sized energy storage, and agrid-interactive controls schema which would allow the introduction of locally generated solar
energy and increased resilience (i.e., the ability to operate independently even when the public
3

NOAA National Centers for Environmental Information (NCEI) U.S. Billion-Dollar Weather and Climate
Disasters (2022).
4
SEPA, Commonwealth of Kentucky Regional Microgrids for Resilience Study, p. 7 (2021).

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grid is temporarily inoperable). This feasibility study included engagement with key
stakeholders, energy, disaster, and site-specific data collection, preliminary microgrid systemsizing and analysis, and financial and environmental impact analysis.
WI OEI defines a microgrid as “a group of interconnected loads and distributed energy
resources within clearly defined electrical boundaries that acts as a single controllable entitywith respect to the grid. A microgrid can connect and disconnect from the grid to enable it tooperate in both grid-connected or island-mode.”5

Identification of Critical InfrastructureThis project was proposed for Sauk Prairie Police Commission’s new police station, which willhouse an EOC and serve Sauk Prairie Police Department, Prairie du Sac Fire Department,
Sauk City Fire Department, Sauk Prairie EMS, Village of Prairie Du Sac, and Village of Sauk
City during any major events. The EOC may also be used by other area emergency
government or law enforcement agencies as needed, including Sauk County Sheriff’s
Department, Sauk County Emergency Government, and Sauk County Public Health
Department.

Key Partners and Stakeholders
Within this report, the core project team comprises stakeholders who supported the evaluationof preliminary microgrid scenarios to best support the Sauk Prairie Police Station and analyze
the financial, societal, and environmental benefits of the microgrid. The findings of this report
may support future endeavors by the WI OEI to build energy resilience at sites similar to the
Sauk Prairie Police Station.
SEPA, Sauk Prairie Police Commission, WPPI Energy, and Village of Prairie Du Sac are theprimary partners leading the project. Table 1.1 summarizes the role of each organization incarrying out the project.

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https://apps.psc.wi.gov/ERF/ERFview/viewdoc.aspx?docid=420888

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Table 1.1 - Core Project Team and Responsibilities
Project Partners

Responsibility

Sauk Prairie Police
Commission

Technical and strategic
support

Applicant and microgrid
customer

Village of Prairie Du Sac

Technical and strategic
supportLocal electricity distribution
utility

Stakeholder engagement andtechnical assistanceMicrogrid feasibility study
leadTechnical and strategic
supportElectric wholesale supplier

Smart Electric Power Alliance(SEPA)WPPI Energy

Role

Source: Smart Electric Power Alliance, 2022

Financial and Environmental Impact Analysis
This study includes a financial and environmental impact analysis of five proposed microgrid
scenarios that serve the police station through different asset mixes including solar PV, battery
storage, diesel generation, and EV charging stations. The scenarios represent a range of
renewable resource intensities, islanding capabilities, and related costs and benefit
propositions. The analysis aims to quantify the net present value costs and benefits associatedwith each scenario to determine a BCR for each. The specific costs and benefits of the analysis
are detailed fully in 4.2 Financial and Environmental Impact, including costs associated with thedevelopment, design, components, and operation of the microgrids, and benefits associatedwith emissions reductions, demand and energy rate benefits, and solar generation credits.

1.2 Feasibility Study Methodology and Assumptions
Stakeholder Engagement
The core project team, composed of SEPA, Sauk Prairie Police Commission, WPPI Energy, andthe Village of Prairie Du Sac discussed the resilience needs of the new Sauk Prairie Police
Station site, and assessed feasibility in the development of a microgrid project. Each month,
beginning in January of 2022, SEPA hosted virtual check-in meetings to build connections withthe entire team, foster a collaborative project environment, and maximize engagement
throughout the project. For summaries of each monthly check-in discussion, see Appendix 1:
Project Team Check-In Summaries.
Fostering a collaborative relationship between project team members encouraged productive
conversations and provided SEPA with key input regarding the study, microgrid site, and themicrogrid design that would best serve the site’s needs. Furthermore, the project teamengagement provided members with the information they needed to engage in meaningfulconversation, and communicate, via feedback, their input on project design.
8Data Collection
The team collected data from a variety of sources to model preliminary microgrid scenarios.
While the team was unable to gather detailed load profile data from the site, SEPA estimatedSauk Prairie Police Department’s hourly load profile based on a historical hourly kW load profile
from a nearby fire station that WPPI Energy provided. SEPA assumed that Sauk Prairie Police
Station would have a similar load shape and adjusted the proxy load profile to match theestimated peak facility load (kW) and annual consumption (kWh) of the planned Sauk Prairie
Police Station, as provided by WPPI Energy. The estimated load data helped to quantify a load
duration curve, which determines how much designed load the microgrid scenarios should
serve.
To plan where to construct the microgrid at the police station, Sauk Prairie Police Commission
provided a site map and additional information regarding land availability for storage systems
and solar PV. WPPI provided maps of existing electric distribution infrastructure. Multiple
contributors supported the data collection effort, which was valuable in developing model
assumptions and designing the microgrid scenarios.

System Sizing and Analysis
SEPA considered site area limitations identified in the site map provided by Sauk Prairie Police
Commission, preferences vocalized by project team members, and internal expertise to informthe fuel source mix for each scenario. SEPA ensured that the scenarios reflected a range ofoptions with respect to renewable assets, islanding capabilities, and project costs that adhered
to site area limitations.
To determine solar PV site constraints, SEPA referenced a 2013 NREL study on land-use
requirements for solar power plants which estimated the direct area capacity-weighted averageland use of solar PV at 5.5 acres/MWac for a fixed-axis system. This value and the landavailable from the site assessment determined the maximum buildable solar capacity (kWac) on
the site. To estimate the maximum buildable DC solar capacity, SEPA multiplied the maximum
AC solar capacity by the conservative DC-to-AC ratio of 1.3 that was used in the study, insteadof the ~1.18 value that was used in the NREL study.6 As a result, estimates for maximum DC
solar capacity might be slightly high, though this estimate would potentially only impact scenario
D and the Renewable + EV Fleet scenario, which propose an additional 97.5 kWDC ofground-mounted Solar PV–well below the calculated limit noted in Table 2.3.1.7

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The NREL study used a weighted-average PV derate factor of 0.85 that was calculated by dividing the
AC reported capacity by the DC reported capacity for each project that was included in the study. Thisvalue implies a DC-to-AC ratio of 1 / (0.085) = 1.176.
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Using a DC-to-AC ratio of 1.176 instead of 1.3 would reduce the maximum DC solar capacity at Sauk
Prairie Police Station from 130 kWdc to 118 kW DC. This situation would not require a reduction of thesolar capacity in Scenario D and the Renewable + Fleet scenario. It is also likely that the site would havean AC-to-DC ratio closer to the 1.176 implied by the NREL study, and Sauk Prairie Police Department
would be able to achieve a greater amount of generation than modeled in the scenario.

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To a lesser extent, SEPA also considered land availability to site a BESS noting that the footprintof each is fairly insignificant compared to the requirements for solar PV. For a BESS, SEPA
used reference data from a publicly available SCE battery storage project which assumed afootprint of ~0.2 sq ft/kWh.8

Financial and Environmental Impact Analysis
SEPA carried out a financial and environmental impact analysis for each of the five scenariosthat compared the net present values of project costs and benefits, including emissions
reduction benefits, over a presumed 20-year lifespan. This report shares the net present valuesof costs and benefits associated with each of the six scenarios and includes low-, medium-, andhigh- cost estimates for each scenario to compare to actual component costs in further analysis.
This report also shares the BCR values related to each scenario and cost estimate to
demonstrate whether each scenario would be cost-effective given the estimated costs andbenefits over the life of the microgrid.
Costs in the financial impact analysis include component costs, microgrid design andconstruction costs, and long-term operating and maintenance costs for solar and BESS.
Economic and environmental impact benefits included demand reduction, energy rate savings,
and excess generation credits from solar and BESS, as well as emissions reduction benefits
from solar. SEPA’s processes for estimating specific microgrid costs and benefits for thefinancial and environmental impact analysis can be found in 4.2 Financial and Environmental
Impact and Appendix 2: Detailed Benefits.

2.0 Site Assessment
2.1 Site Overview
Sauk Prairie Police Commission’s new police station is located on a 3.6 acre lot. Solar will be
installed on the police station, which is 22,000 square feet. For two of our scenarios, solar will
also be deployed on the surrounding property, which is 24,101 square feet. The site parcel
outline is shown in an aerial image below.

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https://insideevs.com/news/323829/sce-unveils-americas-largest-battery-energy-storage-site/

10Figure 2.1.1 - Site Boundaries and Aerial Imagery

Source: Statewide Parcel Map Initiative, V7 Statewide Parcel Data (2021) and GeoData@Wisconsin, WROC
Aerial Mosaic (WTM) Prairie du Sac, WI 2020 (2020)

Available areas of the property are being considered for solar PV, battery energy storage, diesel
back-up generation, and EV charging stations along with a microgrid controller functionality toallow for sustained islanding capabilities during a grid outage.

Detail infrastructure
The new Sauk Prairie police station was completed in 2022 with a 94.5 kW dc rooftop solar PV
array. The solar PV will yield energy cost savings at the facility, and it will be paired with a 154
kW diesel generator to provide energy resiliency.
The planned generator, transformer, utility primary conductors, telephone and cable lines, andexterior lighting conduit are displayed on the map below.

11Figure 2.1.2 - Site Infrastructure

Source: SEPA, 2022

Community vulnerability indicators
Figure 2.1.4 and 2.1.5 below show census block groups in Wisconsin categorized by their Area
Deprivation Index score. The yellow marker on the map indicates the location of the site. The
legend in Figure 2.1.3 can be used to read the following maps. The EOC site is located in a lessdisadvantaged block group.

Figure 2.1.3 - State View: Area Deprivation Index Legend

Source: University of Wisconsin-Madison, Neighborhood Atlas Map (2021)

12Figure 2.1.4 - State View: Area Deprivation Index by Census Block Group

Source: University of Wisconsin-Madison, Neighborhood Atlas Map (2021)

Figure 2.1.5 - Local View: Area Deprivation Index by Census Block Group

Source: University of Wisconsin-Madison, Neighborhood Atlas Map (2021)

The EPA’s Environmental Justice Screening and Mapping tool, highlighted in Figure 2.1.6 below,
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shows that the EOC site is located in an area where the percent of the population that is over
the age of 64 is in the 70-100th percentile of the state, making it a strong candidate for equitable
resilience benefits.

Figure 2.1.6 - Percentile of Population over 64 by Census Block

Source: Environmental Protection Agency, EJSCREEN (2020)

Flood hazards
Figures 2.1.7 and 2.1.8 indicate the EOC site is located near a floodway and areas with 1%
Annual Chance Flood Hazard and 0.2% Annual Chance Flood Hazard. The FEMA National
Flood Hazard map also indicates where existing energy infrastructure is in relation to the EOC
site. The site is surrounded by areas of high and medium flood hazard. A microgrid in thislocation may be ideal to support emergency services when critical infrastructure is inundated.

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Figure 2.1.7 - Level of Community Resilience by County

Source: FEMA, The National Risk Index (2021)

Figure 2.1.8 - Flood Hazards Near Proposed Site

Source: GeoData@Wisconsin, The National Risk Index (2018)15

Below, Figure 2.1.9 indicates that the EOC is located in an area where the energy burden islower (3%). The red outline on Figure 2.1.9 delineates indigenous land, which is not locatednear the emergency operations center.
The prevalence of vulnerable populations, such as elderly communities, indigenous tribes, andlow-moderate income customers, make SPPD all the more important to have resilient power.
Therefore, a microgrid solution could benefit the community tremendously by providing
uninterrupted power during grid power outages.

Figure 2.1.9 - Average Energy Burden Near Proposed Site

Source: Department of Energy, Low-Income Energy Affordability Data (LEAD) Tool (2021)

Site application and functionality
Sauk Prairie Police Commission is interested in improving resilience for the EOC for the Sauk
Prairie police station. The Prairie du Sac Fire Department covers 2 square miles serving a
population of 4,193. The Sauk Prairie EMS covers 196 square miles serving a base populationof 14,983. Additionally, Sauk City Area Fire District covers 175 square miles serving a base
population of 10,000. Based on the number of customers that the EOC can serve, the inclusionof redundant power capabilities is critical in serving communities particularly during an outage.

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Critical services
The EOC will be utilized by Sauk Prairie County and the Village of Prairie Du Sac during grid
outages and other events. Examples of critical services to be provided by the EOC are as
follows:● Emergency call response and dispatch● Radio communication from EOC to officers and emergency responders● Television monitoring● GPS mapping capabilities● Facility lighting, heating and HVAC equipment● Security cameras● Freezers and refrigerators in the evidence room
The station will have a diesel generator available as backup during power outages, but thissystem is not as environmentally friendly as the solar option.

Customer information and historical outage information
Neither Prairie Du Sac Municipal Electric and Water nor WPPI energy indicated that any
significant outages have impacted the circuit to which the police station will be connected,
though this may not fully reflect the possibility of future outages. Solar PV and a diesel
generator are already planned to avoid short- and medium- term outage impacts at the newpolice station and EOC. Due to its designation as an EOC for emergency services in Prairie Du
Sac, it is imperative that the facility is able to operate during outage events.
Prior to December 2020, Prairie du Sac and Sauk City were served by the American
Transmission Company (ATC) via a radial line. ATC identified an opportunity to increase
reliability and flexibility to these customers. As a result, substation upgrades and an additional
69 kV radial line were put into service in December 2020, which created a looped system.

Rate schedule
Given the estimated load at the facility, Prairie Du Sac Municipal Electric and Water will likely
serve the EOC under the Small Power Time-of-Day Service – Cp-1 electric rate (Figure 2.1.10).

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Figure 2.1.10 - Prairie Du Sac Municipal Electric and Water Small Power TOD Service(Cp-1) Rate Structure18

2.2 Initial Load and Solar Analysis
Load Analysis
Several different load and asset mix scenarios served as additional inputs in the microgrid
sizing, siting, and financial analysis processes. For this study, SEPA considered two load
scenarios. In the first scenario, the microgrid would serve the EOC’s load only. In the second
scenario, the microgrid would also serve the load of an EV fleet consisting of six police vehicles.
The load depends on the time of year and time of day. The EOC’s load clearly peaks in thesummer. Throughout the year, the load peaks in the afternoon, though in January and February,
it peaks in the morning. In November, we observed a load peak in the middle of the night, butthat could be the result of an anomaly in the base data from the fire station. Note that this data
is based only upon a proxy load profile and energy consumption estimates, and the true facility
load profile may deviate from the load analysis laid out in this report. Figure 2.2.1 illustrates thevariation of the EOC’s load throughout the year.

19Figure 2.2.1 - Sauk Prairie EOC Load by Month

Source: Smart Electric Power Alliance, 2022

EV Charging Analysis
In addition to the estimated base load profile of the new EOC facility, Sauk Prairie Police
Department suggested that it would be valuable to consider a scenario in which the vehicle fleet
is transitioned to plug-in electric vehicles (PEVs) and fleet charging loads would need to beconsidered when building a microgrid. In order to estimate a charging load profile for this
scenario, SEPA worked with the Sauk Prairie Police Department to gather assumptions about
potential vehicle specs and planned EV charging stations at the EOC. Vehicle and charging
station assumptions are highlighted in Table 2.2.1.

20

Table 2.2.1 - Sauk Prairie EOC PEV and Charging Station Assumptions
Vehicle Assumptions
Vehicle Type

Tesla Model Y Long-Range AWD 9

Battery Size

75 kWh 350 V lithium-ion

Efficiency (kWh/mi)

0.3010Daily Mileage (mi)100

Number of Vehicles

6

Recommended Max Charge

90%11Charging Station Assumptions 12
Charging Station Model

ClipperCreek HCS-D50, Level 2 Dual
Charging Station

Charging Power

32 Amp (7.7kW max)

Supply Circuit

240 V, 40 A

Number of Chargers

3

Charging Efficiency

90%13

Source: Smart Electric Power Alliance, 2022

To estimate the additional facility load resulting from charging an EV fleet, SEPA worked with the
Sauk Prairie Police Department to make final assumptions about charging schedules based on
department needs. The team sought to maximize charging time across 5am - 5pm shifts in order
to avoid significant hourly load increases that would result from more rapid vehicle charging. In
order to achieve this charging schedule, SEPA assumed that three of the six vehicles would
charge during each shift between 6am - 4pm and 6pm - 4 am, respectively. Note that the threedual chargers would only be used to charge one vehicle each at any given time. Finally, SEPA
9

Selected in coordination with Sauk Prairie Police Department. This vehicle has been selected for use in
several EV pilot programs at police stations across the United States. Notably, in Boulder, CO(https://www.bouldercounty.org/news/boulder-county-sheriffs-office-is-testing-out-use-of-tesla-as-a-patrolvehicle/), Eden Prairie, MN (https://www.edenprairie.org/Home/Components/News/News/10271/28), andCary, NC.
(https://www.cbs17.com/news/local-news/wake-county-news/cary-police-department-to-show-off-new-tesl
a-model-y-cruisers-at-thursday-media-event/)
10
From 2022 Tesla Model Y long-range per fueleconomy.gov; added a buffer of 0.02 kWh/Mile to accountfor increased weight from modifications
11
Per Tesla Support - Home Charging - Frequently Asked Questions
12
Specifications gathered fromhttps://store.clippercreek.com/dual-ev-charging-station?gclid=Cj0KCQjwpv2TBhDoARIsALBnVnlqdq7v4p
yHEf6t_5Xb6UQfhVJ3IBeN6Cw02QhgvXj_xl29rmRNSXcaAps6EALw_wcB unless noted otherwise
13
Assuming 90% charging efficiency (89.4% per https://ieeexplore.ieee.org/document/7046253)

21

assumed that vehicles would begin charging with a 65% charge and would charge to 90% perrecommendations noted in Table 2.2.1.14
SEPA leveraged an internal EV fleet charging model and the assumptions noted above toestimate the daily charging profile for the fleet. SEPA’s analysis estimated that the EV fleet
charging would add 9 kW to the EOC’s hourly load during the hours of 6am - 4pm and 6pm 4am each day. Figure 2.2.2 illustrates the daily charging profile of the proposed EV fleet.
Figure 2.2.2 - Estimated Daily EV Fleet Charging Load

Source: Smart Electric Power Alliance, 2022

With the addition of the EV fleet, the new EOC facility load, as shown in Figure 2.2.3, still peaksin the summer and experiences similar load peak hours, with the exception of December’s peakhour shifted to 8pm. That said, the monthly load peaks are increased by 9 kW from the site’sbase load as they occur in coincidence with EV charging.
14

SEPA used the charging calculator available at https://evadept.com/calc/ev-charging-time-calculator toestimate the beginning battery charge given the daily mileage estimate and recommended max charge.

22

Figure 2.2.3 - Sauk Prairie EOC and EV Fleet Charging Load by Month

Source: Smart Electric Power Alliance, 2022

Solar Analysis
Within the asset mix scenarios, SEPA evaluated various combinations of solar PV, battery
storage, and islanding duration. The Sauk Prairie police department already plans to include
94.5 kWDC of roof-mounted solar PV, which was excluded from the BCA along with the planned
154 kW diesel generator. In addition to the roof-mounted solar PV, two of our scenarios;
Scenario D and the Renewable + EV Fleet scenario, included an additional 97.5 kWDC ofground-mounted solar PV which was included in the BCA. To estimate hourly solar production at
the site throughout the year, SEPA used NREL’s PV Watts Calculator and the following inputs tobuild an annual baseline solar generation profile:
●
●
●
●
●
●

Solar Resource Data Site: Lat, Lon: 43.29, 89.74 W
DC System Size: 1000 kW
Array Type: Fixed (open rack)
System Losses: 14.08%
Tilt: 20°
Azimuth (deg): 180°First, SEPA adjusted the baseline solar profile to match the proposed solar capacity. SEPA thenmodeled each of the asset mix scenarios in order to estimate financial and environmental
23

benefits related to that solar generation. Figure 2.2.4 highlights the average monthly solar
generation for each scenario alongside monthly energy consumption at the site.
Figure 2.2.4 - Proposed Solar Generation and Energy Consumption at Sauk Prairie
Emergency Operations Center by Month

Source: Smart Electric Power Alliance, 2022

Following the initial solar and load analysis, SEPA sized different variations of battery energy
storage to shape solar production and provide back-up emergency generation during outages.
In cases where solar and battery storage scenarios were unable to serve the site’s entire load,
SEPA ensured that they were sized so that the planned 154 kW diesel generator would be able
to meet the project team’s desired islanding duration.

2.3 Site Availability
The team calculated the site availability of solar energy, battery energy storage, and diesel
generation with the support of the Sauk Prairie Police Department. As illustrated in Figure 2.3.1,
Sauk Prairie Police Department and the Village of Prairie Du Sac provided SEPA with the sitelayout, and electrical plans, which were used to identify a potential section of the property that
could host microgrid assets. The section for potential microgrid asset installation were identified
in accordance with relevant building and fire codes. The site assessment considered areas
located at least 10 feet away from landscaping and 100 feet from the road, and in sections of
the property not demarcated for stormwater management.

24

Figure 2.3.1 - Sauk Prairie Police Station Site Map

Source: SEPA, 2022

Site Assessment for Solar PV
In addition to cost and load analysis outputs, SEPA considered site availability when proposing
solar capacity for each scenario. As noted in the Solar Analysis above, the team used NREL’s
PVWatts Calculator to estimate the anticipated solar output at the site. Ground mounted solar
siting estimates are summarized in Table 2.3.1.

25

Table 2.3.1 - Sauk Prairie Emergency Operations Center Site Map KeyParcelUsable Ground
Area

Potential Solar PV (kW DC)

Additional
Identified Area
for Microgrid
Assets24,101 sq. ft

130

Source: Smart Electric Power Alliance, 2022

Site Assessment for Microgrid Assets
Potential spacing for microgrid assets is available in the southern end of the site just below theplanned police station. The feasibility of this location is subject to review by the Sauk Prairie
Police Department and other stakeholders. A required site review will also assess site civil
limitations and clearances to safely operate the equipment. Additionally, the facility would likely
choose to install screening planting around the electrical service equipment. Screening planting
was not considered in the scope of this assessment.

Existing Electric Feeders
The Village of Prairie Du Sac identified the location of the planned electric distribution feeder on
the north end of the police station off 13th Street to support the preliminary siting of the battery
storage system. This asset is tentatively sited near the southern edge of the facility due to theavailable space for microgrid assets.

3.0 Microgrid Scenarios Development
Microgrids across the country vary significantly in both their average capacity and fuel source,
as shown in Figure 3.1. According to a study by NREL in 2019, U.S. microgrid projects totaled
729 MWs in capacity. The most widely used energy source is combined heat and power, whichpowers 51% of the microgrid projects. After CHP, the most widely used energy source is diesel,
which powers 17% of microgrid projects. Natural gas powers 12% of microgrid projects andsupports 91 MW on average, making fossil fuels the energy source of the vast majority of
microgrid projects. Renewable energy fuels about 18% of microgrid projects, which may be a
result of a number of factors including local regulations, budget restrictions, or preferences.
Solar photovoltaic (PV) energy is the most abundantly used renewable fuel source, powering
11% of microgrid projects. Wind energy is only utilized in 1% of U.S. microgrid projects. Other
microgrid fuel sources include energy storage and fuel cell technology.

26

Figure 3.1 - Current Microgrid Installations by Technology

Source: ICF International, U.S. Department of Energy Combined Heat and Power and Microgrid Installation
Databases, 2022.

3.1 Stakeholder Process and Findings
When determining potential asset mix and load scenarios for a Sauk Prairie Police Department
microgrid, SEPA engaged with the project team to adequately consider the needs of the site, WIOEI grant guidelines, and the preferences of key stakeholders.

Process
The core team, especially members from the police department and local utility, provided input
regarding project requirements to meet resilience, sustainability, and environmental goals. SEPA
met with the full project team on a monthly basis to discuss scenario development
considerations and study progress. During the January and February check-in meetings, theteam held discussions around microgrid resilience needs at the police station with respect to thepercentage of load served, islanding duration, asset location and sizing, ownership models, andthe use of standby back-up generation to establish microgrid scenarios. Project team members
considered a number of questions as highlighted in Figure 3.2.

27

Figure 3.1.1 - Key Microgrid Scenario Development Questions

Source: Smart Electric Power Alliance, 2022

Findings
From these discussions, SEPA identified several key findings.
1. A microgrid would need to serve at least 50% of the site’s load to ensure that the facility
can provide critical services that ensure the computer servers and evidence room
refrigeration remains on.
2. Our scenarios B and C would incorporate a relatively small BESS into the existing sitethat could serve as a demonstration project for how a battery could be used for BTM
economics to reduce risk of using diesel.
3. Given that electric vehicles will be part of the fleet at the Sauk Prairie Police Department,
SEPA was able to incorporate the projected load from the planned fleet and identify
charging profiles.
4. An ideal EV scenario might look at adding additional solar or storage in phases to alignwith the adoption of EVs for the police department.
5. Providing frequency regulation to MISO using an oversized battery would not provide asignificant enough benefit to justify the costs of such a significant investment. Notably,
given the solar development limits at the site, a developer would likely be unable tomonetize the federal investment tax credit. Additionally, providing frequency regulation to
MISO would not provide a significant enough benefit to justify the costs of such asignificant investment, even under optimal conditions.
28

6. Strategic load shedding could be used to reduce the emergency operations center’s
energy consumption during a long-term outage.

3.2 Microgrid Scenarios
Overview
Scenario modeling produced the preliminary asset mix design for five microgrid scenarios,
which Table 3.2.1 summarizes.
Table 3.2.1 - Microgrid Scenario Components
Scenario

Load

ScenarioA

PoliceStationScenario
B

PoliceStationScenario
C

PoliceStationScenarioD

PoliceStationEV
Scenario

PoliceStation +EV Fleet

Solar

Rooftop
Solar Only

Rooftop +Ground-Mo
unted
Solar

Solar
kW-DC*

Battery
kW-DCIslandDays15

-

360

2-3**

-

150

1**

-

150

1**

97.5

3,200

365**

97.5

75

1**

*This table (and the BCA) only includes solar in addition to the 94.5 kWdc already planned at the site. Note that theislanding capacity in Scenarios A-C is calculated with the assumption that a total of 94.5 kWdc is available to reduceload during the day and charge the battery during an outage. Scenario D and the EV scenario is calculated with theassumption that a total of 192 kWdc is available to reduce load during the day and charge the battery during an
outage**Battery Only - Islanding capacity only includes battery capacity. The 154 kW diesel generator can provide an
additional 5-6 days of islanding capacity assuming that the 595 gal tank is full and the generator is operating at ~25%
load. In the EV scenario, this capacity is reduced to 4-5 days.
Source: Smart Electric Power Alliance, 2022

15

This value is an estimate of the duration of islanding capability that the microgrid can provide on a
typical day during the peak load month, August. Estimates may be given as a range to account forfluctuations in islanding capability based on instantaneous weather and grid conditions. Islanding duration
at any given time is based on the ability of the on-site PV generation to meet the facility’s load and charge
the battery, the facility’s demand during an outage event, and the time of day and year that the outage
occurs.

29Preliminary Economic Analysis
The preliminary economic analysis included an initial high-level look at each preliminary draft
scenario. The analysis included some easy-to-calculate estimates of the costs and benefits ofeach scenario, especially as related to the generation and resilience characteristics of each.
The preliminary economic analysis included order of magnitude estimates of solar andemissions benefits, as well as capital costs and O&M estimates. Select cost and benefit
highlights were then presented to the project team to demonstrate the unique and relative value
propositions of each scenario, and to validate each scenario prior to the final economic analysis.
Figure 3.2.1 summarizes relative emissions reductions, projected costs (per kWh load served),
and resilience capabilities for each microgrid scenario. The costs, carbon emissions, load
coverage and grid support all vary in each of the five designs. The designs range from
inexpensive to most expensive, carbon free to significant diesel generation.

30

Figure 3.2.1 - Scenario Asset, Load Coverage, Outage Capability, and Cost Overview

Source: Smart Electric Power Alliance, 2022

The initial normative cost considerations above for the five microgrid scenarios came from the
NREL 2019 Annual Technology Baseline, vendor quotes, and NREL’s Phase I Microgrid Cost
Study: Data Collection and Analysis of Microgrid Costs in the United States.

Scenario Pros and ConsThe five microgrid design scenarios present their own benefits and drawbacks.

31

Scenario A proposes a microgrid that adds a moderately-sized battery to the planned 94.5
kWdc solar PV and 154 kW diesel generator planned for the site. During normal operations, thebattery is capable of providing some additional economic benefit, as 25% of the battery’s
capacity is reserved for demand reduction. Paired with the planned solar PV, the battery canprovide a few days of carbon-free islanding capacity.
Scenarios B and C propose more economical microgrid designs that provide limited
carbon-free resilience while minimizing costs and optimizing the economic benefits of a batteryenergy storage system. These scenarios suggest deploying a smaller battery in addition to theplanned 94.5 kWdc solar PV and 154 kW diesel generator planned for the site. During normal
operations, these two scenarios compare the benefits of using the battery for demand reduction
versus energy arbitrage. Paired with the planned solar PV, the battery can provide one day ofcarbon-free islanding capacity.
Scenario D, the most costly and only 100% renewable design, serves the load of the entire siteand maximizes on-site generation by deploying an additional 97.5 kWdc ground-mounted solar
PV at the site. During normal operations, the battery is capable of providing an economic
benefit, as 25% of the battery’s capacity is reserved for demand reduction. Paired with theproposed and planned solar PV, the battery can provide indefinite carbon-free resilience.
The EV Scenario proposes a microgrid that maximizes on-site generation by deploying an
additional 97.5 kWdc ground-mounted solar PV at the site. The additional generation, pairedwith a small battery, serves to ease the demand burden of the additional EV fleet charging at thefacility, and provide additional economic and resilience benefits. During normal operations, thebattery is capable of providing an economic benefit through energy arbitrage. Paired with theproposed and planned solar PV, the battery can provide one day of carbon-free resilience.

4.0 Microgrid Feasibility
4.1 Preliminary Engineering Considerations
In addition to the loads and DER assets noted in the scenarios above, several other factors
must be considered during the engineering design phase of a microgrid project including a
microgrid controller and the distribution system. The components of a microgrid include facility
load, generation (solar PV or diesel generation), battery energy storage, a microgrid controller,
and interconnection to an existing distribution line.
For the purposes of this analysis, it is assumed that Prairie Du Sac Municipal Electric and Water
will own and operate the medium voltage distribution infrastructure, while the other infrastructure
including solar facilities, battery storage and diesel generation would be owned by the Sauk
Prairie Police Department. In general, the scope of the necessary fieldwork is largely agnostic tothe ownership model.
32

SEPA designed scenarios A-D to serve the EOC, and one additional scenario to serve both the
EOC and an EV fleet through a mix of ground-mounted solar, battery storage, and diesel
generation. Each of the preliminary sizing estimates for each scenario enable the microgrid torely significantly on generation from solar PV during the summer and utilize battery storage andthe diesel generator for islanding during periods of low solar output.
Note that SEPA estimated the EOC’s loads using the historic load profile data for a nearby firestation and, therefore, the site’s load could change once real-world data becomes available.
This could lead to different results for the load analysis.

Site Layout
SEPA developed a conceptual microgrid configuration for each scenario, but suggests thatstakeholders reference 2.3 Site Availability and coordinate with an engineering design team todevelop a site layout that best suits the final project. Microgrid configurations are noted below
for each scenario.

Scenario A*BCA does not include the costs and benefits associated with the planned 94.5 kW Solar PV**BCA does not include the costs and benefits associated with the planned 154 kW diesel generator

33

Scenarios B and C*BCA does not include the costs and benefits associated with the planned 94.5 kW Solar PV**BCA does not include the costs and benefits associated with the planned 154 kW diesel generator

Scenario D*BCA only includes additional 97.5 kWdc ground-mounted PV proposed beyond the planned 94.5 kWdc
roof-mounted PV

34

EV Scenario*BCA only includes additional 97.5 kWdc ground-mounted PV proposed beyond the planned 94.5 kWdc
roof-mounted PV**BCA does not include the costs and benefits associated with the planned 154 kW diesel generator

Microgrid Operations
Prairie Du Sac Municipal Electric and Water will own and operate all medium voltage
equipment, which includes disconnecting and reconnecting the microgrid from Prairie Du Sac's
distribution system. The microgrid will have three modes described below. During eachscenario, the microgrid controller will ensure proper voltage and frequency levels, manage loads
and generation, and optimize battery charge/discharge schedule and charge levels.

Operating Mode 1: Normal Operation/Blue Sky
During normal operation, the solar PV system will operate in parallel with Prairie Du Sac's
distribution system. Where relevant, the diesel generator will only operate for maintenancepurposes. A schedule of maintenance operations will need to be provided to Prairie Du Sac’s
Systems Operations. The microgrid controller will ensure that the battery storage system
maintains a full charge.
The battery storage system would also be used to reduce demand charges, or engage inenergy arbitrage, bringing in revenue to offset costs. WPPI’s Systems Operations Center will
only need to be alerted if energy is being discharged to the grid.

35

Operating Mode 2: Microgrid Operation - Disconnecting from the Grid
During a scheduled or unplanned outage, Prairie Du Sac Municipal Electric and Water will
initiate the microgrid isolation from the distribution grid. During a scheduled outage, this will be aseamless transition. During an unscheduled outage, the facility will be served by the BESS until
the outage is repaired, or until the battery is drained and the diesel generator comes online, if
included in the scenario. The BESS and diesel generator, where relevant, will operate tostabilize load and maintain voltage and frequency. Once voltage and frequency levels havestabilized, the solar will resume operation. During a long-term outage, battery storage will
operate to manage variations in voltage or frequency and reduce peak load times. The scenario
assumes that the battery will be fully charged when microgrid operation is initiated. Once
initiated, the battery can temporarily suspend energy arbitrage or demand reduction capabilities
to ensure that the battery is fully charged in preparation for a forecasted outage-causing event.
Once the microgrid is in operation, the controller will manage the charge and discharge of thebattery storage based on microgrid conditions and available solar output. The controller will act
to maximize the usage of PV energy and minimize the use of the diesel generator.

Operating Mode 3: Microgrid Operation – Resuming Normal Operation
Once the distribution grid has been restored, the facility will be re-connected to the larger
distribution grid. To do this, the microgrid will re-synchronize and operate in parallel with the
distribution grid and the generator will power down. The battery storage system will discontinue
operation except to re-charge or carry out economic functions. This will be designed to be aseamless transition.

Interconnection
All resources will follow Prairie Du Sac’s standard interconnection process for distributed
generation.

MicrogridTo house the microgrid controller, manage the electrical isolation of the facility from Prairie Du
Sac’s distribution system, and provide an interconnection point for the battery storage system
and/or diesel generator, an upright switchgear may need to be installed at the site. Since this is
the isolation point for the microgrid from Prairie Du Sac’s distribution system, it will need to beconnected at the point where Prairie Du Sac’s distribution enters the facility.
Typical dimensions for an upright 13 kV switchgear would be approximately 10’ wide, 9’ deep,
and 9.5’ tall.

Solar, Diesel, and Battery Storage
The solar, BESS, and diesel generation unit, if included, will interconnect to the microgrid
isolation switchgear. The solar, BESS, and diesel generator may require step-up transformers toconvert to the distribution line voltage. For layout purposes, SEPA assumed that the battery
storage system and the diesel generator were close enough to each other to use a single step36

up transformer. The solar PV ground-mounted system will not require separate metering or aseparate service transformer.
For layout purposes, SEPA assumed the footprint of the battery storage system in eachscenario to be between 60 and 2,520 sq ft. based on battery sizes and available references.16
Exact dimensions will depend on the equipment vendor selected.

4.2 Financial and Environmental Impact
The financial and environmental impacts summarized in this section build on the technicalanalysis and focus on developing a high-level inventory of potential benefits and costs for the
proposed microgrid scenarios to assess the net benefits of each.
Understanding the balance between benefits and costs can clarify whether the proposed
investment (and other costs) of the project are justified by the resulting benefits. Suchassessments are especially important when the investment is being made “for public benefit,” orwhen externalized or non-economized benefits (such as cleaner air, reduced greenhouse gas(GHG) emissions, or improved public health) are realized.
The goal of this study is to develop a high-level inventory of potential benefits and costs for thisspecific microgrid project, and to establish a foundation for a more formal benefit-cost
assessment once additional project details are finalized. The study focuses on quantifying utility
and societal benefits in economic terms, and determining how these economic benefits
compare to the costs of implementing, operating, and maintaining the project over its lifespan.
This report was prepared by project participants and written in a relatively non-technical way tosupport engagement with stakeholders.
All benefits and costs included in the analysis are quantified, and the multi-year cash flow (overan assumed project life of 20 years) is translated into a Net Present Value (NPV). A simple
benefit-cost ratio can then be computed based on the NPV of all benefits divided by the NPV of
all costs. A benefit-cost ratio of 1.0 would indicate that benefits exactly match costs. A ratio of
more than 1.0 indicates a net benefit in which benefits exceed costs, with higher ratios
indicating a greater net benefit. A ratio of less than 1.0 indicates that costs exceed benefits, withlower ratios indicating a less favorable benefit-cost balance.
All five proposed Sauk Prairie EOC microgrid scenarios would provide uninterrupted power tothe facility for a period of at least one day. The use of additional renewable generation assets
beyond the 94.5 kWdc solar PV planned for the site will increase total benefits associated withclean on-site generation. These microgrid functions represent the basis for an inventory of bothbenefits and costs that can be used to quantify the net benefit of the project.

16

SEPA used reference data from a publicly available SCE battery storage project which assumed afootprint of ~0.2 sq ft/kWh.

37

Inventory of Benefits and Costs
Development of the benefit and cost inventory depends on detailed information about aproposed microgrid project, including possible microgrid configurations, microgrid asset sizing,necessary changes to the local distribution system serving the planned facility, islanding
switchgear, and a specialized microgrid control system. Cost estimates include the initial capitalcosts of the microgrid assets and the expenses associated with operation and maintenance ofthe microgrid infrastructure over the long term.
The benefit-cost inventory assumes that the project will have a 20-year life-span and that, overthat time, the solar production will decline by 0.4% annually, as is typical of photovoltaic
systems. The solar system will supply renewable energy, and for the purpose of this analysis is
assumed to be net-metered. The emissions reduction value associated with solar generation is
the same regardless of interconnection method. No additional “grid services” are assumed forthe microgrid components – such as dispatch of either the battery or diesel generator.17
The load served by this project consists of the Sauk Prairie EOC or the Sauk Prairie EOC and afleet of six electric vehicles. For purposes of this analysis, all outages experienced by the facility
are assumed to be the result of feeder-level failures – i.e., not the result of issues within theboundaries of the facility itself.
A formal benefit-cost analysis would make use of standardized tests. The protocols associatedwith those tests dictate what combination of benefits and costs are used in each case. Making
those determinations depends upon knowing important details about ownership structure, which
parties bear various real-world costs18, benefits (often in the form of revenues) or avoided costs
and to whom they accrue, and the role of the utility in the project. Many of those details are notknown yet, as is typical for a feasibility study at this stage of development.
As a result, this study focused on developing an inventory of the benefits and costs that might
be included in a formalized benefit-cost test. That inventory can provide early insight about thebenefit-cost balance, and help establish the foundation for formalized benefit-cost assessment.
It is important to note, however, that not all benefits or costs noted in the inventory below might
be included in a particular test. Care is needed to ensure that a formalized test balances thegroup of benefits and costs included, and that issues such as double-counting and “transfer
effects”19 have been addressed.
The inventory summarized below has been developed with a focus on taking a “common sense”
view of both benefits and costs, looking broadly at the “societal scale” of impact, and building
upon the details about project implementation that are known at this time. The combination of
Additional grid services, if added to the operating profile of the microgrid, might introduce additional
benefits that could be quantified.
18
Whether these affect the benefit-cost analysis depends on which test you use. For instance the utility
test versus the societal test. If the societal test was used, these would not change the overall results.
19
Transfers exist within a benefit-cost test when both the benefits and costs flow to and from the same
impacted population considered by a particular test, thereby canceling each other out. The nature oftransfer considerations depends on the test being used.
17

38

these benefits and costs used in a specific formal test will depend on the test being performed,
and additional project details being specified.
Figure 4.2.1 - Overview of Benefits and Costs

Source: SEPA, 2022

Overview of Costs
The costs for the microgrid project relate primarily to the costs of construction, and long term
operating and maintenance costs. These cost estimates were taken from a technical evaluation
completed by the SEPA team, and are associated with each proposed scenario. The costinventory includes:
1. Generation (PV + NG): Generation costs only reflect the purchase and installation of
additional solar photovoltaic capacity beyond the newly commissioned 94.5 kWdc
rooftop solar PV array at the site. In each scenario, a photovoltaic system has been
proposed for the microgrid to generate clean electricity, and (with the support of theplanned diesel generator and/or a BESS) allows the facility to operate independent of
the grid. The PV system partially replaces traditional fuel use, providing significant
emission reductions that are a key benefit of the overall project. The diesel generator
can be dispatched on demand, and can be used to firm the solar generation, as well as
provide power in parallel with the solar system or when no sunlight is available. This is a
one-time construction cost. The costs for the solar system include a long-term warranty
for the inverters to ensure their continued operation over the assumed lifespan of the
project. The costs for the solar system do not include the Federal Investment Tax Credit(ITC). Further BCAs may need to reassess the value of the ITC, assuming that it would
be available at the time of construction.
39

2. Battery Energy Storage Systems (BESS): This is a highly valuable component of alarger system that generates energy using intermittent sources of renewable energy
such as solar, since it helps to balance the production and use of energy. The BESS is
also important for a microgrid to handle transition events and to ensure power quality.
For this study, initial BESS costs were captured in the first year as part of construction,
but further BCAs may want to assume that the battery would need to be replaced
partway through the life of the project, as the lifespan of a BESS is likely to fall short ofthe 20-year project life-span assumed in this study. Estimating the future costs of
replacement must account for the net impact of inflation and expected reductions inbattery costs over time, for example, a net cost reduction of 5% per year might be used
to estimate replacement costs in a future year. Additionally, the costs for the BESS do
not include the Federal Investment Tax Credit (ITC). Further BCAs may need toreassess the value of the ITC, assuming that it would be available at the time of
construction and the system is eligible to receive the credit.
3. Soft Costs, Controller, and Communications: A specialized controller is used to
manage the microgrid when in island mode, including direct interaction with thegeneration resources and the BESS. The costs of the controller, along with the costs ofengineering, construction, commissioning, and regulatory affairs, are included as a
one-time construction cost estimated at 16% of the component costs for each scenario.
4. Distribution Upgrades: In order to implement the microgrid, SEPA assumed that theexisting distribution system at Sauk Prairie EOC will not require significant modifications.
Construction costs for distribution upgrades were not included in this study, but may
need to be incorporated into further BCAs.
5. Operations & Maintenance: Unlike other cost components, operations andmaintenance is an ongoing, recurring cost. These costs were taken from the NREL
Annual Technology Baseline (ATB) 2021 for commercial solar PV and 4hr Lithium Ion
BESS on an annual basis for the lifespan of the project.

Overview of Benefits
Most of this study focused on identifying and quantifying the benefits from the microgrid project.
All of these benefits are incremental to the baseline provision of service to the facility. As
covered in more detail in Appendix 2: Detailed Benefits, the study modeled and estimatedsignificant benefits associated with solar generation and improved resilience, including:
1. Value of Solar Generation: The value of solar generation was represented as the total
annual value of:○Energy Rate Savings: Bill savings resulting from avoided energy purchases, as
energy consumption at the facility is offset by on-site solar generation.

○

Excess Generation Credit: Bill credits resulting from solar generation in excessof the facility’s load that is metered back to the grid at a predefined rate.

40○Demand Savings: Bill savings resulting from the reduction of facility load peaks
that coincide with on-site solar generation.

2. Value of Battery Savings: The value of battery savings was represented as the total
annual economic benefits provided by a BESS through:○Energy Savings: Bill savings resulting from shifting on-peak energy purchases
to off-peak hours as noted in the TOU rate by charging the battery from excess
solar or from the grid during off-peak hours and discharging it for use duringon-peak hours.

○

Demand Savings: Bill savings resulting from the reduction of facility load peaks
by strategically discharging the battery during hours of peak load.
3. Value of Emissions Reductions: Solar PV generation reduces harmful emissions fromburning fossil fuels that have local, regional, and global impact. Benefits include the total
dollar value of reductions in mortality and morbidity from PM2.5, SO2, and NOx20, andthe CO221.
4. Implied Value of Resilience: The implied value of resilience focused on the ability of a
microgrid to provide power to the facility when the public grid is inoperable. For the EOC,
resilience value should be based on its ability to serve as an emergency operations
center for a number of Sauk Prairie emergency services during major events, criticalincidents, and man-made or natural disasters, especially when the power is out as aresult of the event. In this study, the implied value of resilience is the remaining
difference between the NPV of costs and benefits in each scenario when the costs
outweigh the benefits. This value will not be included in the final BCRs for each scenario,
but it can be used as a benchmark for stakeholders to consider when estimating thevalue of resilience at the site for future cost tests. In cases where the benefits exceed
costs, this value will not be noted, as the project can be considered to be cost effective
without the inclusion of this benefit.

Summary of Results
The study quantified the economic valuation of both benefits and costs for the microgrid
scenarios, including a nominal sum (i.e., the simple sum of annual costs), and a Net Present
Value using a discount factor of 5%. That is, the weighted average cost of capital (WACC) is
assumed to be 5%. A high-level summary of benefits and costs is displayed in Figure 4.2.2.
Figure 4.2.2 - Summary of Benefits and Costs

20

https://www.epa.gov/sites/default/files/2018-02/documents/sourceapportionmentbpttsd_2018.pdf

21

https://19january2017snapshot.epa.gov/sites/production/files/2016-12/documents/sc_co2_tsd_august_20
16.pdf41

Source: SEPA, 2022

Summary of Cost Results
The costs for each scenario are based on the initial construction costs and O&M costs eachyear over the 20-year period.
Table 4.2.1 - Summary of Costs
Microgrid Costs

Low Cost Scenario

Mid Cost Scenario

High Cost Scenario

Scenario A
Generation (PV)

$0

$0

$0

BESS

$475,701$583,280$654,949

Soft
Costs/Controller/Comms$90,610$111,101$124,752

Operations & Maintenance$95,246$135,169$171,670

Total$661,556$829,550$951,372$0$0Scenario B
Generation (PV)

$0

42

BESS

$198,209$243,033$272,895

Soft
Costs/Controller/Comms$37,754$46,292$51,980

Operations & Maintenance$39,686$56,320$71,529

Total$275,649$345,646$396,405

Scenario C
Generation (PV)

$0

$0

$0

BESS

$198,209$243,033$272,895

Soft
Costs/Controller/Comms$37,754$46,292$51,980

Operations & Maintenance$39,686$56,320$71,529

Total$275,649$345,646$396,405

Scenario D
Generation (PV + NG)$147,518$151,551$162,173

BESS$4,228,453$5,184,712$5,821,770

Soft
Costs/Controller/Comms$833,518$1,016,431$1,139,799

Operations & Maintenance$846,629$1,201,503$1,525,957

Total$6,056,118$7,554,197$8,649,699

EV Scenario
Generation (PV)$147,544$151,579$162,202

BESS$99,104$121,517$136,448

Soft
Costs/Controller/Comms$46,981$52,018$56,886

Operations & Maintenance$34,217$44,085$55,461

Total$327,846$369,199$410,997

Source: SEPA, 2022

43

Summary of Benefits Results
The following chart summarizes the economic value of the benefits associated with themicrogrid scenarios.
Table 4.2.2 - Summary of Benefits

Microgrid Benefits

NPV of Benefits ($2022)

First Year Benefits(Nominal $)Scenario A
Solar Generation$0$0Battery Savings$4,951$324

Emissions
Reductions$0$0

Implied Value ofResilience*$52,688 - $75,943

-

Total

$4,951$324

Scenario B
Solar Generation$0$0Battery Savings$4,973$325

Emissions
Reductions$0$0

Implied Value ofResilience*$21,720 - $31,410

-

Total

$4,973$325

Scenario C
Solar Generation$0$18,109

Battery Savings$26,440$1,728Emissions
Reductions$0$0

Implied Value ofResilience*$19,997 - $29,687-

44

Total$26,440$1,728Scenario D
Solar Generation$98,916$6,693

Battery Savings$5,239$342

Emissions
Reductions$110,487$6,921

Implied Value ofResilience*$469,888 - $678,431

-

Total

$214,642$13,957

EV Scenario
Solar Generation$104,101$7,044

Battery Savings$27,486$1,797

Emissions
Reductions$110,507$6,922

Implied Value ofResilience*$6,881 - $13,553

-

Total

$242,093$15,763*The “Implied Value of Resilience” is an annual estimate, and displays a range of values for low, mid, and high-costestimates. This value is not included in the “Total” benefits noted in the table, and does not impact the BCR values
related to each scenario. A value of $0 suggests that the scenario is cost-effective without including resilience
benefits in the BCA.
Source: SEPA, 2022

Summary of the Benefit-Cost Ratio
A typical benefit-cost analysis greater than 1.0 indicates that benefits exceed costs, and the
project is generally beneficial. In the simple case where all the benefits identified above can be
included in the benefit portfolio22, the net benefit results are as follows.
Table 4.2.3 - Summary of Benefits and Costs
Low Cost
Scenario

Mid Cost
ScenarioHigh Cost
Scenario22

As noted in the introduction, a formal benefit-cost test would specify exactly which benefits and costs
should be included for the benefit-cost calculation. Depending on the test, not all the benefits or costs
identified in the inventory may be included in a particular test.

45

Scenario A
Total Value of Costs (NPV)$661,556

Total Value of Benefits (NPV)$829,550$951,372$4,951Net Impact (Benefits minus
Costs)($656,606)($824,599)($946,421)

BCR

0.01

0.01

0.01

$345,646$396,405

Scenario B
Total Value of Costs (NPV)$275,649

Total Value of Benefits (NPV)$4,973Net Impact (Benefits minus
Costs)($270,676)($340,673)($391,432)

BCR

0.02

0.01

0.01

$345,646$396,405

Scenario C
Total Value of Costs (NPV)$275,649

Total Value of Benefits (NPV)$26,440Net Impact (Benefits minus
Costs)($249,208)($319,206)($369,965)

BCR

0.10

0.08

0.07

$7,570,119$8,669,392

Scenario D
Total Value of Costs (NPV)$6,070,490

Total Value of Benefits (NPV)$214,642

Net Impact (Benefits minus
Costs)($5,855,848)($7,355,477)($8,454,751)

BCR

0.04

0.03

0.02

$369,198$410,997

EV Scenario
Total Value of Costs (NPV)
Total Value of Benefits (NPV)$327,846$242,093

46

Net Impact (Benefits minus
Costs)($85,752)($127,105)($168,903)

BCR

0.74

0.66

0.59

Source: SEPA, 2022

47

Interpretation
The proposed Sauk Prairie EOC scenarios A-C provide limited benefits, solely through batterysavings, as no additional solar PV is proposed to offset the costs of the additional battery
storage. In these three scenarios, the benefits of the planned 94.5 kWdc solar PV (and theplanned 154 kWdc diesel generator) were not included in the BCA as it only sought to provide
insight into the benefits of introducing a battery to the planned on-site generation. The proposed
scenario D and EV scenario provide more substantial benefits, mainly due to the additional solar
production and associated emissions and rate benefits. However, due to the small scale of thisproject and the uncertainty associated with behind-the-meter solar and battery economic
benefits, these benefits on their own do not balance the construction andoperation/maintenance costs across all scenarios whether considering low-, mid-, or high- costs.
Although the benefit-cost ratios resulting from this high-level inventory of benefits and costs fall
below 1.0, other considerations provide additional context for this outcome:1. Benefit-cost analysis is highly sensitive to scale, and smaller projects almost always
result in lower benefit-cost ratios. This is especially true when there are relatively fixed
costs, as are evident for this project. In this case, the benefit-cost ratio is primarily aresult of the small project scale, not a meaningful representation of intrinsic microgrid
technology value.
2. Actual economic (demand and rate savings) benefits related to solar and battery storage
are very difficult to quantify accurately beyond those that would result from the mostconservative generation and load scenarios (i.e. maximum historic load and minimum
expected solar generation). For this reason, real-world benefits from these economic
functions could surpass those estimated in this study, and increase cost-effectiveness.
3. Development of microgrid technology, and improved resilience for all utility customers, isa strategic goal that is not easy to quantify. The strategic value of the project, including
workforce development, customer education, and benefits to the community who haveaccess to the EOC are not quantified in the benefits portfolio. These are qualitative
factors that provide important context for the benefit-cost evaluation.

5.0 Conclusion
Despite providing significant measurable advantages, the net present value of benefits for the
Sauk Prairie EOC do not exceed the costs of the project under any scenario before including
resilience benefits in the analysis. That said, the EV scenario presents a situation in which a
relatively modest valuation for the benefit of resilience at the site would make the additional
battery storage and solar cost-effective, as noted by the “Implied Cost of Resilience” values in
the previous section.
This analysis establishes a framework for assessing the economic value of the microgrid
project, including a preliminary quantification of the value of emission reductions and increased
resilience. Further formalized benefit-costs tests can build upon this foundation once additional
details about the project and other similar projects are finalized.
48

However, the benefit-cost outcomes are not the whole story. Small-scale programs frequently
result in unfavorable benefit-cost ratios, especially when the fixed costs are large. Trialing newtechnologies, strategies and programs offer learning opportunities, and may advance strategic
goals that intrinsically hold value themselves, but are often not quantified or included in afeasibility analysis. Externalities, such as the value of reducing emissions are likely undervalued
in these scenarios, despite providing important societal benefits. Most importantly, the research
and methodologies for quantifying the economic value of resilience is relatively new and likely
incomplete. As such, they may not capture the strategic value of improved resilience, especiallyas more extreme weather (and other) events become more common.
From the perspective of technical feasibility, Sauk Prairie EOC is a reasonable site to construct
and install a microgrid project. Project team members believe that this project would increase
resiliency in Prairie Du Sac, WI by serving as an EOC for emergency service providers in thecommunity during major events or prolonged outages.
Key learnings from this study include:
●
●

●

●

Given the open space at the site, the Sauk Prairie EOC is well suited to host additional
ground-mounted solar PV for on-site generation.
The solar and battery benefits are likely undervalued in the current benefit-costframework and are dependent on real-world performance beyond the conservative
estimates that were used for this study.
A fully renewable scenario is not economically feasible at the site given solar capacity
limitations which would force a large BESS charge mainly from the grid rather thanon-site solar.
Resilience benefits are likely to be significant given the facility’s role as an emergency
operations center.

If the project partners decide to move forward, next steps include:
●

●
●
●

Determine ownership and operation structures between Prairie Du Sac Municipal
Electric and Water, Sauk Prairie Police Department, and a developer in order to have theappropriate information needed for the final BCA
Identify potential funding sources to facilitate a public-private partnership (e.g.,
third-party finance, customer finance, utility investment and recovery in rates)
Conduct a full engineering design and construction study
Explore additional state and federal funding and grant programs (e.g., IIJA and FEMA
BRIC)

49

6.0 Appendices
Appendix 1: Project Team Check-In Summaries
This appendix includes summaries of each monthly project team check-in.

January 2022
During the initial kick-off meeting with the project team, SEPA focused heavily on getting thegroup acquainted with each other. SEPA provided a background on the microgrid feasibility
study and the grant, including information regarding project tasks, goals, and timeline. Project
team members began to discuss the site, its role as an EOC, its critical loads, and its resilienceneeds. Sauk Prairie Police Department shared details surrounding the plans and timeline for the
new EOC site construction, including the intention to build a roof-mounted solar PV array andincorporate a 154 kW diesel generator to provide backup power. SEPA started a discussion
around data collection expectations and needs in order to begin the site analysis and develop
preliminary microgrid scenarios. WPPI noted that since the site is not yet operational, SEPA and
WPPI would have to discuss how to estimate the site’s load using existing data from a similar
facility. Following this meeting, SEPA began to gather relevant data and began an initial solar,load, and site assessments.

February 2022
The second project team check-in meeting included a discussion around the site’s estimatedload and solar production, especially which facility loads were critical or could be shed during an
extended outage or emergency event. The project team also brainstormed potential microgrid
scenarios, considering the possibilities of incorporating additional solar PV at the site,
introducing battery storage to the planned solar PV and backup generator, or proposing a 100%
renewable scenario. Following this meeting, SEPA began to develop preliminary microgrid
scenarios and finalized the site assessment.

March 2022
The third project team check-in meeting focused on validating the site assessment anddiscussing the proposed preliminary microgrid scenarios. SEPA shared its site assessment withthe project team, and had a discussion surrounding the footprint of additional solar or a BESS.
SEPA also shared an outline of four initial microgrid scenarios in order to discuss the pros andcons of each with the project team. The project team also discussed the possibility of including
an additional scenario that includes the added load of transitioning to an EV fleet. Following thismeeting, SEPA finalized the microgrid scenarios and shared them with the project team.

April 2022
The fourth project team check-in meeting was fairly brief, but included a short discussion about
how the value of resiliency would be determined by the analysis. Additionally, the project team50

suggested resizing the EV scenario to make it more cost effective by downsizing the battery andrelying on the diesel generator to provide backup power. Following this meeting, SEPA finalized
the BCAs for each microgrid scenario in preparation for writing the final report.

Appendix 2: Detailed Benefits
This appendix includes the quantification of significant benefits associated with solar generation,battery storage, and improved resilience for the facility.

Value of Solar Generation
The Value of Solar Generation was determined on an hourly basis, then aggregated for annual
values. This represents the total annual value of:●●●Energy Rate Savings: Bill savings resulting from avoided energy purchases, as energy
consumption at the facility is offset by on-site solar generation.
Excess Generation Credit: Bill credits resulting from solar generation in excess of the
facility’s load that is metered back to the grid at a predefined rate.
Demand Savings: Bill savings resulting from the reduction of facility load peaks thatcoincide with on-site solar generation

PV Watts, developed by the National Renewable Energy Laboratory (NREL) was used toprovide an estimate of solar generation on an hourly basis for the first year. This tool is widely
accepted in the industry, and accounts for the location of the solar installation, local weather
patterns, the size of the system, characteristics of the array, system losses, tilt, azimuth, andother parameters. The tool is commonly used to estimate the energy production andperformance of potential photovoltaic energy systems. SEPA provided a PV Watts production
profile for the site, which was the basis for estimating solar generation value for each scenario.
Energy rate savings were estimated by calculating the average site load that would be met byon-site solar for each hour of the year and multiplying that value by the energy rate during thattime to determine the rate savings (or avoided costs) associated with purchasing that energy
from the grid to meet the site's load. When estimating this benefit, SEPA assumed an annual
solar degradation rate of 0.4% and an annual rate increase of 2.5%.
Excess generation credits were estimated by calculating the average on-site solar generation inexcess of the facility’s load for each hour of the year and multiplying that value by the buyback
rate to determine the benefit associated with delivering energy back to the grid after meeting thesite's load. Again, SEPA assumed an annual solar degradation rate of 0.4% and an annual rateincrease of 2.5%.
Demand savings were estimated by examining the new load peaks for each month after
considering the load peak reductions that would result from on-site solar generation. In order toavoid over-valuing this benefit, SEPA only considered demand reductions that would occur from51

the least favorable circumstances, that is days in which load is at its highest and solar
generation is at its lowest. In order to achieve this, SEPA created sample hourly profiles for eachmonth that represented the lowest observed solar generation for each hour during that month(from the PV Watts profile), and the highest observed site load for each hour during that month.
SEPA subtracted the hourly minimum solar generation figures from the corresponding hourly
maximum load figures for each month to generate a net hourly site load profile for each monthunder the least favorable circumstances. SEPA compared the new monthly and annual load
peaks to those in the original load profile to estimate a conservative, but plausible estimate fordemand savings.

Value of Emissions Reduction
Electricity generation that results from the burning of fossil fuels results in harmful emissions
that have local, regional, and global impact. Over recent decades, renewable energy, like solar
power, has emerged as a key strategy in reducing these emissions to improve air quality(especially key criteria pollutants like NOX, SO2, and PM2.5) and avoid the release of greenhousegasses that contribute to climate change.
The avoided emissions are quantified by determining the emission output that would have been
produced on a “pounds per MWh” basis had that energy been generated at a traditional fossil
fuel plant. The Emissions and Generation Resource Integrated Database (eGRID) provided
region-specific emissions factors as “Pounds per MWh” values which were used to determine
the environmental or emissions reduction impact of the avoided fossil fuel plant generation.23
This process was repeated for four criteria pollutants which all have their own uniqueenvironmental impacts and behave differently in the atmosphere: carbon dioxide (CO2), nitrogenoxides (NOx), sulfur dioxide (SO2), and particulate matter (PM2.5). The economic impact ofemissions was quantified using parameters from the Federal Interagency Working Group on theSocial Cost of Carbon (for CO2), and a separate study from the U.S. Environmental Protection
Agency for impact factors on NOx, SO2, and PM2.5.24 These conversion factors translate theemissions reductions (in tons) to an economic benefit (in dollars) to society at large.

Value of Battery Savings
The value of battery savings was represented as the total annual economic benefits provided by
a BESS through:●Energy Arbitrage: Bill savings resulting from shifting on-peak energy purchases to
off-peak hours as noted in the TOU rate by charging the battery from excess solar orfrom the grid during off-peak hours and discharging it for use during on-peak hours

23

United States Environmental Protection Agency (EPA), Emissions & Generation Resource Integrated
Database (eGRID).
24
The Interagency Working Group on the Social Cost of Greenhouse Gases, Technical Support
Document:- Technical Update of the Social Cost of Carbon for Regulatory Impact Analysis - Under
Executive Order 12866 (2016).

52

OR
●

Demand Savings: Bill savings resulting from the reduction of facility load peaks bystrategically discharging the battery during hours of peak loadNote that each scenario assumed that the battery was being used for either one of theeconomic functions, but not for both. Energy arbitrage benefits were estimated by calculating
the minimum value of either:●

The annual net energy consumption during peak hours as defined in the TOU rateschedule (i.e. the annual total (kWh) of energy consumption after estimated solar
generation for all hours between 8:00 AM and 8:00 PM) multiplied by the difference
between the on-peak and off-peak rates. This demonstrates the maximum annual
savings that could result from charging the battery during off-peak hours and discharging
it during on-peak hours to meet the facility’s load, given that the battery has sufficient
capacity to do so.

●

The sum of the capacity of the battery (kWh) or the capacity of the battery designated forenergy arbitrage multiplied by the difference between the on-peak and off-peak rates foreach day of the year. This demonstrates the annual capacity-limited maximum given thatthe battery does not have sufficient capacity to mitigate all on-peak energy purchases
and deliver maximum annual savings from energy arbitrage. Each day, the battery would
be fully charged during off-peak hours and fully-discharged during on-peak hours.

OR

It is worth noting that this value does not take into account additional benefits that would result
from on-site solar generation charging the battery and further reducing off-peak energy
purchases.
Demand savings benefits were estimated by assuming that the battery would be discharged
strategically to reduce site demand by avoiding going above a certain set demand peak for eachmonth. SEPA calculated the value of that demand peak for each month by maximizing theannual savings that could be achieved given the limits defined by the capacity of the BESS, theextent to which on-site solar generation is able to charge the battery under unfavorable
conditions, and the costs associated with charging the battery from the grid in order to reducedemand peaks.
When estimating this benefit, SEPA assumed an annual rate increase of 2.5% for both energy
and demand rates.

Implied Value of ResilienceA primary focus of this project was to quantify the value that a microgrid could bring to thefacility in terms of resilience (i.e., the ability to provide power when the utility grid is inoperable).
53

In order to quantify resilience value as part of the benefit portfolio, it must be expressed ineconomic terms. Valuation of resilience is relatively new and the study team found that there islittle research and few precedents upon which to base the analysis. For that reason, SEPA
presented an “Implied Value of Resilience” that is equivalent to the annualized benefit required
to make each microgrid scenario cost-effective.
The implied value of resilience should be compared to the project team’s own valuation of theability of a microgrid to provide power to the facility when the public grid is inoperable. For Sauk
Prairie Emergency Operations Center, this real-world resilience value should be based on its
ability to provide emergency services to the community during an extended outage or
emergency. In this study, the implied value of resilience was noted as the remaining difference
between the NPV of costs and benefits in each scenario, annualized over the 20-year project
lifecycle. In cases where the benefits exceed costs, this value was not noted, as the project canbe considered cost-effective without the inclusion of this benefit. This value was not included in
the final BCRs for each scenario, but it can be used as a benchmark for stakeholders toconsider when estimating the value of resilience at the site for future cost tests. That is to say, if
stakeholders perceive the actual value of resilience at the site to be greater than the impliedvalue of resilience noted here, then it is more likely that the project would be cost-effective infurther BCAs.

54