2nd Quarter 2025
INCORPORATING CUSTOMERRSIDED RESOURCES INTO INTEGRATED RESOURCE PLANNING
INTEGRATING ELECTRIC TRANSPORTATION | RESILIENCE PLANNING AND EXECUTION
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BOARD OF DIRECTORS
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Alvis Wright, Alabama Power Company
Antonia Ornelas, Elevate
Art Christianson, Resource Innovations
Paul Douglas, The JPI Group
Deb Dynako, Slipstream
Brett Feldman, Rhode Island Energy
Elizabeth Freeman, REAP Energy
Jeff Brown, Public Service Company of Oklahoma
Katie Falk, Evergreen Consulting Group
Knox Cameron, DTE Energy (BOARD CHAIR)
Derek Okada, Energy Solutions
Liz Haworth, Michaels Energy
Pamela Fann, Impact Energy
Quinn Parker, ENCOLOR
Sue Hanson, VEIC
Dena Jefferson, J.D., Franklin Energy
Lisa Rae, CIET
Luke Surowiec, ICF
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Table of Contents
BY KNOX W. CAMERON
A Letter From Our Board Chair
22
BY NICK TURCHAK AND WESLEY ANDREWS
BESS integrations at gas-powered datacenter expansions:
an untapped opportunity
41
BY ADDIE MELVIN
Beyond Time-of-Use: How Dynamic Pricing Optimizes EV
Charging for Grid Optimization
BY ANIRUDH KSHEMENDRANATH AND BRENDAN MCEWAN
Charging in Sync: Coordinating EV Infrastructure in
Multifamily Housing for Equitable Electrification
14
BY KESSIE AVSEIKOVA
Making Room for Resilience: Reflections from the Grid Edge
18
BY LEE ANN HEAD
Integrating Programs to Expand EV Charging Infrastructure,
While Enhancing Grid Planning, and Load Optimization
29
BY PAT PHELPS
Integrating Electric Transportation: A Framework for Electric
Vehicle (EV) Simulations, Operation, and Aggregation
34
BY PRANAV GUPTA AND GREG DONWORTH
Exploring Targeted Customer Programs with Digital Twins
for Grid Resiliency The What, Who, Where, When, and Why
45
BY SARAH COLVIN
From Obstacle to Opportunity: Rethinking Large Loads as
FlexibleResources in Grid Planning
48
BY SHRIRAM RAMANATHAN
Next-Gen Grid Planning: Leveraging GenAI to Simulate the
EV Future
56
BY VIKAS PAREKH
Building Resilience - The Future of Grid Reliability in a
Changing World
60
BY KENNETH A. COTTRELL, M.A.
Aligning IRP and ADR Strategies to Support Sustainable
Growth in Data Center Infrastructure
64
BY SAMEER KALRA
Leveraging ML/AI for disaggregation of DERs to enhance
operational decisions in power systems
A Letter From Our Board Chair
Knox W. Cameron, Director of Renewable Solutions, DTE
To the entire AESP community,
Welcome to the Q2 edition of Energy Intel. As the year unfolds, we continue to find ourselves
at the crossroads of rapid innovation and urgent transformation. The pace of change, driven
by electrification, grid pressures, and evolving customer expectations, is matched only by the
resilience and creativity of the professionals shaping our industry.
Now more than ever, our community is leaning into complexity, asking sharper questions, and
building smarter systems. Whether we’re preparing the grid for a surge in EVs, embedding
resilience into our infrastructure, or using AI to simulate the future, the work we’re doing is laying
the foundation for a more responsive, equitable energy ecosystem.
As we look across this quarter’s contributions, several themes stand out:
Grid Flexibility as a Planning Imperative
The influx of large, electrified loads, from EV fleets to AI-powered data centers, is straining
traditional interconnection models. Utilities are being challenged to move beyond binary planning
assumptions and instead embrace dynamic, conditional frameworks that prioritize flexibility and
speed.
Valuing Resilience as a Standalone Service
DERs like storage and microgrids play a vital role in strengthening local energy resilience, especially
during extreme weather events. Yet consistent frameworks to value and compensate resilience
remain elusive. Bridging this gap is essential for scaling equitable, future-ready energy solutions.
Digitalization of Demand-Side Programs
The rise of digital twins, AI, and granular customer data is redefining how DSM programs are
designed and deployed. These tools are enabling precision targeting, smarter load management,
and stronger cost-effectiveness across the board.
Smarter, More Equitable Electrification
Managed EV charging, dynamic pricing, and community-centered electrification strategies are
proving that grid benefits and customer savings can go hand-in-hand—if solutions are designed
with equity, automation, and scalability in mind.
Content Highlights
Grid Flexibility and Future-Ready Planning
As large, energy-intensive customers seek to electrify at speed, Sarah Colvin explores how utilities are
rethinking interconnection through flexible models that turn grid constraints into opportunities. Her
article encourages planners to move beyond binary assumptions and instead view big loads as assets
capable of supporting, not straining, the grid.
Resilience and Equity at the Grid Edge
In a thoughtful reflection on resilience, Megha Lakhchaura challenges us to reconsider how we define
and value it. She highlights how distributed energy resources (DERs) like solar and storage can provide
life-saving backup power, especially in underserved communities, if we build the right compensation
and planning frameworks to support them.
Digital Innovation in Demand-Side Management
Pranav Gupta and Greg Donworth take us inside the world of digital twins: virtual models that help
utilities plan, target, and optimize demand-side programs down to the household level. By answering
the “5 Ws” of grid modernization, their work demonstrates how simulation and segmentation can
make DSM efforts more efficient, equitable, and scalable.
EV Load Management through Dynamic Pricing
Addie Melvin’s piece on the ChargeWise Phase 1 pilot shows how dynamic pricing paired with
automation can shift EV load away from grid peaks with minimal behavior change from customers.
This results in lower bills, reduced emissions, and a glimpse into how real-time pricing can reshape
electric mobility.
As we move deeper into 2025, one thing is clear: the future of energy is not being built in silos. It’s
being shaped through cross-sector collaboration, shared data, and a collective commitment to do
better for customers, for communities, and for the climate.
Thank you for being part of that shared mission. We’re proud to feature your work, your insights, and
your leadership in this issue of Energy Intel.
Knox W. Cameron is currently director of DTE’s Renewable Solutions or-
ganization, where he has end-to-end responsibilities for MIGreenPower,
the largest utility Green Tariff program in the country. During his 14-plus-
year career at the company, he has served in a variety of roles, including
sales, marketing, and operations project management. Knox is an industry
leader with considerable experience designing, launching, and managing
utility programs. His professional affiliations include serving as the Chair-
man of AESP's Board of Directors, along with serving on the American
Wind Energy Association's DE&I Task Force. He has also chaired DTE’s
employee resource group for African American employees. Knox was
born and raised in Kingston, Jamaica. He currently resides in Ann Arbor,
Michigan, with his son, Drew. Knox has a passion for soccer, playing the
sport both on the collegiate level and professionally with the Columbus
Crew. He has an undergraduate degree from the University of Michigan
and is currently pursuing an MBA at the University of Michigan’s Ross
School of Business.
AESP Board Chair
Knox W. Cameron, Director of Renewable Solutions, DTE
Warm Regards,
Charging in Sync: Coordinating EV
Infrastructure in Multifamily Housing
for Equitable Electrification
by Anirudh Kshemendranath
and Brendan McEwan
As EV adoption grows, uncoordinated charging in multifamily housing risks higher costs, grid strain,
and inequitable access. This article makes the case for a coordinated EV Ready strategy, highlighting
how proactive planning, smart load management, and utility-aligned incentives can lower costs and
deliver greater long-term value for ratepayers.
Despite potential policy headwinds, electric vehicle (EV) adoption in North America will continue to
accelerate, driven particularly by declining battery prices and global market shifts. Yet the ability to
charge at home, the most convenient and affordable option, remains deeply unequal. In particular,
multifamily housing residents face a shortage of charging infrastructure and unclear rules around who
is responsible for installing chargers, and how those costs are shared.
About one-third of housing units in North America (US + Canada) are multifamily buildings; this share
reaches nearly half in many urban centres and is increasing as cities densify. Most multifamily buildings
in Canadian metro areas are condos, though a sizeable stock of rental apartments, co-ops, and other
building types also exist. But unlike single-family homeowners, multifamily housing residents often lack
a driveway, a garage, or control over their building’s electrical infrastructure.
Figure 1: Housing Starts by Market Type and Census Metropolitan Area,
1988-2023 (7% discount rate on future cashflows)
• Per-stall installation costs increase significantly, especially as early installations exhaust avail-
able electrical capacity.
• Building-wide electrical upgrades become unavoidable, but are often implemented too late,
resulting in higher costs.
• Stranded assets emerge when new installations are incompatible with older ones.
• Perhaps most critically, the grid absorbs unmanaged loads, increasing peak demand as local
transformers near their capacity limits.
The result? A mounting electrification gap. Without proactive planning, these buildings will become
bottlenecks in the clean transportation transition, creating grid strain, inequitable access, and rising
retrofit costs. Fortunately, the same complexity that makes multifamily buildings challenging makes
them uniquely valuable. With the right strategy, multifamily buildings can be transformed into hubs
of cost-effective, grid-friendly electrification.
Unplanned Charging Retrofits Drive Up Costs and Inequity
Today, most EV charger installations in multifamily housing are reactive and uncoordinated. A multi-
family building owner typically contacts an electrical contractor, who determines how to source power
for a few EV charger installations. Contractors rarely consider how to optimize subsequent installa-
tions without explicit direction. Over time, this approach leads to duplicated panel upgrades, repeated
trenching, and inconsistent technology choices.
The consequences compound:
Beyond infrastructure and cost, there's an equity dimension. Early adopters, often higher-income res-
idents, secure access while it’s still easy. Later adopters, including renters and lower-income owners,
face capacity limits, rising costs, or resistance from building residents. The result is a two-tier electrifi-
cation system: one for those who move early, and one for those left behind.
How Futureproofing Lowers Costs and Grid Strain
Instead of retrofitting one charger at a time, a coordinated “EV Ready” strategy installs the foundation-
al electrical infrastructure, conduits, panel capacity, and intelligent load management systems build-
ing-wide so that every space can be electrified over time without costly rewiring.
This future-proofing model is not only more equitable; it’s also more cost-effective. Studies show that
fully EV Ready retrofits can reduce per-stall infrastructure costs by up to 55% compared to piecemeal
installations. In addition to the lower costs for the building owner, this approach creates savings for
the grid. Central to this approach is the EV Energy Management System (EVEMS), which allows mul-
tiple chargers to share one circuit while managing real-time load. An EVEMS can enable four or more
vehicles to safely charge using the capacity needed for just one.
Figure 2: Net present cost of different futureproofing configurations per parking space
(7% discount rate on future cashflows)
• Accelerated EV adoption: More residents are likely to switch to EVs when at-home charging
is convenient and cost-effective. This can drive increased electricity sales, helping to spread
fixed system costs across more kilowatt-hours, ultimately reducing per-unit rates for all cus-
tomers.
• Lower peak impacts through smart design: Comprehensive EV Ready retrofits that use
EVEMS enable multiple vehicles to share a single circuit by allocating charging power dy-
namically across connected EVs. Instead of all vehicles charging at full power simultaneously,
EVEMS staggers or modulates charging, assigning different percentages of available capacity
to each vehicle based on need, timing, or grid signals. This avoids coincident peak loads and
flattens overall demand, reducing strain on local transformers and upstream grid infrastruc-
ture.
• Grid-aligned charging behavior: The EVEMS platforms that manage building-level loads can
also be configured to respond to utility demand response signals. This enables EV charging
to shift away from periods of peak wholesale costs or grid congestion, reducing the need for
costly upstream infrastructure upgrades and enhancing system reliability.
1. Uncoordinated Expansion: A status quo
approach where individual residents install
EV chargers independently or rely on public
charging infrastructure. While some home
charging is managed, a significant portion of
this load cannot be controlled to avoid system
peaks, exacerbating grid strain.
2. Comprehensive EV Ready Futureproofing:
Utilities or governments offer a $600 per-
stall incentive for 100% EV Ready retrofits. All
eligible multifamily buildings implement fu-
tureproofing upgrades. With EVEMS in place,
charging is load-shared at the building level and
responsive to utility demand signals, enabling
strategic load shifting and demand response.
Furthermore, comprehensive futureproofing strategies can generate meaningful ratepayer benefits,
positioning EV Ready infrastructure as a utility-aligned investment rather than a customer-side cost.
Specifically:
Step 1: Estimate Load Impacts: We projected the incremental annual energy consumption and coinci-
dent peak demand associated with each scenario. While energy use was similar, the peak load contri-
bution in the uncoordinated scenario was substantially higher due to uncontrolled, coincident evening
charging.
Step 2: Quantify System Costs and Revenues: We estimated the incremental grid costs — including
generation, transmission, and distribution — alongside additional utility revenues from increased elec-
tricity sales. These were benchmarked against Ontario system values, with customizable parameters.
Step 3: Assess Net Ratepayer Impact: We calculated the net utility benefit under each scenario by
comparing costs and benefits. While requiring an upfront incentive, the futureproofed pathway
showed a superior return, with lower per-kWh rates due to improved system utilization and peak
avoidance.
Our analysis followed three steps:
From Cost to Value: Applying a Rate Impact Framework to Multifamily Housing Electrification
As utilities and regulators find new ways to support the energy transition, understanding how EV
infrastructure investments impact rates and reliability is essential. To provide that insight, we applied a
Rate Impact Framework tailored to the Ontario context, quantifying the utility and ratepayer impacts
of proactive, EV Ready retrofits in multifamily buildings. At the core of this analysis is a practical ques-
tion:
What happens when we scale smart, managed charging, and what does that mean for utility costs and
rates?
We modeled two contrasting deployment pathways:
While both scenarios increase utility system costs over time, particularly for supply, transmission,
and distribution, those increases vary sharply. In the Uncoordinated Scenario, unmanaged evening
charging drives marginal costs to nearly 3.5% above baseline by the 2040s. In contrast, the Compre-
hensive EV Ready Scenario, supported by EVEMS-enabled load shifting and strategic planning, holds
those increases to around 2.5%.
A Comprehensive EV strategy Reduces
Marginal System Cost Pressures by ~30%
The model is intentionally high-level, designed to inform utility planners, policymakers, and program
designers. Its assumptions can be adapted to reflect regional utility costs or specific program designs,
and it serves as a foundational tool to assess whether ratepayer-funded multifamily housing incentives
are economically justified.
What the Numbers Tell Us: Coordinated Planning Pays Off
Our analysis confirms that comprehensive EV Ready retrofits deliver greater value to the grid and rate-
payers than uncoordinated, piecemeal installations.
Figure 3: Rate Impact Framework
Finding 1:
10
Coordinated EV Readiness Drives Stronger
Downward Pressure on Utility Rates
EV adoption results in downward pressure on rates over time, as incremental revenues from increased
electricity sales outweigh the associated costs. However, the magnitude of the benefit is consistently
higher under the Comprehensive EV Ready Scenario. This is because coordinated infrastructure plan-
ning and managed charging lead to lower peak demand growth, reducing the need for costly system
upgrades.
Generation Rate Impacts: Under the Comprehensive
Scenario, generation rates exhibit a more pronounced and
sustained decline over the study period. This is primarily
driven by reduced coincident peak demand, which lowers
the need for incremental generation capacity. For this anal-
ysis, we assume a uniform zonal price across Ontario and
that incremental EV charging is billed at the same genera-
tion rate as other loads. As a result, both the incremental
cost and the revenue benefit are distributed throughout
the province.
Transmission Rate Impacts: The transmission rate sees a
slight initial increase in the Comprehensive Scenario, as the
utility incentives for EV infrastructure are assumed to be
funded through transmission rates. However, this is offset
over time as managed charging reduces peak system loads
and limits the need for upstream transmission capacity in-
vestments. The result is a flatter and more favorable trans-
mission rate trajectory than the Uncoordinated Scenario.
Distribution Rate Impacts: Distribution rates decline under
both scenarios as the new EV load brings incremental rev-
enue. However, the Comprehensive Scenario consistently
shows lower rates over time. This is attributed to avoiding
localized distribution system upgrades that unmanaged,
resident-led charger installations would otherwise trigger.
Coordinated retrofits with EVEMS significantly reduce peak
contribution at the building level.
Finding 2:
11
Over the study period, both scenarios yield net benefits to ratepayers, as incremental electricity rev-
enues exceed the costs of serving EV loads. However, the Comprehensive EV Ready Scenario consis-
tently delivers significantly greater cumulative ratepayer benefits, reaching nearly $70 million by 2050,
compared to approximately $50 million under the Uncoordinated Scenario for the province of Ontario.
These enhanced benefits are driven by:
Long-Term Ratepayer Benefits Are Up to 40% Higher
Under a Coordinated Strategy
Finding 3:
• Higher overall EV adoption, enabled by access to convenient, reliable home charging
• Reduced peak demand, lowering the cost of grid capacity investments
• Greater flexibility, allowing utilities to fine-tune system operations through load manage-
ment
12
Why Utilities Should Invest in EV-Ready MURBs Now
The path to equitable transportation electrification runs through the parking garages of our multi-unit
buildings. As EV adoption accelerates, the stakes of how we equip multifamily buildings are rising.
When done reactively, the costs are high, the benefits are uneven, and the grid impacts are significant.
However, when done strategically, multifamily housing become one of the most effective — and equi-
table — platforms for electrification at scale.
The evidence is clear: coordinated EV Ready retrofits don’t just lower costs and improve access for
building owners and residents — they generate real, measurable benefits for the entire system. By re-
ducing peak demand, deferring costly upgrades, and aligning charging with grid needs, future-proofed
infrastructure can unlock up to 40% greater ratepayer value over the long term.
For policymakers and utilities, the implication is straightforward: supporting comprehensive, managed
EV deployment in multifamily housing is not only defensible but also prudent. Incentives for EV Ready
infrastructure, especially those that prioritize underserved buildings, can drive faster adoption, stabi-
lize rates, and prepare the grid for what’s next.
EV charging is just the beginning. The systems we establish today — from smart panels to shared
circuits — lay the groundwork for tomorrow’s fully electrified buildings, where vehicles, appliances, and
heating systems all operate in sync with a cleaner, more resilient grid.
About the Authors
Anirudh Kshemendranath is a seasoned energy consultant with over a decade of experi-
ence in energy storage, regulatory services, market entry strategy, and electricity wholesale
markets. He has a proven track record of leading complex projects and providing strategic
insights to accelerate the clean energy transition.
At Dunsky, Anirudh leads analytical and strategic consultations on energy storage, solar
adoption, distributed energy resources (DERs), utility planning, and rate design. He has
played a pivotal role in shaping regulatory frameworks, including serving as an expert
witness in high-profile cases such as the New Hampshire Value of Distributed Energy Re-
sources (VDER) study.
Anirudh Kshemendranath Senior Technical Consultant, Dunsky Energy
His work spans across North America, where he has conducted solar compensation assessments, due diligence for utility-scale
storage projects, and innovative rate design methodologies. Anirudh’s expertise extends to strategic planning, where he has led
studies on Canada’s hydrogen export potential, long-duration energy storage, and clean energy transition strategies. His work
has directly informed policy decisions, supported renewable energy legislation, and advanced the integration of emerging tech-
nologies in the energy sector.
Beyond his consulting work, Anirudh is an active industry leader. He serves on the AESP Ontario Chapter Board and is regular-
ly engaged with utilities and policymakers in the Ontario energy sector. He is a recognized speaker, having presented at AESP
SWITCH, Electricity Transformation Canada, and multiple industry events over several years. He has also conducted technical
workshops and training sessions at Energy Storage North America and frequently speaks on DER-related issues in panels and
industry discussions.
Before joining Dunsky, Anirudh worked at Strategen Consulting in Berkeley, California, where he helped policymakers develop
clean energy roadmaps and assisted energy developers in evaluating project financial viability. He holds a Master of Science in
Energy Science, Technology, and Policy from Carnegie Mellon University, Pittsburgh, and a Bachelor of Technology in Metallurgy
and Material Science from the National Institute of Technology, Nagpur, India
13
13
Brendan supports utility, government and private-sector clients in developing and
implementing strategies to decarbonize the transportation and building sectors.
Brendan has been central to some of North America’s most innovative climate policies
and programs. Notably, as a city staff person, he led development of the world’s first
100% “EV Ready” parking requirement, which is now widely recognized as the global
best practice to future-proof new construction for EV charging. He has since consult-
ed to multiple other jurisdictions to integrate such requirements in building codes and
by-law requirements, including Natural Resources Canada; BC Hydro; and the cities of
Toronto, Vancouver, Calgary, Edmonton, Halifax, and several others.
Brendan McEwan
Managing Consultant, Dunsky Energy
He collaborated with a coalition (comprised of the US Department of Energy, ChargePoint, Tesla, New Buildings Institute,
and others) that successfully proposed EV charging infrastructure requirements for the 2024 International Energy Conser-
vation Code.
He recently led the development of an “EV Knowledge Product” to help Canadian municipalities identify and promote
the optimal approach for enabling comprehensive EV-ready retrofits at scale across the country. He also convened and is
currently directing Dunsky’s Consortium for Power Efficiency, a first-of-its-kind national Consortium of utility, government,
and non-profit partners, that share the common goal of accelerating decarbonization by enabling cost-effective alterna-
tives to electric utility service upsizing.
Prior to joining Dunsky, Brendan directed an electric mobility and decarbonization practice at a prominent electrical
engineering firm. Before that, he served as Sustainability Manager at the City of Richmond, BC. He has also consulted on
energy policy in various other capacities, including as a sole proprietor; as Associate Director of the MIT Green Economic
Development Initiative; and at a leading urban planning consultancy. He holds a Master’s in City Planning from the Massa-
chusetts Institute of Technology.
14
Making Room for Resilience:
Reflections from the Grid Edge
by Kessie Avseikova
Making Room for Resilience: Reflections from the Grid Edge
Resilience has become an increasingly prominent theme in utility and regulatory discussions, spurred
by the rising frequency and severity of weather-related disruptions. Recently, I’ve been prompted to
explore this topic more deeply, given the industry’s heightened focus on resilience and the evolving
conversation around distributed energy resources (DERs).
While resilience is gaining visibility, especially in the context of grid modernization and climate ad-
aptation, its consideration in DER planning and valuation remains nascent. The terms resilience and
reliability are still often used interchangeably, and resilience is typically assessed using conventional
reliability metrics – like frequency and duration of outages. There is a critical lack of consistent defi-
nitions, valuation frameworks, and performance metrics. And although DERs – like solar, storage, and
microgrids – can clearly support resilience by supplying local power during grid disruptions, that value
is rarely quantified or compensated directly. As I have seen it, compensation for most DERs related to
resilience is indirect, categorized under associated values such as reliability or peak load reduction.
Some states and regions – such as New York, Illinois, and California – are increasingly incorporating
resilience into utility filings and policy frameworks, often as a response to recent high-impact weath-
er events. In other areas, resilience may be recognized but lacks the necessary support, such as clear
regulatory structures or investment mechanisms. As a planning priority, it remains unevenly developed
across the country.
15
Start with Definition
Defining resilience distinctly from reliability is a necessary first step – and several efforts, including
those led by National Renewable Energy Laboratory (NREL), New York State Energy Research and De-
velopment Authority (NYSERDA), and the Department of Energy (DOE) have started to do so. While
reliability focuses on maintaining consistent service during routine conditions and short-term disrup-
tions, resilience is landing closer to the concepts of withstanding, adapting to, and recovering from
high-impact, low-probability events – like wildfires, hurricanes, or human-induced activities (cyberat-
tacks). The distinction often hinges on factors such as duration (longer outages lasting days or weeks),
spatial extent (disruptions across broader geographic areas), event severity (extreme or compounding
events), and economic impact (wider societal losses beyond lost load). Notably, the applicability of
this definition may vary across jurisdictions and may need to be reasonably adapted to specific juris-
dictional context. A clear definition of resilience though will inevitably lead to the development of the
new metrics reflective of DER capabilities, new planning frameworks, and better direction for valua-
tion and monetization research.
DERs at the grid edge offer a range of resilience-enhancing capabilities, but their contributions are
highly context-dependent and still being systematically defined. Several efforts have emerged to clas-
sify DERs based on their specific resilience attributes – such as islanding capability, black-start func-
tionality, dispatchability, and backup duration. For example, the NARUC’s Valuing Resilience for Micro-
grids2 and Advancing Electric System Resilience with Distributed Energy Resources: A Review of State
Policies3 work have mapped how different technologies perform under stress conditions. However,
this field is still evolving, and one complicating factor is that resilience is often delivered not by a single
DER, but by a coordinated suite of technologies, such as solar paired with storage and smart inverters,
working in tandem. This system-level interplay means that assessing resilience value requires looking
beyond individual assets to consider how combinations of DERs can maintain critical services during
prolonged outages or grid failures.
Identify and Quantify Value Streams
As the industry begins to define resilience more clearly and identify the technical capabilities of DERs
that support it, the next major hurdle is valuation. Unlike traditional reliability investments, which have
established methodologies for assessing avoided outages or deferred infrastructure, valuing DERs for
their resilience benefits remains complex and often context-specific. Resilience benefits are hard to
quantify with conventional cost-effectiveness tests. Moreover, these benefits often materialize under
rare but high-impact scenarios, making them difficult to forecast or model probabilistically. Adding to
the complexity is the above-mentioned fact that the greater resilience value is likely delivered through
a stack of coordinated assets – like solar, storage, and automated controls – working in tandem. This
interdependence challenges traditional asset-level valuation approaches and calls for more holistic
system-level assessments. While emerging methods – such as those piloted by the DOE, NARUC,
and NYSERDA – are beginning to account for avoided societal costs, critical load protection, and risk
reduction, consistent application and regulatory adoption remain limited. To advance this work, valu-
ation frameworks must evolve to explicitly recognize resilience as a standalone value stream, capture
synergies across DER portfolios, and provide utilities and regulators with the tools to assess when,
where, and how resilience investments deliver the greatest impact. In addition to evolving valuation
frameworks, innovative data collection and analytical methodologies are needed to more accurately
capture DER resilience value.
THE ABILITY TO ANTICIPATE, PREPARE FOR, AND ADAPT TO
CHANGING CONDITIONS AND WITHSTAND, RESPOND TO,
AND RECOVER RAPIDLY FROM DISRUPTIONS.
– NREL AND NYSERDA DEFINITION OF RESILIENCE1
Resilience:
16
Develop compensation structures and mechanisms
As valuation frameworks for DER resilience mature, a parallel effort is needed to establish mechanisms
for monetization – that is, turning theoretical value into real, recurring compensation for the resilience
services DERs provide. Today, most DERs that support resilience do so without direct financial rec-
ognition; instead, resilience value, while generally recognized, is either bundled into broader program
goals (like demand response or peak load reduction) or delivered through one-time grants and incen-
tives. However, a few early examples are beginning to chart a path forward including NYSERDA’s Re-
silient Energy Systems4, Tennessee Value Authority’s ARCHER Project5, as well as in the private sector
through “resilience-as-a-service” models, where third-party providers install and operate DER systems
– often microgrids – for commercial or institutional customers in exchange for fixed payments or
service contracts. Still, these examples remain the exception, not the norm. Widespread monetization
will require clear tariff structures, performance criteria, and cost-allocation methodologies that enable
resilience to function as a standalone value stream – distinct from, but complementary to, traditional
grid services. Without such mechanisms, DER resilience will remain undercompensated, limiting in-
vestment and deployment in the communities that may need it most.
Set planning priorities and supportive recovery structures
Recognizing and compensating DERs for resilience benefits delivered to a targeted subset of facilities
– such as critical infrastructure or vulnerable communities – remains a significant regulatory challenge.
While these assets can provide life-saving services during grid outages, the costs are often borne by
all ratepayers, prompting questions of fairness, equity, and value. In some cases, resilience investments
are justified through their public-good nature, contribution to community-wide benefits, or alignment
with climate and equity goals. However, these cases remain the exception rather than the rule. To
make this approach more widespread, regulators and utilities need clear, standardized frameworks for
valuing resilience – including benefit-cost methodologies that account for avoided disruptions, societal
losses, and indirect community benefits. It also requires stronger policy guidance, public communica-
tion, and thoughtful integration of resilience into utility planning processes – so that resilience is no
longer seen as a niche or exceptional case, but as a core, shared objective of modern grid investment.
“We find a correlation between high levels of vulnerability and low
levels of resilience, suggesting that indeed there is a trend where the
most vulnerable counties are also the least resilient.”6
“
At the same time, it is essential to ensure that resilience investments actually reach the communities
who need them most. At the distribution level, where infrastructure is particularly vulnerable to haz-
ards such as wind, flooding, and wildfires, challenges to resilience are especially severe – and these
vulnerabilities tend to disproportionately impact underserved communities. These same communities
often face socioeconomic and structural barriers that slow or prevent recovery, resulting in longer out-
ages, deeper losses, and greater long-term harm. Studies have consistently shown a strong correlation
between social vulnerability and reduced resilience levels, underscoring the need for more targeted,
inclusive strategies. By directing DER-driven resilience efforts – such as community solar+storage,
microgrids, and critical load support – to these high-need areas, resilience planning can deliver not
only technical value but also social equity. In this context, cost socialization may be not only justified
but necessary to ensure fair access to resilience as a public good – helping close resilience gaps while
maximizing societal benefit.
17
Final Thoughts
Resilience is no longer a fringe consideration – it is rapidly becoming a defining test of our energy sys-
tems' fitness for the future. As climate risks intensify and grid-edge technologies mature, we face both
a technical imperative and a moral opportunity: to intentionally integrate resilience into DER planning,
valuation, and compensation in ways that prioritize the people and places most at risk. This means
moving beyond narrow metrics and siloed programs toward comprehensive, equity-centered frame-
works that treat resilience as a shared, system-level objective. Making room for resilience will require
more than modeling and tariffs – it will require rethinking how we define value, who we design for, and
what success looks like in an era of compounding disruptions. It’s a challenge – but also a chance to
align our tools, investments, and intentions with the realities of a rapidly changing grid and a warming
world.
17
About the Author
Kessie Avseikova
Kessie Avseikova specializes in research and advisory services related to grid-edge
innovation and load flexibility. With over 15 years of experience in the energy sector,
she brings a strong foundation in evaluation management, statistical analysis, and
program design—particularly for demand response, rates-based programs, and be-
havioral strategies across a variety of distributed energy resources (DERs) and flexible
load solutions. Kessie currently supports a range of utilities in advancing their flexible
load strategies. Kessie is a respected thought leader in the flexible load space, serv-
ing as an evaluation instructor for Demand Response Evolution Training at Peak Load
Management Alliance (PLMA). She has also written and presented extensively on
flexible load and demand response for multiple industry conferences, engagements,
and publications.
Vice President, Opinion Dynamics
Sources:
https://www.cpuc.ca.gov/-/media/cpuc-website/divisions/energy-division/documents/self-generation-incentive-pro-
gram/2023-sgip-handbook-v3.pdf
https://icc.illinois.gov/downloads/public/edocket/585486.PDF
https://www.hawaiianelectric.com/documents/products_and_services/customer_renewable_programs/battery_bonus.
https://www.nyserda.ny.gov/All-Programs/NY-Sun/Con-
tractors/Value-of-Distributed-Energy-Resources
1 Understanding Resilience Valuation for Energy Systems.
An Overview of the NYSERDA-NREL Research Collabora-
tion https://docs.nrel.gov/docs/fy23osti/86923.pdf?utm_
source
2 National Association of Regulatory Utility Commissioners
(NARUC). Valuing Resilience for Microgrids: Challenges, In-
novative Approaches, and State Needs. https://www.naseo.
org/data/sites/1/documents/publications/NARUC_Resil-
ience_for_Microgrids_INTERACTIVE_021122.pdf
3. National Association of Regulatory Utility Commission-
ers (NARUC). Advancing Electric System Resilience with
Distributed Energy Resources: A Review of State Policies.
https://docs.nrel.gov/docs/fy24osti/90137.pdf
4 https://www.nyserda.ny.gov/Impact-Resilient-Ener-
gy-Systems
5 https://www.tva.com/energy/technology-innovation/
connected-communities/connected-communities-pilots/
clone-the-archer-project--resiliency-planning-framework
6 Cutter, S.L., Burton, C.G., & Emrich, C.T. (2010). Disaster
Resilience Indicators for Benchmarking Baseline Conditions.
Journal of Homeland Security and Emergency Management,
7(1)
18
Integrating Programs to Expand EV
Charging Infrastructure, While Enhancing
Grid Planning, and Load Optimization
by Lee Ann Head
As electric vehicles (EVs) proliferate across the United States, utilities are facing a pivotal moment in
grid planning. The rapid deployment of EV charging infrastructure, particularly for commercial and
public applications, has introduced new challenges—and new opportunities—for utilities seeking to
manage load growth and ensure grid reliability.
At Franklin Energy, we’re fortunate to support utilities on the frontlines of this transformation. From
years of implementing and refining transportation electrification programs, we’ve learned that the
most effective EV strategies don’t treat grid management as an afterthought. Instead, they weave it
into every layer of program design—from incentive structures and siting to contractor engagement and
customer education.
In this article, we’ll share lessons from our work supporting New York State Electric & Gas (NYSEG)
and Rochester Gas and Electric (RG&E), which have launched one of the country’s most integrated
approaches to grid-friendly EV infrastructure development. Their innovative trio of programs, the EV
Make-Ready (EVMR) program, the Demand Charge Rebate (DCR), and the Load Management Tech-
nology Incentive Program (LMTIP)—developed by the Joint Utilities of New York in collaboration with
the New York Public Service Commission, offer a blueprint for other utilities looking to strengthen grid
outcomes while accelerating EV adoption.
Building Charging Infrastructure, With the Right Incentives
The EVMR program dramatically reduces the upfront costs of installing EV charging infrastructure. By
covering both utility-side and customer-side upgrades, the program removes major financial hurdles
that can stall projects—especially in Disadvantaged Communities (DACs), which receive increased lev-
els of funding.
Upfront cost, however, is just one piece of the expense equation for customers considering an EV
charging investment. Demand charges can dramatically increase ongoing operational costs. The DCR
Program provides eligible commercial EV charging customers with a 50% rebate on their billed de-
mand charges.
Encouraging Technology Adoption to Optimize Load
The NY PSC and Joint Utilities recognized that simply increasing the number of chargers wasn’t
enough. Without access to data and load management, widespread deployment could result in unpre-
dictable demand spikes and localized grid stress. That’s where LMTIP comes in.
Launched in 2024, LMTIP provides targeted incentives for technologies that actively manage EV
charging loads. This includes onsite energy storage, energy storage integrated into EVSE, load man-
agement software, and load management hardware. Importantly, it does not prescribe utility-direct-
ed control. Instead, it empowers customers and developers to select technologies that fit their use
cases—provided they share all data, meet clear technical standards, and deliver measurable demand
impacts. Customers are empowered to optimize their own load, and the program gets access to valu-
able data to support grid planning, evaluate technologies and approaches, and create best practices
and recommendations for new charging program prospects.
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From Coordination to Cohesion: A Programmatic Approach
Individually, EVMR, DCR, and LMTIP provide valuable incentives. But their real power lies in how
they’re combined—and how they’re marketed. NYSEG and RG&E intentionally co-market their EV
programs, creating a cohesive narrative that guides customers and contractors through a grid-smart
project journey.
This includes:
By taking this holistic approach, the utilities ensure that infrastructure deployment and grid optimiza-
tion go hand-in-hand.
Lessons from the Field: Data-Driven Insights
Over four years of program implementation, Franklin Energy has gathered extensive data and stake-
holder feedback. Here are some key insights:
• Encouraging LMTIP applications alongside EVMR projects, particularly in grid-constrained
areas.
• Training and certifying trade allies to understand and promote the benefits of load manage-
ment.
• Structuring program eligibility to reward integrated design choices, such as combining ener-
gy storage with demand-flexible software.
• Timing Matters: Most projects take more than a year from application to completion. This
lag creates challenges in forecasting grid impacts—but also opportunities to engage early and
influence technology choices.
• Segment-Specific Trends: Hospitality, retail, multifamily housing, and office buildings are lead-
ing adopters. Each has distinct usage patterns that affect grid planning. For instance, hotel
charging is often overnight and flexible, while retail tends to demand fast charging during
peak hours.
• Contractor Consolidation: A small number of developers install the majority of EVSE equip-
ment, creating a powerful channel for education and influence. Engaging these contractors
early—and equipping them with the right tools—is critical to scaling smart load management.
• Data Sharing Is Feasible: Stakeholders are willing to share charger usage data, provided it’s
anonymized and not burdensome. However, utilities must be prepared to manage a wide
range of data formats and intervals.
20
Grid Benefits Without Tradeoffs
One of the most promising aspects of the LMTIP approach is that it doesn’t require sacrificing custom-
er experience to achieve grid benefits. For example:
These technologies are particularly valuable for public and fleet charging scenarios, where demand
spikes can be extreme but somewhat predictable.
Planning for Equity and Scale
Both EVMR and LMTIP emphasize equity—not just in theory, but in implementation. By allocating a
substantial portion of funding to DACs and offering higher incentives for qualifying projects, the pro-
grams have helped to ensure that all communities benefit from clean transportation.
In practice, this means supporting installations in areas with historically limited access to infrastructure,
engaging local contractors, and providing educational materials tailored to diverse stakeholders. It also
means working closely with site hosts—who may be unfamiliar with utility processes—to set expecta-
tions, navigate timelines, and overcome common barriers.
Recommendations for Other Utilities
Based on our experience, here are a few recommendations for utilities exploring similar approaches:
1. Design with Integration in Mind: Align infrastructure and load management programs from
the start. Consider how customers will navigate them and remove friction wherever possible.
2. Use Contractors as Multipliers: Equip trade allies with clear, plainspoken resources. Consider
small incentives for promoting co-enrollment or educating customers.
3. Embrace Flexibility: Not every customer wants (or needs) the same solution. Design incentive
tiers that allow for modular adoption of technologies.
4. Invest in Awareness: Develop case studies, testimonials, and FAQs that demystify the pro-
cess. Highlight real-world examples and success stories from local communities.
5. Plan for the Long Haul: Charging stations are long-term infrastructure. Ensure that your pro-
grams account for lifecycle costs, operational support, and evolving grid needs.
A Model for the Future
The transition to electric transportation is not just about replacing engines—it’s about rethinking how
we manage energy. At Franklin Energy, we believe that utilities play a central role in this shift, not just
as service providers but as trusted partners and planners. By integrating grid considerations into every
stage of EV program design, we can build systems that are resilient, equitable, and ready for what’s
next. Because the grid of the future isn’t just smarter. It’s shared, it’s flexible, and it’s built together.
The Joint Utilities of NY model demonstrates what’s possible when vision, coordination, and execution
come together.
• Load management software can modulate charging without noticeably impacting driver con-
venience.
• Energy storage allows for fast charging while buffering peak grid demand.
• Power-sharing hardware can optimize usage across multiple ports, enhancing uptime while
reducing costs.