The Arthur L. Irving Institute for Energy & Society

To negotiate paths for incorporating Distributed Energy Resources (DERs) into the grid, innovators need to understand the utility perspective. Utilities and the DER industry “need to talk to each other more. There's a whole lot of collaboration we can have together, but I think empathy building is really valuable for our collective industries.” That’s what Ryan Long, Executive Vice President of Xcel Energy, shared at the October 2025 DERVOS conference. And common language for DERs may facilitate such collaboration. [1]

Taking the Utility Perspective

Ed Schmidt, Director at MCR Performance Solutions, a consultancy that serves utilities, echoes Ryan Long’s sentiment. “If we’re going to find common ground and chart a path forward, all parties to incorporation of DERs into the grid need to get out of our silos and understand other perspectives.”  This piece articulates key aspects of the utility perspective for the benefit of those in the DER industry, including regulatory constraints, the reliability imperative, and challenges that utilities face when DERs are put on their grid.

Many system thinkers, including DER enthusiasts, wonder how they can help utilities respond to load growth, but it is easy for them to overlook key constraints and risks utilities face. Schmidt describes the situation. “How are we going to help utilities thread the needle to survive what they face: meeting load growth given the variable availability of renewables and the constraint of federal and state regulatory frameworks? Many parties – including DER companies and some data center organizations – are complaining that utilities resist their proposals. But most proposals don’t recognize two key concepts – the risks utilities face and that Investor Owned Utilities (IOUs) need to make a buck.”

Let’s address the risks first. Schmidt describes the risks. “In each potential  scenario, the utility faces risks, including the possibility of financial penalties. For example, utilizing a DER could help, but one big outage due to DER reliability or availability problems could be disastrous for a utility. Or, if connecting a data center requires infrastructure investment that increases customer rates, the utility will get hammered. Other parties need to be part of the solution, but in our regulatory environment the risks are not always shared evenly. The utilities will be harmed – financially and in terms of goodwill – by the inevitable failures and missteps that will occur as all parties address these unprecedented changes in the energy and utility landscape.” Utilities are resisting the asymmetric reliability risk of DERs and that risk is real – history has shown DER performance is uncertain. When control rooms at utilities and market operators can treat DERs like their other power plants – that is, see what DERs are doing, dispatch them, and accredit them – such control and visibility will reduce DERs’ reliability risk.

The business perspective is also key. Third-party DERs actually reduce utility earnings by displacing opportunities for owned resources. Plus, DERs add costs for utilities. With DERs sprouting across the grid, utilities need new workstreams and teams to manage interconnection requests, programs, and the complexities of a distribution grid with randomly located (unplanned) DERs with two-way flows. In short, it costs utilities money to integrate DERs for a negative return.

Business Model: Regulated Monopoly vs. Free Market

Electric utilities are public purpose regulated monopolies in every U.S. state, allowed to invest private capital in civic infrastructure with the requirement to balance their obligations: the ‘duty to serve’ customers reliably while minimizing costs.  Pier LaFarge, CEO of Sparkfund, emphasized the grid’s purpose in a Volts podcast. “The grid is civic infrastructure intended to provide reliable, low cost energy for everyone, whether or not they have the time or money to think about it. That energy is a foundation for our economy and human flourishing. The grid was not built for individual value to come off of it.”

LaFarge described the regulatory compact. “The utility regulatory compact was designed to pull off a magic trick, which is take Wall Street’s money, private money, and give them a 3.5% net dividend every year. So, for every 100 bucks they put in, they make three or four bucks. Let a private operator who has some profit incentive build the grid and then submit to a civically accountable regulator to control every one of its decisions, actions, and profits. It’s Wall Street’s money building public infrastructure. The result is that in a lot of states, the infrastructure that lets us have as much power as we want, anywhere we want it, all the time, is 3 or 4% of the state’s total economy. Does this system have flaws and imbalanced incentives? Yes. Can you name me a landscape-scale, public regulated compact and institution that doesn’t?”  

Because utilities cannot engage in market-based investment and pricing for their product, they operate under different rules than the companies and organizations interacting with them regarding DERs. Utility regulation centers on several fundamental principles, which we summarize here from a recent article in Energy Law Journal. [2]

• Duty-to-serve - Within the service area where a utility has a monopoly, it must provide safe and adequate service to all interested parties. Because the statutes don’t define “adequate”, public utilities commissions and the courts have interpreted the term to encompass three facets:
  • Reliability: Act in a reasonable manner under the circumstances to minimize outages and notify customers when outages occur (Reliability needs are different for residences and critical services – like hospitals and fire stations.)
  • Quality: Provide the customer’s maximum allowable load within (often) specified ranges of power quality (e.g., voltage and frequency)
  • Timeliness: Provide electricity to new customers in a reasonably timely manner.
• Just and reasonable rates – Public utilities commissions have authority over the rates utilities charge to ensure that they are just and reasonable. One key component of rates is recovery of capital and operating costs. With respect to capital, utilities may charge their customers to recover the cost of an investment only if the investment is:
  • Used-and-Useful: The investment actually serves customers (used) and provides benefit to the customers by either lowering costs or increasing service quality (useful). (This is a present-oriented analysis.)
  • Prudent: The investment decision was reasonable given the information available at the time the decision was made (This is a backwards-looking analysis). 
• Tension among the principles – On one hand, a utility could spend more to substantially improve reliability, but if that requires enormous increases in customers’ rates, that investment would likely be ruled imprudent. On the other hand, a utility could lower customers’ rates by delaying replacement of aging assets on the grid, but if that results in degraded reliability, that decision would violate the utility’s duty to serve.

Implications for DER advocates 

DER innovators are risk-tolerant with large up-side potential. But because utilities are regulated monopolies, they are risk-averse with small up-side potential and large down-side risk: regulators are reluctant to permit price increases and penalize utilities for unreliable – or otherwise inadequate – service. “Utilities are generally risk-averse,” said Yoh Kawanami, Director at Hawaiian Electric Company. “Utilities don’t want to risk a new technology that may jeopardize safety or reliability.”

DER providers focus on providing different value than utilities do. Utilities are typically focused on system-wide value for the entire customer base whereas DER providers primarily focus on the actual customer they’re contracting plus a secondary focus on the broader system. For example, when a Virtual Power Plant (VPP) operator signs a contract with a big box retailer their primary focus is to save that retailer money. That might be good or bad for the broader customer base.

DERs present one of three current challenges to utilities’ ‘regulatory compact’. A recent Heat Map article explains the compact -- utilities provide low cost, reliable service in exchange for cost recovery and a defined potential return on investments (i.e., profit). The article explains current stresses on the compact: the public is angry about rising prices, yet utilities need to make big investments not included in the original compact [3], that is, not included in the rate base (i.e., set of investments) current rates are based upon. Currently, utilities need to increase electricity supply for electrified home heating or electric vehicles (EVs). That requires adding capacity to meet customer demand, which is at the core of the utility compact. The end-use of the electricity is different, but the work to be done is similar to the buildout of air conditioning across the country in the 1960s-1970s. But three things seem new and may be outside of the original compact. First is building a grid capable of two-way electricity flows to accommodate DERs. Next are data centers because the scale is fundamentally different. Third is wildfire liability and wildfire mitigation investments.

Implications of the Reliability Requirement

To keep the lights on, utilities’ control rooms need to precisely balance supply with demand at every instant under highly dynamic conditions – all without substantial storage. This balancing is less challenging when a utility can dispatch lots of fast-ramping capacity they can count on, exactly where they need it. Four aspects of the balancing act are grid reliability, dynamic conditions, control of resources, and limited inventory.

Grid reliability

Reliability is maintaining an adequate, secure, and stable flow of electricity as consumers may need it, so when they flip the switch, the lights turn on. This requires two key elements:

• Reliable operation – the ability to withstand sudden electric system disturbances at the generation, transmission, or distribution level that can lead to blackouts.
• Resource adequacy – the ability of the electric system to meet the energy needs of electricity consumers by having sufficient supply (generation) to meet projected demand.[4]

The U.S. grid is 99.95% reliable, with the average customer losing power less than two times per year for a total of less than five hours. Most outages are due to issues on the distribution system that brings power to individual customers, not in the generation or transmission systems that bring bulk power to large areas. [5]

Dynamic conditions

Reliability under dynamic conditions is a critical priority for electric utilities. Specifically, they need to keep electric service perfectly balanced almost all the time despite highly dynamic conditions, including load uncertainty (fluctuating demand), weather variability and lightning strikes, scheduled maintenance on aging infrastructure, grid damage from vehicles that collide with poles, shorts across lines from animals and falling trees, extreme weather (such as flood, ice storm, or wildfire), and cyber and other human-caused attacks. Plus, solar and wind generation adds more dynamics with shifting clouds and intermittent wind. Here are two illustrative examples.

• Demand constantly fluctuates. Supply needs to meet demand every instant, even when things are starting and stopping. For example, the biggest load in a home is Heating, Ventilation, and Air Conditioning (HVAC). “In a typical home without an electric vehicle, HVAC uses more energy than all other appliances combined” according to Kendrick Li, Director of Clean Energy Programs at Pacific Gas and Electric Company. HVAC load is dynamic with hourly changes in the weather.
• With renewables, supply fluctuates, too. Li says, “Intermittent electricity sources (like solar and wind) create fluctuation in supply, which would benefit from load flexibility that does not inconvenience the customer or is invisible to the customer’s experience.”

Control of resources

Every load or resource that the utility does not control adds to the challenge of precisely balancing supply and demand 24/7.

Historically, utilities generated electricity using large, centralized, dispatchable, plants to unidirectionally feed the transmission grid to balance dynamic load on the distribution grid. Generally, this continues to be the case in traditional, vertically integrated jurisdictions such as much of the Southeast. However, in “restructured” jurisdictions such as those where utilities are no longer allowed to own generation, an Integrated System Operator (ISO) such as ISO-New England or PJM creates a wholesale market into which non-utility, unregulated entities (“merchant generators”) bid generation capacity into an auction for capacity sufficient to meet the ISO’s forecasted load and then manages dispatch of the power plants and bulk transmission system. In these restructured jurisdictions, the local distribution utility and its control room manage only local distribution of electricity received from the bulk power (inbound) side of a substation.

With DERs located across the distribution grid, the game has changed, which introduces new dynamics to manage--bidirectional flow and control at the grid edge:

• Bidirectional flow: Grid control was designed for unidirectional flow. Now, the utility must manage the upstream (reverse) flow of any surplus DER generation on the distribution system even when it is “behind the meter” and not controlled by the utility.
• Control at the grid edge
  • Demand reduction: When load-shedding DERs are under utility control, the utility has a “lever” for reducing demand.
  • Supply on distribution grid: When batteries are under utility control, whether in front of the utility meter or behind the meter, the utility can dispatch supply on the distribution grid.

Limited inventory

The traditional electric grid has no way to hold inventory. Batteries can change the game for utilities by adding “inventory” capacity as a “lever” for precisely balancing supply and demand on the electric grid.

Li believes that VPPs will be split into two categories: load shedding devices and batteries. “Batteries are a special category because they create inventory – that is, stored electricity – in an industry that has traditionally never been able to hold inventory.”

In this era of load growth, LaFarge sees batteries as DERs that help utilize the grid better, no matter where they are placed, who puts them there, or who pays for them. His reasoning is that batteries allow us to store up electricity inventory during periods of low demand (off-peak) and then, during periods of high demand (peak), use more power than could otherwise be delivered by the grid we already have. Overall, utilities may theoretically, be able to sell more power without expanding the wires and other infrastructure, which, in theory, could lower prices for everyone. LaFarge sees batteries as the next innovation in distribution infrastructure, no different than substations, transformers, or capacitor banks.

LaFarge uses air conditioners with embedded batteries as an example. “If you have a residential neighborhood of houses that have air conditioners with batteries in them, as they all spin up, each house could cool down using power from a battery that charged while there was plenty – when no one was using their electric appliances in that neighborhood. When all the AC turns on at once, they all draw down their batteries without a spike in demand on the grid. Put the battery inside the air conditioner and it can directly alleviate the peak stress that the air conditioner puts on the grid. This air conditioner example illustrates the general concept – the value of batteries at every scale and every size is how close you can put them to the infrastructure that needs it most.”

New Grid Challenges Introduced by DERs

Virtual Power Plants don’t behave like peaker plants (yet): Because a VPP – an aggregation of thousands of small DERs – behaves differently than large, centralized capacity feeding the transmission grid, a new model was developed for evaluating VPP capabilities with respect to utilities’ needs. In this section, we briefly summarize that model as described in a 2026 report by EnergyHub. [6]

As VPPs mature, they are moving beyond peak reduction to deliver flexible dispatch, distribution-aware control, and higher-value grid operations. The VPP Maturity Model offers grid planners and control room operators criteria for assessing whether a VPP is operationally indistinguishable from a conventional peaker plant for planning, dispatch, and crediting purposes. [6]

• Can the VPP match a peaker plant? Specifically, is its capacity dependable – that is, available, shapable, reliable, precise, responsive, and integrated? Is it available for the utility to dispatch for 6+ hours during most portions of the year? Can its capacity follow a grid signal and be shaped to support a variety of dispatch profiles that go beyond simple start/stop events, such as a flat reduction period and then gradual recovery that avoids snapback surges? When dispatched, can it reliably deliver a target load shape and respond in seconds? Does the resource integrate with the control room’s platforms and provide accurate, verifiable data at short intervals (at most every five minutes)? [6]
• Can the VPP exceed a peaker plant? Specifically, 
  • Will it automatically do the right thing without a human intervening? Can it self-dispatch in real time, optimally selecting among grid services based on i) system conditions to support the grid and ii) market prices in day-ahead and real-time markets? Can it operate within the DER owner’s parameters, such as time-of-use rate periods, EV charging schedule, battery reserve settings, or temperature comfort bands? [6]
  • Does it deliver value where the grid needs it? Can the VPP dispatch geographically co-located groups of DERs to address localized grid constraints on feeders and substations in real time, rather than deliver “a lot of kilowatts somewhere”? [6]

Implications for DER advocates

DER innovators are motivated by the promise of benefits to the grid system, but can easily overlook the exacting challenge of keeping the lights on 24/7 at a reasonable price by precisely balancing supply with demand at every instant under highly dynamic conditions. So far, on the whole, DERs have not dependably delivered what is promised to utilities. Instead, they have added uncertainty to managing the grid.  According to Bryant Komo, Customer Energy Resources Director at Hawaiian Electric Company, “In Virtual Power Plants of home batteries, we know how many batteries are signed up, but it’s uncertain what we’ll get. Say, if 100 MW are signed up, the utility may get only 60 to 80 MW when dispatched because the batteries are not fully charged or customers have opted out of the event. If we can’t count on DER capacity, it’s not very useful to us. It’s something nice to have but cannot be considered comparable to traditional power plants.”

DER owner satisfaction matters. If customer-owned DERs are used by the grid, their owners want simplicity: no inconvenience and seamless payment. They will not be inconvenienced so long as their parameters are met. For example, dispatch of customers’ equipment must be at a time that makes sense with their time-of-use rates  and doesn’t disrupt their EV charging schedule.. Likewise, temperature comfort bands are an important consideration for thermostat programs. Program design and customer education are critical. Kawanami says that “managers of DER programs need to understand the technical side and monitor whether the DER program is doing what it should. But they also need to explain the program to the customer and work with customers who may be angry about the inconvenience of sharing their DER or not getting their check.”  According to Li, utilities need “automatic machine-to-machine dispatch where VPP operation is invisible to the customer, so they are not inconvenienced, they just save money on their bill.” At PG&E, “rates of customers opting-out of dispatch events are lower for automated, smart thermostats because the customer doesn’t have to do anything. Still, customer opt-outs are higher on multi-day events, so we’ve learned the art of not dispatching too many days in a row or knowing if customers need a break on weekends in a week-long heat wave.”

DER location matters: DER enthusiasts often make naive proposals based on the misconception that kilowatts provided anywhere can get wherever they are needed. This is akin to presuming that the grid is like a huge lake where water added anywhere can be used anywhere along the shore. This misconception is called the “copper plate model” representation of the grid, which assumes that everything is connected without regard for the physical network of wires confining the flow of electricity and the devices that act as gates in that flow. In reality, a DER’s ability to support the grid depends on its location. In addition, bidirectional power flow often requires system upgrades, and distance matters: costs increase the farther you move electricity.

At the October 2025 DERVOS conference, Ryan Long described the location-inspired motivation for his utility’s Capacity*Connect program, which includes utility-deployed, aggregated, and controlled batteries in front of the meter on Xcel Energy’s distribution grid.

Long explained, “As a utility that understands our grid and has deep planning expertise, we thought we could deploy batteries strategically by targeting circuits and feeders to solve problems in specific locations as opposed to having to deal with the challenges caused by resources showing up randomly on our distribution grid. We think that VPPs that leverage customer equipment behind the meter – like thermostats – absolutely have a place on the grid. We just saw this as an opportunity for us.”

Security and Privacy Matter: Long admitted that utilities’ reluctance to make information public “is frustrating to a lot of people, but it comes from a place of responsibility. There are always going to be limits related to security and cybersecurity. But we need to find where the right line is to make choices around security that allow enough transparency to make our grid accessible to third parties in ways that bring value to our customers. It's not just us looking at more granular hosting maps. It's leveraging our scale and our understanding around integrated system planning and our communities and where they're headed as well.” Beyond data security, confidentiality laws related to personally identifiable information (PII) of customers are also a constraint.

Size matters: Part of a VPPs ability to match the capability of a peaker plant is meaningful scale or size. Utilities talk about size of aggregated DERs in terms of the size of equivalent conventional power plants. And it takes a lot of DERs to match the scale of a conventional plant. For example, when Kendrick Li spoke of California’s test dispatch of 100,000 customer-owned batteries in July 2025, he noted size. “At 535 MW, that’s comparable to the third biggest hydropower plant in California or about half of a large nuclear reactor.”

Accurate measurement matters: VPP success depends on measuring not simply what a DER delivered but what benefit it provided beyond what it was doing when dispatched. Without this distinction, utilities are concerned that they’ll pay for more benefit than they actually receive. Kawanami said, “We’d love to pay for performance above what the batteries would normally do anyway, like if a battery VPP is rated for 500 MW, but those batteries were already delivering 300 MW to self-supply customer load before they were dispatched, we want to pay for the 200 MW benefit, not all 500 MW. We also need to thoughtfully measure if the VPP is delivering the value it was supposed to.”

DERs change utility workforce needs: Deploying and managing DERs on the grid requires skills that are new for the utility workforce. Komo says the existing traditional utility workforce has knowledge gaps on how to manage DERs and DER programs. His colleague, Yoh Kawanami explains, “It is difficult to find the unicorn. A person interested in Demand Response (DR) and DERs with the technical know-how to interpret load profiles to monitor if the DR program is doing what it should and also the business skills to explain the program to customers and manage their expectations.” At PG&E, Kendrick Li has been hiring DER team members for new skills, like coding and integrating APIs.

Example DERs from the Utility Perspective

We talked to Shawn Grant, Director of Customer Solutions at Rocky Mountain Power (RMP) about their Cool Keeper program. This conversation touched on most of the utility constraints described in this article: regulation, reliability, dynamic conditions, utility control, automatic self-dispatch of responsive DERs, no inconvenience to DER owners, and VPP size on par with conventional power plants.

Grant spoke enthusiastically about “real time demand response to meet real time grid needs. We are growing our programs at a sustainable level - not too fast or slow, and we have the regulatory flexibility to operate how we need to. We have 7,000 batteries enrolled in our Wattsmart Battery program. We’ve had our Cool Keeper program for over a decade. It’s not smart thermostats – it is a load control receiver installed on central air conditioners that we can curtail when the system notices a need for frequency response over a two second period. Without anyone pushing a button, 130,000 residential air conditioners shut off within 10 seconds, and we turn them back on in less than 10 minutes so we don’t cause inconvenience. Enrolled customers get a $6 credit on their bill each month from May to September. During peak, Cool Keeper gives us over 300 MW, comparable to a medium to large power plant.”

Rocky Mountain Power’s Cool Keeper program is just one of the VPP programs that utilities are implementing across the country. Programs by other utilities are described in the U.S. Department of Energy’s report: Pathways to Commercial Liftoff: Virtual Power Plants Update, 2025. The report describes features of VPP programs at utilities, including Roanoke Cooperative, San Diego Community Power, Minnkota Power Cooperative, Arizona Public Service, AES Indiana, Baltimore Gas & Electric, National Grid, Green Mountain Power, Con Edison, NYSEG, Central Hudson, Orange and Rockland, Eversource, and Unitil. [7]

Perspectives for Moving the Grid Forward with DERs

DER enthusiasts often bash utilities for being slow. Some of the reasons for utility sluggishness are not good ones, like bureaucratic inertia and scale. Some are features of the regulatory process, like slow regulated proceedings. Some are business challenges, like asymmetric risks, reduced revenues, increased costs, increased complexity, and the need for workforce upskilling. And some are good reasons related to responsibility for things like safety, reliability, and critical function.

In DER discussions, it is easy to focus on excitement about new technology or business models or the drive for speed. We can lose sight of the big goal: maintain the infrastructure intended to provide everyone with low cost energy for a thriving economy and human flourishing – as much power as we want, anywhere we want it, all the time – without customers needing to think about it. That is the value that regulators are charged to protect. When DER advocates present proposals that make sense from the utility and regulatory perspectives, paths forward will emerge with less frustration on all sides.

New DER technology has sparked innovation. That new technology has led to new value and new business models. The new entitities investing in the grid – who are trying to snag a piece of that value – should get a return for that risk. But, how much return is fair? And, who should own, manage, and take responsibility for the new technology? How can regulatory structures better incentivize utilities to adopt DERs in ways that benefit society? How will the new technologies and business models affect everyone? It's time for regulators – working in the public interest – to be decisive on these questions.

Honor Passow is a Senior Fellow at the Irving Institute and a Senior Lecturer at Dartmouth's Geisel School of Medicine.

References
[1]    H. Passow, “Unlocking Grid Value with a Common Language for Distributed Energy Resources,” Sparks & Currents, Dartmouth’s Arthur L. Irving Institute for Energy & Society, November 24, 2025. Available: https://irving.dartmouth.edu/news/2025/11/unlocking-grid-value-common-language-distributed-energy-resources

[2]    C. Jermyn and M. Zimmerman, “Utilities’ Duty to Serve in an Era of End-Use Electrification,” Energy Law J., vol. 46, no. 3, pp. 491–527, 2025. Available: https://www.eba-net.org/wp-content/uploads/2025/11/463-7-Jermyn-491-528.pdf

[3]    M. Zeitlin, “Is this the end of the utility as we know it?,” HeatMap. Accessed: Jun. 01, 2026. [Online]. Available: https://heatmap.news/energy/utilities-greg-abel-josh-shapiro  

[4]    Federal Energy Regulatory Commission (FERC), “Reliability Explainer.” [Online]. Available: https://www.ferc.gov/reliability-explainer

[5]    P. Denholm, “Top 10 Things To Know About Power Grid Reliability,” National Laboratory of the Rockies, Golden, CO, Jan. 2024. [Online]. Available: https://www.nlr.gov/news/detail/program/2024/top-10-things-to-know-about-power-grid-reliability

[6]    EnergyHub, “Building Trustworthy Virtual Power Plants: The VPP Maturity Model,” EnergyHub, 2026. Accessed: May 20, 2026. [Online]. Available: https://www.energyhub.com/resource/building-trustworthy-power-plants-vpp-maturity-model

[7]    S. Razdan, J. Downing, L. White, “Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update,” U.S. Department of Energy, Jan. 2025. [Online]. Available: https://climateprogramportal.org/wp-content/uploads/2025/02/LIFTOFF_DOE_VirtualPowerPlants2025Update.pdf