The modern electrical grid is standing at a precarious crossroads. Utilities and grid operators are currently navigating a "perfect storm" of challenges: surging electricity demand driven by electrification and data center expansion, the urgent need to harden infrastructure against increasingly severe climate-driven weather events, and the necessity of navigating a complex landscape of shifting state and federal energy policies—all while maintaining affordable rates for consumers.
For decades, the utility playbook relied on a centralized, supply-side strategy: build more power plants and expand transmission lines. However, as the industry grapples with these multi-front pressures, that traditional model is proving insufficient. The solution, increasingly, lies not in building more, but in optimizing what is already there. Enter Distributed Energy Resources (DERs)—a fleet of customer-sited technologies that are rapidly moving from the margins of reliability planning to the center stage of grid operations.
The New Frontier: Aggregated Grid Assets
In a recent episode of the Factor This! Policycast, produced in partnership with Advanced Energy United, industry experts gathered to discuss the maturation of Virtual Power Plants (VPPs). By aggregating behind-the-meter technologies—such as residential battery storage, smart thermostats, backup generators, microgrids, rooftop solar, and flexible EV charging—utilities can transform individual customer devices into a cohesive, dependable grid asset.
The conversation, which built upon discussions initiated at the DTECH Reliability & Resiliency 2026 conference in Chicago, featured perspectives from Emma Heins of Advanced Energy United, Bart Jackson of Sunrun, Maxwell Burke-Scoll of EnergyHub, and Kahri Gehrke of Alliant Energy. Together, they explored the transition from small-scale pilots to full-scale, grid-integrated programs.
Chronology of a Paradigm Shift: From Niche to Necessity
The evolution of DERs can be categorized into three distinct phases that have defined the current industry trajectory:
- The Experimental Phase (2010–2018): During this period, utilities experimented with basic demand response programs, primarily focusing on manual curtailment of air conditioning units during peak summer months. These programs were limited in scope, often plagued by high friction for the user and low reliability for the grid.
- The Integration Phase (2019–2024): As battery costs plummeted and smart home technology proliferated, industry leaders began to treat DERs as "non-wires alternatives." Pilot programs emerged to test whether fleets of residential batteries could provide frequency regulation and peak shaving.
- The Operational Phase (2025–Present): We are currently in the era of active, automated dispatch. With the success of large-scale events in California and robust programs like the East Coast’s "Connected Solutions," VPPs are now being integrated into day-ahead and real-time market designs, proving they can function as reliable firm load.
Supporting Data: The Case for Economic Efficiency
One of the most persistent myths surrounding DERs is that they only benefit the wealthy, "ownership-gated" segment of the population—those with the capital to purchase solar panels or home batteries. However, industry experts argue that the economic benefits are systemic.
The Multiplier Effect
"While technologies like battery storage and rooftop solar are ownership-gated, the system benefits in affordability, resiliency, and reliability to all ratepayers are not gated," explains EnergyHub’s Maxwell Burke-Scoll. When an aggregate of thousands of batteries reduces the need for a utility to fire up a "peaker" plant—which is often expensive and highly polluting—all customers see the benefit through lower overall capacity costs.
Quantifying Resiliency
Emma Heins of Advanced Energy United emphasizes that the value of resilience is often underestimated in traditional utility cost-benefit analyses. "It costs money to replace medication that needs to be refrigerated," Heins notes. "If there’s a power outage, that’s a direct financial hit. Avoiding that loss is a quantifiable savings for the ratepayer, even if it doesn’t appear as a line-item credit on a monthly bill."
Performance Metrics
The financial viability of these programs is increasingly concrete. Sunrun’s Bart Jackson highlights the "Connected Solutions" program as a gold standard. With performance payments hovering around $300 per kilowatt-hour, the program boasts a ratepayer impact score of nearly 2.0. In economic terms, this means that for every dollar invested in the program, the system realizes two dollars in value through deferred infrastructure upgrades and avoided energy procurement costs.
Official Responses and Strategic Implementation
For VPPs to scale, the industry must overcome barriers related to enrollment friction, data visibility, and market design. The experts highlighted several critical areas for improvement:
The "One-Click" Enrollment Strategy
Kahri Gehrke of Alliant Energy stresses that utilities must treat the customer experience as a core component of grid reliability. "We want the least amount of impact on the customer’s daily life," Gehrke said. Alliant’s recent success in streamlining enrollment—moving from complex forms to one-click, authenticated email opt-ins—demonstrates that reducing administrative burden is the primary lever for increasing capacity participation.
The Integrity of the "Customer Promise"
A major point of consensus among the panel was the fragility of customer trust. If an EV charging program fails to deliver a charged vehicle for a morning commute, the customer is likely to opt out permanently.
"The program doesn’t just lose that event capacity," Burke-Scoll warned. "The program loses that customer forever." Consequently, programs are increasingly built around "hard constraints"—such as ensuring an EV hits its target state of charge before a pre-set departure time. These concessions to the customer are not merely gestures of goodwill; they are necessary investments in maintaining the scale of the resource.
Implications: The End of the Pilot Era
The most significant takeaway from the Factor This! discussion is that the industry has outgrown the need for small-scale, tentative pilot programs. The technology is proven, the market signals are present, and the grid need is urgent.
The California Proof-Point
The recent, record-breaking dispatch of over 580 megawatts (MW) to the California grid serves as a definitive case study. During a recent heat wave, the California Energy Commission and state utilities successfully triggered the dispatch of home batteries via the Demand Side Grid Support (DSGS) and Emergency Load Reduction Program (ELRP).
When the CAISO day-ahead locational marginal price surged past $200 per megawatt-hour, the VPPs responded exactly as designed. The batteries discharged for three hours, providing critical stability to the grid and putting downward pressure on prices. "It’s the first time that the $200 price trigger has been hit," Jackson observed. "The program was designed to respond to that price, and it did."
A Future of Flexible Load
As we look toward the future, the integration of flexible load will become a standard utility function. Alliant Energy’s Gehrke summarized the industry sentiment effectively: "All demand response is good demand response. It’s cost-effective, it’s worthwhile, and we need to be doing it."
The transition from a "build more" philosophy to a "manage better" philosophy is no longer a theoretical exercise for policy wonks. It is a practical, scalable, and increasingly urgent operational reality. By focusing on customer-centric design, robust market signals, and the seamless integration of distributed assets, utilities can meet the demands of a high-electrification future while keeping the grid resilient, reliable, and affordable for all.
The era of the Virtual Power Plant has arrived. The only remaining question is how quickly the broader utility sector will abandon the old-school reliance on traditional generation to fully embrace this agile, decentralized future.
