Expert in energy policy and utility regulation Christopher Hailstone has spent years navigating the complex intersection of grid reliability and emerging technology. As the energy landscape shifts toward a decentralized model, the debate over who should own and control distributed assets has intensified, pitting traditional utility-owned infrastructure against the rise of customer-led virtual power plants. In this discussion, we explore the nuances of these competing models, the economic trade-offs for ratepayers, and the regulatory frameworks required to balance innovation with a secure, stable power grid.
Utility-owned programs often feature front-of-meter batteries controlled directly by the utility, while aggregator models rely on residential assets. How do these different ownership structures impact long-term grid reliability, and what specific operational hurdles arise when managing thousands of customer devices compared to larger utility installations?
The primary distinction lies in the certainty of the resource; a utility-owned front-of-meter battery is a 20-year asset that behaves much like a traditional substation or transformer. When a utility owns the hardware, they have absolute control over dispatch without having to worry about whether a homeowner has decided to override their smart thermostat or if a residential battery is depleted from personal use. Managing thousands of individual customer devices introduces significant “noise” because availability varies based on the season, the time of day, and the simple willingness of the consumer to participate. While aggregators are getting better at predicting this behavior, a utility-owned system ranging from 1 MW to 3 MW per site provides a level of “operational excellence” and firm capacity that decentralized, behind-the-meter assets struggle to match. However, the superpower of the customer-owned model is the sheer scale of engagement, as residential battery capacity recently grew by 70% in a single year, representing a massive untapped resource if the coordination hurdles can be cleared.
Front-of-meter battery programs can reach costs over $2,000 per kW, whereas aggregator-led initiatives often report significantly lower figures. What factors justify these price discrepancies for ratepayers, and how should regulators evaluate the trade-offs between high-capital utility assets and the variable availability of customer-owned resources?
At first glance, the price gap is startling—Xcel’s proposed Minnesota program is estimated at $2,150 per kW, while their aggregator-led Colorado pilot sits around $624 per kW. The justification for the higher utility cost is rooted in the lifespan and firm nature of the investment; these are 20-year utility assets designed for consistent service, whereas aggregator costs often reflect shorter-term contracts or five-year payment structures for the use of existing customer hardware. Regulators have to look beyond the upfront sticker price and conduct a granular benefit-to-cost analysis, noting that some utility-led pilots have shown benefit ratios around 0.96, which critics argue is lower than many third-party aggregations. The real challenge for a regulator is weighing the “cost discipline” brought by market competition against the long-term reliability and 24/7 visibility that a utility-owned asset provides to the distribution system.
Some jurisdictions are moving toward technology-neutral competitive bidding for distribution capacity rather than sole-source partnerships. How does a utility-led approach affect the local market for third-party energy providers, and what steps can be taken to ensure that utility investments don’t inadvertently stifle innovation from independent aggregators?
There is a valid concern that if a utility selects a single partner to develop a program—as seen with the selection of Sparkfund for the Minnesota pilot—it can create a closed ecosystem that shuts out other innovators. Competitive procurement is essential because it introduces market pricing and prevents a utility’s natural bias toward capital-heavy investments from inflating ratepayer costs. To ensure innovation isn’t stifled, utilities should be required to issue technology-neutral solicitations where third-party aggregators can bid their “virtual” capacity against physical battery installs. We also need clear “anti-competitive” guardrails; for instance, ensuring that a utility’s own batteries are not placed in a way that consumes all the available hosting capacity, which would effectively block independent providers from entering that specific local market.
Bulk system capacity revenue from regional operators is a major driver for new storage pilots. Beyond resource adequacy, how do these distributed batteries provide local distribution benefits, and can you explain the step-by-step process of “stacking” these different value streams to lower overall customer rates?
The beauty of these distributed resources is their ability to perform “value stacking,” where a single battery serves multiple masters to maximize its economic return. In the Minnesota model, over 65% of the revenue is expected to come from the Midcontinent Independent System Operator for bulk system capacity, helping the entire region stay powered during peaks. Locally, the utility can use those same batteries to manage “load growth surges” that might otherwise force an expensive upgrade to a neighborhood substation, effectively deferring capital spending. By stacking these revenues—system-wide capacity payments, local distribution deferral, and even frequency regulation—the utility can lower the net cost of the asset, ultimately putting downward pressure on customer rates.
Utilities often argue that direct ownership is essential for maintaining strict cybersecurity and reliability standards on the distribution network. What specific security protocols are necessary for integrating distributed energy resources, and how can third-party aggregators demonstrate that their managed fleets meet the same rigorous operational requirements?
The utility perspective is that the distribution grid is a sensitive environment where a single cyber-vulnerability could have cascading effects, and they feel more secure managing assets behind their own firewalls. However, modern cybersecurity standards can be written directly into third-party contracts, requiring aggregators to meet specific situational awareness and data encryption protocols. Aggregators can prove their reliability through rigorous performance evaluations, such as the Huels Test, which measures how precisely a virtual power plant responds to dispatch signals compared to a physical power plant. By integrating a Grid Distributed Energy Resource Management System (DERMS), utilities can gain the visibility they need into third-party fleets without necessarily needing to own the hardware themselves.
With growing electricity demand, some experts suggest that utility-owned batteries and customer-led virtual power plants are complementary rather than mutually exclusive. In a scenario where both exist, how would a utility coordinate dispatch between its own assets and third-party aggregations to maximize grid efficiency?
In a truly efficient grid, these two models function like a synchronized orchestra where the utility-owned batteries act as the “base” to handle predictable infrastructure limits, while customer-led VPPs provide the “flexible peak” response. If a specific neighborhood is hitting a transformer limit due to a heatwave, the utility would first dispatch its own strategically placed front-of-meter batteries to stabilize the local circuit. Simultaneously, the utility would send a price signal or a dispatch request to third-party aggregators to curtail residential demand or discharge home batteries in that same area to provide an extra layer of relief. This coordinated dance allows the grid to absorb gigawatt-scale growth by utilizing every available electron, whether it’s stored in a utility-scale container or a homeowner’s garage.
What is your forecast for the future of virtual power plants and utility-owned distributed energy?
I expect we are moving toward a hybrid “ecosystem” where the distinction between utility assets and customer resources becomes increasingly blurred by sophisticated software. By 2028 and beyond, we will likely see “bring your own offsite flexibility” programs, where large industrial users might even fund customer-owned battery aggregations as a way to offset their own grid impact. While the debates over ownership will continue in state commissions, the sheer volume of decentralized demand—driven by electric vehicles and home electrification—will eventually force a reality where utilities must become expert orchestrators of third-party assets just to keep the lights on. The future isn’t about one model winning; it’s about the regulatory maturity to compensate every resource appropriately for the specific grid service it provides.
