Planning And Operations Integration As The Gating Step For Trust
Sources: 1 • Confidence: Medium • Updated: 2026-03-11 09:09
Key takeaways
- Operators can accept non-identical resources if there are repeatable, reliable forecasts for required notice time, run duration, and recovery time before redeploying.
- Duke is operating programs outside the peak hour and is working with regulators to recognize incremental value in additional hours so more value can be shared with customers to increase participation.
- Different distributed resources have distinct capability profiles and use cases, including switches, smart thermostats, batteries that can be flexed daily, and EVs that can be smart-charged overnight.
- Adoption of customer-owned devices (smart thermostats, batteries, and grid-connected water heaters) is reducing customer friction compared with legacy one-way load control switches and enabling more interactive programs.
- A proposed VPP trust framework (referred to as the Hewles test or Huell's test) is that an operator could swap a VPP for a traditional power plant and not be able to tell the difference in operational integration and performance.
Sections
Planning And Operations Integration As The Gating Step For Trust
- Operators can accept non-identical resources if there are repeatable, reliable forecasts for required notice time, run duration, and recovery time before redeploying.
- Duke planners start with what customers can provide at peak to reduce the peak challenge and then plan remaining centralized generation needs around that contribution.
- A modern VPP is distinguished from traditional demand response by two-way data, real-time visibility of response during dispatch, and sufficient scale (on the order of tens of megawatts) to resemble a peaker plant to operators.
- EnergyHub's VPP maturity model defines level three as requiring automated VPP capability plus integration into utility operational and planning systems (e.g., unit commitment, forecasting tools, and IRP models).
- Duke's portfolio includes about one million participating customers and roughly 2 GW of winter capability and 2.5 GW of summer capability across its utilities, and this capability is included in integrated resource plans.
- Before operators will treat a VPP resource as reserves, Duke requires multi-year performance evidence, forecasting confidence, and sometimes third-party audits.
Valuation And Regulation Constraints In Vertically Integrated Contexts
- Duke is operating programs outside the peak hour and is working with regulators to recognize incremental value in additional hours so more value can be shared with customers to increase participation.
- In vertically integrated utilities, incremental technology upgrades (e.g., replacing one-way switches with 4G) do not necessarily translate into linear increases in system value.
- Even when upgrades do not add immediate value, utilities may justify them as building trust that DER resources are durable planning assets.
- In Stacy Phillips' markets, program system value is largely determined by avoided generation, transmission, and distribution costs in the peak average hour, with limited incremental value in other hours.
- Regulatory structures often limit VPP operation (for example via hour limits) and do not consistently recognize differing capabilities across DER types under measurement and verification approaches.
Maturity Roadmap Toward Distribution-Support Coordination And Its Prerequisites
- Different distributed resources have distinct capability profiles and use cases, including switches, smart thermostats, batteries that can be flexed daily, and EVs that can be smart-charged overnight.
- EnergyHub's maturity model defines level four as coordinating DERs to support the distribution network while simultaneously considering bulk system conditions and customer objectives such as bill savings.
- Duke self-assesses as a strong level two VPP operator today, with substantial portfolios still at levels zero and one, and sees major remaining work in data-system connectivity and cybersecurity to progress further.
- A key barrier to level four managed EV charging is that many utilities lack readily usable distribution network models and asset thermal-limit data that VPP platforms could plug into for coordinated control.
- EnergyHub expects level four VPP capability to be achievable on about a five-year horizon, with industry focus currently on making level three consistent across DER classes.
Customer Friction As A Primary Constraint On Dispatchability And Persistence
- Adoption of customer-owned devices (smart thermostats, batteries, and grid-connected water heaters) is reducing customer friction compared with legacy one-way load control switches and enabling more interactive programs.
- With large participation counts, VPP output becomes statistically forecastable and resilient to a small fraction of customers opting out on an event day.
- Reducing dispatch duration for certain switches from three-to-four hours to one hour decreased customer attrition and increased operator willingness to use the resource.
- Stacy Phillips evaluates VPP maturity primarily through the lens of customer friction rather than technology features.
Taxonomy And Acceptance Frameworks
- A proposed VPP trust framework (referred to as the Hewles test or Huell's test) is that an operator could swap a VPP for a traditional power plant and not be able to tell the difference in operational integration and performance.
- There is an industry dispute about terminology for these resources (e.g., 'virtual power plants' vs 'distributed power plants') because they can support the distribution network in addition to bulk-system roles.
- Stacy Phillips prefers the term 'customer power plant' and argues that 'virtual power plant' is misleading because these resources are real and customer-driven.
- Stacy Phillips believes a VPP maturity framework is valuable for helping load flexibility practitioners plan portfolio maturation and communicate it internally.
Watchlist
- Duke is operating programs outside the peak hour and is working with regulators to recognize incremental value in additional hours so more value can be shared with customers to increase participation.
Unknowns
- What were the measured MW delivered, response time, sustained duration, and recovery characteristics of Duke's winter events, and how variable were these across events?
- How is Duke defining and calculating the stated 2 GW winter and 2.5 GW summer capability (e.g., enrollment vs accredited capacity), and what fraction is considered planning-grade vs experimental?
- What are the concrete criteria (thresholds, tests, audit scope) that Duke uses to move a VPP resource from program status to reserve-eligible operational status?
- What are the customer participation and attrition rates across device types, and how do event design choices (like one-hour vs four-hour dispatch) change those rates over time?
- What are the costs (utility capex/opex and customer incentives) associated with achieving operational integration (e.g., 'single pane of glass') and with cybersecurity/connectivity upgrades?