Bridging the DER planning gap to unlock distribution operational potential

With energy demand surging, utilities are working to modernize the grid, address reliability and resilience concerns, and tackle capacity constraints, all while maintaining service quality within defined capital budgets. Rising distribution capital expenditures are creating affordability challenges for customers and increasing the need to find cost-effective alternatives to traditional infrastructure expansion. These mounting pressures are driving new approaches to capital deployment and grid operation, creating opportunities to optimize investments.

As distributed energy resources (DERs)—like energy efficiency measures, rooftop solar, batteries (customer and utility), electric vehicles, and smart devices—proliferate, the opportunity to leverage their support for improved asset utilization and capacity becomes more prominent. However, existing planning methods leave a critical gap between projected DER potential and real-world performance.

Traditional DER potential studies often focus on “achievable potential,” estimating how many DERs can be added to the grid based on cost-effectiveness metrics and expected customer participation rates. These studies presume that achieving this potential will help reduce or delay the need for new investments across generation, transmission, and distribution. But they do not consider the specific DER’s performance efficacy (individually and collectively) needed to deliver that value.

Because these studies aren’t grounded in operational performance, they can overestimate DER capabilities, particularly for predicting dependable distribution grid support. They can also overlook DER contributions to resource adequacy and capacity needs. Without sufficient rigor and confidence in these estimates, DERs are often excluded from distribution capacity expansion models, load forecasts, and reliability planning—limiting their role as a dependable distribution grid resource.

From projection to performance: A risk-based approach

To capture the true value of DERs, utilities need a shift in methodology from theoretical modeling based on technical potential and adoption curves to risk-based planning grounded in locational performance and efficacy. This means evaluating not just what DERs could do, but unpacking their unique performance characteristics to assess what they can reliably provide under real-world operating conditions.

This forms the foundation of distribution operational potential: a risk-adjusted accreditation framework that forecasts and evaluates what distributed resources can dependably deliver based on demonstrated performance in an operating environment.

The framework involves assessing specific DERs—individually and as portfolios—for key performance characteristics (e.g., latency, communication protocol, repeatability, availability) and scalability to determine what quantity of energy, capacity, and ancillary services they can provide under operating conditions and evolving grid needs.

When these DERs are aggregated and orchestrated as virtual power plants (VPP), the framework also evaluates their collective ability to deliver reliable, dispatchable grid services at scale. It captures the incremental value from coordinated operations, diversity in device performance, and the VPPs capacity to dynamically match grid constraints, locational needs, and market signals. This ensures that planners can understand not only the capabilities of individual devices, but also the enhanced system-level performance, flexibility, and predictability enabled through VPP aggregation.

Key elements of distribution operational potential include:

Technology-specific performance characteristics: Historical data on DER availability, controllability, and reliability during both normal operations and high-stress grid events. This includes temporal characteristics, such as response speed (latency), event timing, and duration’s impact on performance.

For example, a thermostat program may be ill-suited for frequency response, given the intermittent nature of the need and high-speed requirements for dispatch. By contrast, distributed battery energy storage may be better equipped to serve this use case due to its speed, control, and dispatchability.

Alternatively, with autonomous control, rooftop solar inverters can supply reactive power for voltage support during cloudy conditions and nighttime—capabilities rarely viable without such control. The objective is to align the efficacy of the broader portfolio across disparate DER types and leveraging the unique performance characteristics of each to the operational needs of the grid.

Localized forecasting: Circuit-level energy use data and DER adoption forecasts predict how load and generation may vary by location. This provides a more granular view of distribution system behavior and emerging grid constraints and opportunities for DER integration to meet future capacity and reliability needs.

Institutional and market realities: Customer participation variability, third-party provider economics, and operational coordination complexity across multiple entities and domains, including transmission and distribution operators (TSOs and DSOs), aggregators, implementers, end use customers, and equipment manufacturers.

Together, these elements form the building blocks of a systematic framework that replaces aggregate projections with a more granular, risk-based planning approach.

Whether driven by regulatory mandates, strategic interconnections, or affordable electrification goals, utilities need a structured way to convert DER potential into tangible grid value. That’s the role of the operational potential framework, which involves systematic analysis through several stages.

Operational potential determination

While technical and achievable potential assessments are commonly performed to inform demand-side management (DSM) program goals, operational potential studies provide a rigorous approach tailored for the needs of distribution grid engineers and operators. This stage analyzes technology supply curves, specific DER efficacy (e.g., communication protocol, latency factors, dispatch attributes), distribution grid capacity expansion costs, and system needs to determine how much of the achievable DER capacity can be operationalized to serve the grid. Grid modernization and customer program teams also have agency at this stage to ensure that investments, DER sourcing strategies, and future programs align with the operational potential.

Economic optimization

Building on the operational assessment, this stage uses an orchestration simulation model to evaluate capital mitigation opportunities and the potential for downward pressure on rates across different deployment scenarios. By parameterizing these characteristics, utilities can directly compare DERs to traditional infrastructure investments—such as substations and feeders—on cost and value. This allows for more precise economic modeling in distribution planning, helping utilities make informed decisions about how and where DERs can deliver the most benefit.

Procurement and programs

Finally, the framework delivers a clear sourcing strategy showing which DER technologies to deploy, where, and when—forming the basis for resource procurement and DSM program filings.

An iterative implementation

Once the framework is applied and DERs are deployed, distribution operational potential becomes a critical input for broader utility planning, supporting transmission, distribution, and resource adequacy efforts.

Equally important, this approach acknowledges that DER performance evolves over time. As utilities gain experience with orchestrated DERs, performance data feeds back into planning cycles, continuously refining future assessments. This feedback loop builds institutional confidence in DERs as dependable resources, allowing utilities to better align customer-side flexibility with grid needs.

A strategic path forward

The end goal is clear: move beyond theoretical projections to develop a robust, risk-adjusted DER planning framework that delivers tangible grid value. This approach unlocks the full value of customer-side flexibility, enables more targeted and efficient capital investment, and supports a more resilient, modern distribution grid.

Ready to bridge your DER planning gap? We help utilities develop distribution operational potential assessments that reflect on-the-ground operational realities. This builds trust around DER predictability while institutionalizing DERs into the planning process. Our integrated planning approach, supported by tools like the Sightline platform, combines technical rigor with distribution planning and engineering expertise to support your DER sourcing strategies.