The grid is changing faster than most utilities can measure. Rooftop solar, batteries, managed EV charging, heat-pumps, distributed energy resources (DERs) of every kind are multiplying behind the meter, while electrification is rewriting demand patterns in real time.
And adoption continues to accelerate; NREL modeling suggests electrification alone could increase U.S. electricity demand by 30–40 percent by 2050.1
For utilities, this growth creates a new planning challenge. DERs are increasingly shaping distribution system demand, yet many utilities still struggle to quantify their actual system impact.
The technologies are visible. Their performance on the grid often is not.
DER Performance Often Appears as a Black Box
Here’s the paradox: most utilities aren’t short on DER data.
Solar production data arrives through interconnection processes or vendor portals. Managed EV charging platforms track charging activity and participation in programs. Battery aggregators report dispatch events. But most of these systems measure device activity, not grid outcomes.
The challenge is that DERs operate continuously. Unlike demand response (DR) events that occur at specific moments, DER impact unfolds across the day. Solar shifts load midday. Electric vehicles often increase demand in the evening. Batteries respond to price signals or grid needs depending on program design.
What matters is the combined impact.
Many utilities already operate DER management systems (DERMS) or vendor platforms that coordinate individual devices. These tools are essential for dispatch and control, but they typically report device-level activity rather than the net effect on system load. Without a consistent way to observe what actually happens at the meter, it remains difficult to understand how multiple technologies interact or exactly how much demand is reduced on the grid.
The complexity grows when multiple technologies and programs interact. A single home might have rooftop solar, an electric vehicle, and a battery enrolled in a managed charging or demand response program.
Each technology is often evaluated separately:
- Solar output may be tracked through interconnection data.
- Managed charging programs are monitored through 3rd party platforms.
- Energy efficiency programs follow an entirely different framework.
When data is scattered across programs, technologies, and vendor platforms, utilities often struggle to answer basic questions, like how much peak load did these DERs actually reduce? Where did those reductions occur? Did electrification increase peak demand before mitigation programs offset it?
Without a consistent view at the service point, DER performance is often difficult for program and planning teams to interpret or act on.
The Consequences
When DER performance cannot be easily measured, planning teams rely on modeled assumptions rather than measured outcomes. Electrification impacts and mitigation programs may be evaluated independently even though they interact at the same location. Solar generation, managed charging, and other programs may each be modeled using different assumptions, making the combined impact difficult to interpret.
Research from Lawrence Berkeley National Laboratory has shown that differences between projected and realized demand-side savings can introduce uncertainty in utility planning models and resource forecasts.2 When planners cannot clearly observe how distributed resources affect system load, they often respond by applying conservative assumptions to protect reliability.
The result is a double loss: utilities build infrastructure they might not have needed, and DERs get sidelined in planning even where they could have deferred those upgrades, leaving real grid value on the table.
What It Takes to Fix DER Visibility
The good news? Improving DER visibility does not require any new technologies. It simply requires measuring what is already happening on the grid in a standardized way.
The same principles discussed in the previous post on demand response also apply here:
1. Measure DER impact at the meter.
Understanding the impact of DERs begins at the service point. Interval meter data captures the combined effect of multiple technologies operating together and shows how electricity use shifts over time as solar generates power, electric vehicles charge, or batteries discharge during peak periods.
Measuring performance at the meter also reveals the net impact when multiple technologies interact, which is often difficult to see through device-level reporting alone. This makes it possible to separate electrification-driven load growth from mitigation programs such as managed charging or storage.
Example: A utility analyzes interval data from homes with rooftop solar and electric vehicle charging. Solar consistently reduces midday net load, while unmanaged EV charging increases evening demand. Customers enrolled in managed charging avoid that evening peak. Planning teams incorporate this difference into load forecasts and expand recruitment for managed charging.
2. Standardize DER performance reporting for more actionable insights.
DER data becomes far more useful when it is measured consistently across technologies and programs. When solar, batteries, and managed charging are evaluated using different vendor reports or assumptions, utilities struggle to compare their impact or understand where distributed resources actually reduce peak demand.
A standardized, meter-based view allows utilities to analyze DER performance across feeders, customer segments, and device types using the same framework. Instead of relying on portfolio averages, teams can see where distributed resources are delivering meaningful system value and where they are not. That insight helps utilities refine program targeting, prioritize constrained areas, and focus investments where demand-side resources can deliver the greatest impact.
Example: A feeder-level analysis shows that battery incentives in one constrained area consistently reduce late-afternoon loading. Similar incentives elsewhere have little impact on peak conditions. With this insight, the utility shifts program targeting toward feeders where constraints are most severe.
3. Turn continuous DER data into planning-grade insight.
When performance is measured consistently, utilities can turn continuous DER data into insights planners can use.
It also opens the door to treating distributed resources more like capacity assets. Utilities routinely procure capacity to meet reliability needs, but behind-the-meter resources are often discounted because their system impact is difficult to verify. When DER performance can be measured at the meter, planners gain the evidence needed to incorporate these resources more confidently into forecasts and resource planning decisions.
Meter-based analysis allows utilities to evaluate solar, storage, electric vehicle charging, and demand response using a shared measurement framework. Observed performance can then inform system forecasts and resource planning assumptions.
Example: At the end of the year, planners consolidate measured impacts from solar, batteries, and managed charging programs. Observed peak reductions replace static assumptions in the next planning cycle, allowing planners to incorporate verified DER performance into load forecasts and resource planning decisions.
What Comes Next
As DERs continue to scale, the challenge is no longer whether they influence the grid. The challenge is measuring that impact clearly enough to plan around it.
Utilities already procure capacity to maintain reliability. So if DER performance can be verified at the meter, what prevents those resources from being treated as capacity as well?
DERs are far from the only measurement problem on the demand side. Energy efficiency programs face a version of this challenge as well and in some ways, it’s even harder to solve. Many still rely on deemed savings and static assumptions that were never designed to reflect real-world performance.
Next in this series: Fixing Energy Efficiency: Connecting Program Results to Grid Impact.
Connect with our team to learn how FLEX can support you and your team’s demand-side goals.
- NREL, 2025: Distribution System Planning for Electrification and Distributed Energy Resources ↩︎
- Lawrence Berkeley National Lab, 2025: Reimagining Energy Efficiency Resource Standards ↩︎