---
title: "Relying on BTM Distributed Energy Resources (DERs) is Nothing To Fear: Addressing 8 Common Challenges For Utilities"
id: "6536"
type: "post"
slug: "relying-on-btm-distributed-energy-resources-ders-is-nothing-to-fear-addressing-8-common-challenges-for-utilities"
published_at: "2026-10-28T13:00:05+00:00"
modified_at: "2026-10-27T16:05:30+00:00"
url: "https://virtual-peaker.com/blog/relying-on-btm-distributed-energy-resources-ders-is-nothing-to-fear-addressing-8-common-challenges-for-utilities/"
markdown_url: "https://virtual-peaker.com/blog/relying-on-btm-distributed-energy-resources-ders-is-nothing-to-fear-addressing-8-common-challenges-for-utilities.md"
excerpt: "Behind-the-meter (BTM) distributed energy resources (DERs) like smart thermostats, water heaters, home batteries, EV chargers, and rooftop solar are already […]"
taxonomy_category:
  - "Demand Response"
---

Demand Response

# Relying on BTM Distributed Energy Resources (DERs) is Nothing To Fear: Addressing 8 Common Challenges For Utilities

[Virtual Peaker Team Published Oct 28, 2026](https://virtual-peaker.com/author/virtual-peaker-team/)

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Behind-the-meter (BTM) [distributed energy resources (DERs)](https://virtual-peaker.com/blog/distributed-energy-resource/)
 like smart thermostats, water heaters, home batteries, EV chargers, and rooftop solar are already installed in homes and proliferating across every service territory. Through residential demand flexibility programs such as [demand response](https://virtual-peaker.com/demand-response/)
, [bring your own device (BYOD) programs](https://virtual-peaker.com/bring-your-own-device/)
, [managed EV charging](https://virtual-peaker.com/ev-charging/)
, and [virtual power plants (VPPs)](https://virtual-peaker.com/blog/what-is-a-virtual-power-plant/)
, utilities can shift or shed that load during peaks to meet rapidly rising demand without waiting years for new infrastructure.

So why do so many utilities still hesitate? Because for many DERs, which are not owned by the utility, represent an unknown and, thus, unreliable quantity. As a [Dartmouth Irving Institute review of utility perspectives](https://irving.dartmouth.edu/news/2026/06/viewpoints-distributed-energy-resources-utility-perspectives)
 puts it, one major outage caused by unreliable DERs could be disastrous for a utility, so the risk feels lopsided.

That doubt is understandable, although increasingly outdated. Closed-loop, fleet-level control approaches such as [Topline Demand Control (TDC)](https://virtual-peaker.com/blog/what-is-topline-demand-control/)
 now steer thousands of devices toward a target load shape and hold it for the full event, yielding reliable outcomes from BTM distributed energy resources.

Distributed energy resources (DERs) are nothing to fear, but we understand. In celebration of Halloween and all things spooky, we examine the eight most common challenges to BTM DER programs and how each can be solved.

## In This Article

- Challenge 1: BTM DERs Are Seen As Unreliable
- Challenge 2: Operators Can’t See or Verify What DERs Deliver
- Challenge 3: The Interconnection Queue is Long
- Challenge 4: DER Value Doesn’t Always Match Utility Objectives
- Challenge 5: DERs Threaten Customer Disintermediation
- Challenge 6: Marketing Has Never Been a Utility Strength
- Challenge 7: Market Rules Don’t Credit DERs Fully
- Challenge 8: Interoperability, Cybersecurity, & Workforce Gaps
- Conclusion: BTM DERs Have Earned a Place in the Resource Plan
- FAQs
- Glossary of Terms

## Challenge 1: BTM DERs Are Seen As Unreliable

Grid operators plan around the minimum a resource will deliver, not its peak. A traditional thermostat event sends a pre-cool command and a setpoint change, then stops. As homes warm and customers override their settings, the load reduction fades, and it fades most on the hottest days. Batteries face a similar gap: a Hawaiian Electric director told the [Irving Institute](https://irving.dartmouth.edu/news/2026/06/viewpoints-distributed-energy-resources-utility-perspectives)
 that 100 MW of enrolled home batteries may yield only 60 to 80 MW when dispatched.

### Solution: Control the Fleet, Not Just the Device

Closed-loop, fleet-level control starts with the load shape the operator needs. Then, TDC employs live telemetry, the [Shift Grid-Edge DERMS](https://virtual-peaker.com/platform/derms-suite/)
, [forecasting](https://virtual-peaker.com/platform/forecasting-suite/)
, and model predictive control to keep adjusting devices for the full event. In a[head-to-head field test](https://virtual-peaker.com/blog/53-more-firm-capacity-closing-the-gap-in-demand-responses-final-hour/)
 of several thousand thermostats, this approach:

- Raised firm capacity from 24.7% to 37.7%, about 53% more
- Raised final-hour reduction from 28.7% to 44.9%
- Lowered customer opt-outs by 25%

In practice, a 10,000-thermostat program can deliver the [firm capacity](https://virtual-peaker.com/blog/how-topline-demand-control-reliably-increases-firm-capacity/)
 of roughly 15,000 thermostats, with no new recruitment.

## Challenge 2: Operators Can’t See or Verify What DERs Deliver

Visibility metrics like [measurements and verifications matter](https://virtual-peaker.com/blog/how-to-measure-the-success-of-your-demand-flexibility-program/)
, which is why control rooms trust what they can monitor and dispatch. Likewise, utilities worry about paying for load reduction that would have happened anyway, such as a battery already powering its own home before an event.

### Solution: Control Room-Grade Data & Honest Baselines

A robust Grid-Edge DERMS platform offers reporting backed by real-time and historical data to show the efficacy of each program. Likewise, effective forecasting is useful in helping grid operators plan for everything from when demand flexibility events might run to [power purchasing agreements](https://virtual-peaker.com/blog/dont-get-caught-off-guard-why-rising-power-purchase-agreement-prices-mean-utilities-need-a-virtual-power-plant-strategy/)
 and beyond.

To maximize visibility, utilities can:

- Stream device data at short intervals; the VPP maturity criteria summarized by the Irving Institute call for verifiable data at least every five minutes.
- Measure incremental performance against a sound baseline, not gross device output.
- Where meter data is hard to get, use statistical sampling, an approach [asked recently of FERC](https://www.latitudemedia.com/news/pjms-data-center-auction-may-be-the-break-vpps-have-been-waiting-for/) to allow in PJM.

With that visibility in place, DERs can [move into the control room](https://virtual-peaker.com/blog/how-topline-demand-control-moves-distributed-energy-resources-ders-into-the-control-room/)
 alongside conventional assets.

## Challenge 3: The Interconnection Queue is Long

Utilities hear “interconnection” and picture years of studies. Data through 2025 shows that there were approximately 8200 projects representing 1312 GW of generation in the U.S. grid interconnection queue. For now, distribution-level requests are climbing as homes, businesses, and large loads all seek capacity at once.

### Solution: Use Connected Load & Reformed Processes

Thermostats, water heaters, and managed EV chargers shift load that is already on the grid, so most residential demand flexibility programs don’t need a new generator interconnection at all, allowing utilities to sidestep the queue. For exporting resources such as batteries, the DOE’s [DER interconnection roadmap](https://www.energy.gov/cmei/i2x/doe-distributed-energy-resource-interconnection-roadmap)
 sets 2030 targets of under one day from request to agreement for systems below 50 kW, and under 75 days for systems up to 5 MW. Furthermore, distributed energy resources can even speed up other interconnections: aggregations behind a congested node can [create headroom for new data centers](https://www.utilitydive.com/news/distributed-energy-resources-can-accelerate-data-center-interconnection/801964/)
, and DOE case studies show dispatch software can be deployed in as little as four months.

## Challenge 4: DER Value Doesn’t Always Match Utility Objectives

Because utilities don’t own BTM DERs, each device type, owner, and aggregator comes with its own priorities. A third-party provider serves its customer first and the system second. Location also matters: a kilowatt on the wrong feeder does little for a constrained substation.

### Solution: Dispatch by Location & Design to Grid Needs

Although each OEM has different device constraints, utilities can leverage grouping tools to organize OEMs as needed. To address disparities in how different devices can be dispatched, utilities can:

- Group DERs by feeder or substation and use [localized dispatch](https://virtual-peaker.com/localized-dispatch/) where constraints exist.
- Honor customer parameters, such as time-of-use periods, EV charging schedules, and comfort bands, through automated optimization.
- Match procurement to the need. A new [SEIA white paper](https://pv-magazine-usa.com/2026/10/26/new-seia-white-paper-outlines-pathways-for-distributed-resources-to-meet-grid-needs/) outlines three pathways, from open-enrollment tariffs for system-wide needs to targeted solicitations for site-specific ones.

## Challenge 5: DERs Threaten Customer Disintermediation

For years, BTM DERs evoked concerns over [customer disintermediation](https://virtual-peaker.com/blog/utility-customer-defection/)
. Customer disintermediation, or customer defection, is the circumstances where individual ratepayers bypass access to the centralized power generation created by conventional electric utilities. Customer disintermediation challenges utilities with the potential of decreasing revenue. As such, every new home battery or rooftop array can feel like a customer stepping away from the utility. The Irving Institute notes that third-party DERs can displace utility-owned investment while adding integration costs.

### Solution: Make the Utility the Orchestrator

Customers with distributed energy resources not only still depend on the grid, but can serve as grid assets once enrolled into a demand flexibility initiative. Utilities that run [BYOD programs](https://virtual-peaker.com/bring-your-own-device/)
 and VPPs become the hub that turns private investments into system resources, without putting those assets in the rate base. For example, [more than 10.7 million customers were enrolled in U.S. residential demand response programs](https://www.statista.com/statistics/669480/electricity-demand-response-customers-in-the-us/?srsltid=AYCX9vKE6K4gpGWSQPZL0nOwo9_9RQxTEXrgzZ2l_kpWPPcIQW29zHhn)
 in 2024, yielding approximately [248 terawatt-hours of aggregate load shift](https://www.statista.com/statistics/669502/energy-savings-from-electricity-demand-response-programs-in-the-us/)
 the same year.

## Challenge 6: Marketing Has Always Been A Challenge for Utilities

As regulated natural monopolies, most utilities have never needed to persuade customers to buy anything. Unfortunately, demand flexibility programs can only thrive with a growing pool of active participants; [scalability is critical](https://virtual-peaker.com/blog/scale-demand-response-program/)
 to the long term success of any BTM DER portfolio.

### Solution: Frictionless Enrollment & Invisible Participation

The easiest fix to scaling demand flexibility programs is robust, and continuous marketing efforts. That includes regular customer outreach, meeting customers where they are in their journey, educating them on common misconceptions about customer programs. That also includes simplifying any barriers to enrollment and participation that customers might experience.

To solve for outreach challenges, utilities can:

- Enroll customers at the point of sale or through instant rebates, backed by fast [incentive processing](https://virtual-peaker.com/incentive-processing/) .
- Automate events so participation is invisible; PG&E reports lower opt-outs from automated smart thermostats than from manual devices.
- Rotate cohorts and limit back-to-back event days so no customer carries too much of the burden.
- Use [program management automation](https://virtual-peaker.com/program-management-automation/) for timely, consistent messaging.

## Challenge 7: Market Rules Don’t Credit DERs Fully

Most wholesale markets, including PJM and MISO, credit distributed energy resources for demand response but not for exporting power. PJM’s first draft of its 15 GW emergency backstop procurement effectively excluded load management until a coalition of companies pushed back.

### Solution: Build the Track Record Regulators Need

Firm, verifiable performance is the strongest case for full accreditation. Utilities that can show steady load shapes event after event give regulators and market operators the evidence to treat DERs like other capacity. At the state level, tariff-based and RFP-informed procurement can credit DERs while wholesale rules catch up.

## Challenge 8: Interoperability, Cybersecurity, & Workforce Gaps

Every device manufacturer has its own API, which adds time and cost. Utilities must also protect grid security and customer data. And many lack staff who combine DER technical skills with customer program experience.

### Solution: Standards-Based Integrations & Shared Expertise

To curtail these processes, while safely expediting program deployment, utilities can:

- Choose platforms with established [device partner integrations](https://virtual-peaker.com/partners/device-partners/) and open standards such as OpenADR and IEEE 2030.5.
- Treat each integration as part of the utility’s cybersecurity program, with clear rules for customer data.
- Lean on outside [program design](https://virtual-peaker.com/program-design/) experience while internal teams build [API](https://virtual-peaker.com/apis/) and data skills.

## Conclusion: BTM DERs Have Earned a Place in the Resource Plan

The doubts utilities hold about behind-the-meter distributed energy resources were reasonable when programs fired commands and hoped for the best. With the introduction of functionality like Topline Demand Control, that’s no longer the case. Closed-loop fleet control, control room-grade data, locational dispatch, and automated [customer engagement](https://virtual-peaker.com/platform/customer-engagement-suite/)
 now let grid operators plan around DERs with confidence. With load climbing and new supply years away, the resource already sitting in customers’ homes is one utilities can rely on, not fear.

## FAQs

**What are behind-the-meter distributed energy resources (DERs)?** BTM DERs are energy devices on the customer’s side of the utility meter, such as smart thermostats, water heaters, home batteries, EV chargers, and rooftop solar. The customer, not the utility, owns or controls them.

**Why are grid operators skeptical of DERs?** Historically, DER performance has been uncertain. Load reduction from traditional events fades as customers opt out or homes warm up, and operators often lacked real-time visibility into what the fleet was delivering.

**Can DERs provide firm capacity?** Yes. Fleet-level, closed-loop control holds a steady load reduction for the full event. In one field test, it raised thermostat firm capacity by about 53% compared with a traditional event.

**Do residential demand flexibility programs need to enter the interconnection queue?** Most load-shifting programs, such as thermostat demand response and managed EV charging, use load already on the grid and need no new generator interconnection. Exporting resources such as batteries do, and DOE’s roadmap targets much faster approvals by 2030.

**How do DERs help with data center load growth?** Aggregated DERs can free up capacity at a constrained substation or during regional peaks, creating headroom that lets new large loads connect sooner.

**How can utilities keep customers enrolled?** Make enrollment simple, automate events so participation is invisible, rotate cohorts across events, and pay incentives promptly.

## Glossary of terms

- Behind-the-meter (BTM): Equipment on the customer’s side of the utility meter, owned or controlled by the customer.
- [Bring your own device (BYOD) program](https://virtual-peaker.com/bring-your-own-device/) : A program where customers enroll devices they already own in exchange for incentives.
- Closed-loop control: A control method that feeds live performance data back into decisions during an event, rather than sending fixed commands.
- [Demand response (DR)](https://virtual-peaker.com/blog/what-is-demand-response/) : A program in which customers reduce or shift electricity use during peaks or grid stress.
- [Distributed energy resources (DERs)](https://virtual-peaker.com/blog/distributed-energy-resource/) : Smaller-scale energy devices spread across the grid, such as thermostats, batteries, EV chargers, and solar panels.
- [Distributed energy resource management system (DERMS)](https://virtual-peaker.com/blog/distributed-energy-resource-management-systems-derms/) : Software that lets a utility monitor, forecast, and dispatch DERs as a coordinated fleet.
- Disintermediation: When customers rely more on their own resources and less on the utility.
- [Firm capacity](https://virtual-peaker.com/blog/how-topline-demand-control-reliably-increases-firm-capacity/) : The load reduction a resource can reliably deliver for the full duration of an event.
- Interconnection queue: The list of projects awaiting study and approval to connect to the grid.
- [Localized dispatch](https://virtual-peaker.com/localized-dispatch/) : Dispatching DERs by location, such as a feeder or substation, to relieve specific constraints.
- Model predictive control (MPC): A technique that predicts a system’s behavior and repeatedly chooses actions to reach a target outcome.
- Opt-out: When a customer overrides or leaves a demand response event.
- [Topline Demand Control](https://virtual-peaker.com/blog/what-is-topline-demand-control/) : A fleet-level control approach that combines AI, forecasting, and model predictive control to hold a target aggregate load shape.
- [Virtual power plant (VPP)](https://virtual-peaker.com/blog/what-is-a-virtual-power-plant/) : A network of DERs coordinated by software to act like a single power plant.

### Is Your Grid-Edge DERMS Built for What’s Next?

[Explore Shift](https://virtual-peaker.com/platform/derms-suite/)

About The Author

[https://virtual-peaker.com/author/virtual-peaker-team/](https://virtual-peaker.com/author/virtual-peaker-team/)
Virtual Peaker is a remote-first company based in Louisville, KY, with employees in many time zones. Since 2015, Virtual Peaker has worked to help our utility partners around the world build a better, greener grid through scalable, cloud-based software solutions. Founded by Bill Burke, Virtual Peaker has grown to serve utility DER and demand response management needs, as well as providing resources to help utilities meet decarbonization regulations and grid reliability.

[More About Virtual Peaker](https://virtual-peaker.com/author/virtual-peaker-team/)

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