Demand Response Can Boost the Economics of Microgrid & DER Projects yet Participation has Stagnated

For those seeking to gain resilience by deploying a microgrid or other distributed energy resources (DER), participating in wholesale demand response markets can yield extra income and help support the grid during energy emergencies or high demand periods.

Under demand response programs, utility customers can adjust their electricity consumption to help balance the power grid. Microgrids can even island to free up power for the grid, and get paid to help out during peak demand periods or crises.

Yet microgrid and DER providers who can take advantage of demand response programs in wholesale markets aren't stepping up. In fact, participation in most markets had stagnated or decreased, according to a new report from the nonprofit Energy Systems Integration Group (ESIG), “Gap, Barriers and Solutions to Demand Response Participation in Wholesale Markets.”

Adding resilience and demand response

“Whether it’s a microgrid or someone with a behind-the-meter battery at home, people place value on that resilience benefit,” said Derek Stenclik, lead author of the report.

“If you’re doing that, you have all the technology you need to offer it into markets and get compensated and everyone shares in the benefit,” he said.

In spite of studies that show the potential for demand response, especially given the grid’s growing need for resources, demand response capacity is below 7% of peak load across U.S. wholesale markets, according to the executive summary of the report. Participation is low even though deployment of other clean energy resources– wind, solar and batteries –is growing.

Demand response players want consistent market rules

The ESIG report, based on interviews with aggregators and others trying to sell demand response into the wholesale market, yielded a consistent theme, Stenclik said.

“They like consistent market rules and large markets with the same rules across a footprint,” he said.

For all load serving entities, both within Independent System Operator (ISO) programs and within retail load-serving entities, peak demand savings did not expand between 2017 to 2022, said the report. About half of potential peak savings is in the ISO jurisdictions, it noted. Demand response participation across states showed enrollments of between 2% and 8%, and averages of 6.5% nationwide.

There’s significant untapped potential for demand response that could help with grid flexibility and capacity needs, the report said.

“Interestingly, there appears to be little correlation between participation levels and the market structure and whether a customer is in a vertically integrated utility or wholesale market regions,” said the report. “In fact, if any trend emerges, it is that participation rates tend to be higher in states where programs are administered primarily at the retail level.”

Challenges to attracting more participation in demand response

The ESIG report identifies five challenges to deploying demand response:

The demand response markets are undermined by fragmentation and inconsistent rules.
System operators, state regulators and consumers don’t have experience and knowledge about demand response technology and programs.
Communication and metering requirements tend to be onerous.
System operators don’t have detailed, publicly available information on demand response performance during emergency events, which undermines confidence in the resource.
Weak financial incentive–and even disincentives–exist for demand response at the wholesale market, load-serving entity and consumer levels.

Aggregators and demand response providers said they want a consistent set of rules across large areas that have big loads.

“Whenever they see uniformity around marketing, metering or communication, it helps them build out technology,” Stenclik said.

Penalties slow demand response rollouts

During ESIG’s interviews, one aggregator said that the n the U.S., but some recent rule changes have created obstacles, Stenclik said. Over the last several years, PJM’s demand response participation has been flat or declining. The problematic rules include provisions that impose penalties if demand response providers don’t show up when the resource is needed.

“That changes the risk that aggregators and demand response providers have. That’s one of the components of why we’ve seen the market retract,” Stenclik said.

Another obstacle in PJM is how demand response contributions are measured. This is called capacity accreditation, he said.

Capacity accreditation slows demand response

For example, wind power is seen as less reliable, so it gets credited for 38% of its capacity in PJM’s territory. Demand response is credited with 77% of capacity in the capacity market and gas plants are about 80% of capacity, Stenclik said. In the past, demand response was credited with at least 90% of capacity in the capacity market, he said.

Another challenge is lack of confidence in demand response as a resource.

During interviews with ESIG over the past several years, industry members have said that demand response can’t be counted on.

“They’re not sure if people will change their thermostats or if resources will be available,” Stenclik said.

Data about demand response programs needed

Data about the performance of demand response during emergencies would help combat this lack of confidence, but it’s not always easy to find that data.

“Performance data from recent events will help inform accreditation so we can build confidence overall so that people are willing to do market programs and design,” he said.

In wholesale ISO markets, typically the ISO will be charged as the market design team, and a stakeholder process is generally required that includes demand response providers and other stakeholders. Generally, a committee will propose new rules and revisions, and the ISO will submit a plan to the Federal Energy Regulatory Commission, which will decide whether the rules are appropriate.

In the regulated space, utilities develop programs and submit them to regulators. Public utility commissions generally support demand response programs and push utilities to offer them more quickly, he said.

The need for stronger incentives

The report also cited weak incentives as barriers to demand response uptake.

Consumers with controllable loads or behind–the-meter storage argue that it’s not worth it to participate in demand response for a small amount, say $20 a month in savings, Stenclik said.

“You hear incentives aren’t there and consumers don’t want to be bothered,” he said.

A lack of adequate incentives also hurts those who are aggregating resources into virtual power plants (VPP). That’s because the financial benefits of VPPs have to be spread out among many consumers and the technology providers who offer thermostats, electric vehicles and other equipment.

“It’s not that the resource isn’t cost effective, but you’re spreading it out across a lot of people. It’s hard to have enough of an incentive to get the end user engaged,” Stenclik said.

A surprise finding in the report

One surprise resulted from the interviews: Many people said that demand response programs are most successful when an individual at the ISO or utility champions it.

For now, more of those champions may be needed to make the most of demand response and help the microgrid industry take advantage of the benefits.

“As traditional power plants retire and renewable resources increase, demand response technologies offer a flexible, fast acting solution for balancing supply and demand,” the report said. “Unlike new generation, which takes years to develop, demand response can provide immediate support to the grid.”