This is a challenging time for demand response programs operating in PJM Interconnection: The grid operator is poised to integrate new capacity performance rules that will complicate market participation, cleared DR resource volumes are down and revenues have been declining.

In the residential demand management space, utilities are increasingly seeking to bolster offerings and customer service as a way to ensure the resource remains robust. Now, AEP Indiana Michigan Power is demonstrating that some of the same concepts can be transferred to the more staid industrial and commercial market, where even sophisticated buyers still need assistance.

The utility's Demand Response Service Emergency Program was recently recognized by the Peak Load Management Association as a "Program Pacesetter" in the group's annual awards. By directly contracting with customers, as well as leaning on aggregators to expand the program's reach, I&M has about 110 customers which combine to provide 55 MW of load curtailment capabilities.

According to PLMA, there are three primary reasons for the program's success: customer performance obligations are simple, based on requirements developed by PJM, and the use of load management aggregators has helped expand the scope. But I&M's ongoing efforts to work with customers and curtailment service providers (CSPs) to aggregate resources "is the key piece in all of this," the association said in highlighting the program.

"We've been doing interruptible programs for decades, even before we joined PJM," said Michael Weinstein, a principal customer program support analyst at American Electric Power. "We see value in interruptible programs--especially emergency interruptible programs."

When I&M joined the PJM marketplace, the utility was vertically integrated and wanted to continue using interruptible resources for planning. That request led the Indiana Utility Regulatory Commission to open a docket and ultimately determine the utility's demand management programs would need to align with PJM requirements to take advantage of capacity resources for planning purposes.

The emergency demand response program, which operates in PJM as a "pre-emergency" resource, "really took off when we started working with [curtailment service providers] to get program off the ground," said Weinstein.

Aggregators expand program reach

Industrial or commercial customers can sign up for the program either directly with I&M or with a curtailment aggregator: The back-end functions the same either way, utility officials say, sometimes causing confusion with customers who don't realize they will ultimately have to sign contracts with I&M as well as the CSP.

"We do allow customers to sgn up directly with us, or they can use a CSP — we have no preference," said Scott Shudick, a customer services account manager principal for Indiana Michigan Power. Among his responsibilities is to help implement the utility's demand response rider for Indiana Michigan Power. Ultimately, I&M is responsible for bidding the capacity into PJM's market. By leaning on aggregators to expand the program, and the two officials said they are creating multiple value streams and grid benefits.

The CSPs may offer other energy management services to customers as well, though Weinstein stressed the utility is "wholly agnostic" as to which route they ultimately choose.

Shudick and Weinstein participated in a demand response dialogue hosted by PLMA earlier this month.

“If a customer in another territory signs up directly with PJM, they sell their capacity resource, the DR resource, into the market. There are market benefits as well as bulk electric system benefits, but the incumbent utility doesn't really get much benefit—at least not directly," said Weinstein. "So when we sign them up through AEP's account, what we can do is then claim that as a capacity resource."

I&M uses a four-year average clearing price to determine the value of load reduction, which Weinstein said takes some of the volatility out, and also puts a floor price in place to help recognize resource values even outside PJM marketplace.

"It's win-win," he said. "We can continue to use that capacity resource in our planning and it also helps our customers as they're not having to build or buy capacity elsewhere ... we're all sharing the value of the resource."

Changes on the horizon

Among the biggest challenges to managing the program, said Weinstein, is "keeping abreast of all the changes in PJM."

Years after the polar vortex paralyzed PJM Interconnection's grid, when bitter cold temperatures forced about 20% of generation offline and left the operator scrambling to meet demand, new rules are about to be fully implemented that place stricter requirements on capacity resources in exchange for more generous rewards.

For demand response, the key issue in the new rules is PJM's decision to require all capacity resources be available year-round. That's a sticking point for many demand response programs, like HVAC cycling, which are seasonal.

The new requirements will be fully implemented in the next auction, held in June for the 2020/2021 delivery year. Results released last year showed 10,348 MW in demand response resources cleared the auction – the lowest point in years, partly due to phasing-in of the stricter requirements over a few years. Demand response clearing the capacity auction peaked at 14,800 MW in 2012, for 2015/2016 delivery.

"A couple of years ago PJM rolled out operational changes: they changed the lead time, changed how we measure some of our resources, and now we have capacity performance coming up, which is going to change us from a summer-only program to an annual program," said Weinstein. That means a lot of the effort is spent keeping customers informed while also navigating the regulatory side.

And it's not just customers: Shudick said another challenge is educating I&M's own staff, "so we're giving customers the right information."

In PJM's last capacity auction, of the roughly 10,000 MW of demand response clearing the auction only 600 MW was bid as the new capacity performance production. The grid operator saw about 4,700 MW of demand response bid as capacity performance but which failed to clear.

In the coming auction, only resources with those capacity performance attributes will be allowed to participate. 

"We need to get filings out to commissions and orders out to change the program," said Weinstein. "But it's also making sure the existing customers in the program still qualify, and making sure we community effectively, giving our customers a chance to adjust their load reduction processes accordingly."

“Some of these customers are going to need to look ... at what they needed to reduce to in the past and adjust. There's also going to be a different measurement method," he said. The changes will include a shift in how winter requirements are calculated: the customers will need to guarantee a load drop measured against a baseline, rather than simply reducing demand below a certain point," said Weinstein.

The new system will require customers to know what their load is going into a demand response event, and know how far they can reduce it, Weinstein explained. "It's a challenge, both explaining the new rules and working with customers to make sure they can be in compliance, or possibly adjusting how much load they wan to bid into the system."

“Although those rules are changing as we speak," he said.