The value of electricity is never greater than when it is not available. Take California’s historic energy crisis in the early aughts.

Big power users had promised in the 1970s they would reduce energy usage or pay high prices if ever the state grid operator needed help meeting demand, but when the crisis hit in California in 2000-01, many refused to cooperate and conserve energy. The subsequent skyrocketing power bills caused political furor, the recall of Gov. Gray Davis (D) and the election of Gov. Arnold Schwarzenegger (R).

That series of events also led to real demand response programs across the United States, which the California Independent System Operator (CAISO) and other system operators could now depend upon. Instead of asking for help from “interruptible” electricity customers, they began offering big power users remuneration in return for load reductions.

But those demand response programs do not have the flexibility grid operators need today. Coping with today’s dynamic grid and rising levels of variable renewables takes more than just load reduction because demand response is no longer simply about meeting demand peaks, but also managing voltage and frequency fluctuations and handle shifting loads and over-generation.

As a result, demand response is turning into aggregated distributed energy resources, according to a recent report from GTM Research.

Traditional demand response is “heavily entrenched” in wholesale markets, according to the paper. But the increasing penetration of DERs and the capability of providers to deliver aggregated behind-the-meter fleets of them is allowing system operators to seize their value, eventually allowing the private sector and system operators to partner in bringing consumers into energy delivery.

But that valuation will not come quickly, the paper noted, as grid operators must learn to deal with diverse aggregations of resources such as rooftop solar, battery storage, EV batteries, hot water heaters, and home appliance loads.

Of North America’s nine major grid system operators, the report looks carefully at changes being made in four: The PJM Interconnection, the Midcontinent Independent System Operator (MISO), the Electric Reliability Council of Texas (ERCOT), and the CAISO. The purpose is to audit the “market evolution” necessary to “transition to the next-generation energy system,” according to the report.

“There is no one perfect system,” Elta Kolo, grid edge analyst for GTM Research Grid Edge  and lead author told Utility Dive. The two strongest markets for aggregated DERs are PJM and the CAISO. "PJM offers the best prices but the CAISO probably offers more opportunity and the California prices are becoming more attractive," Kolo added. "Pricing in ERCOT and MISO is still low.”

The shift to aggregated DERs as legitimate demand response

“Each of the four systems is moving forward in its own way but there is one shift clearly happening in all of them,” Kolo said. “Aggregators are now working with utilities to be able to stack benefits to provide this new kind of demand response and are already doing so to some extent on some systems.”

The shift is leading to a clear and important trend, Kolo noted. As system operators find aggregated DERs able to provide demand response, they are also designing market mechanisms to allow their use in their demand response markets, mapping out rules to give providers more access, particularly to capacity markets. Listed below are four grid operators and their efforts to incorporate aggregated DERs. 

MISO’s market opportunities for aggregated DERs

MISO is restructuring its capacity market to increase the opportunity for aggregated DERs to benefit from supplying emergency capacity, Kolo said, a major opportunity for utilities on a slowly changing system.

Results of the 2016/2017 Planning Resource Auction show “an overall decline in demand response capacity….[and] significantly higher prices than previous years, indicating the region’s tightening reserve margins for the coming year,” the paper reported..

The changes MISO is seeking, like moving to a three-year forward auction for local resource requirements, could better address resource adequacy needs, Kolo said.

MISO’s ongoing annual review of its markets is prioritizing several aspects of aggregated DER integration, MISO spokesperson Andy Schonert told Utility Dive. Those aspects include aggregation of behind the meter storage, various forms of demand response for emergency capacity, and utilizing storage as demand response.

MISO’s unique challenge is dealing with limitations imposed by the many regulated states in its footprint. Kolo said. Dealing with multiple regulatory jurisdictions “makes change very slow.”

Great River Energy (GRE) offers an example of what state regulatory barriers are holding back in MISO. The Minnesota rural electric generation and transmission cooperative’s load management program includes 110,000 electric water heaters.

That is a huge aggregation of year-round controllable load with a combined storage capacity of more than 1 GW, the paper reported. But Minnesota rules prevent this type of aggregated DER from being bid into MISO’s demand response market.

MISO is, however, “coming to the end of a multi-year process to determine the appropriate pricing of emergency energy," the paper added. That is expected to "stimulate further demand response activation and in turn properly remunerate both load resources and behind-the meter generation."

Whether this will have an impact on the system operator’s struggle with state-level regulators remains to be seen.

“We are working with MISO and other stakeholders to make it possible to aggregate demand response loads,” GRE Member Services Director Gary Connett told Utility Dive.

CAISO’s DRAM opportunities

CAISO’s announcement of its third round of Demand Response Auction Mechanism (DRAM) acquisitions “with double the funding of the recently held 2017 round,” is another indication of grid operators taking demand response seriously, Kolo said. The previous two rounds included multiple bids from aggregated DER providers.

The California Public Utilities Commission (CPUC) earlier ordered CAISO  to transition its demand response from utility control to market control while completing a “bifurcation” of load-modifying and supply-side demand response resources by 2018, the paper reported. As a result, almost 1.5 GW of Southern California Edison’s available demand response has already been integrated into the system.

The Aliso Canyon gas leak also propelled the move to make demand response, including aggregated DERs, available to the markets, Kolo said.

Though contained, the fuel supply disruption created by the leak continues to threaten the supply of electricity available to the Los Angeles region from its gas-fueled power plants. That threat heightened CAISO’s recognition of the new demand response’ value, as evidenced by its call for a third round of DRAM bids, she said.

Whether aggregated DER at scale will be available to significantly participate in alleviating any Aliso Canyon-provoked threats to the system is not clear because “the timing of DER projects is not up to the ISO,” CAISO’s spokesperson Anne Gonzales told Utility Dive. “If natural gas shortages occur, the grid will pull from any available resources.”

CAISO has advanced more rapidly than other grid operators in its efforts to make resources on the distribution system more visible at the wholesale transmission system level, Kolo said.

With the bifurcation of demand response ordered by the CPUC, market mechanisms will control utilities’ load-modifying and supply-side demand response resources. This will allow the system operator to more readily assess the moment to moment capabilities of aggregated DERs at the distribution level, she explained. “This has system level implications and will help in balancing and managing the system more efficiently.”

The main value of aggregation for the CAISO is how it increases visibility of the DERs, CAISO’s Gonzales said. The details of how visibility will be increased remain to be worked out when the products and services are bundled and bid into the system, she added.

PJM performance rules for demand response resources

PJM’s new performance rules requiring demand response resources to be valued for their ability to supply year-round capacity are another example of a system operator moving to aggregated DERs as demand response, Kolo said

Such rules could be a barrier to a traditional demand response resources like reducing air conditioning load because that can only be cut down in the summer, she said. But aggregated DERs would be available year-round to serve as demand response so the new PJM rules favor it.

These performance rules could represent a big step forward for aggregated DERs in the demand response market beginning in 2017. PJM’s last five capacity auctions have engaged between 10 GW and 12 GW, according to the report.

Aggregated DERs could capture a lot more of the GW in the 2017 auction, for 2020/2021 delivery, because it will only include “capacity performance” products, Jason McGovern, PJM spokesperson, told Utility Dive.

For PJM, the  new performance rules are just one example of how it is leading the way with market products, the paper reported. Transitioning to capacity performance remains challenging but will lead to a better balance between demand response and generation. “The evolution to a single, year-round product will further refine the opportunity for aggregation of resources to clear capacity that meets performance requirements.”

ERCOT’s push to integrate DERs

Earlier this year, ERCOT disbanded  its Distributed Resource Energy and Ancillaries Market (DREAM) Task Force aimed at studying ways to integrate DERs. The action appears misleading at first glance, Kolo acknowledged, with the Texas grid operator appearing to lose interest in integrating DERs. But in actuality, it was terminated because it completed its “high level analysis to define the different approaches that could be used to integrate more DER[s].”

“ERCOT is actively seeking more concrete proposals from would-be providers and suggestions for how to integrate various resources and the nitty gritty of how DER mechanisms would work in the markets,” Kolo added.

The goal is to identify the framework necessary to enable market participation by aggregated DERs and to create “the operational visibility necessary to ensure reliability,” ERCOT spokesperson Robbie Searcy told Utility Dive. Some proposals are already in the works, but it’s not clear what direction Texas will take in regards to more DERs on its system. Greentech Media pointed to a proposal from Shell Energy Services to bring larger gas and diesel distributed generators into the market as emergency resources. But more work will need to be done when it comes to smaller behind-the-meter assets.

For ERCOT, changes to its Emergency Response Service (ERS), a form of load modification that is its only capacity market could help make DERs more available” Kolo said.

ERS is procured three times per year for four-month standard contract terms and for 30 minute and 10 minute response times, making it “a very expensive form of capacity,” she said. “ERCOT is considering other ways to have capacity available, including through mechanisms closer to day-ahead or real time markets.”

ERS is important in protecting grid reliability “when available capacity and reserves are not sufficient to serve demand,” Searcy said. But ERCOT will await specific proposals for revisions from the ongoing ERS rulemaking process at the Public Utilities Commission of Texas. 
 

Moving ahead in different ways

Because of diverse historic constructs, infrastructure and generation resources, each system has different drivers, meaning their market designs will evolve differently, Kolo said.

“Electricity markets have made progress, slowly maturing and gaining confidence that flexibility from distributed energy resources is a vital resource for system planning and operation,” the paper reported.

The technology to bring aggregated DER into wholesale markets is there, Kolo said. “What is needed is a market design that allows them to participate and be properly remunerated.”

The challenge and the opportunity are in developing a market design that defines which AgDER fit which market mechanisms, she said. Not every technology can provide regulation or frequency response or capacity. “The market design has to target each technology to the right market mechanism.”