In the year since FERC issued Order 2222 to usher distributed energy resources into the wholesale energy markets, RTOs/ISOs have been creating market rules to comply with the order.

Advanced Energy Economy on Tuesday hosted a panel of industry experts and regulators who evaluated the progress and potential of the grid operators’ various paths to compliance.

To enable frequently dispatched DERs to participate in the markets, it’s important to have a continuous participation model that gives the resources credit for their full capacity value, said Greg Geller, senior director of regulatory affairs at Enel X North America.

“We can just count what those resources can do to reduce their on-site consumption, but a lot of them are going to be able to inject into the grid as well, and … we need to make sure that they can get credit for that injection,” Geller said. While grid operators such as ISO-NE and NYISO allow that now, “PJM does not have that today, and we’re hoping that as part of 2222 they will have that that single continuous model.”

In January 2020, FERC approved NYISO’s DER model, “which actually has a solution to this that we think works pretty well and we’d like to see other ISOs replicate,” Geller said. (See NYISO DER Participation Model Gets FERC OK.) The commission said that NYISO’s approach enables “heterogenous groups of technologies to aggregate and be compensated for services that they are collectively capable of providing.”

Regional Rundown

Both CAISO and NYISO are expecting FERC to fully approve their DER participation models and any subsequent Order 2222 tariff changes by the end of 2022, said Peter Dotson-Westphalen, senior director of market development at CPower Energy Management. But the commission early this month asked both ISOs to clarify details about the treatment of DER aggregations described in their filings (ER21-2455, ER21-2460). (See FERC Asks Details from CAISO, NYISO on Order 2222 Compliance.)

“We’re looking at markets that may not have significant system market model changes, whether leveraging existing market models to some degree, and whether or not the changes would actually require any significant software development or require other subsequent system changes already planned or in progress by each of the ISOs/RTOs,” Dotson-Westphalen said.

In the case of ISO-NE, stakeholders are currently discussing how the energy and ancillary services market changes would probably not go into effect until 2026, whereas the capacity market changes would be implemented in time for the Forward Capacity Auction 18, which covers the delivery year beginning in June 2027, he said.

In SPP and in PJM , DER aggregations could begin participating as early as 2023, although that could slip to 2024. Both RTOs are currently restricting multi-node aggregations in their proposals, while single-node aggregation may require system changes that could delay implementation, Dotson-Westphalen said.

Clockwise from top left: Allison Wannop, Voltus; Peter Dotson-Westphalen, CPower Energy Management; Prusha Hasan, Advanced Energy Economy; Greg Geller, Enel X North America; and Tricia Debleeckere, Minnesota PUC | AEE

MISO is currently working on a market system enhancement project, he said.

“This is all information that hasn’t really been put down in writing, but has come up in stakeholder discussions, and at this point it’s probably at least going to be 2023 before the market system enhancements project is completed and we would expect to see the participation model resulting from order 2222 to be able to be enacted. But depending on the timeline of that project and other factors, that could also slip further on down the line,” Dotson-Westphalen said.

The go-live date for the MISO region is likely 2025, said Tricia DeBleeckere, assistant executive secretary for the Minnesota Public Utility Commission.

“What that does is set a deadline for the states, essentially for our distribution utilities, to ensure that we have the systems in place to operate a reliable grid when this market product goes live,” DeBleeckere said. “There is value that we can unlock in all the different ranges of DER that are coming onto our system, and whether we utilize that through retail programs or through the wholesale program, as regulators we want options and choices to make sure that we’re picking the most cost-effective resources to participate.”

Location and Size

Two specific issues working their way out in the Order 2222 compliance process — and critical to enabling watershed change —are locational requirements and size settings, said Allison Wannop, director of legal and regulatory affairs at DER aggregator Voltus.

“Order 2222 says that each RTO/ISO must establish locational requirements that are as geographically broad as is technically feasible, but what does that mean?” Wannop said. “In California you can aggregate with energy or ancillary services within a [sub-load aggregation point] and a sublap is very large. There are 24 sublaps in California and each of those is about a gigawatt.”

California’s daily peak load of around 30 to 40 GW provides a very large area over which to aggregate, allowing for a large range of resources that can be brought into those sublap footprints, she said.

“Just to give some real-world context, San Francisco is one sublap, and the East Bay is another one,” Wannop said. “New England is pretty similar … in the size of the aggregations where you can aggregate across a metering domain, which is generally the electric distribution company territory, but then you start to see them get smaller. You have aggregations being limited to a single node and I think that is a really critical point, what a barrier a small geographic footprint for aggregation is.”

PJM limits energy aggregations to a single pricing node of only 5 to 8 MW compared with a gigawatt for aggregation in California, she said.

“We know that a DER aggregation has a minimum size but … the core point is, if you’re limiting aggregation to a single node or an interconnection point, is it really aggregation or simply a path to market for larger resources on the distribution system?” Wannop said.

On the positive side, PJM has a sampling methodology for demand response, which Voltus would like to see applied to other DERs where a subset within a group of homogeneous resources can be metered individually — for example, 100 out of 1,000 devices, and performance is determined based on the performance of that representative sample, she said.

“That puts us on a glide path at least for full DER participation,” Wannop said. “We want to look not just at what does day one implementation look like, but what does it look like in three years, and ideally, we can write rules that allow participation as technology catches up — this idea of skating to where the puck will be rather than writing rules that lag behind the technology and are stuck to the pace of a stakeholder process.”