By Michael Kuser and Jason Fordney

Grid operators and regulators on Tuesday hashed out the complexities of integrating distributed energy resources (DER) during the first session of a two-day FERC technical conference on boosting the role of energy storage in wholesale electricity markets.

FERC ordered the conference in February after issuing Order 841, which requires each RTO/ISO to develop a “participation model” allowing storage resources to provide any energy, capacity and ancillary services of which they are capable and be eligible to set clearing prices as both buyers and sellers. (See FERC Rules to Boost Storage Role in Markets.)

A morning panel brought together RTO/ISO representatives who discussed the operational intricacies of integrating DER into wholesale markets, focusing on approaches to aggregating the market participation of the small-scale resources to make them manageable for grid operators.

“DER aggregation requires a level of cooperation you don’t see to this point, not even in demand response, because of the impact DER can have on the system,” said John Goodin, CAISO manager of infrastructure and regulatory policy. “It’s important if you’re going to establish DER aggregation, that you impose both size and boundary constraints; that’s something that the ISO has done.”

CAISO set a 20-MW size limit on aggregations participating in its market, although individual resources can range from 0.5 to 1 MW. Any resource exceeding 20 MW becomes a participating generator subject to a different set of requirements, Goodin noted.

Nodal vs. Zonal

Pointing to the dual nature of DER as both transmission and distribution resources, Jeff Bladen, MISO executive director for market services, said it’s important to distinguish between the challenges of taking load off the system and putting supply onto the system.

“As we think about aggregation groups, it needs to be more than how do we do security-constrained aggregations for the transmission system, but how are we going to manage potential restraints at the distribution level,” Bladen said.

“Let’s remember we are a nodal system,” cautioned Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor. He encouraged industry stakeholders to think about developing a sustainable model for significant expansion of DER.

“It’s critical to think about how [aggregation] works in a nodal system,” Bowring said. “It’s not possible to predict congestion; it’s not possible to predefine constraints that exist or don’t exist in a zone.” Any configuration larger than a node is “way too big for aggregation,” he said.

Michael DeSocio, NYISO senior manager for market design, said while New York does allow zonal aggregations, none is participating in the market today.

“So as much as we hear it’s important, we don’t see much of that actually occurring in New York,” DeSocio said. “As we thought about making sure the values were there for DER and making sure the price signals incentivize DER to locate in the right places, it occurred to us that nodal made the most sense.”

Henry Yoshimura, ISO-NE director of demand resource strategy, noted resources coming into the New England system are primarily solar and energy efficiency and the RTO’s settlement-only construct allows any resource up to 5 MW to participate in the wholesale market. “Because there’s no size limitation, there’s no real need for aggregation,” he said.

Goodin said CAISO sees significant benefits to aggregation.

“We don’t have a single node,” Goodin said. “You can have an aggregation across the [sub-load aggregation point], across multiple nodes, and why is it advantageous? One, it allows for the providers to actually go out and solicit and pull together, aggregate, meaningful-sized customers, meaningful from the ISO’s perspective … the key thing is that aggregations allow for the right sized resource.”

Andrew Levitt, PJM senior market strategist, said, “We think there are benefits to aggregation in ensuring open market access to resources of all sizes, including resources smaller than our 100-kW minimum highest threshold.”

National Solutions?

Commissioner Cheryl LaFleur asked why there should be different processes among the different regions.

“Shouldn’t we try to solve the coordination process once and then sort of spread that, as opposed to developing six ways to do it?” LaFleur asked. “Maybe we should standardize more. Can we skip a step and figure it out?”

“I don’t know that the rules are the issue,” DeSocio said. “I think really what the main difference that we’ve observed in New York is what is the posture of each of the different distribution utilities, what is their ability to actually see into their own grids.”

Goodin added, “If we are going to enable DER to really flourish, you have to address some of the things that are outside the walls of the ISO and the authority of an ISO through FERC.”

He enumerated three priorities: access to capacity markets and capacity payments; reducing interconnection barriers and cost; and creating more clarity around allowing DER to tap multiple value streams and simultaneously provide grid services to the both ISO and distribution domains.

“In my opinion, those are the much more weighty issues — resource questions, interconnection, multiuse — than sort of the day-to-day functionality of managing these DER and settling these DER resources in the wholesale market,” he said.

Yoshimura said the primary issue is a lack of “consensus in the industry as to how distributed energy resources ought to be operated, if at all. And the struggle that any ISO would have is, whereas we model transmission constraints, I don’t think any of us model distribution constraints.”

MISO’s Bladen said, “We like to think of ourselves as a service provider, to the states in many respects, that our job is to take the fleet that regulators are designing and implementing through their integrated resource plans and to optimize that, to get the most value you possibly can out of that fleet across a broad region.”

“We don’t know yet what best practices are going to look like, don’t know what the dominant DER technologies will be, and that what you have in front of you are a number of companies interested in identifying best practices,” Bladen said.

Bowring said: “We should have the same rules. The fact there’s all this complexity doesn’t mean we shouldn’t have the same set of rules. They will evolve, but we to need start in the same place where everyone is facing the same issues.”

Head Banging

During the afternoon panel, regulators from California, Ohio, Pennsylvania and D.C., as well as others, carried on the discussion of DER aggregation, including issues around reliability and markets. The conversation illustrated the newness of the technology and the many challenges of coordinating state regulations, markets, and the requirements for utilities.

FERC commissioners noted the difficulties for states developing separate policies and approaches that will need to be integrated into wholesale and retail markets. The panel covered how federal and state regulators — and others — can better coordinate on the issue.

“This is a case where all the technology might be ahead of the regulators,” LaFleur said.

FERC Chairman Kevin McIntrye put it simply, telling the state regulators, “We want to avoid messing anything up.” He asked about the negative impacts of individual and aggregated DER on states and said the discussion should help build a robust evidentiary record.

California Public Utilities Commission (CPUC) President Michael Picker recommended a “DER roadmap” similar to one developed by his agency, which looks at grid architecture, DER planning, and developing appropriate rates and tariffs. California is a leading state in DER integration, including efforts by the CPUC and CAISO.

“There are a lot of challenges here,” Picker said, adding that the CPUC’s effort has uncovered issues around safety for workers and emergency responders who have to deal with DER equipment. The effort has also identified operational issues around DER integration, including congestion in the distribution system, and is mapping the distribution system similar to how RTOs map transmission systems.

“We have a grid system that was never designed for a lot of two-way flow,” Picker said. The CPUC effort is “acknowledging that these are trends that are going to happen,” he said. He noted that other states will be able to learn from and “leapfrog” California’s efforts.

“I would recommend you let us bang our heads against those brick walls,” he told FERC, pointing to CAISO’s Energy Storage and Distributed Energy Resources program, now in its third phase. (See CAISO Storage, DER Plans Progressing.)

Different States, Different Rules

The regulators noted their states have different policies with different cost impacts that will need to be integrated into markets. They also hold differing views on allowing DER to participate in wholesale and retail markets.

Public Utilities Commission of Ohio Chairman Asim Haque discussed an issue raised by several regulators: that DER should not be compensated twice — in retail and wholesale markets — for providing the same services.

But Haque added that DER owners and operators should be left to decide how they choose to be compensated for behind-the-meter DER, such as staying on a net metering tariff or participating in the wholesale market through aggregation if that is more profitable.

“Their goal is to maximize the value of that resource,” he said. “That is acceptable to us as well.”

Ben D’Antonio, counsel for the New England States Committee on Electricity, said distribution utilities in New England are going to drive many of the outcomes as DER resources are added, but “the operational impacts are not known at this time.”

“We are actively working on it, but some of ours states have some pretty ambitious goals and others do not,” D’Antonio said. He said it’s unclear how quickly DER will grow in New England, but he thinks the integration effort will need to be consistent with the integration and interconnection requirements of the distribution utilities, who have a “critical gatekeeping role.” Utility decisions will be driven by the tariffs, requirements, and incentives that federal and state regulators put in place, he said.

”We support the idea of DER being able to take part in both wholesale and retail markets,” said Tammy Mitchell, deputy director of the New York State Department of Public Service. But she thinks much work remains to develop the rules and protocols, including the double-payment issue, which could increase ratepayer costs.

D.C. Public Service Commissioner Willie Phillips said he thinks the city can benefit from DER, but “it’s really a resource-by-resource analysis.” The city has seen no negative impact from its load control programs, for example, he said.

“Here in the district, people are dying to get at this,” but the compensation issue must be solved first, Phillips said.