By Rory D. Sweeney and Rich Heidorn Jr.

WASHINGTON — Panelists at day 2 of FERC’s technical conference on distributed energy resources (AD18-10, RM18-9) debated whether electric distribution companies (EDCs) should serve as gatekeepers or facilitators for resources seeking to participate in energy markets.

EDCs and their allies said they should have control over DERs on their systems, while DER supporters called for strict criteria on utilities’ ability to block DERs.

The first day of the conference focused on how RTOs and state regulators can craft policies that encourage DER to participate in wholesale markets while minimizing the burden on grid operators. (See RTOs, Regulators Set Course for DER Market Participation.)

Conflicts of Interest?

Audrey Lee, vice president of energy services for residential solar and storage provider Sunrun, said EDCs should only be allowed to block DERs through a showing that they would endanger system reliability.

“I think we need some specific examples [of problems] before creating any rules on this,” she said, adding that utilities seeking to install their own resources could have conflicts of interest. She noted that CAISO’s Tariff gives EDCs a deadline for reviewing DER applications and reserves the final decision for the ISO.

Maria Robinson, director of wholesale markets for Advanced Energy Economy, said distribution companies “should be facilitators, not a gatekeeper … preventing the ability of [DER] aggregators to enter.”

She suggested EDCs identify zones that can absorb DERs without reliability problems. If they are to review DER applications, EDCs should be given deadlines requiring them to act quickly, and rejected applicants should have the right to appeal to the RTO/ISO or FERC, she said.

“The vast majority of issues should be worked out with the interconnection agreement” between the resources and transmission operator, she said, adding that reviews should be done only once for each interconnection.

Pete Langbein, manager of demand response operations for PJM, also said interconnection studies should consider DERs once, as opposed to “iteratively.” The studies “may evolve over time” to provide the information needed to evaluate DERs’ impact, he acknowledged.

Interconnection Agreements not Enough

But David K. Owens, retired executive vice president of the Edison Electric Institute, said EDCs need to know DERs’ attributes to understand which ones could cause system disturbances. “Just having a list of aggregators is not sufficient,” he said. “[Distribution] utilities have to know when DERs are deployed. … Interconnection agreements alone will not do it.”

Jeff Taft, chief architect for Pacific Northwest National Laboratory, said DERs become potentially more disruptive as their density increases and that the effects are more significant on distribution lines. “The closer you get the edge of the distribution system, the more you see the volatility caused by DERs,” he said.

Taft said that although distribution lines are generally designed as radials rather than the “mesh” network of transmission, they are “dynamic” because EDCs reconfigure their systems daily. “A resource that may be running through substation A, a few minutes later may be running through substation B.”

State ‘Opt-out’

David Crews, senior vice president of power supply for East Kentucky Power Cooperative, said EDCs must have authority to protect their systems to avoid imbalances on distribution feeders. He disagreed with projections that DERs will be evenly distributed, saying they are more likely to be clustered in wealthier areas where residents can afford solar panels and storage. “It can cause problems; I’m not saying it will.”

Crews also said state regulators should have the ability to “opt out” from allowing retail customers to participate in wholesale markets. EKPC joined PJM in 2013 based on an agreement with Kentucky regulators that state residents would not be able to participate in the RTO’s markets, he noted.

Crews said there is little use of solar and storage among EKPC’s 16 distribution utilities, which use five different makes of meters. “For us to go through the administrative cost of developing a tariff is burdensome to our members” at current penetration levels, he said. “If our members have enough [resources] out there that they want it, we’ll do it.”

Cross Purposes

Mark Esguerra, director of integrated grid planning for Pacific Gas and Electric, warned of conflicts between DERs transacting with RTOs/ISOs and ones providing services to distribution companies. “You could have a situation that none of the parties — the ISO and the distribution utility — get the response they’re looking for.”

Esguerra said the 10-day EDC review deadline suggested by some “could be a challenge without more sophisticated modeling tools.”

Missouri Public Service Commission Chairman Daniel Hall, vice president of the Organization of MISO States, said state regulators should set criteria for DER registration and that EDCs must have authority to approve DERs on their systems. “All distribution systems are unique and the people who know them best are the people on the ground, which is the utility and the utility’s regulator.”

Hall said clear criteria on when EDCs can reject DERs will keep EDCs honest. “That gets us beyond the gatekeeper/facilitator” debate, he said.

There was general agreement that RTOs/ISOs, EDCs and aggregators will need to develop new communication protocols to manage higher levels of DERs. Hall urged FERC to allow regional differences by allowing each RTO and its stakeholders to develop their own rules, subject to commission approval.

Visibility

Gerald Gray, the Electric Power Research Institute’s (EPRI) program manager for information and communication technology, said that although some utilities do not have supervisory control and data acquisition (SCADA) at all substations, the expansion of advanced metering infrastructure means “there is a lot of granular data providing visibility” on distribution systems.

But Matthew Glasser, a director at Consolidated Edison, said his company and other New York utilities do not have the visibility they need to manage DERs. “Communication with DERs now is low-tech. It’s phone and emails.”

Joseph Ciabattoni, PJM’s manager of markets coordination, said the RTO typically communicates — via phone — with transmission operators, which do the same with their DERs.

Brandon Middaugh, senior program manager for distributed energy for Microsoft, said ISOs and RTOs have “very limited visibility into distribution.”

Visibility also was the subject for the first panelists of the morning — five of eight of whom were from grid operators or utilities. As Portland General Electric Vice President of Transmission and Distribution Larry Bekkedahl put it, system operators “can’t manage what you don’t measure.”

Bekkedahl said the information would allow utilities to avoid overbuilding capacity to the “worst-case scenario,” as is done today, and instead “put in as much capacity as necessary.”

Jens Boemer, the principal technical leader of EPRI’s Transmission Operations and Planning Group, said he learned from experiences in his native Germany that any data that can be collected “relatively easily” should be done “as early as possible” because it becomes more expensive to do it later. He also said it’s important to stop combining DER performance with load because it masks the additional services it provides.

Unpredictability

Clyde Loutan, a principal on renewable energy integration for CAISO, said DERs contribute to the unpredictability of load. “We have system operators trying to control a grid with unpredictable demand and variable supply, so we’re always in reactive mode,” he said.

Donnie Bielak, PJM’s manager of reliability engineering, called that “a scary thought,” because the RTO watches CAISO as a barometer of what’s to come on DER issues. “We need an absolutely accurate load forecast to operate the system and operate it economically,” he said.

Ganesh Velummylum, a senior manager of system analysis at NERC, placed the responsibility with transmission owners. He said they should ensure they have the necessary data before they agree to interconnect the resources.

“It starts with the TO,” he said. “Once we have the data, we can do studies. … We have to start with collecting the data through the interconnection process.”

‘52-Hz Problem’

Lack of data can create wider issues, as Boemer illustrated through what he called the “52-Hz problem” in Germany. Many DERs were programmed to trip off at frequency thresholds that are very close to normal frequency, which meant that small and normal frequency variations could cause widespread loss of DERs on the system.

It’s an issue PJM is currently looking at by increasing resources’ “ride-through” requirements. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)

None of Germany’s transmission operators had modeled that problem in its studies, Boemer said. But the industry was able to identify the risk through published research and knowledge of system operations and operating standards. A catastrophic trip never occurred, but the German government set up a retrofit program to reprogram the trip settings for more than 400,000 distributed photovoltaic resources, he said.

Benefits

Panelists also said DERs have the potential to benefit systems by addressing reliability issues and perform important grid services. In fact, the variability is useful, Bekkedahl said.

“What used to be very stable generation is moving on us,” he said. “Now that we’ve got variable generation going on, it’s really nice to have variable load.”

“The technology is there” to set up support for power, frequency ride-through and voltage support on the system, Velummylum said.

“They all interact,” he said. “I think it’s important that we look at the collective support DER can provide.”

DERs can also provide non-wires solutions, Bekkedahl said, noting their role in the cancellation of the Bonneville Power Administration’s I-5 Corridor Reinforcement Project. The 80-mile, $1.2 billion, 500-kV line would have helped Oregon utilities manage summer peaks when they were receiving no generation support from south of Portland.

“If Oregon was hot, California was hotter,” Bekkedahl said.

But subsequent DER development in California has changed the situation and eliminated the need for the transmission project. “Can we find non-wires solutions? I think absolutely,” he said.

Unlocking such solutions will require encouraging DERs to participate in wholesale markets so they are committed and required to provide information, Bielak said. “The only way you can determine if you can rely on them is with enough data,” he said.

Long-term Projections

FERC staff also asked panelists to discuss how to develop long-term projections, and many panelists looked to state policies because they drive development. Marcus Hawkins, the director of member services and advocacy for the Organization of MISO States, noted that a MISO study ended up relying on publicly available data because a voluntary survey of DER owners performed by a consultant received low participation.

“I think it starts with having a good understanding of the status quo” of what’s on the system today, Boemer said. He outlined “hosting capacity” studies that analyze distribution systems to identify potential thermal issues that could limit DER deployment on feeder lines. The analysis creates a heat map “that can indicate how much DER may be able to interconnect to certain areas on the distribution grid,” Boemer said.

DERs in Planning

The morning’s second panel focused on including DERs in system planning. Velummylum, who remained for the second panel, had a quick response. He held up two reliability guideline studies NERC has published that discuss DERs. “Folks, it’s out there,” he said.

Ning Kang, a staff scientist at Argonne National Laboratory, said the lab is working on improving its models through analysis it performed by studying smart inverter functions and focusing on how applicable standards impact performance.

Brant Werts, Duke Energy’s lead engineer for DER technical standards, said his company only considers the impact of losing DERs in specific areas. During the recent solar eclipse, he said the company lost a significant amount of DER but also knew it was coming and prepared for it. “We don’t believe that we would lose all of our DER at one time,” he said.