By Rich Heidorn Jr.

WASHINGTON — The changing resource mix and growth of distributed generation means planners must adopt new models and new mindsets, speakers said at NERC’s biennial Reliability Leadership Summit on Thursday. The event attracted more than 120 RTO officials, utility executives and regulators at the Mayflower Hotel.

David Ortiz, deputy director of FERC’s Office of Electric Reliability, said the growth of renewable generation and distributed resources requires planners to broaden their focus.

“Our general assumption that we can disaggregate this analysis into bulk [power system-] and distribution-level analyses that interact in well-defined and predictable ways is losing its validity,” he said. “Studies of seasonal peak load and traditional measures of resource adequacy and capacity no longer provide a general representation of the reliability of the electric system.”

‘Natural Experiments’

Ortiz said planners should learn from “the natural experiments that are taking place before us.”

“We can’t randomly assign solar panels to houses and then take a look [at the impact]. They’re just there. But what we can do is pose and assess alternative explanations for observed facts. By doing this in a rigorous way, we can make sure our analysis of the situation is technically sound and is therefore a good basis for decision-making.”

For example, he said, one could hypothesize that the lack of coordination between distributed energy resources and the BPS will cause operators to dispatch plants uneconomically. “We have all the data. We can take a look and determine whether or not that is correct,” he said, posing a second hypothesis. “Or maybe, during times of high distributed energy resource output, transmission constraints will be relieved.

“In the past … it was possible to consider a handful of cases. If we’re going to appropriately and effectively deal with the kind of changes that are coming, it’s going to be necessary to consider not a handful of cases or hundreds, but potentially thousands of different scenarios spanning the complete space of uncertainties in generating resources, access to supporting infrastructure [and] contributions of distributed energy resources.”

The shift will require “prioritizing insight over precision,” Ortiz said, citing the aphorism, “All models are wrong, but some are useful.”

“Models [can] highlight tradeoffs in system investments and approaches to solving problems such as transmission constraints, need for voltage support, integration of DERs, management of inverter-based resources, [greenhouse gas] and criteria pollutant emissions, and other factors. By doing so, planners can support a robust stakeholder process based on a common understanding of the various tradeoffs and then develop appropriate plans.”

Mark Ahlstrom, vice president of renewable energy policy for NextEra Energy, said the increasing sources of uncertainty may require a shift in system operations.

“We still don’t seem to have the commitment to get into actual probabilistic system operations in terms of … dispatch,” he said. “It keeps coming up. It’s complicated. Its computational. But I think that’s something we have to consider … in the future.”

The Impact of Inverters

Peter Brandien, vice president of system operations for ISO-NE, said planners need a “mindset change” as inverter-based resources grow.

“We used to get a lot of services we naturally took for granted from the rotating mass of the generators. … Now we’re trying to [determine] exactly what those services are and put controllable devices on the system to mimic what we used to get from this rotating mass. … We need a mindset that we’re almost protection control engineers on this big machine…

“We have to understand that this system probably needs to be tuned on a regular basis as the resources change. And I think until we accept that concept, then I fear we’re going to run into problems and we’re always going to be one event behind in addressing the problem.”

NERC CEO Jim Robb expressed similar concerns over the organization’s response to the August 2016 Blue Cut wildfire, when 1,200 MW of solar disconnected from the grid. The October 2017 Canyon 2 fire resulted in the loss of more than 900 MW of solar. (See NERC to Try Again on Inverter Rules.)

“The sad thing about that was it took the Blue Cut fire and gigawatts tripping offline for us to realize that we really do have a problem … when I think every engineer knew that that problem was out there,” he said. “But it took an event to mobilize us to start to deal with it.”

Becoming Proactive

David Morton, chairman of the British Columbia Utilities Commission, said regulators must change their “capacity” by adding engineering talent and “culture” through a willingness to take more risks. For its part, Canada is beginning to use regional modeling “to understand the potential economic benefits of reinforcing limited interregional interconnections,” he said.

“There’s a wealth of analysis of the many benefits of transmission. However, not all the benefits attributable to transmission are exclusive to the actual route or corridor in which it’s constructed,” he said. “There’s often no one to speak, much less decide, on the merits of a given project on behalf of the entire regional market it will affect. Transmission planning and construction should anticipate development of generation resources and access to lower-cost resources in order to avoid significant economic congestion.”

David Weaver, vice president of transmission strategy and planning for Exelon, sounded a similar theme, referring to offshore wind targets set by state officials in New York, New England and PJM. “With these really aggressive state goals, we need to get more proactive about what transmission investment is needed to be able to reliably deliver those renewable resources.”

Weaver asked whether planners also need to consider the impact of climate change and sea level rise. “Do we need storm-hardening standards?” he asked. “Do we need to build our assets at higher elevations above sea level?”

Spotlight on the West

Many of the changes discussed at the summit are being felt most acutely in the West.

Rich Hydzik, senior transmission operations engineer for Avista, said he’s seen changes he never expected.

“In the 15 years I’ve worked in system operations, I’ve never seen a coal plant [output] go up and down regularly. But I see them do it probably six months of the year now between day and night. And that is a big change,” he said.

He also cited California’s excess daytime solar capacity. “If you’d have told me 10 years ago [that] we’d see big time power flow out of California almost year-round during certain hours of the day, I would never have believed it.”

Mark Rothleder, vice president of market quality and renewable integration for CAISO, said that scheduling day-ahead resources on an hourly basis is no longer sufficient because of how much solar output can change within an hour.

“We’re looking at going to a 15-minute granularity … in the day-ahead time frame. We already do it in the real-time [market], but we’re finding it’s increasingly necessary to do that in the day-ahead. We’ve got 7,000 MW of behind-the-meter solar; 12,000 MW on the grid side. So, we see those evening and morning ramps as a significant challenge.”

Minnesota Public Utilities Commissioner Matthew Schuerger said the growth of distribution-level solar means his state needs to incorporate distribution planning into its integrated resource planning, “where they haven’t traditionally been.”

Planners also are having to look differently at how they procure reliability services. “When you planned for capacity, you got everything else: energy, voltage support, frequency response and ramping flexibility,” Schuerger said. “We’re moving out of that world.”

One thing that won’t be changing, said Thad LeVar, chairman of the Public Service Commission of Utah, is the IRP process itself.

LeVar said the proposed addition of a day-ahead market in the Western Energy Imbalance Market has “real potential.”

But he said his state won’t be signing up if it means the end of IRPs.

“I think I’m safe in predicting that Western states like Utah are not — at least in the near future — going to express an interest in joining an RTO that has authority over resource adequacy and system planning,” he said. “The IRP model is going to continue to be a bedrock principal in the Western U.S. in the near term.”