When FERC issued Order 2222 in September, then-Chair Neil Chatterjee declared it a “landmark … that paves the way for the grid of tomorrow” by opening RTO/ISO wholesale markets to participation by aggregations of distributed energy resources.

Realizing the potential of DERs — including storage, electric vehicles and rooftop solar — however, will require a new level of coordination among transmission operators, distribution utilities and aggregators to protect reliability.

In few places are the stakes higher than in sunny Arizona, which ranks fifth in solar capacity among U.S. states, with solar power providing almost 8% of total generation.

“We’re always going to feel obligated to make sure we’re looking out for the reliability for our customers,” Jacob Tetlow, Arizona Public Service’s senior vice president of operations, told WIRES’ virtual spring conference Tuesday. “In Arizona we look at that like it’s the difference between life and death for our customers. It’s hot here. It’s 117 [degrees Fahrenheit] for days on end. That’s not the kind of place where you can take a lot of risk when it comes to reliability.”

APS, which has a summer peak load of about 7,000 MW, has about 1,000 MW of utility scale solar and another 1,000 MW of distributed solar, with 123,000 residential solar locations, representing about 10% of the company’s customer base.

“When you have a gigawatt of renewable energy at the utility scale and a gigawatt of residential solar, you can see where that becomes a pretty major component of the system,” said Tetlow, who added that distributed generation is essential to meeting APS’ goal of 100% carbon-free power by 2050.

A ‘Moment’ for DERs

Chatterjee cited studies projecting that the U.S. will add 65 GW of DER capacity by 2025; others have said the growth could be as large as 380 GW by that time. He also cited the potential for EVs to provide energy, spinning reserves or frequency regulation while plugged in. (See FERC Opens RTO Markets to DER Aggregation.)

Bud Vos, president of Enbala, which makes software for real-time control and optimization of DERs — including the ability to aggregate DERs into “virtual power plants” to supplant gas peakers — believes the hype is justified.

He told WIRES that Order 2222 will open wholesale markets for DERs in the same way Order 745 did for demand response. “We’ll look back on this moment and say this was a moment that fundamentally changes the game,” he said.

Vos said Enbala’s work in North America, Australia and Europe illustrates how DERs provide new options for system operators, such as “flexing up” storage to soak up excess power on the system.

“Now when you start thinking about going into the world of voltage impacts — the ability for assets to actually change their inverter position at the same time while they’re doing capacity or demand response moves — well now we’re actually serving two different grid services at the same time,” he said.

But the reliability stakes are higher under Order 2222 than the DR order, he said. “When you start putting distributed energy resources in the forms of solar or storage or electric vehicles on the distribution grid, you are fundamentally creating a power system problem, which is very different than just pure load drop.”

Visibility

Tetlow said one of the major reliability concerns with DERs such as rooftop solar is limited visibility of the resources’ status. Because utility-scale solar is centralized, it provides less of a challenge to system operators, Tetlow said. “You have control of the resource. You can view what’s happening.”

Not so with residential solar.

“We’re one of the few utilities with production meters on each residential solar array. But even then, it’s not real-time information and … even if you have a smart inverter, the ability to control it is limited at best,” he said. “I think there’s a lot of value in the aggregation because in some ways aggregation actually gives you more visualization into what’s going on.”

Vos said software is essential to provide data and transparency regarding DERs’ activity. “So if there’s a situation where an asset does need to behave differently than the aggregator needed it to because the distribution company had to flex it in a different way, then the data should show the aggregator what actually happened, and it should also show the distribution company what actually happened,” he said.

“Of course, you then have to figure out what the economics are of that, and you have to figure out what the policy is around that. But I believe these two things should go hand in hand; a good solid interconnection design, rules and policies along with transparency and data should show us the way so that everyone can benefit appropriately in the value chain.”

Lessons Learned

Tetlow said APS has been surprised by some of what it has learned in recent years. “If you go back a couple years ago, you would have heard anecdotally, ‘Well, 30% would be the most penetration you could put on a distribution feeder. And then we quickly realized that a lot of those [assumptions] didn’t make any sense, because it really becomes situationally dependent. For example, if the solar happens to be very close to the substation, it has very low impact. If it happens to be at the end of a very long feeder — we operate a very large service territory with a lot of rural areas — it can have pretty significant impacts to voltage. And frankly, you could have other customers harmed because the voltage at the end of the feeder might go high during times of low usage and that actually trips off a solar inverter.”

Several years ago, in an area that was very heavily penetrated with both utility-scale and residential solar, APS experienced voltage problems between its sub-transmission and distribution system, Tetlow said. “It was springtime and [there was] very little system load. We would actually have to push the 69-[kV] system high and the 12-kV [lines] would come low. … You end up running around with capacitors and regulators trying to fix the voltage.”

The experience has led to changes in APS’ system planning.

“We have learned over the years that we study our system not just at peak output but [also] at peak renewable generation,” Tetlow said. “So for us our peak demand will always be around 4 or 5 [or] 6 p.m. Peak renewables is about 12:30 or 1 in the afternoon. So doing your system studies starts to look very different at certain times of the year in areas with heavily penetrated renewables. It’s just a reality of ensuring reliability in both states.”

Clear Roles Needed

Tetlow and Vos said maximizing the value of DERs while minimizing the risks requires distribution utilities, aggregators and residential customers to have clear roles in the system. Vos said interconnection rules need to spell out when the distribution company can take control of DERs for reliability. In Australia, he said, the rules allow the distribution company to take control of an asset “under certain conditions. Frequency [problems] is one. Voltage is another.”

Ready or not for EVs?

EVs also will present challenges and new opportunities as they grow in scale, Vos said.

He expressed concern that utilities conducting pilot projects of 20 or 100 cars may be unprepared for the coming transition. “They’re coming fast, and if I were a utility executive, I would be doubling down on how much I can embrace and help bring electric vehicles into the fold,” he said, citing their potential for load growth and value as sources of stored energy and controllable loads.

“These things are coming in the thousands, so we as an industry better get our arms around this, or we’re going to … see an impact on reliability.”

Increasing Complexity

Order 2222 required RTOs to submit compliance filings revising their tariffs by July 19. But earlier this month, the commission granted requests by MISO, PJM and SPP to delay their filings by up to nine months. ISO-NE also said it will seek a delay. (See FERC OKs Delay on Order 2222 Compliance.)

Kristin Swenson, senior market development adviser for MISO, told the WIRES audience that the RTO needed more time to complete necessary software upgrades and work with stakeholders.

“This is an awful lot of people to get on the same page, especially when you talk about an area as large as MISO. We know that we will need regulators to come along with us. We have to be able to not just say, ‘Here’s what we’re doing,’ but we have to engage in conversation about what we should do. So that’s a process,” she said.

The process was slowed by the pandemic, which eliminated in-person meetings. “There’s [no opportunity for] hallway conversations outside the stakeholder meeting where you kind of hash things out and realize: ‘Oh wait, we were talking [about] the same thing; we just used different language,’” she added.

Tricia DeBleeckere, planning director in the regulatory analysis division of the Minnesota Public Utilities Commission, said the growth of DERs and other changes in the electric industry are straining regulators’ capacity.

“There’s a lot of new territory we’re wading into, both from the distribution system as well as potentially new constructs for regulation,” she said. “The scope, pace and depth of the work has dramatically increased over the last five years, and I think it’s only going to get even more complicated.”

Tetlow agreed that the grid is “complex, and the reality is we’re making it more complex.”

“That’s not necessarily bad,” he added. “If done right, there’s tremendous opportunities there. But everything needs to be done with the lens of reliability.”