SAN DIEGO — State regulators generally expressed support for minimum requirements on interregional transfer capacity Wednesday, saying they believed it could produce cross-border transmission projects where FERC Order 1000 failed.

But defining the minimum and ensuring it doesn’t result in inefficient, single-purpose transmission lines remain concerns, the regulators said during the fourth meeting of the Joint Federal-State Task Force on Electric Transmission. The session, which concluded the National Association of Regulatory Utility Commissioners (NARUC) Summer Policy Summit, focused on interregional transmission planning and project development and FERC’s April Notice of Proposed Rulemaking (RM21-17), which would require planners to use longer time horizons and consider multiple scenarios. (See Christie Talks up Flexibility of Transmission NOPR.)

Lessons from Uri

FERC Chairman Richard Glick said the need for more interregional capacity was demonstrated during Winter Storm Uri, when “a couple hundred people [in ERCOT] died, literally, just because they didn’t have access to power.” In contrast, SPP and MISO, which also lost many generating units, were able to minimize blackouts because they were able to import power from PJM and other regions, Glick said.

FERC Commissioner Mark Christie noted that PJM was able to export 6 GW of energy this week despite approaching its projected summer peak of 149 GW. “Interregional transfers do have reliability benefits, no question about it,” he said.

Several state members of the task force said minimum transfer requirements could simplify cost allocation, one of the most vexing barriers to new transmission.

“I don’t know of any regulators in the West who aren’t willing to pay for reliability and resilience,” said Utah Public Service Commission Chair Thad LeVar.

“It simplifies the cost allocation to set the minimum [requirement]. It also simplifies the benefit calculation by basically assuming benefits,” said Ted Thomas, chair of the Arkansas Public Service Commission. “If you can study rigorously and get the level set right, I’d rather spend that money than trying to come up with a formula that measures the impact of what might happen [in the future] and use that to come up with a cost allocation methodology. I think the minimum transfer benefit solves a lot of those other problems.”

He added: “We’re in a foot race between implementing the solution and the next time we get hit. And laying down a marker is important. If somebody gets hit and we didn’t act, it’s on us.”

Thomas said FERC should set such levels first in the organized markets. “If the non-RTOS don’t like it, you know, or want to study it or want to see what happens, that’s their choice. [I would] point out when you do that, you’re picking up a pair of dice and hoping” for the best.

Kansas regulators made a straw proposal to set the minimum at 10% of each region’s peak load. “That was essentially based on the experience during Winter Storm Uri — the level of demand that had to be interrupted, and the level of imports that we relied on,” French said. “I don’t know that we’re here saying that’s the right number. I’ve seen numbers as high as 40%.”

North Carolina: No Thanks

A numerical requirement would not be welcome in North Carolina, said North Carolina Utilities Commissioner Kimberly Duffley. Although a small part of the state is within PJM’s territory, most of it is not part of an RTO.

“Areas of the country like the Southeast — where through the IRP [integrated resource plan] process the generation is located close to load — may not need this type of interregional transmission, or they just may need less of this transfer capability,” she said.

Duffley also said the Southeastern Association of Regulatory Utility Commissioners (SEARUC) states would oppose “top-down” planning, preferring a “bottom-up” process that preserves regional flexibility.

“When I say regional differences, I mean market structures, natural resources, job development, just the geography of the different regions, to name a few,” she said, noting that Duke Energy does not measure market efficiency benefits based on LMPs, unlike PJM and other RTOs. “A one-size-fits-all approach is not an appropriate way to incent new transmission.”

She also urged caution on FERC establishing a minimum set of benefits to be considered in evaluating new transmission. “There are some states that are opposed to that, but I’m not taking any position on it here today,” she said.

Responding to Duffley, FERC Commissioner Allison Clements said that for interregional planning to be successful, two entities must come to an agreement despite having different resources, methodologies and benefit determinations. “The Order 1000 interregional coordination process kind of just assumed those differences would go away; they don’t go away,” she said.

Role for NERC

Duffley endorsed Michigan Public Service Commission Chair Dan Scripps’ proposal that any minimum transfer requirement be a “definition” rather than a number, “so that non-RTO states are not burdened with a too high of any type of minimum.” Christie, who has warned against FERC being overly prescriptive in its rulemaking, also expressed support for a definition.

Vermont Public Utility Commissioner Riley Allen said he was “intrigued” by a minimum transfer capability but feared that it could lead to “stopgap solutions that are kind of singularly focused on one category … undercutting the benefit cost or the economic case for a larger solution.”

If the focus is on reliability and resilience, he said, perhaps NERC should “identify what that level should be and whether it should vary between regions.”

LeVar said it was unclear how a minimum transfer capacity would affect the WestConnect and NorthernGrid planning regions, which have little or no cost allocation authority. “If that’s an issue that’s going to be pursued, the NERC reliability standards process is a great process for an issue like that,” he said. “WECC can be a valuable tool … because they don’t have an agenda other than reliability.”

Glick also hinted at a role for NERC, saying a FERC rulemaking could be based not just on Federal Power Act sections 205 and 206 — the source of much of FERC’s authority — but also under its reliability authority under Section 215, which the commission used to delegate to NERC the power to impose mandatory reliability standards.

FERC Commissioner Willie Phillips said he hoped the national laboratories’ efforts to quantify the resilience benefits of new construction would provide a foundation for a FERC rulemaking. Under current rules, he said interregional projects have often foundered because neighboring regions could not agree on benefit calculations. When “those projects fall out … we do wash, rinse, repeat — things don’t get built.” Phillips said.

FERC Commissioner James Danly, the lone dissent on the April NOPR, questioned whether FERC could make the “showing” necessary for the commission to issue any requirements.

“I have yet to hear anything that makes me think we’re going to be able to make that showing for us to actually impose something,” he said. “I don’t believe that every wrong can be remedied under the statutes that we administrate.”

Thomas and French disagreed, citing Uri. “I frankly think we have a pretty strong evidentiary basis right now that something needs to be done,” French said.

Pushback on ROFR Reversal

Another subject of discussion was the NOPR’s proposal to reverse Order 1000 and allow incumbent transmission owners a federal right of first refusal (ROFR) if they give an unaffiliated company a “meaningful level of participation and investment” in the project. (See Ratepayers Protest FERC Retreat on Transmission Competition.)

“I can’t say we have consensus in the West about this … but I can speak for myself and the PUC,” said California Public Utilities Commissioner Clifford Rechtschaffen. “We strongly oppose the idea of a conditional ROFR. We think it’s a step backwards.

“We’ve had experience with competitive bidding in California: It’s worked,” he said. “It’s reduced prices. It’s been successful. We have a lot of regionally cost-allocated projects. There’s no real evidence that in states with ROFRs, that they have more regional projects, or that costs are lower.”

Rechtschaffen said FERC should consider other steps to address “legitimate concerns” about unanticipated effects of Order 1000’s ROFR provision. “At a minimum, our recommendation is that FERC leave it up to each state to determine whether or not transmission should be developed competitively,” he said.

Kansas’ French said he had “very complicated” thoughts on the issue. “But we have seen tremendous cost savings in our region, as well, over the last few years on several projects. And it seems the wrong time to turn away from that,” he said.

Rechtschaffen said he welcomed the NOPR’s proposals for more transparency in local transmission planning and said they should include “repair and replacement” or supplementary projects, which receive little or no scrutiny under regional planning processes.

Rechtschaffen said these “utility self-approved” projects represent half of all investor-owned utility spending in RTOs and ISOs.

“In 2022, our largest utility, PG&E, forecast $1.2 billion on capital spending; 88% of that will be spent on utility self-approved projects,” he said. “We heard a similar story yesterday on a panel from Greg Poulos,” executive director of the Consumer Advocates of the PJM States.

Appreciative of FERC Outreach

Several of the state commissioners praised FERC for establishing the task force and including in the NOPR a requirement that planners seek states’ agreement on cost allocation.

“We’re very pleased in terms of the direction and tone of the NOPR,” said Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille. “We’re very appreciative because you did put a lot of effort into understanding and hearing the concerns that were expressed by not only us but other people.”

Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille | © RTO Insider LLC

Brown Dutrieuille said she supported FERC’s proposal to consider an expanded set of benefits in transmission planning and cost allocation but said they should not be “mandatory nor exclusive.

“I do have some concern that list of potential benefit metrics includes metrics that may double count the same benefit,” she said.

“It’s really hard to be frustrated with FERC when they’re actually listening to you,” said Maryland Public Service Commission Chair Jason Stanek, a former FERC staffer. “When I first read the NOPR, I felt like the dog that caught the car. So be careful what you wish for, because FERC is saying if you want a seat at the table, pull up a chair, and you have 90 days to sort it out amongst yourselves.”

Stanek also called on East Coast states to coordinate on building transmission to serve their offshore wind projects, saying New Jersey so far is “going it alone” under PJM’s state agreement approach. (See PJM Sees Wide Range of Costs in NJ OSW Tx Proposals.)

“That is not the way for us to be developing transmission along the coast,” he said. “We have to have clear open communication coordination between the RTOs.”

LeVar said “it’s obvious FERC went to great lengths to try to preserve flexibility and state input.”

“What I don’t know … is what impact this different planning scenario would have on momentum towards RTO development in the West. … I think it’s a real issue.”

French voiced a similar worry, saying FERC should ensure that any new requirements not interrupt ongoing intraregional work. “I have some concerns that could inadvertently press a pause button on some of the important work that’s taking place,” he said.

The task force’s next meeting is scheduled for November at the NARUC annual meeting in New Orleans.