U.S. power industry experts Dec. 6 wrestled with potential requirements for minimum levels of interregional electric transmission capacity as federal regulators seek to fortify the nation's power grid against extreme weather events.

Federal Energy Regulatory Commission staff convened a two-day workshop on crafting a minimum transfer requirement after members of a joint federal-state task force expressed broad support for the idea in July.

Most regions of the U.S. lack the ability to transfer more than 10% of a neighboring region's peak load, a U.S. Department of Energy official noted during the first day of the workshop.

Insufficient transfer capacity makes transmission systems more vulnerable to extreme weather events such as Winter Storm Uri, a storm that in February 2021 knocked out power for millions of customers in Texas who are served by a largely siloed electric grid. The Electric Reliability Council of Texas Inc. has less than 1 GW of interregional transfer capacity, which is less than 1% of the system's peak demand, according to the DOE official's presentation.

On the second day of the FERC-led workshop, panelists addressed the thorny issues of cost allocation and the potential market impacts of new power lines designed, in part, to avoid future grid outages.

Concerns over market impacts, cost allocation

Texas featured heavily in the Dec. 6 discussion, as the state is uniquely situated within the broader U.S. bulk power system. ERCOT is largely exempt from FERC's jurisdiction over interstate transmission and wholesale sales of electricity because the state has limited interconnection ties with neighboring systems.

Some workshop participants called for a baseline minimum transfer level of between 15% and 25% of a neighboring system's peak load.

But Travis Kavulla, vice president of regulatory for Houston-based independent power producer and retail provider NRG Energy Inc., pushed back on the idea of requiring such a standard for Texas. Kavulla noted that a 15% minimum transfer standard for ERCOT would require the system to add roughly 10 times its existing transfer capacity.

"You're talking about multiplying it by 10 from the status quo and then you're talking about an involuntary regime of cost allocation," Kavulla said. "I honestly can't think of anything that would stop the conversation that needs to happen in its tracks more than that."

Kavulla said FERC would be better served by establishing a process in which merchant interregional transmission developers can propose high-voltage direct-current transmission interties with the broader grid and then negotiate bilateral contracts with willing customers.

FERC could then approve those projects through emergency orders issued under Sections 210 and 211 of the Federal Power Act, as it has previously done for ERCOT's limited number of existing grid interties, Kavulla said.

"There should at least be an opportunity for merchant cost allocation to be undertaken in this exercise before the commission even gets involved," Kavulla argued.

Kavulla said any remaining capacity for merchant transmission lines that is not purchased through bilateral contracts could be subscribed through an auction process.

Kavulla also stressed that FERC should be mindful of the potential market impacts that could result from a minimum transfer requirement. ERCOT's wholesale power market construct relies on scarcity pricing to ensure grid reliability, meaning that more interregional transfer capacity could erode price signals designed to ensure resource adequacy.

"Adding even just 1,000 megawatts of import capacity, it's very easy to erode the economics of a new generator, a new storage facility, a new [direct-current] intertie, all of which are effective substitutes for one another," Kavulla said.

Kris Zadlo, chief development officer for the Houston-based merchant developer Grid United, said FERC should work to ensure that costs are broadly allocated for interregional transmission lines to account for market impacts.

"If you're moving several gigawatts of power back and forth between regions, you're going to be impacting pricing on a very large regional basis," Zadlo said. "So, in order to capture this properly, you're going to have to have a large area to socialize the costs because these lines are expensive."

Arnold Quinn, chief economist for Vistra Corp., an independent power producer and competitive retail electricity supplier headquartered in Texas, added that customers will be more amenable to projects with broad benefits.

"Where it's a simple mandate like a 15% minimum interregional capacity, I think people are going to have real problems with broad socialization costs because it will feel like they're being asked to pay for something where they don't know whether it will deliver benefits," Quinn said.

'Some bare minimum'

Rob Gramlich, president and founder of the consulting firm Grid Strategies, urged FERC to establish some level of required interregional transfer capacity as a baseline.

"Purely voluntary-based transmission will necessarily under-plan the grid," Gramlich said. "Some bare minimum would also be helpful."

Gramlich also said FERC should acknowledge that more interregional transmission will inevitably create winners and losers among market participants.

"There are a lot of vertically integrated utilities, and they're wonderful companies and people, but when they own generation that would lose money from competing generation coming in from the next region, they obviously don't support that happening," Gramlich said.

Kansas Corporation Commission member Andrew French added that FERC should clarify its expected outcome if the agency does finalize a minimum transfer requirement.

"Requiring a process without providing any guidance on the expected outcome may not produce enough results," French said.

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