The Federal Energy Regulatory Commission should require minimum levels of the amount of electricity that can flow between regions, a move that could increase grid reliability and lower power prices, some panelists at an agency workshop said Monday.
There appears to be broad support for the concept, including from a majority of members on a FERC-National Association of Regulatory Utility Commissioners transmission task force, Commissioner Allison Clements said at the workshop.
“Part of the appeal of a minimum transfer capability requirement, in addition to its specific reliability benefits, is that it could prove to be a mechanism for aligning regions around a clear goal,” Clements said. “I'm a fan of this concept.”
FERC Commissioner Willie Phillips said interregional transmission hits his priorities.
“Reliability and resilience because it strengthens the voltage and minimizes the likelihood of load shedding and … affordability because it allows ratepayers to access lower cost generation, and … sustainability because it accommodates the demand for more clean energy,” Phillips said.
FERC’s consideration of setting required transfer capability requirements is partly driven by winter storm Uri in February 2021, which led to historic load shedding and about 250 deaths in the Electric Reliability Council of Texas footprint. ERCOT has only 820 MW of bilateral transfer capacity.
An option some stakeholders have suggested is for FERC to require regions to be able to transfer at least 15% of peak load between neighbors, according to Adria Brooks, a transmission planning engineer in the Department of Energy’s Grid Deployment Office.
Under that requirement, the United States would need to add 114 GW of transfer capacity between regions, doubling the existing amount, she said.
The interfaces with the biggest increases would be the Midcontinent Independent System Operator and ERCOT with 17.3 GW, the New York Independent System Operator and the PJM Interconnection with 16.7 GW, and the Southeastern Regional Transmission Planning area and the Florida Reliability Coordinating Council with 15.3 GW, according to Brooks’ estimates.
Reliability and resiliency benefits alone are sufficient reasons for requiring more interregional transfer capacity, but there are broad economic benefits from more transmission capacity, according to Liza Reed, a research manager for electricity transmission at the Niskanen Center. A 15% transfer level should be considered a starting point for setting a requirement, she said.
With the electric system becoming more weather dependent, increased transfer capacity between regions offers less expensive electricity, the sharing of resource adequacy over wider areas and improved resilience during extreme events, according to Debra Lew, associate director at Energy System Integration Group.
While transfer capacity is an “insurance policy” against extreme events, the capacity would provide benefits daily, Lew said.
Some panelists opposed or were cautious about transfer capacity requirements.
A 15% transfer capability requirement could equate to billions of dollars in ratepayer costs without evidence it would deliver benefits, said Laura Rauch, MISO senior director for transmission planning.
It could be more productive to develop a benefit metric for transfer capability that could be included in existing transmission planning processes, Rauch said.
Improving existing processes would be better than setting minimum requirements, according to Neil Miller, California Independent System Operator vice president of infrastructure and operations planning.
“Given our particular set of needs, the processes we have, as well as the issues that we're trying to address by improving some of those processes, I'm afraid we're not seeing a specific minimum interregional transmission capacity necessarily helping that conversation,” Miller said.
Also, a transfer requirement could add to already rising transmission costs, according to Michele Kito, a supervisor in the California Public Utilities Commission’s electric market design section.
CAISO’s 20-year transmission plan calls for $35 billion in spending while the grid operator’s high-voltage access charge has grown to $16.39/MWh from $3.83/MWh, Kito said.
Non-regional transmission organization areas don’t need minimum transfer capacity requirements, Georgia Public Service Commission Chairman Tricia Pridemore said, pointing to her state’s “robust” integrated resource planning process.
“Our bottom-up approach maintains reliability and does not put upward pressure on rates by constructing unnecessary or duplicative transmission assets,” she said.
However, the Southeastern Regional Transmission Planning organization, which includes Georgia utilities, lacks data transparency and assesses potential interregional transmission using limited metrics, “making it nearly impossible for stakeholders and regulators to show the economic value associated with better transmission planning,” Simon Mahan, Southern Renewable Energy Association executive director, said.
The workshop finishes on Dec. 6.