By Robert Mullin

PORTLAND, Ore. — Stakeholders last week expressed concerns over how the Western Interconnection’s four transmission planning organizations can align their separate regional processes to identify projects that could provide interregional benefits.

“I think we need to have a bit of a rethink about the relationship between planning processes — either at the planning regions or at [the Western Electricity Coordinating Council] — [and] the interregional coordination process” among the four Western planning groups, Fred Huette, senior policy associate with the Northwest Energy Coalition (NWEC), said during the Western Planning Regions’ annual interregional coordination meeting.

The Feb. 23 meeting brought together stakeholders and representatives of CAISO, ColumbiaGrid, Northern Tier Transmission Group (NTTG) and WestConnect to discuss interregional coordination under FERC Order 1000. The order requires transmission providers to participate in a planning process that identifies the most cost-effective solutions to transmission needs and allocate costs based on estimated benefits.

No Interregional Projects Identified

In the 2016/17 planning cycle, the four groups have not identified any interregional projects driven by regional needs. Like most parts of the country, the West is experiencing stagnant or declining loads. None of the regions declared a reliability, economic or public policy requirement for any transmission projects, let alone one that crosses regional seams.

NTTG and WestConnect received submissions for three interregional projects — SWIP-North (Western Energy Connection), Cross-Tie (TransCanyon) and TransWest Express (TransWest Express) — intended to move renewable energy from the inland West toward California. The projects are based on the prospect that California will need more renewables, but no requirement has been identified yet.

All three are seeking cost allocation through WestConnect. NTTG said Western Energy Connection did not submit details on SWIP-North in time to be considered for cost allocation during the current cycle, while the other two projects have not sought allocation.

“The conclusion that came out of [the study process] is that our draft regional plan will support the addition of any one of those interregional projects, but those interregional projects are not necessary to satisfy NTTG’s needs,” said Craig Quist, PacifiCorp director of area transmission planning and vice chair of the NTTG Planning Committee.

‘Areas of Concern’ Dissolved by Load Reductions

Larry Furumasu, senior planning engineer with ColumbiaGrid, said his group’s study showed that 15 previous “areas of concern” within the Pacific Northwest were ameliorated by load reductions last year.

Neil Millar, CAISO executive director of infrastructure development, said the ISO’s transmission plan this year is a “bit unique in being so light.” He said loads are declining because of increased behind-the-meter generation — largely rooftop solar.

“We think we’ve at this point exhausted economically driven transmission opportunities,” Millar said. “So we’re really at a bit of a calm before the storm until we move forward with transmission planning to address broader renewable portfolio standards, with [California’s] 50% by 2030 goal in particular.”

‘Big Picture’ on Economic Upgrades

On the theme of economically driven projects, Ellen Wolfe of Resero Consulting asked WestConnect a “big picture” question: How is a project determined to be “economic?”

Wolfe posed the actual case of a CAISO transmission path in Valley Electric Association’s Nevada service area that rings up about $60 million worth of congestion annually in the export direction. The ISO has little motivation to relieve the constraint because the trapped generation means lower costs for California consumers, although in-state renewables are more likely to be curtailed.

“So Nevadans would actually win if this constraint was relieved, because they would see this renewable energy flow to Nevada,” Wolfe said, asking how such a project would get identified and paid for if the ISO was not motivated to do so. “I didn’t see in [WestConnect’s] study description how that kind of project would pop up. It’s really a project in the CAISO footprint that would benefit WestConnect.”

Kegan Moyer, a consultant representing WestConnect, said he wasn’t familiar with the constraint in question, but that “high levels of congestion on a regionally significant element” would prompt the group to explore potential upgrades. He noted, however, that there is “very, very little” congestion within WestConnect, a U-shaped region that includes all or most of Nevada, Arizona, New Mexico, Colorado and Wyoming.

Wolfe pressed her point.

“So that’s the question: If the constraint’s not in WestConnect, but it benefits WestConnect [to relieve it], how does anyone ever decide to relieve it?” she asked.

Moyer replied that WestConnect would not have the “purview” to plan within the Valley Electric system.

“It seems like a great project for interregional coordination, but I don’t really see how it gets actually coordinated,” Wolfe said.

Inherent Challenges

Dave Smith, director of engineering and operations at TransWest Express, wondered what is preventing the current interregional planning process from performing more like a regionalized process that would come about with the expansion of CAISO into PacifiCorp’s territories and other parts of the West.

CAISO’s Millar pointed to the inherent challenges of having multiple organizations work together on a project-by-project basis as opposed to a more “coordinated, programmatic” approach under a single organization.

“I don’t believe the ISO message is that the interregional process flat out won’t work, but we do [have] a higher … expectation for success on an opportunity in a broader footprint as opposed as to having to move through all the different reviews [and] approvals,” Millar said.

“I think one of the biggest challenges with regards to interregional transmission projects is that they’re all tied to the regional process,” Moyer said. “And for an official [interregional transmission project] evaluation to really have full meaning behind it, there has to be a regional need identifying each of the applicable regions.”

Solution?

NWEC’s Huette offered a possible solution: that the four organizations consider more closely coordinating their regional planning processes, rather than just collaborating on the interregional process. The theory: Interregional projects could be the most cost-effective way to collectively serve regional needs, which are currently identified through discrete, if not isolated, regional processes.

“If we get too process-bound here, I think we may lose some opportunities or delay some opportunities that might be worth looking at,” Huette said.

Smith said it would be helpful to have some kind of scorecard showing where each group is in its evaluation of an interregional project. “You all say it’s in different places, but where is it?” Smith said.

Allocating Costs, Calculating Benefits

Smith also contended that the planning groups should start thinking about cost allocation, perhaps drawing up a sample project to demonstrate how costs would be shared according to benefits.

“I would encourage that this group move forward with those discussions. …Waiting for the next annual meeting is a long time away for that discussion,” he said.

“All four regions … we have a common tariff,” ColumbiaGrid President Patrick Damiano responded. “There is a common tariff language framework that’s been approved through FERC that talks about how cost allocations take place for interregional transmission projects.”

“Everybody won’t be adopting California’s [cost allocation], if that’s what you’re asking,” PacifiCorp’s Quist told TransWest Express’ Smith.

Gary DeShazo, CAISO director of regional coordination, said he didn’t think the issue was so much cost allocation but rather how to calculate the benefits of a project.

“You can’t do cost allocation unless everybody can agree to the benefits,” DeShazo said. “So if you’ve got four different ways to calculate the benefits across the four different planning regions, then there will be questions asked. Am I paying more from this project than I should be?”

Non-Transmission Alternatives

Julia Prochnik, director of western regional grid planning with the Natural Resources Defense Council, said she saw no mention of non-transmission alternatives in the groups’ presentations. “I know that right now that there wasn’t any identification of need in regional plans, but it would be something nice for the future to see how some of these other components could address different scenarios,” she said.

Damiano explained that ColumbiaGrid has a complex mix of FERC-jurisdictional, federal and municipal members — with only its FERC-jurisdictional members subject to Order 1000.

“We didn’t identify any Order 1000 need, so there was no reason to look at non-wires alternatives under Order 1000, at least for ColumbiaGrid,” Damiano said.

CAISO’s Millar joked that he was “crushed” that Prochnik didn’t see his reference to non-transmission alternatives buried in his slides.

“But we do look for those solutions and we do have a separate section in the transmission plan now where we identify all the places [where] we are already relying on the emergence of preferred resources,” he said, referring to non-emitting generation.

As the meeting wrapped up, Huette raised the need for stakeholders to be kept regularly informed about the interregional planning process, even if not required to be part of every step of the process.

“I’m not asking for a lot here,” he said. “I’m not asking for every single detail, but I think it would be helpful for those of us not involved in those discussions to hear a bit more about what is happening on the interregional level among the four planning regions during the year.”