By Robert Mullin

PORTLAND, Ore. — Bonneville Power Administration officials on Monday likely dispelled any lingering doubts about their intent to join the Western Energy Imbalance Market (EIM), but it will take some time to address stakeholders’ questions about how the move will affect them.

BPA last month circulated a letter to its customers seeking comment on a plan to sign an implementation agreement with CAISO this September as a first step to joining the EIM. While that agreement would be nonbinding, it would also commit the federal power agency to shelling out a $1.8 million nonrefundable implementation fee, the first of $30 million to $35 million in estimated startup costs. BPA will not issue its final record of decision on becoming a member until late 2021, just months before it plans to join in March 2022. (See BPA Marches Toward EIM Membership.)

A proposal attached to that letter detailed the raft of benefits of joining the EIM, including more efficient generation dispatch, as well as improved transmission usage, congestion management and voltage control. BPA also touted the ability to use the EIM as a “non-wires” solution to address congestion and avoid new transmission builds while also helping to identify areas of needed investment.

Some BPA “preference” customers attending the last in a series of “EIM stakeholder” meetings Monday sought to get into the weeds of what EIM membership would mean for them and their workaday relationships with the federal power agency. Those customers represent the Pacific Northwest’s publicly owned utilities, which get first priority for the energy coming off the Columbia River Power System managed by BPA.

Tom Haymaker, manager of energy planning and operations for Clark Public Utilities in Washington, said he’d been “wrestling” with the issue of the “interplay” between the region’s existing hourly bilateral market and the EIM’s intra-hour market — and how BPA would make decisions about offering energy into each after joining the EIM.

“We’re going to be a player in the real-time hourly market, but we won’t be in the intra-hour market,” Haymaker said. “Are we going to be precluded from getting access to certain kinds of power from Bonneville because you’re wanting to put that into the intra-hour, or is there going to be some sort of process where we would have an opportunity to perhaps buy that power ahead of time that you were planning to offer up in the intra-hour?”

Steve Kerns, BPA’s director of grid modernization, offered a roundabout answer. After explaining that the agency already trades in a “very complex set of markets,” he recounted a previous trip to SPP, whose market participants told him that real-time bilateral markets started to “go away” after roll-out of the RTO’s Integrated Marketplace.

“That’s almost the inevitable outcome here … So that means we have to be smarter about how much we want to take to real-time,” Kerns said. “If we think that the [bilateral] market depth in general is going to be less than what it is pre-EIM, we’re going to have to make different decisions about day-ahead marketing than what we did in the past and also consider what we want to roll into the Energy Imbalance Market.”

Kerns said that, like hydro-heavy EIM member Powerex, BPA is not going to stop trading in the bilateral market. “They participate in the EIM, but they still participate in the real-time market as well.”

Haymaker expressed concern that BPA would at times “park” power, reserving it for sale into the EIM rather than making it available to its preference customers.

“We certainly don’t feel we would need to do that in order for the EIM to pencil out,” said Russ Mantifel of BPA’s transmission marketing and sales division. “Joining the EIM does not make future policy decisions about what we’re going to offer up. In order for us to achieve the benefits, I think we don’t have to make the sort of zero-sum decisions that you’re talking about here.”

Haymaker agreed that “the more markets, the better,” an acknowledgment that BPA preference customers pay lower prices for their contracted power when the agency gets higher prices for its surplus sales — which effectively subsidize preference customers.

“I think you’re going to find better pricing in the real-time market after you do this because you’ve got alternatives, so we understand that. But we want access, or the ability to compete with that intra-hour market,” Haymaker said.

“The heart of a lot of this is how do you meet your statutory obligations for both regional preference and preference for the consumer-owned utilities,” said Betsy Bridge, an attorney representing Northwest Irrigation Utilities. “It’s not a question of whether the preference customers get first dibs to that power — so it’s a balancing act. But to reiterate Tom’s point, we have to find a balance there of making sure that preference customers have the first opportunity.”

“And it’s an assumption that we will meet those obligations,” Mantifel said. “We’re confident that joining the market does not create any issues with our ability to do that and that a lot of market changes are going to make that more complicated moving forward — the proliferation of the EIM being one of them.”

Tx Questions

Anna Berg, senior manager of power supply for Snohomish County (Wash.) Public Utility District, wondered how transmission curtailments would affect resources not participating in the EIM.

“What does that look like for the rest of us who are using BPA’s point-to-point transmission or [network transmission]?” Berg asked. “So, if there’s congestion that is occurring between EIM entities, how is that resolved?”

Saying he would be “riffing a little bit” in his response, BPA’s Todd Kochheiser explained that — “where appropriate” — transmission operators would still likely curtail prior to the hour in the face of commercial congestion. But he noted that the EIM also ensures that participating balancing authorities begin the hour with adequate resources by applying a “resource sufficiency test” that also includes a transmission feasibility assessment.

“I could envision as a result of that assessment, we could potentially identify transactions or tags or base schedules that need to be adjusted, either through curtailments or some other mechanism, in order to go into each hour feasible,” Kochheiser said. “To the extent there ends up being congestion within the hour … the market will use available resources that have been bid into the market to try to resolve that congestion. Failing that, I think we would be left with no alternative other than other operational tools such as curtailments, redispatch, etc.”

Mantifel added that, “Even if you’re not participating in the market, the odds of a curtailment ought to be reduced due to the active redispatch of the market, so the market will proactively try to get the flows below whatever physical limits that we’re managing within the market.”

Lauren Tenney, senior policy analyst with the Public Power Council, asked whether BPA expected to see congestion benefits focused primarily in areas where transmission is “donated” to the EIM to facilitate transfers between BAs — known as energy transfer system resources (ETSRs) — or whether there would be enough donated transmission to spread the benefits.

Mantifel said he didn’t think there was a strong correlation between benefits and the number of ETSRs.

“The market’s always working to manage the transmission system better, even if there’s no ETSRs,” he said, adding that it’s not always clear when the EIM is just providing economic benefits rather than relieving a stressed system.

‘Sound Business Decision’

BPA’s resolve to join the EIM became evident during a hair-splitting discussion in which a few stakeholders pressed agency officials on whether the agency had already determined that it would be a “sound business decision” to join the EIM — or if that determination only extended to the signing of the non-binding implementation agreement.

“I think it is a sound business decision,” Mantifel said of joining the EIM. “I mean, this is what we’re establishing. We’ve gone through a pretty arduous process of establishing what we believe to be facts and assumptions and analysis that justify this as a sound business decision … If you think the facts are wrong, if you think they’re insufficient, if you think the analysis is wrong or insufficient in scope or detail, this is your opportunity to disagree with that.”

Stakeholders have until July 22 to submit comments on the plan.

Tenney sought to clarify whether BPA would still in some way revisit the “sound business” issue before issuing its record of decision in two years.

“If nothing changes between now and the final decision, would this issue be something that’s addressed in a final letter to the region?” she asked.

Kerns confirmed that it would, and then attempted to reframe the subject:

“If we do decide to join the Energy Imbalance Market, what strategic value do we get as being a player and helping form the markets? On the other side of the coin, what is the strategic risk to Bonneville of being potentially one of the only balancing authorities on the West Coast not participating in the market? So, I think there’s two ways to look at that.”