The second half of Friday’s meeting of the Joint Federal-State Task Force on Electric Transmission started off with a touch of irony.
“Now we’ll move on to the much less controversial issue about funding and cost allocation” of transmission projects, Jonathan Raab — president of consultancy Raab Associates and facilitator of the meeting — said about a topic that has sparked sharp disagreements in organized electricity markets across the country.
The first part of Friday’s conference of federal and state regulators focused on clogged generation interconnection queues in RTOs and ISOs. (See related story, FERC-State Task Force Considers Clustering, ‘Fast Track' to Clear Queues.) The next half delved into the even thornier issue of who should pay for the needed transmission network upgrades spurred by the interconnecting resources piling up in the queues.
The issue of cost allocation has grown in controversy as the grid integrates increasing volumes of renewable resources. Developers must often site renewables far from load centers, other generating resources and existing high-voltage transmission lines in order to cover enough ground to capture economies of scale and locate in areas that offer higher capacity factors resulting from more consistent winds or sunlight.
“In recent years, I think we’re at a point where the changing resource mix has already triggered a number of challenges, and the solutions required are effectively transmission solutions,” Michigan Public Service Commission Chair Dan Scripps said in opening remarks.
“It’s not that we’re building out backbone transmission projects in order to simply accommodate generators, but really to keep the lights on. And whether we continue to allocate a disproportionate share of the cost to interconnecting generators in order to fulfill this reliability imperative, I’m not convinced that the current model strikes the right balance,” he said.
Friday afternoon’s discussion aimed to get closer to that balance. Raab framed the session by outlining four cost allocation approaches for the regulators to consider, including:
State regulators have generally supported the first option, with some flexibility — and some notable deviations.
In its comments on FERC’s 2021 Advance Notice of Proposed Rulemaking to improve regional transmission planning, cost allocation and interconnection processes (RM21-17), the National Association of Regulatory Utility Commissioners urged the commission to “retain the core tenet of participant funding, while exploring the as yet untapped potential economies of scale that could result from increased coordination among participants,” such as through clustering of projects. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)
On Friday, FERC Commissioner Allison Clements encouraged industry stakeholders to be flexible in their thinking about cost allocation.
“I don’t think the solution is going from all to nothing. I don’t think that, while interconnection customers currently pay off needed upgrade costs, the solution should be jumping to having them pay nothing. That doesn’t jive with [FERC’s] cost allocation principles,” Clements said.
“I’ve never had a project sponsor suggest to me that they’re unwilling to pay their fair share, and I’ve also never had a transmission provider suggest to me that in all, or even in most cases, the whole of network upgrade benefits accrue only to the interconnection customer customers paying for them,” she added.
“I am a believer that when we make certain high-voltage upgrades as part of the [generator interconnection] process, there are real benefits that flow to load,” Kansas Corporation Commission Chair Andrew French said.
Changes to cost-sharing models should not be a “one-way street” directed only at electricity customers, according to French.
“This is not just about getting load to pay more, or to chip in more of the cost to help interconnect generators. It’s to try to find the most accurate cost allocation over all of our investments,” he said.
French pointed out that SPP’s regional planning process can produce a “big backbone” project on which generation developers can “basically free ride for a few years” without dealing with many upgrades.
“They don’t have to pay anything for them, and that’s the situation we were in for maybe the last 10 years before we ran out of capacity,” French said. “I just want to make the point that, ultimately, we need to get to a more holistic, consolidated planning process.”
The intertwining relationship between transmission planning and cost allocation was a recurring theme during the discussion.
Michigan’s Scripps encouraged fellow regulators to avoid “siloing” the cost allocation issue “because it really does connect with a number of other concerns, and I’d argue that participant funding reform should go hand-in-hand with interconnection key reforms.”
Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille noted that there isn’t a consensus of support for a 100% participant funding model within the Mid-Atlantic Conference of Regulatory Utilities Commissioners, which she was representing during the meeting. But she also emphasized the support for that model in her own state, which deregulated its electricity market to offload generation investment risks from ratepayers.
“The participant-funding model is based on the tried-and-true ratemaking principle of cost causation. And I just want to highlight what I believe its benefits include: and that would be promoting efficient siting of generation projects, as well as allowing parties that are best positioned to control the interconnection costs to bear the costs.”
North Carolina Utilities Commissioner Kimberly Duffley said there’s a “strong consensus” within the Southeastern Association of Regulatory Utility Commissioners and the industry at large for maintaining the participant-funding model. Duffley cautioned that straying from that model could saddle ratepayers with costs for transmission projects they neither want nor need.
“Enjoyed listening to Commissioner Dutrieuille. Enjoyed listing to Commissioner Duffley,” FERC Commissioner Mark Christie said. “All I can say is, ‘What she said — twice.’”
FERC Chair Richard Glick and Commissioner Willie Phillips both reminded their fellow regulators that judicial precedent requires the commission to look beyond participant-driven costs to consider wider system benefits.
“There’s a number of cases where the courts have essentially said cost-causation really is benefits, and you have to look at who benefits in terms of who pays,” Glick said.
“I believe that cost sharing might actually be more cost-effective for consumers overall, because it could provide some incentive for [transmission owners] to proactively plan and build the optimal transmission lines in the first place,” Phillips said when the subject turned to an allocation approach that splits costs between generators and load.
Phillips pointed favorably to CAISO’s model in which TOs are required to refund upgrade costs back to generators within five years of a project’s operation date, as well as the MISO model where load pays 10% of transmission upgrade costs for lines rated at 345 kV or above.
California Public Utilities Commissioner Cliff Rechtschaffen said that CAISO’s practice was designed to ensure that generators have financial “skin in the game” before seeking interconnection.
“The generator still covers the cost between the generation facility and the point of interconnection. The costs that are covered by this policy are the reliability, substation and deliverability backbone upgrades,” Rechtschaffen said, adding that CAISO caps the level of reimbursement.
“Only upgrades that are needed to meet resource adequacy requirements are reimbursable. So that ensures that the load that’s charged for the upgrades is benefiting and adhering to the beneficiary-pays principle that is so important,” he said.
“I think to the extent that we’re looking for something with relative simplicity, and something with a framework that FERC is familiar with and has approved in the past, a voltage threshold [as in MISO] would seem to make sense,” Maryland Public Service Commission Chair Jason Stanek said.
Dutrieuille called the MISO cost-sharing mechanism “intriguing” and “easy to understand,” but she was reluctant to endorse it. “I would make sure that we understood what the benefits were … [and that] you can quantify them, and they’re not speculative in nature.”
Arkansas Public Service Commission Chair Ted Thomas said as the electricity grid continues to undergo its transition, the “right transmission plan” should function as the shared cost. “Doing that right, there shouldn’t be that many remaining shared costs. That’s a critical point,” he said.
An allocation approach in which load bears 100% of the costs for transmission upgrades found no support among the commissioners, but a model in which generator subscriptions supported the development of new or upgraded infrastructure sparked some interest.
Stanek pointed out that FERC has used the subscription model in the past for natural gas pipelines and some merchant transmission projects.
“I think some of the benefits that could flow from this would be a faster interconnection process, efficiency and, probably most important to this afternoon’s conversation, making sure that the costs of this upgrade would be paid for in a fair and equitable manner,” Stanek said.
“It’s a framework that I think addresses some of the big thorny knots that we’re dealing with when we talk about free ridership, lumpy and large payments, cost uncertainties — some of the big things that we can’t seem to kind of get around,” Vermont Public Utility Commissioner Riley Allen said.
Allen likened the subscription model with ISO-NE’s cluster interconnection process, in which the RTO assigns the costs for major transmission upgrades to clusters of interconnecting resources. He envisioned a way of scaling up that process for “superclusters” of resources in allocating costs for upgrading a larger backbone system. Instead of being responsible for incremental upgrades to a network on an individual basis, interconnecting generators could be allocated costs based on a per-megawatt fee.
He also proposed the further step of adopting Vermont’s system of using a cost “adjuster” to steer development to areas of the system that already have existing capacity. “So it kind of checks a number of boxes, at least for me, in terms of getting around the problem, working our way past the kind of participant-pays versus load-pays, because this is relatively agnostic,” he said.
“I think the proposal that Commissioner Allen just outlined would be very helpful when in terms of offshore wind if you build a collector system. That’s probably the fairest way of allocating the cost,” Glick said.
Speaking as the lone representative from the “non-RTO West,” Utah Public Service Commission Chair Thad LeVar noted that issue of participant funding is not something the region currently wrestles with. But LeVar cautioned FERC about developing cost allocation rules that could “chill” the West’s efforts toward increased regionalization and — “hopefully” — an RTO.
“I would hate to see the RTO rules that don’t currently apply to us evolve in a way that would scare off stakeholders from the work that’s happening across the West,” he said.
In wrapping up the meeting, Glick said it was evident there appeared to be “a lot of consensus” on how to address logjams in RTO interconnection queues, and “a little less consensus” on cost allocation for transmission upgrades.
Glick said the lack of agreement was “not surprising” given NARUC’s comments on FERC’s ANOPR last year and the divergent opinions among states on the need to “reform” cost allocation rules.
“So that’s something we need to consider as well, and we’re certainly cognizant of all the actions that are going on at the state level,” he said. “And whatever actions we take at FERC, I think we certainly will, at least from my perspective, take into account what the states are doing and certainly not try to reverse or impede the progress that the states are making.”