SPP’s Market and Operations Policy Committee last week endorsed a revision request that would again eliminate Z2 revenue credits for sponsored transmission upgrades, overlooking some members’ concerns about a second regulatory defeat at FERC.
The commission in January rejected without prejudice SPP’s proposal to use incremental long-term congestion rights (ILTCRs) instead of Z2 credits, finding the modifications to the existing ILTCR compensation term to be unjust and unreasonable. However, the commission allowed the RTO to submit a revised proposal for the commission’s consideration without a cap limiting the terms and potential value of the credits’ replacement (ER20-453). (See FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)
SPP has proposed two changes in its latest revision request (RR 401), removing “maximum” from the placeholder for the ILTCR’s term and removing the cap on the amount recoverable through the candidate ILTCRs. The latter change would allow for a term of at least 10 years, but not more than 20 years, making the candidate ILTCRs viable and tradeable.
“We are confident this revision request addresses the concerns that were raised and will be approved by FERC,” SPP attorney Tessie Kentner told the MOPC during its April 14 webinar. “Just because our ILTCR process is different than other ISOs and RTOs doesn’t mean it’s different from FERC’s requirements.”
SPP is required to file again with FERC by the end of April. It hopes to have ILTCRs replace Z2 credits by July 1.
Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.
EDP Renewables’ David Mindham argued that because the latest Z2 filing fails to address substantive arguments raised in previous protests, it faces the “real risk” of being rejected by FERC. EDF Renewable Energy has said eliminating the Z2 credits would allow certain transmission customers to become “free riders,” as they would no longer have to reimburse the upgrade sponsors for directly assigned upgrade costs.
“What’s left after Z2 is removed is discriminatory, unjust and unreasonable,” Mindham said. “It’s clear from FERC precedent that all funders of transmission should be treated equally. This filing is a step back.”
EDF legal counsel Dan Simon charged that SPP’s ILTCRs are lacking, when compared to other RTOs and ISOs.
“The current rules for ILTCRs are just not as strong as they ought to be,” he said. “We continue to hear people refer to the ILTCR product as ‘worthless.’ That demonstrates pretty clearly that the ILTCRs … are not as good as other [RTOs].
“There needs to be some sort of rate recovery mechanism for the entity that pays for that upgrade. ILTCRs don’t serve that function in their current form,” Simon said.
EDP cast the only vote against RR 401. Seven other members, primarily renewable developers and independent generators, abstained.
Zonal Planning Criteria Meets Opposition
MOPC members also sought to address another nettlesome issue — the tension between transmission owners and customers in the same transmission zones — with their approval of RR 391.
As written, the change establishes uniform local planning criteria within each pricing zone under the Tariff’s Schedule 9, placing the responsibility on the host TO to facilitate a “consensus-driven” criteria for reliability upgrades. Schedule 9 pricing zones calculate network service request charges as a ratio share of the monthly annual transmission revenue requirement.
Transmission customers pushed back against RR 391 over concerns the process lacks transparency and does not treat all loads equally. The request hinges on the facilitating transmission owner (FTO), determined yearly by the network customer with the largest load, scheduling an open meeting with other TOs, transmission customers and firm-service customers to establish the zonal planning criteria or any changes to it.
“If you look at the definition of the FTO, one of the things it requires is that the largest load in the zone determine who the FTO is,” Kansas Power Pool’s Larry Holloway said. “I’ve never seen a more open violation of open access.”
“I know consensus can’t be forced, but this revision request does not even call for consensus,” said consultant Jack Madden, representing the East Texas and Northeast Texas electric cooperatives. “It calls for a meeting, maybe only one, in which others are invited. After that, the FTO does or doesn’t establish local planning criteria.”
Madden said the Holistic Integrated Tariff Team, which included the Schedule 9 planning criteria among its recommendations last year, “clearly” considered a process that would lead to consensus. (See SPP Board Approves HITT’s Recommendations.)
“That language has been left on the cutting-room floor,” he said.
Melie Vincent, director of operations for the Oklahoma Municipal Power Authority, referred to business clichés “hope is not a strategy” and “the past does not predict the future” in stating her case.
“Sure, we could have some blind faith. … I don’t want to hamstring efforts in the future, but I don’t feel it protects the smaller players in the market,” she said.
Oklahoma Gas & Electric’s Greg McAuley, warning against the “esoteric rabbit trails” so common during MOPC discussions, said, “I haven’t seen an example within SPP of anything like this being used in a heavy-handed way to force something down someone’s throat when reliability is the ultimate goal.”
“There’s a difference between trying to reach consensus and actually reaching consensus,” said Southwestern Public Service’s Bill Grant. “It’s important everyone gets to have input, and it’s important you try to develop criteria that applies to everyone in the zone. It’s in nobody’s best interest to come up with criteria that doesn’t work for everyone in the zone.”
Not surprisingly, it took an electronic vote to determine the motion had passed with an overall approval of 73.44%. Fifteen of the 17 TOs approved the motion, but the margin was much slimmer among transmission customers. They approved the motion 17-15, with 10 abstentions.
Members Reject 60-40 Split in ITP 2021 Futures
The MOPC revisited the consolidation of futures in the Integrated Transmission Planning process’ 2021 assessment, rejecting a working group’s recommendation for a more conservative blending of the scenarios.
Members voted down a motion to use a 60-40 split between the two futures: the “business-as-usual” Future 1 case that reflects current trends, and the “emerging technologies” Future 2 case, which is driven by assumptions that distributed generation, demand response, energy efficiency and energy storage will have a major effect on load and energy growth rates.
The motion came up short of the necessary two-thirds mark for approval with only 65.17% approval. The discussion was a carryover of an unresolved discussion during the January MOPC meeting. (See SPP Members Delay Decision on 2021 Tx Assessment.)
ITC Holdings’ Alan Myers, who chairs the Economic Studies Working Group that proposed the 60-40 split, said the weighting responded to concerns over favoring extra-high-voltage solutions without making a major change in the process. SPP has said a similar weighting would not have changed the results of the 2019 assessment. (See “MOPC Approves $336 ITP Portfolio,” SPP MOPC Briefs: Oct. 15-16, 2019.)
Renewable interests favored a more aggressive forecast that incorporates additional energy growth. Others, wary of increasing transmission costs, favored the more conservative approach. Future 1 projects about 32 GW of wind installations by 2031, while Future 2 foresees about 37 GW.
“The more renewables you have, the more risk you have in building transmission due to the uncertainty of where the wind will be sited,” said Golden Spread Electric Cooperative’s Natasha Henderson. “I’m more confident of the transmission being built in Future 1.”
“I’m concerned when you hear load-serving entities are committing their customers to these long-term assets,” said McAuley, who has long expressed his concerns over escalating transmission costs and proposed a 70-30 split. “Being the Saudi Arabia of wind is absolutely a positive thing, but [SPP has] spent $10 billion already in transmission. Our transmission rates are not going down. The question has to be who’s going to be paying for the transmission in this tsunami of wind that’s going to swamp this footprint.”
American Electric Power’s Richard Ross said the 50-50 consolidation would be the “appropriate rating,” given customers demand for renewable energy.
“We have to look out for the benefits customers get from delivering these resources and building the backbone we need for the increased transition of our fleet,” Ross said. “Some of you seemed to be quite happy with the [wind] facilities and construction of the system while meeting your needs. Now that we’ve gotten there, when we’re trying to take steps to build the last miles on the eastern side of grid, you’re opposed. That kind of mindset is short-sighted.”
SPP’s COVID-19 Load down 4-6%
SPP COO Lanny Nickell said the RTO will begin holding hourlong conference calls to update the MOPC on SPP’s responses to the COVID-19 pandemic. The first members-only call, to protect confidential information, will be held next week.
Nickell said that like much of the rest of the electric industry, SPP has experienced a 4 to 6% reduction in load stemming from stay-at-home measures to halt the pandemic. The reductions have increased as temperatures have risen. The RTO has also noticed an uptick in canceled planned generation and transmission outages.
“There’s a 30% reduction in capacity that is currently scheduled to be out over the next couple of months, compared to the same time frame in the last few years,” he said.
In preparing his update, Nickell said he contacted each of the operations crews for their feedback.
“They said, ‘We just want to stay healthy so [members] can continue to do their work. We know our members rely on us to keep the lights on,’” Nickell said.
In a follow-up email to stakeholders, CEO Barbara Sugg said SPP has not had a confirmed case of COVID-19 among staff. She said the organization has adapted to the pandemic — the web-only MOPC meeting attracted 229 attendees at one point — and is already developing plans to ensure a safe and orderly transition.
“Like the rest of you, our staff anxiously awaits the end of the pandemic and our collective return to business as usual,” Sugg said.
Meter Ownership Still an Issue with Some
A Market Working Group recommendation to align the protocols with current metering standards was passed over the objections of several members who felt the revision request (RR 324) was not specific enough. A motion to endorse received six opposing votes and nine abstentions.
Several members pointed out market participants are not always the owners of the equipment they represent in the market and suggested replacing the term “market participant” with “asset owner” to more accurately represent who is responsible for the equipment.
“There’s not specific identification of who is responsible for paying for things and testing for things in the meters. It puts the market participant as responsible for everything,” said Tenaska Power Services’ John Varnell. He said other SPP documentation and FERC documentation are more specific, laying similar responsibilities on the interconnection customer.
Richard Dillon, SPP market policy technical director, said market participants sign documents that clearly state they are responsible for the meter and are required to have meter agents.
“We don’t know who owns it, who installed it, but the responsibility is on the market participant,” Dillon said.
Grant, who initially opposed RR 324, said he was comfortable to move along with the change because of his confidence that “meter agent agreements will cover this.”
MOPC Reorg ‘90%’ Complete
Nickell said SPP is “about 90% there” in its reorganization of the MOPC’s structure, which currently includes 16 working groups that report up to the committee’s leadership.
Working with Chair Holly Carias and Vice Chair Denise Buffington, Nickell said they have divided the groups into the committee’s primary responsibilities: markets, operations and planning. Their goal is to better align the group structure with SPP’s primary functions and oversight responsibilities, focusing MOPC on policy-level work while letting the working groups take care of tactical issues.
The effort will result in the retirement of a couple of working groups, while others will be repurposed as user groups or advisory groups that “facilitate advice when advice is needed to be given to those functional areas,” Nickell said.
For instance, the Business Practices Working Group will become the Transmission Service User Group. Other user groups will include Generation Interconnection, Operations Training, Security and Change.
“We’ll ensure … the appropriate functions are in the right place,” Nickell said. “This will facilitate a more effective and efficient approach to our work.”
Some stakeholder groups will become advisory groups, including the Seams Steering Committee. That will incorporate seams oversight into applicable functional areas, Nickell said.
The Value and Affordability Task Force last year recommended the reorganization after eight months of study. The senior-level group was created to search for ways to increase SPP’s value and improve affordability while maintaining and protecting its mission. (See SPP Value Group Finds No ‘Silver Bullets’.)
Saying he believes the benefits are “numerous,” Nickell said staff are still working on a cost-benefit analysis.
MOPC leadership also plans to recommend improvements to the revision-request process. “We want to make it clearer and streamline it and ensure we have the appropriate inputs for policy,” Nickell said.
The recommendations will be documented as a revision request, to be presented to MOPC during its July or October meetings.
SPP to Recommend Pausing Competitive Project
Casey Cathey, SPP director of system planning, told the MOPC that staff will recommend to the Board of Directors next week that they suspend a competitive, interregional project, pending FERC’s approval of an agreement with Associated Electric Cooperative Inc. (AECI).
SPP and AECI have agreed to perform a joint study that will include a 345-kV competitive project approved in January by the board as part of the 2020 SPP Transmission Expansion Plan. The $152 million, 105-mile Work Creek-Blackberry upgrade in Kansas and Missouri will be analyzed to determine whether there are any system reliability impacts. (See “SPP, AECI Agree to Joint Study,” SPP Seams Steering Committee: April 2, 2020.)
Cathey said SPP and AECI are developing a cost and usage agreement to execute once the joint study identifies whether the project will create any reliability issues. Should the study, which is expected to be completed in August, identify additional upgrades on the AECI system, staff will revisit the project with stakeholders and the Regional State Committee.
“We recognize this potentially delays issuance of a [request for proposals], but there’s so much uncertainty with outside entities associated with FERC,” Cathey said. “FERC is probably the biggest wild card here, because of the coronavirus.”
He said the delay may push the project’s energization date back one or two months.
Members Approve 1 RAS, Retirement of Another
The MOPC unanimously approved its consent agenda, which included one revision request, a remedial action scheme (RAS) retirement and five project cost reset recommendations, but not before discussing separately the creation of another temporary RAS.
Members approved Xcel Energy’s recommended RAS to allow its 522-MW Sagamore Wind Farm in West Texas to interconnect with subsidiary SPS’ Crossroads substation before an additional 345/230-kV transformer at Tolk Station is in place. The RAS would monitor the 345-kV Crossroads-Tolk line’s current, tripping the wind farm when the current exceeds a specified level in place. The second 345/230-kV Tolk Station transformer is expected to be in service in March 2022.
Grant said the utility is working “diligently” to upgrade its system, at which point the RAS would no longer be needed. Nebraska Public Power District, Tri-County Electric Cooperative, Missouri River Energy Services and GridLiance opposed the motion, and 11 other members abstained.
The committee also asked the Transmission, Operating Reliability and System Protection and Control working groups to develop policy around future RAS schemes.
The consent agenda’s approval also resulted in the retirement of a RAS in effect at the Oklaunion Power Station in the Texas Panhandle since the mid-1980s. The plant itself is scheduled to be retired in October. (See PSO Officially Retires Oklaunion Coal Plant.)
The Project Cost Working Group recommended baselines be reset for several previously approved projects. Three of the projects, located in North Dakota and belonging to Basin Electric Power Cooperative, were approved by FERC before Basin joined SPP in 2015 and are now in service.
The Basin projects included a nearly $30 million decrease, to $89.2 million, for a 70-mile, 345-kV line, a new switching station and an expanded substation; a $36.6 million decrease, to $95.7 million, for a 75-mile, 345-kV line, a new substation and necessary terminal upgrades; and a $27.3 million decrease, to $95.3 million, for a 58-mile, 345-kV line and new substation.
Other projects included:
- SPS’ reconfiguration of a 230-kV bus tie into a double-bus and breaker scheme in West Texas. The project’s costs have increased by $8.5 million to $19.7 million.
- Central Power Electric Cooperative’s 24-mile, 115-kV line in North Dakota. The project costs have dropped $8.5 million to $14.4 million.
The lone Tariff change request (MWG–RR 383) revises the Integrated Marketplace protocols’ mitigation requirements by clarifying that energy offers below $25/MWh and operating reserve products below $10/MWh are not subject to the mitigation process. It also makes clear that energy offers for locally committed resources are not subject to the normal mitigation process, but are capped at 10% above their mitigated offer and removes language requiring market participants to contact the Market Monitoring Unit before submitting an offer above their conduct threshold.
— Tom Kleckner
