DES MOINES, Iowa — Saying “no feedback is bad feedback,” SPP Seeks Slimmer Stakeholder Group Structure.)
“Not just consolidation, but also how to improve the effectiveness and efficiency of the groups,” the MOPC staff secretary said during the July 16-17 meeting. “Do they have the right structures? The right representatives? Do they coordinate when they coordinate? Should they coordinate? Are there opportunities to consolidate?”
Members pushed back against recommendations that would disband the Seams Steering Committee (SSC) and parcel out its responsibilities to other working groups.
American Electric Power’s Jim Jacoby, who chairs the SSC, said he supports handing off planning functions and operational issues to other groups to retain a focus on the interregional transmission process. He also said much of the SSC’s recent work has been related to markets and improving their coordination with MISO.
“To me, it comes down to policy issues,” Jacoby said. “I want to keep the focus on the seams. If you push that into other groups, I think you will lose that focus.”
Jacoby is supported by the Holistic Integrated Tariff Team (HITT), which recommends that SPP continue to make seams a high priority and address them as a part of the strategic plan. The HITT says the SSC “should continue to provide direction to SPP staff on seams issues.”
“We need to collapse the groups for the sake of efficiency, but we need to maintain and increase the focus on seams questions,” the Advanced Power Alliance‘s Steve Gaw said, adding that his main concern is that interregional planning with MISO is shifting into the regional planning process. “If it morphs into something different than today, we will really need closer coordination, particularly with the Economic Studies Work Group (ESWG), to make sure those two groups are linked.”
Gaw credited Jacoby, who also participates on the ESWG, with ensuring coordination between the two groups. The ESWG develops and evaluates the planning processes’ economic studies.
Reacting to the possibility of combining the Operating Reliability and Transmission working groups, Southwestern Public Service’s Bill Grant drew laughs when he said, “I want to be in the room when you do that.”
“I come from the operations side, and I’ve had my share of arguments with the planners,” Grant said. “It’s just different issues. I think we lose some expertise when you do this.”
Stakeholders Get Last Chance at HITT Report
The HITT celebrated the release of its executive summary with a tag-team education session for the MOPC and the Strategic Planning Committee. HITT Chair Tom Kent, of Nebraska Public Power District, and Rob Janssen, of Dogwood Energy, took turns reviewing the group’s 21 recommendations and offering stakeholders one last chance to provide comments before the Board of Directors sees the final report July 30.
“When I walked out of that last meeting, I thought, ‘I wish I had another three months of this process, because we have X, Y and Z issues that we can now pursue,’” Janssen said. “I’m glad we didn’t extend the timeline. We’re done, but this packet of recommendations moves SPP’s operations to a different level. As a result, everyone involved will see new things to resolve and new opportunities to pursue that we haven’t seen before.”
The HITT separated its recommendations into four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study. (See HITT Shares Draft Report with SPP Stakeholders.)
Kent said the team spent much of its time improving SPP’s congestion-hedging practices, before determining the RTO should continue with a market mechanism to hedge load against congestion charges. It suggested the existing market design include modifications to implement counter-flow optimization that is limited to excess auction revenues.
A suggestion to decouple the Schedule 9 and Schedule 11 transmission pricing zones and create larger Schedule 11 pricing zones and/or Schedule 9 sub-zones was also the subject of much conversation before the HITT. The team said that when creating the new pricing zones, “consideration should be given to new deliverability sub-regions, distribution factor calculations, and market and power flows.”
“The debate … could be part of a broader policy debate. There are a lot of things to sort out, such as how transmission planning, cost allocation and resource adequacy issues interact within new zones or sub-regions in SPP,” Janssen said.
The recommendation is being handed to the Regional State Committee and its Cost Allocation Working Group for further evaluation.
“Finding common thought and commonality to deliver holistic recommendations is pretty exceptional,” Kent said, thanking staff and stakeholders for their input. “There was a lot of response in bringing their issues and putting them on the table. We’re ready to drop our mics.”
Fortunately, no microphones were harmed during the presentation.
Western EIS Market Drawing Interest
While SPP works to complete NERC certification as a Western Interconnection reliability coordinator by September, it is holding “a lot of interesting” discussions with parties interested in its Western Energy Imbalance Service (WEIS) market.
Vice President of Operations Bruce Rew said there has been “significant interest” in SPP’s proposal to stand up an EIS market in the West. An original Friday deadline for commitments has been pushed back to Sept. 3, extending the go-live date to February 2021. (See SPP’s Western EIS Market Poised to Challenge EIM.)
Rew said market participants are expected to make a four-year commitment to the WEIS, with new entrants added every six months after go-live and allocated a portion of the start-up costs. Participants will be charged for implementation and ongoing costs based on a proportional share of annual net energy for load.
The WEIS is modeled on SPP’s Energy Imbalance Market, which was replaced by the Integrated Marketplace in 2015.
MOPC Approves Early Market Close
The MOPC approved the Market Working Group’s recommendation to shorten the window between submitting day-ahead offers and their posting by moving the award time from 2 p.m. to 1 p.m. CT. The MWG said the revision request (RR365) would result in a shorter day-ahead market time frame and move SPP closer to meeting FERC Order 809’s requirement that the timely nomination cycle for scheduling gas transportation be from 9 a.m. to 1 p.m.
AEP’s Jacoby offered an alternative motion that would have shifted the bid/offer submission deadline from 9:30 a.m. to 9 a.m. and the awards to 12:30 p.m. The motion was soundly defeated, receiving only 10 votes. (RR365 passed with five votes opposing and four abstaining.) Members in the northern states said they don’t have price certainty on natural gas until 9:30 a.m.
“Even with price certainty, if you don’t get to the timely nomination cycle, does it help you?” Jacoby said. “You can pick up a bid and hope the market solves for what you want, but that is not always the case.”
“The extra 30 minutes goes a long way for us to have gas-price certainty,” SPS’ Grant said.
The vote was emblematic of the discussion held within the MWG, said Vice Chair Jim Flucke, of Evergy.
“Each had a different gas situation. Some members wanted an earlier time, others advocated for a later start time,” he said, noting the one-hour shift was largely a consensus agreement.
Flucke said the MWG would withdraw RR339, which would set the submission deadline at 10 a.m., in favor of RR365.
The MOPC easily endorsed the MWG’s RR352, which moves up the start of the day-ahead reliability unit commitment process to 1:45 p.m. from 2 p.m. The day-ahead market’s posted results would then follow. ITC Holdings abstained from the vote.
Staff said the change will keep SPP in compliance with FERC’s directive to eliminate “inflexible” operating limits and other rules that the commission said are preventing prices from reflecting the marginal cost of serving load. (See FERC Orders Fast-start Rules for SPP.)
“FERC’s order was not without merit,” Flucke said. “We remove the screening run, because that allows the correct resources to set the price.”
LREs Meet Resource Adequacy Requirements
All of SPP’s load-responsible entities (LREs) are in compliance with the resource adequacy (RA) requirement for the 2019 summer season, according to the Supply Adequacy Working Group’s (SAWG) first RA report.
As a result of the Tariff’s Attachment AA, which went into effect last July, LREs are required to maintain adequate capacity to cover their summer load and planning reserves. SPP’s LREs met the 12% planning reserve margin (PRM) threshold with the exception of the Western Area Power Administration, which met its 9.89% PRM, carved out for LREs with at least 75% hydro-based generation.
SAWG Vice Chair Natasha Henderson, of Golden Spread Electric Cooperative, said generation retirements will drop SPP’s reserve margin to 18.2% through 2024. The footprint will lose at least 1.8 GW in confirmed retirements this year, with confirmed and unconfirmed retirements totaling 3.5 GW in 2024, she said. With peak demand expected to grow at an annual rate of 0.6%, the 12% PRM is expected to be sufficient through 2024.
The MOPC approved an unbudgeted $80,400 for a battery storage study as part of a larger effective load carrying capability (ELCC) assessment. The ELCC study will determine the amount of incremental load a resource can dependably and reliably serve during peak hours by calculating the system’s loss-of-load expectation with and without the resource.
CAISO, MISO and PJM already use the ELCC methodology. The SAWG wants to use ELCC as the guiding principle to accredit wind, solar and battery storage resources. An ELCC wind study will be posted annually in October.
“Companies retiring coal resources need to know what kind of accredited renewable resources they’ll get,” said SAWG Chair Brad Hans, of the Municipal Energy Agency of Nebraska.
2021 ITP Begins, Joining 2019, 2020 Studies
This was supposed to be the year SPP’s transmission planning process was easy. Instead of separate 10-year, 20-year and near-term assessments, the RTO implemented an annual planning cycle with a standardized study scope and common reliability models.
Instead, SPP finds itself with three studies being conducted simultaneously.
The ESWG will present its final package of recommendations for the 2019 Integrated Transmission Planning study in October. Meanwhile, the 2020 assessment is establishing its economic model, while the 2021 study kicked off Thursday with a first discussion of its scope.
SPP Planning Director Antoine Lucas said the studies are hitting their deadlines but admitted the work “is very resource-intensive.”
Questioned as to whether this was the intent of the revised planning process, Lucas said the studies are at very different stages.
“They require different sets of people. There’s some overlap, but we’re able to focus on different specific areas,” he said. “We’ve learned a lot. We’ve been trying to do some refinements as we go along, but it’s still too early in the process to determine whether or not we need to look at any significant changes to the process.”
ESWG Chair Alan Myers, of ITC, said the group will work on “optimizing” the 2019 ITP’s best portfolio for the October meetings, balancing reliability and market efficiency.
SPP Borrowing MISO’s Generation Replacement Process
The MOPC directed staff to work with the Regional Tariff Working Group in developing language addressing the transfer of interconnection rights for existing generators that have been retired, demolished or replaced.
Steve Purdy, SPP’s manager of generation interconnections, said the RTO could benefit from a similar process modeled on a recently approved MISO Tariff change. (See “Other Interconnection Filings,” MISO Promises Refile on Stricter Queue Requirements.)
MISO can now accommodate the replacement of a generator with the same or lesser capacity at the same interconnection point. It will charge generation owners a flat study deposit of $60,000 — regardless of size — and conduct replacement impact studies and reliability assessments. The replacement must undergo the full interconnection study process if the new generator causes a material adverse impact.
Should the new capacity be greater than the existing capacity, only the incremental capacity must undergo the full study process. In any case, the new generator must be in service within three months of the existing facility.
Purdy said if SPP adopts a similar process, it will remove unnecessary barriers to beneficial replacements, facilitate reliable resource planning, and remove incentives for uneconomic retirement and interconnection queue behavior. The proposal would also be consistent with FERC guidance, he said.
“Yes, we should do this,” SPS’ Grant said. “Most of our generation is getting old. If everyone sticks to their plans, there are a lot of retirements coming our way.”
Grant also recommended that SPP proceed with the Market Monitoring Unit’s proposal to measure avoidable costs if a generator is retired or mothballed. (See “Best Practices,” Stakeholders Push Back Against SPP Retirement Changes.)
“It’s not directly related, but you need a process for generation retirement for this to be effective,” he said.
Another BTM Load Survey in the Offing
Staff will once again survey its members and network customers as it attempts to validate billing efforts for behind-the-meter generation reporting network load for transmission service billing.
SPP staff and stakeholders have been wrestling with the issue since 2015. The MOPC rejected a revision request in 2017 that would have established a 1-MW threshold for reporting BTM load. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)
COO Carl Monroe said the survey, which will differentiate between wholesale and retail BTM loads, will be distributed to MOPC members, who would be responsible for providing their companies’ positions. Staff would propose ways to address the issue in order to solicit responses, he said.
SPP will use the responses to bring a proposal clarifying network load calculations and reporting to the MOPC’s October meeting.
Staff last surveyed members in 2018 when they assessed transmission customers’ understanding of their responsibility to report network integration transmission service data.
Consent Agenda Lowers Project Estimate
The committee unanimously passed the consent agenda, which included seven revision requests and a Project Cost Working Group recommendation that a cost estimate for a previously approved project be reduced from $40.4 million to $31.6 million. Evergy’s Kansas City Power & Light, KCP&L-Greater Missouri Operations and Westar Energy companies are responsible for the 345-kV voltage conversion project in Missouri.
The RRs were:
- ESWG RR362: Requires SPP and the ESWG to monitor changes to production tax credit values and federal corporate tax rates before each ITP study to help estimate the curtailment price applied to both internal and external projected wind units on a per-site basis.
- MWG RR356: Cleans up missing language, incorrect capitalized and lowercased terms, typos and other discrepancies between the Integrated Marketplace’s production protocols and the forward-looking protocols.
- MWG RR357: Clarifies language to accurately describe the trading hub modifications process by removing the need for administrative changes.
- MWG RR359: Clarifies that non-dispatchable variable energy resources (NDVERs) registering and converting to dispatchable variable energy resources must do so even if they don’t have generation-interconnection agreements. The change also includes a missed reference to run-of-river hydro in complying with FERC’s conditional order (ER19-356) on RR272.
- MWG RR360: Ensures that settling credits through revenue neutrality uplift is accurately documented in the Tariff and Integrated Marketplace protocols and improves market settlements for emergency energy.
- RTWG RR354: Waives the requirement that a transmission project sponsor provide a letter of credit when funding an upgrade should the sponsor and the transmission owner building the project be the same entity.
- RTWG RR358: Revises the cost-recovery mechanism from market participants who use and benefit from SPP’s services by subdividing Schedule 1-A into four rate schedules, including a mix of demand and energy charges. Current 1-A charges for transmission service will become Schedule 1-A1 charges and three market-related charges would be recovered through three energy charges. (See “Board Approves Modernized Cost-recovery Structure,” SPP Board of Directors/Members Committee Briefs: Jan. 29, 2019.)
— Tom Kleckner
