LITTLE ROCK, Ark. — As expected, SPP staff brought a recommendation to the Markets and Operations Policy Committee for approval of one of three interregional projects coming out of the SPP-MISO coordinated system plan study.
The MOPC approved the recommendation. The catch? MISO is not recommending any of the same three projects. (See SPP Staff Recommends 1 of 3 Interregional Projects.)
“MISO has its own processes,” said David Kelley, SPP’s director of interregional relations. “So far, their analysis indicates they are not willing to move forward with any of the three.”
Staff recommended approval of the South Shreveport-Wallace Lake rebuild, an 11-mile 138-kV project addressing area congestion. SPP estimates the project has a cost of $18.5 million, of which it would fund 20% ($3.7 million), and a benefit-cost ratio of 11.86 — far exceeding the 1.0 threshold.
Kelley said three of the South Shreveport-Wallace Lake futures indicate the project yields “significant benefits,” 80% of which would go to MISO. He said the RTOs’ use the same B/C calculations, “but we use more benefit metrics to determine a project’s value than MISO does.”
SPP does not recommend approving the other two interregional projects evaluated as part of a regional review: the Alto-Swartz series reactor and the Elm Creek-NSUB 345-kV transmission line. Both could be reevaluated in a future regional or interregional study.
With MOPC members wondering how to proceed, Kelley said, “MISO still has [to conduct] a lot of robust discussions with stakeholders over its cost allocations … things we’ve already done.”
MISO has accepted SPP’s invitation to participate in a Thursday debrief of the study process, but Kelley sounded skeptical of a positive result. “Unless there are fundamental changes done with MISO’s stakeholder process, I don’t think [the South Shreveport-Wallace Lake rebuild] will be approved,” he said.
SPP Board of Directors Chair Jim Eckelberger said he would talk with his MISO counterpart, Mike Curran, to “see if the project can get legs and move forward.”
The two RTOs face a December deadline to come to agreement on the interregional projects, though the current six-month window can be extended. MISO’s Board of Directors meets Dec. 10 and will take up staff’s recommendation on the interregional projects at that time.
13 Revision Requests Approved
The MOPC approved 13 revision requests from the Market Working Group totaling about $11.5 million.
A request establishing a new incremental long-term congestion rights (ILTCR) allocation process passed the MOPC with 13 abstentions after clearing the MWG with one positive vote and 17 abstentions.
But, as MWG Chair Richard Ross of American Electric Power said, “We knew we had to move it forward. We have to do this.”
The revision was necessitated by FERC’s 2014 order finding fault with SPP’s interpretation of long-term congestion rights. The commission rejected multiple rehearing requests in July. (See FERC Rejects Rehearing on SPP Congestion Rights.)
The MWG’s new process will result in awards to market participants with ILTCRs when a transmission upgrade goes into service, instead of waiting until the annual LTCR allocation. Rights awarded in the initial allocation cannot be renewed; participants with candidate ILTCRs will be eligible to nominate in the same round of the next annual LTCR allocation as load-serving entity LTCRs.
A second revision request concerned the enhanced combined-cycle project, which was suspended last year to allow for a more thorough cost-benefit study and the Integrated System’s incorporation. The change is intended to ensure the ECC team implements the market-clearing engine’s logic on time and on budget by limiting combined-cycle configurations and offline supplemental offers.
The revision request received the SPP Market Monitoring Unit’s blessing and passed unanimously.
Other approved revision requests dealt with quick-start resource improvements, ramp-scarcity pricing and violation relaxation limits.
11 Transmission Projects Withdrawn in Quarterly Review
The MOPC unanimously approved staff’s recommendation to withdraw 11 notifications to construct (NTCs) as part of SPP’s quarterly review of transmission-expansion projects.
Two of those projects were among seven with out-of-bandwidth cost variances that had their NTCs suspended during the July MOPC meeting until further studies could be conducted. (See “Out-of-Bandwidth Projects Ordered Re-Evaluated,” in SPP BoD/Members Committee Briefs.)
Antoine Lucas, SPP’s planning director, said the additional analysis revealed there was not a reliability need for the Martin-Pantex North-Pantex South-Highland Park 115-kV rebuild (Southwestern Public Service) or the Labette-Neosho SES 69-kV rebuild (Westar). Lucas said a third re-studied project — the Iatan-Stranger Creek 345-kV voltage conversion (Westar/KCP&L Greater Missouri Operations) — should have its NTC reinstated, while the other four out-of-bandwidth projects require further analysis, as a need remains.
“We don’t want to continue to defer the [Iatan-Stranger Creek] project but reinstate the NTC because it’s still beneficial to the region,” Lucas said, referring to its inclusion as an economic project in the 2015 Integrated Transmission Planning 10-year assessment (ITP10).
The other nine withdrawn NTCs came from SPP’s re-evaluation of 24 projects at the transmission owners’ request. Lucas said staff did not have time to evaluate all of the projects; the 15 remaining projects require further analysis.
MOPC Approves ITP10 Scope
Members also approved a recommendation by SPP’s transmission and economic studies working groups to approve the 2017 ITP10 scope, following a discussion on the use of reliability standards.
Ross noted the scope didn’t take into account the North American Electric Reliability Corp.’s coming transmission planning (TPL) standards. “To do the analysis and not be aware of what’s coming would be a mistake,” he said.
Midwest Energy’s Bill Dowling urged incorporating the new TPL-001-4 standards, which take effect Jan. 1.
The committee approved the planning study’s scope with four ‘nay’ votes after inserting language requiring compliance with the TPL standards.
The study will consider three futures: a regional Clean Power Plan (CPP) solution, a state-level CPP solution and a solution assuming the CPP is not implemented. Each future also assumes competitive wind and solar development, high availability of natural gas due to fracking, expected load growth and inclusion of all statutory and regulatory renewable mandates.
The 2020 and 2025 models will include implementation of the Environmental Protection Agency’s interim CPP goals that begin in 2022 and 2025-2027 goals, respectively.
Work Continues on Transmission Planning Improvements
Completion of work to improve SPP’s transmission planning processes may slip from January to April, but the result will be a better product, NextEra Energy’s Brian Gedrich told the MOPC.
Gedrich said the Transmission Planning Improvement Task Force, which he chairs, needs more time despite adding meetings and conference calls to its schedule. “When I saw the only day we could double up on in December was the 25th, I decided maybe we needed more time,” Gedrich told the committee.
The task force faces a January deadline to recommend changes to create more efficient planning processes. Gedrich said the group has already unanimously agreed upon an 18-month planning cycle, a common planning model and a standardized scope. It has also agreed upon a comprehensive planning process that combines the near-term, 10-year and reliability processes into a 10-year study looking at reliability, economic, policy and compliance needs. The current 20-year assessment would be separated from the annual planning cycle.
“We’ve come a long way and had a lot of great ideas,” Gedrich said. “I think it will be fine if we let it slip a little and make sure we get this right.”
Eckelberger supported the delay when Gedrich delivered the same message to the Strategic Planning Committee.
“I’m not speaking for the board, but if you need a little more time and you get it really right, let’s do that,” he said.
The task force envisions overlapping 18-month planning cycles that would produce an annual assessment, with the ensuing cycle’s modeling development beginning as soon as the previous one was completed. By using only three futures, Gedrich said, incremental, easier-to-manage changes would be made from one cycle to the next.
The task force will work with other working groups to confirm the feasibility of its recommendations and to identify any other potential issues and solutions. Gedrich said the earliest the new planning cycle could be in place would be April 2019.
Z2 Crediting Task Force Remains on Track
Stakeholders and staff working on the beleaguered Z2 credit project are still targeting January’s MOPC and board meetings as to when transmission owners will learn the amount of bills that could be as much as 10 years old. (See SPP Z2 Project Team Still Grappling with Problem’s Size.)
The project team is working to create software that would properly credit and bill transmission customers for system upgrades under Tariff attachment Z2. The problem has been avoiding over-compensating project sponsors and including a way to “claw back” revenues from members who owe SPP money for other reasons.
“It would be helpful to see a number at some point,” said ITC Holdings’ Marguerite Wagner. “We know the historic stuff. We know how much has been paid by interconnection customers, but interest is accruing on this.”
Dennis Reed, director of FERC compliance for Westar Energy and chair of the Regional Tariff Working Group, estimated $750 million for creditable upgrades, with up to $90 million in transmission customer upgrades and the remainder from sponsored upgrades. He has said previously the Z2 team can’t produce an accurate number until the software is completed.
“We’re not going to be anywhere close to the final numbers, the real size, who’s owed and who owes until the first of the year,” Reed said. “That’s the only time I’ll be comfortable with saying how big the breadbox is.”
Software is being developed in three different modules (functionality, base calculations and settlement calculations) to help accelerate the process. At the same time, SPP staff has been reviewing previous aggregate transmission service studies dating back to 2005, developing a list of project sponsors and verifying final upgrade costs if the project is still in service.
The team expects to complete historic calculations and develop payment options by April 2016.
Capacity Margin Task Force
Stakeholders working on a task force updating SPP’s capacity margin requirements and methodology said last week its preliminary work indicates the RTO can reduce its planning reserve margin from 13.6% to about 10%.
“But we want to vet that with other stakeholders,” said Mid-Kansas Electric’s Tom Hestermann, who leads the group. “The last thing we want to do is recommend a reduction in planning reserves, and then several years later, have to re-do that.”
Hestermann said the task force is focused on bringing more value to the membership from its investment in transmission infrastructure and to provide a way for entities to meet shortages on a short-term basis. He said a preliminary loss-of-load expectation reserve margin study using existing models shows generation is available, “based on the robust transmission system we have.”
The task force has three white papers in various forms of completion, including one on deliverability and a second on load-responsible entities (accounting for the fact that not all SPP load is associated with load-serving members).
The third concerns a planning-reserve assurance policy. “We thought enforcement sounded kind of draconian,” Hestermann explained.
The team has also suggested a half-day workshop before the January MOPC meeting.
“When we finish our work as a task force,” Hestermann said, “we feel strongly someone should take ownership of this process.”
Integrated System Increases SPP System’s Ramp Rate
SPP’s C.J. Brown told members the Integrated System’s Oct. 1 integration was a “non-event,” with only some tagging and scheduling issues affecting a couple of new market participants. The integration brought on 2,400 MW of load during the transition, with 3,000 MW of generation online.
The system’s nearly 2,600 MW of hydro capacity nearly quadrupled SPP’s existing hydro. More importantly, Brown said, with its quick ramp rates, the hydropower has increased SPP’s rate ramp by 1 MW/minute.
“It may be a minute, but that’s a minute across the entire system,” he said.
Brown also noted SPP’s LMPs have been lowered with the integration, making the RTO more of an energy exporter than it was previously.
Mitigated Offer ‘Strike Team’ on Hold
SPP’s Matt Dillon told the MOPC a “strike team’s” work on mitigated offers is on hold following FERC’s recent rejection of what costs the RTO can include in mitigated offers. (See FERC Sides with SPP Monitor.)
Dillon said SPP has three options: 1) ask for a rehearing, 2) ask for a clarification of “short-run marginal cost” or 3) accept the commission’s decision.
Dillon said SPP remains undecided, and the strike team has no further action.
— Tom Kleckner
