OKLAHOMA CITY — SPP’s Markets and Operations Policy Committee unanimously approved a Market Working Group (MWG) revision request (RR 245) that adds a major maintenance cost in mitigated start-up and no-load offers, resolving pushback from the RTO’s Market Monitoring Unit.

The MWG said the change allows market participants to include major maintenance costs associated with the number of starts or run hours in their mitigated start-up and no-load offers, resulting in the recovery of true variable costs.

The revision received a thumbs-up from MMU Executive Director Keith Collins, who said he was aware the Monitor had opposed previous versions of the change.

“The Market Monitor believes that changes made to 245 … are substantial differences that allow the Market Monitor to find this approach acceptable,” he said. “One, we’re not moving down the variable maintenance approach we tried last time, and two, we are talking specifically about major maintenance for start-up and no-load. This approach is consistent with how other RTOs address major maintenance.”

The MOPC’s endorsement allowed the MWG to recommend closing several action items and withdrawing two other revision requests it had been working on: RR 231, which addressed fuel-cost changes, and RR 214, which removed locally committed resources from the economic mitigation tests. The latter revision request, which also created a 10% cap for resources committed for local reliability, had been remanded back to the working group by the committee for additional review.

The MMU opposed RR 214, saying it discovered resources were “self-mitigating” to pass the conduct threshold test and avoid possible mitigation.

RR 245 “takes a little of what PJM is doing and what MISO is doing, and puts them together,” Collins said. “We like driving in the middle of the road.”

MWG Vice Chair Jim Flucke, of Kansas City Power & Light, said, “Given everything else we passed, 214 as written is no longer the right approach to the remaining issues we have.”

Golden Spread Electric Cooperative’s Mike Wise thanked the MWG for its work, saying, “This is taking SPP substantially forward.”

The MOPC approved the recommendation to withdraw the revision requests with three abstentions.

Members unanimously endorsed two other revision requests brought forward by the MWG:

• • • MWG-RR247: Clarifies language to reflect how the market-clearing engine treats contingency reserves in the real-time balancing market when a contingency reserve event is deployed.
    • MWG-RR257: Responds to a FERC compliance requirement (EL16-110) requiring SPP to limit the eligibility for auction revenue rights and long-term congestion rights of network customers with service subject to redispatch. The changes will ensure network service subject to redispatch is treated comparably with point-to-point service subject to redispatch. (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)

SPP Pays MISO $2.25M After M2M Resettlements

SPP has reimbursed MISO more than $2.25 million after resettlements of several market-to-market (M2M) flowgates and will continue to perform “limited” resettlements because of a memorandum of understanding between the two RTOs.

The resettlements stem from binding events on three flowgates along the SPP-MISO seam. SPP has accumulated $32.73 million in M2M payments through November since the two RTOs began the process in March 2015.

“Large dollars are transferring between SPP and MISO on a daily basis,” said David Kelley, SPP’s director of interregional relations. The resettled payments “shouldn’t have been paid to us to begin with, but we didn’t have a lot of criteria around it. We needed to ensure [M2M coordination] is grounded in some of [the MOU’s] principles.”

The RTOs executed the MOU last summer to improve M2M coordination after what Kelley called a “significant” amount of time and negotiation. They then revised the MOU to address power swings and capping its firm-flow entitlement provisions. FERC accepted the revisions in December (ER18-150).

Kelley reminded members that the commission directed the RTOs to begin M2M coordination with the implementation of SPP’s Integrated Marketplace in 2014. FERC cited the success of a similar process between MISO and PJM.

“We knew we had some room for improvement almost immediately because of the way the system operated,” Kelley said. “From the moment we threw the switch, we saw significant oscillations and power swings on some flowgates. We knew this wasn’t how it was supposed to work.”

“It’s all because Iowa wind is impacting our system,” SPP COO Carl Malone said, issuing a refrain familiar to many of his colleagues.

“I think we’ve ended up in a good place where the process should work much better,” Kelley said.

SPP and MISO will both file waivers with FERC to complete the resettlements.

Kelley also said SPP will “take a run at another filing” with FERC over two potential seams projects with Associated Electric Cooperative Inc. The commission last year rejected both projects, saying SPP had not shown its proposed cost allocations on a load-ratio share basis were “roughly commensurate” with the projects’ benefits. (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)

SPP staff have met with FERC staff to gain further insight as to why their filings were rejected. “It’s not a for-sure slam dunk [for SPP],” said General Counsel Paul Suskie, “but it’s worth another try.”

In the meantime, Kelley has kept open the lines of communication with AECI.

“We’ve reiterated our support and commitment, and they’ve reiterated their support and commitment as well,” Kelley said.

MOPC Agrees to Pull Basin Electric Project’s NTC-C

The committee unanimously agreed with staff’s recommendation to withdraw a notification to construct with conditions (NTC-C) for a Basin Electric Power Cooperative transmission project in North Dakota.

Staff said their updated load projections indicated there was no longer a need for the 33-mile, 345-kV Kummer Ridge–Roundup line. Staff studied winter and summer peak scenarios in 2022 and 2027 before making their decision.

The project began as a 115-kV line in SPP’s 2016 near-term assessment, but its NTC-C was modified by the Board of Directors in July 2016 to reflect the change in voltage to 345 kV. It has an estimated cost of $52.3 million.

The MOPC and board both approved Basin Electric’s request for an expedited re-evaluation in April 2017. (See “MOPC Endorses Re-evaluation of Basin Electric Project,” SPP Markets and Operations Policy Committee Briefs.)

Staff also alerted MOPC about a change in a New Mexico project that came out of its 2014 High-Priority Impact Load Study. Tapping an existing 115-kV line to build a new 115-kV substation at Ponderosa Tap had been approved at a cost of $4.9 million. However, staff said the project costs were incorrectly designated as “direct assigned” and should be “base plan” funded instead. The cost was reduced slightly.

Stakeholders separately unanimously endorsed the 2018 Transmission Expansion Plan, sending it to the board for its approval. Members completed 36 projects costing $246 million in 2017, while SPP issued 71 NTCs for an additional $263.2 million in spending.

North Dakota Sponsored Upgrade Study Approved

The MOPC endorsed SPP’s sponsored upgrade study performed for Central Power Electric Cooperatives, a member company in North Dakota that purchases power from Basin Electric to serve its own six-member cooperative.

CPEC proposed changing a 115-kV breaker status from “normally open” to “normally closed” and completing a 115-kV loop between two Western Area Power Administration substations to correct a potential thermal violation in the 2026 summer models. Staff said CPEC would have to bear the costs of the upgrade and any mitigations.

SPP issued a report to CPEC, Basin Electric and WAPA in November.

NERC Stakeholder Teams to Review, Reduce Standards

‎Charles Yeung, SPP’s executive director of interregional affairs, told members they face a Feb. 2 deadline for submitting input to NERC on its standards streamlining effort.

The agency has formed three teams to review long-term planning, operations planning and real-time operations standards. The teams will provide recommendations on reducing the number of NERC standards — not including critical infrastructure protection standards — by the third quarter of this year.

The teams, which still have open seats, have scheduled one-hour webinars Jan. 24-25 for orientation and to discuss scope, timelines and other matters.

Consent Agenda Clears 10 Revision Requests

The MOPC approved a measure that documents market import service (MIS) as a transmission product in the Tariff; it has been offered in SPP’s Integrated Marketplace since 2014. RR 250 places all information related to reserving and scheduling MIS in one location as a new business practice.

Malone pulled the revision from the consent agenda, pointing to language that said MIS had not been implemented through Tariff language.

“The Tariff language being added is brand new,” he said. “I read that it didn’t exist until today. It looks like new service to me.”

Malone was joined in opposing RR 250 by the Municipal Energy Agency of Nebraska. ITC Holdings abstained from the vote.

The MOPC unanimously approved nine other revision requests on its consent agenda:

• • • CPWG-RR249: Corrects, updates and clarifies unclear or outdated letter of credit language to make it more acceptable to financial institutions.
    • MWG-RR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols and the Tariff.
    • MWG-RR200: Removes bilateral settlement schedules (BSS) at hubs and generation settlement locations from the over-collected losses (OCL) distribution calculation. The revision allows only BSS at a withdrawal point to be included in the OCL distribution calculation. It caps the BSS at the maximum amount of the real-time withdrawal minus any amount of grandfathered agreements and federal service exemptions.
    • MWG-RR246: Clarifies language explaining SPP’s congestion management efforts when declaring transmission loading relief (TLR) and removes a reference to an old system name. SPP does not have an active TLR for every congestion management event, but the protocol language will be updated to read “as soon as practicable,” and adds provisions for market-to-market coordinated curtailments in lieu of TLR market flow curtailment targets when appropriate.
    • MWG-RR253: Changes how dispatchable variable energy resources (DVERs) provide regulation down service. SPP said the change will lower structural barriers to DVERs providing regulation service and allow the system to operate more efficiently in times of high wind when SPP could use online turbines rather than requiring uneconomic commitments of other resources.
    • MWG-RR254: Updates the data requirements requested from SPP’s forecasting vendor to improve the wind and solar power forecast. Additional data requirements include individual wind turbine coordinates, turbine model characteristics, cold-weather packages, and turbine availability and de-rate submissions.
    • MWG-RR258: Recommends modifications to the list of frequently constrained areas (FCAs) and resources from the Market Monitoring Unit’s 2017 study. FCAs are electrical areas with one or more transmission constraints or reserve zone constraints that are expected to be binding for at least 500 hours during a given 12-month period and within which one or more suppliers are pivotal.
    • MWG-RR265: A compliance filing in response to FERC’s order on handling ramp shortages under Order 825. (See FERC Approves SPP Shortage Pricing Changes.) Modifies the methodology through which scarcity pricing reflects the value of regulation and operating reserves. The Tariff language was filed in October (ER17-772).
    • ORWG-RR162: Requires phasor measuring units (PMUs) at new generator interconnections to aid in oscillation detection, generator model validation and post-event analyses, as has become common practice among SPP’s peers.

The consent agenda’s approval also resulted in MOPC’s endorsement of:

• • • A 34.9% decrease in SPS’ escalated baseline cost of $17.67 million to rebuild 22.1 miles of 115-kV line and a 115-kV circuit.
    • A 23.2% decrease, to $58.8 million, in the escalated baseline cost for SPS to build a new 47.2-mile, 345-kV line and a 345-kV substation.
    • A 23.4% decrease, to $28.5 million, in the escalated baseline for Nebraska Public Power District to build a new 35-mile, 115-kV line and complete various upgrades.
    • Charter revisions to the Reliability Compliance Working Group reflecting the SPP Regional Entity’s dissolution.

— Tom Kleckner