OMAHA, Neb. — Given a proverbial second bite of the apple, SPP stakeholders easily approved a revision request that requires non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs) within a multiyear transition period.

The Markets and Operations Policy Committee rejected the measure (RR272) during its April meeting. The Board of Directors/Members Committee tabled the request but asked for a review of RR272’s economic impact and that the Market Working Group build greater consensus among the membership. (See “Board Forced to Table NDVER Conversion Change,” SPP Board of Directors/Members Committee Briefs: April 24, 2018.)

MWG Chair Richard Ross, of American Electric Power, began discussion of the change by noting he was one of the few people in the meeting room wearing a tie.

“I’m not trying to make anyone nervous,” he quipped. “But if you get unruly, I’ll take the tie off.”

There was no need. The measure passed with more than 81% approval, almost 20 points better than it fared in April. It was opposed by only two transmission owners (Empire District Electric and Omaha Public Power District) and eight transmission customers with various ties to renewable energy. Seven transmission customers abstained.

“We wanted to see this happen, sooner than now,” said Southwestern Public Service’s Bill Grant. “This is a compromise we can live with. It took a lot of work to get to this point, but we’ve moved to a point where most people are happy.”

Staff shared its analysis of RR272’s economic effects, which compared the conversion of NDVERs to DVERs against a base case using real-time security-constrained economic dispatch data. They found the conversion resulted in improved congestion management and, with it, better convergence of real-time and day-ahead prices. That resulted in about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.

The data also indicated a significant reduction in the number of operating hours with negative pricing.

The MWG revised the proposal to exempt run-of-river hydro not capable of following dispatch instructions and to provide additional time for certain NDVERS to convert. They now face a deadline of either Jan. 1, 2021, or the 10-year anniversary of a resource’s original commercial operation date.

Market Monitoring Unit Executive Director Keith Collins said he supports the proposal, saying the benefits come from “an increase in prices at locations that are primarily non-dispatchable.”

“We’re investing upgrades for controls we don’t own, which increases the [power purchase agreements] for our customers. That’s not something we’re keen on,” said Empire’s Aaron Doll. “Our specific limitation is contractual language that limits curtailments to a certain amount in a 24-hour period. The dispatch signal puts us in bad spot pretty quickly. Anything short of providing an exemption for entities with contract language that precludes curtailment is not something we can support.”

The MOPC also approved RR266, which would model a joint-owned unit (JOU) as a single resource in market-clearing decisions, while performing an after-the-fact allocation of revenues based on ownership shares. Other JOU shares would be used for settlement purposes, and each share would exist only in the context of settlements where final clearing results are split based on the submitted ownership share percentages.

The change is contingent upon final approval by the Regional Tariff and Operating Reliably working groups. Nebraska Public Power District and Oklahoma Gas & Electric’s Transmission and Electric Services divisions opposed the measure, citing problems with the language.

“We have a couple of JOU situations we manage fine ourselves,” said OG&E-Transmission’s Greg McAuley. “We’ll continue to pound the table as it relates to some of these administrative costs.”

Stakeholders approved against minimal opposition three other revision requests brought forward by the MWG:

• • RR306, which would minimize potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
  • RR304, which streamlines the process by which frequently constrained areas are re-evaluated, in order to make adjustments in a timely manner.
  • RR312, which would calculate the FERC Schedule 12 rate based on current data. The change aligns the collections of revenue against the customers’ megawatt-hours being assessed.

SPP Prepared for January’s ‘Big Chill’

Staff’s update on what they call “The Big Chill,” the abnormally frigid temperatures Jan. 17-18 that led to heavy north-south transfers of MISO flow across SPP’s system and a maximum generation alert in MISO South, caused one member to recall his scouting days.

“I wouldn’t call this an emergency event,” said MOPC Chair Paul Malone, of NPPD. “It was pretty well known we would have severe weather over a wide area. That begs for proper planning. As the Boy Scout motto says, ‘Be prepared!’”

“Let’s just say, some people are surprised every day by what happens,” said SPP COO Carl Monroe, “and some people were surprised that day.”

MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP system during the event and was forced to make emergency purchases from Southern Co.

SPP Vice President of Operations Bruce Rew said the RTO never had to issue an emergency alert, as it was never short of generation. “It was uncomfortable for us,” he said. “We have to make sure it doesn’t happen again.”

David Kelley, SPP’s director of seams and market design, credited SPP’s and MISO’s neighboring reliability coordinators with helping to prevent load shed and keeping the lights on during the event. He said recent discussions among the Regional Transfers Operating Committee (RTOC), a six-person group comprising two representatives each from SPP, MISO and joint parties to a 2016 settlement agreement, centered on better understanding the non-firm, available nature of MISO’s north-south flows and their effects on neighboring entities. (See SPP, MISO Reach Deal to End Transmission Dispute.)

“Anything over 1,000 GW is on a non-firm, as-available basis. To us, that means SPP’s service should not be in jeopardy of load shed,” Kelley said. “When this event happens again, and will happen again, we’ll be prepared.”

Kelley said staff has also met with FERC staff to “ensure FERC had a clear understanding of what happened that day,” given “very inaccurate statements that found their way into the media.” (See SPP Seeks FERC Meet in MISO Tx Dispute.)

Kelley also briefed the MOPC on a proposed interregional project with Missouri-based Associated Electric Cooperative Inc., a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.

The project’s regional cost allocation was rejected by FERC last year. (SPP would be responsible for 89% of the $13.75 million in engineering and construction costs). SPP staff have since developed data that indicate the project would yield the region $17 million in load ratio share benefits by eliminating the need for upgrades at City Utilities of Springfield’s John Twitty Energy Center and also reduce day-ahead market uplift costs.

“We feel like we’re in much better shape,” said Kelley, who met with FERC staff on July 12. “They look forward to seeing our next filing.”

Kelley said that filing should be made in late July or early August.

Stakeholders Endorse $47.4 Million in Near-term Tx Work

The MOPC endorsed the Transmission Working Group’s recommendation to approve the Integrated Transmission Planning process’s 2018 near-term assessment portfolio, a package of 13 transmission projects with an estimated cost of $47.4 million

However, when taking into account four withdrawn projects from previous assessments that cost a total of $53 million, the portfolio has a net cost of -$5.6 million.

Several of the Kansas and Missouri projects are being driven by the retirement of about 1.9 GW of 50- to 60-year-old generation later this year and in early 2019.

The projects will solve 101 reliability needs. They include a new 345-kV, 50-MVAR reactor at City Utilities’ Brookline substation, a project originally identified as an interregional project with AECI.

OG&E’s Travis Hyde, who chairs the TWG, noted SPP approved nearly $8 billion in construction between 2006 and 2014. With the strategic shift to maintaining “an economical, optimized transmission system,” he said, the RTO has since approved just more than $1 billion in base plan funded investment.

Staff developed a summary presentation of the assessment using a story map tool.

Stakeholders also endorsed NorthWestern Energy’s sponsored upgrade of less than 4 miles of new 115-kV line in Aberdeen, S.D., and a working group recommendation to approve the 2019 ITP’s needs sensitivity scope addressing study results affected by Lubbock Power & Light’s potential exit from the system.

RC Efforts in West Absorb MWTG Integration

Monroe told members that the integration of the Mountain West Transmission Group has been “subsumed” in the debate out West over who will provide reliability coordinator (RC) services — a debate that involves SPP.

The RTO said in June that it plans to offer RC services in the Western Interconnection, matching an earlier announcement by CAISO. Not coincidentally, Peak Reliability said last week it will wind down its RC role by the end of 2019. (See related story, Peak Reliability to Wind Down Operations.)

SPP’s Carl Monroe (c), NPPD’s Paul Malone, NE Texas Electric Co-op’s Jason Atwood, GDS Associates’ Jack Madden anchor the MOPC’s head table. | © RTO Insider

“There’s still interest in [joining SPP],” Monroe said. “The importance of making sure RC is provided, and in an efficient and reliable way, has subsumed their work right now.”

SPP’s efforts to integrate Mountain West were dealt a blow in April when Xcel Energy announced it was withdrawing from the Rocky Mountains group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)

Monroe said there have been no changes to the Mountain West’s initial proposal to join SPP, adding he hopes to be able to provide “what kind of a footprint we would have with RC services” by Sept 1.

“As we work through the process, our intent is to meet the goals of what we normally do through contract service, which is providing benefits back to the members themselves,” he said.

MRO’s Patrick Welcomes New Entities

Midwest Reliability Organization CEO Sara Patrick introduced herself to SPP members, many of whom were among the 100 registered entities that joined the organization after the SPP Regional Entity’s recent dissolution. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)

Patrick said all compliance monitoring and enforcement program (CMEP) data was successfully transferred from the SPP RE to MRO on July 3, and that all entities in its expanded footprint are now using MRO’s webCDMS portal.

Patrick gave credit to the SPP RE’s staff in a “well-coordinated” transition and data transfer. The $1.5 million in transition costs will be recovered by transferring assessments from the SPP RE to MRO, she said.

The MRO’s board of directors last month approved a $4.3 million increase, reflecting the expanded footprint. Patrick said the budget will result in $4.8 million in savings, when compared to the combined MRO and SPP RE budgets.

The board also agreed to add four new directors next year, including two regional directors from the SPP RE’s footprint.

MOPC Sends Two Initiatives Back

The MOPC declined to take action on a pair of work efforts, asking that both be returned to the stakeholder process for further clarification.

Following an update on SPP’s prioritization process for revision requests and project proposals, stakeholders debated potential improvements to the process before the committee’s leadership said it would return to the next meeting in October with ideas on how to proceed.

Stakeholders complained about a lack of transparency, the amount of information they had to deal with and not knowing where decision-making authority lies. Staff said it stopped the quarterly meetings because of a lack of feedback.

Several members familiar with ERCOT’s stakeholder process suggested the Texas grid operator’s Protocol Revisions Subcommittee (PRS) as a good model to follow. Tenaska’s John Varnell, who once chaired the PRS, said if members listened in on the group’s meetings, “You will see how we can do better at this process.”

“That’s one thing that ERCOT does quite well,” said Golden Spread Electric Cooperative’s Mike Wise, who sits on ERCOT’s MOPC equivalent, the Technical Advisory Committee.

“[The PRS] does a really good job of ensuring financial stability or accountability. [Members] debate [revision requests] quite substantially before they ever enter in the queue for approval at the TAC. Many of us want this to be like what we have at ERCOT. It puts more decision-making in the hands of the stakeholders, rather than SPP.”

Grant, who headed the task force that developed the prioritization process, called for more stakeholder involvement in the process. He reminded the committee that the task force hasn’t been disbanded.

“If we’re going to spend the time and effort to improve the process, we need better participation and more dedication to the issue,” he said. “It doesn’t matter what we set up if the stakeholders aren’t going to participate in the process.”

The MOPC also sent back a Credit Practices Working Group (CPWG) revision request, saying it needed more information and noting the Finance Committee had tabled the request. The CPWG reports to the committee.

The CPWG’s RR311 would change the way reference prices are used to estimate the settlement exposure of transmission congestion rights (TCRs). The group’s analysis of a two-year period indicated its proposed methodology would have reduced collateralization in the TCR market by $124 million to $327 million, and more than doubled under-collateralization from $17 million to $39 million.

Staff recommended tabling the change, saying it needed more analysis in light of a market participant’s recent default in PJM’s financial transmission rights market. (See “Credit and Default,” PJM MRC/MC Briefs: June 21, 2018.)

“It sounds like the hesitancy to move forward is lack of understanding of what’s happening in the PJM situation,” said Kansas City Power & Light’s Denise Buffington.

Given that the CPWG has yet to gain approval from the Finance Committee and the Regional Tariff Working Group, stakeholders agreed to send CPWG RR311 back to the working group so that it can be properly shepherded through the stakeholder process.

Members Endorse RRs, Process Language Change

Members endorsed language changes to improve efficiency of the revision request process by reducing the time it takes to gain approval for a change and removing duplicate references that cause unnecessary changes.

The proposal (RR291) would allow a revision with approved “normal status” to progress through the stakeholder process while its primary working group waits on the impact analysis. It would also revise language to reference the applicable documents as SPP revision request documents and remove their multiple references.

The MOPC’s consent agenda, which passed unanimously, included nine revision requests and a new baseline cost estimate for SPS’ 115-kV loop rebuild in West Texas. The project’s original cost of $28.4 million was reduced almost 23% to $21.9 million.

• • BPWG RR307: Clarifies that partial service may be offered to short-term transmission service requests when the full amount requested cannot be granted.
  • CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
  • MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governance, to eliminate confusion over whether entities are performing obligations for market or NERC standard reasons. Also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
  • MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
  • MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; circumstances if violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
  • ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
  • RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
  • RTWG RR315: Removes references to the SPP RE in the governing documents.
  • RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.

— Tom Kleckner