RAPID CITY, S.D. — The SPP Markets and Operations Policy Committee last week refused to take action on American Electric Power and Oklahoma Gas & Electric’s revision request to remove the day-ahead limited must-offer.

The Market Working Group approved RR 125 last November but postponed moving it forward in December to allow further discussion on RR 135, which would revise physical withholding rules. It again failed to move the request forward in May on a tie vote (8-8, with one abstention).

“This is about the fourth or fifth bite at the apple others have tried with this issue,” Golden Spread Electric Cooperative’s Mike Wise said. “When we were designing the market, we debated this issue ad nauseam. I suggest we not change something that works right now.”

Wise said he agreed with the Market Monitoring Unit’s position of waiting to move forward with RR 125 until RR 135’s rules for physical holding have been completed. He suggested waiting for the enhanced combined cycle (ECC) project to go into effect next spring. The project — an effort to provide more sophisticated modeling that captures such plants’ flexibility — is being done in conjunction with changes to align the Integrated Marketplace’s day-ahead market with gas nominations.

“We should wait until the enhanced combined cycle [project’s completion] next spring, and then move forward,” he said. “It will remove the difficult decision and guessing about which mode of combined cycle operation the market needs, and remove some of those concerns dealing with the physical withholding in the market.”

“I haven’t heard enough about why it’s so important to remove the limited must-offer provision,” Midwest Energy’s Bill Dowling said. “I haven’t heard enough about the benefits [of] moving forward without knowing what the next steps are.”

RR 125 was a result of the Market Monitoring Unit’s recommendations to improve the Integrated Marketplace. It was designed to run in parallel with another revision request that would revise physical-withholding rules.

“We focus on the market power of units and the specific impact of units on the market,” MMU Director Alan McQueen said. “From a market monitoring perspective, physical withholding is the issue that’s a concern to us. I believe there’s value in coupling these things together and think about it in the way FERC’s going to look at it.”

The MOPC passed three revision request brought up individually, though each received a handful of opposing votes and abstentions.

RR 2, which predates SPP’s new revision request process, gives market participants the option of submitting interchange data in five-minute or hourly intervals. Participants were previously prohibited from submitting the data in five-minute intervals.

“As I understand it, the functionality won’t be used by the entire footprint for a long time,” said OG&E’s Greg McAuley, who cast one of four opposing votes against the measure. “Our MWG rep told me no single market participant intends to use this functionality. If we’re not going to consistently use it, why are we even talking about it?”

McAuley also questioned the estimated $50,000 cost of implementing RR 153, which would eliminate market participants’ need to make two separate submissions for a single intraday change.

Under current protocols, resource offers roll forward hour-to-hour, which can cause problems when intraday changes only meant to apply to the current day carry forward to subsequent days.

“It sounds like a software problem,” Kansas Power Pool’s Larry Holloway said. “If the software isn’t doing what it’s supposed to, isn’t there some sort of maintenance that occurs before [a revision request] comes to MOPC?”

“It’s a very fine nuance in the protocols,” said American Electric Power’s Richard Ross, who chairs the MWG. “I thought it was the software at first, too, but as we dug into it, there’s a very fine, quirky, strange reading of the protocols. We’re changing the protocols and the Tariff to make sure we get exactly what we want.”

Another request approved by the MOPC, RR 167, would avoid Tariff violations resulting from the incorrect submission of annual revenue rights or transmission congestion rights. It is expected to cost $134,000.

“What’s the saying? ‘Sooner or later, it becomes real money,’” McAuley said. “We’re nickel and diming ourselves to death.”

Ross said the MWG has passed or is working on nine improvements to the Integrated Marketplace at a combined cost of about $11.4 million. The bulk of that total — $9.2 million — is linked to the ECC project.

Revision Requests Approved

The MOPC approved nine revision requests on its consent agenda:

• BPWG-RR 88, modifying the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for the next day from noon (CT) to 10 a.m. The change will allow coordination of next-day scheduling with the Western Electricity Coordinating Council.
• MWG-RR 7 MPRR155, revising instructions for dispatching generators out of merit order into two categories: reliability issues and emergency conditions.
• MWG-RR 161, changing the method for calculating make-whole payments for multi-configuration combined cycle resources; the new rules allow use of a netting approach in calculating the commitment-level costs eligible for recovery.
• MWG-RR 165, removing references to the retired Mitigated Offer Task Force from the Tariff’s Appendix G.
• MWG-RR 166, removing references from the protocols and Tariff to the interim transmission congestion rights process developed for the transition into the Integrated Marketplace.
• MWG-RR 169, changes reliability unit commitment calculations from evaluating megawatts needed hourly to those needed for each dispatch interval.
• ORWG-RR 159, moves requirements regarding the outage-coordination function into SPP Operating Criteria Appendix OP-2 “Outage Coordination Methodology,” eliminating redundant language elsewhere.
• RTWG-RR 160, clarifying the Integrated Transmission Planning manual to note which generation interconnections and associated upgrades are required to be modeled in ITP assessments.
• RTWG 163, correcting Tariff language to specify the ITP manual includes references to requirements.

Working Group Closes 5 of 9 MMU Market Recommendations

AEP’s Ross briefed the committee on the MWG’s progress in implementing the market monitor’s recommended improvements to the Integrated Marketplace. The recommendations were a result of the July 2015 State of the Market report, which covered the markets’ first year of operation.

Four of the MMU’s nine recommendations are considered closed, having been addressed by revision requests:

• Not subjecting quick-start resources to reliability unit commitment and not providing make-whole payments for resources dispatched in the real-time balancing market;
• Reducing available financial transmission rights to minimize over-allocations when not supported by day-ahead congestion revenues;
• Improving transmission-outage reporting in the FTR process; and
• Automating the bidding process for transmission congestion rights to prevent ongoing Tariff violations.

The MMU withdrew a fifth recommendation, related to market power mitigation conduct thresholds. The monitor said it had observed lower-than-expected mitigation levels during the Integrated Marketplace’s second year of operation.

Ross said a task force has been formed to address ramp-constrained shortage pricing, which the MMU suggested should be priced the same as operating-reserve capacity shortages.

SPP RE Selects New Trustee Candidates

The Regional Entity’s trustees have worked with a search firm to select two candidates as new trustees: Mark Maher, who retired as the WECC’s CEO, and retired NYISO CEO Steve Whitley. SPP’s Members Committee will vote on their nominations during the July board meeting.

Maher and Whitley would join incumbents Dave Christiano and Gerry Burrows. Christiano replaced John Meyer as the trustees’ chairman earlier this year, when Meyer resigned to join Western Interconnection reliability coordinator Peak Reliability.

RE General Manager Ron Ciesiel told the MOPC the trustees approved the entity’s $10.9 million budget for 2017 and its business plan during their June meeting.

Ciesiel said the RE continues to see a downward trend in standards violations and vegetation contacts. He reported just two regional events during the second quarter, an outage and a 30-minute partial loss of monitoring at a control center.

The RE is conducting its first Critical Infrastructure Protection v.6 audit this month. Ciesiel said a FERC-led CIP compliance audit is expected next year, as the SPP footprint was not selected for an audit this year.

Recommendation: Retire Task Force, Create New Working Group

The MOPC unanimously approved the Capacity Margin Task Force’s recommendation that it and the Generation Working Group retire and be replaced by a Supply Adequacy Working Group. The new working group would also assume fuel supply work now performed by the Gas Electric Coordination Task Force.

The CMTF held its last meeting June 30, when it finalized a charter for the new working group. It also reviewed its final deliverable, a resource adequacy workbook that combines the data needed for complying with NERC standards with those needed to validate SPP’s planning reserve margin. Chairman Tom Hestermann, of Sunflower Electric Power, said many of the task force’s members will transition to the new group.

The task force was created in 2014 to update SPP’s capacity margin requirements and methodology. Its work resulted in the RTO’s first reduction in its planning reserve margin since 1998 and a package of policies defining a load-responsible entity and its obligations. The task force also drafted a planning-reserve assurance policy and conducted a deliverability study. (See “Lowered Reserve Margin Promises $86M in Annual Savings,” SPP Board of Directors Briefs.)

Study Scopes Approved

The MOPC unanimously approved study scopes and revisions for a pair of studies, the Variable-Generation Integration study and the 2017 Integrated Transmission Plan’s 2017 Near-Term assessment.

The variable-generation study will include stability and frequency-response analyses with wind resources representing 30%, 45% and 60% of total SPP generation. SPP’s peak wind penetration record is 49.17%, and staff has said it expects to see levels approaching 60%.

Asked whether the task force is trying to determine when the 60% figure will be reached, SPP’s Casey Cathey, manager of operations analysis and support, said, “Sixty percent is a good level [to measure], because we have to add wind [generation] to get to that level. …The real issue, based on our footprint and our models, is will we see such penetration?”

Cathey said he is interested in determining whether there will be any voltage issues, saying, “We have to make sure that, given how we work the market, including dispatchable wind, whether we can maintain nominal voltage levels.”

The study will also analyze a potential five-minute ramping product.

The 2017 ITPNT’s scope was revised to include additional NERC transmission system planning performance (TPL-001-4) contingencies. Members also approved a modification to the 2017 ITPNT’s scenario 5, which sets all wind generation and reservations between companies to maximum firm service, as allowed on a pro rata basis. The modification aligns with the TPITF’s white paper, which assumed long-term firm transmission-service usage levels and conventional renewable resource output levels.

Regional Cost Allocation Review Approved

Members approved the Regional Allocation Review Task Force’s second regional cost allocation review of SPP’s regional- and zonal-allocation methodologies (RCAR II). There was one dissent.

The report’s 10 recommendations included proposed Tariff revisions and a proposal to incorporate its lessons learned in future assessments of the SPP highway/ byway methodology.

RCAR II identified the City Utilities of Springfield zone as SPP’s only deficient zone, with a benefit-cost ratio of 0.59, below the 0.8 threshold. Future transmission and seams studies with MISO and Associated Electric Cooperative Inc. are expected to help address the deficiencies. If not, a high-priority study for the area remains an option.

Two other zones (the Omaha Public Power District and Empire District Electric) are above the 0.8 cost-benefit threshold but below 1.0, requiring the RCAR II’s analysis be considered in future transmission plans.

The task force shared its report Monday with the Regional State Committee. Stakeholders will be able to provide their input through Aug. 5 for a lessons-learned report.

–  Tom Kleckner