OKLAHOMA CITY — Southwest Public Service last week withdrew its appeal of a rejected revision request, saying it was satisfied with SPP’s direction to address reporting behind-the-meter network load.

Staff told the Board of Directors and Members Committee on Jan. 30 that it will continue to foster discussion and educate its members, with the intent of determining consistent reporting practices of network load. SPP is digging into the data from a recent survey of members with network integration transmission service (NITS) load and said it will work through the Strategic Planning Committee to develop a common methodology. It hopes to produce a final report in April.

The RTO’s legal staff have met separately with FERC to gain a better understanding of what is and what isn’t net metering, and are continuing their effort to clarify BTM rules. (See SPP Stakeholders Still Struggling on BTM Reporting.)

That was enough for SPS, which filed an appeal with the board after the Markets and Operations Policy Committee rejected a proposal in October that would have required a 1-MW threshold for reporting BTM retail load. (See “Stakeholders Unable to Reach Consensus on Network Load,” SPP Markets and Operations Policy Committee Briefs.)

In its appeal, SPS said RR241 was “critical to ensuring that the costs of network service are fairly distributed to SPP network service customers and to prevent some SPP customers from subsidizing network service used by other customers.”

“Our retail tariff requires everybody to follow the tariff and enter an interconnection agreement with us, so we do track that [load],” SPS President David Hudson said. “By others not reporting it, it is creating some sort of cost shift. We just want to ensure we take care of this problem.”

“We’re not opposed to working through the stakeholder group,” said Bill Grant, SPS’ vice president of regulatory and strategic planning. “If the stakeholders want to do that and make an attempt at consensus and file something at FERC, we’ll participate in that. Once we understand what the requirements are and the stakeholders want to come together, we will embrace that effort.”

Board Chair Jim Eckelberger summarized stakeholders’ agreement to move forward, saying the board’s point of view is “equity across the system.”

Staff, MWG ‘Looking into’ Cold-Weather Price Spikes

Bruce Rew, SPP’s vice president of operations, said staff are “looking into” several five-minute price spikes that occurred Jan. 16-17, when the RTO set several new highs for winter peak demand. (See ERCOT, SPP Extend Winter Peak Records.)

“The story is related to scarcity pricing,” said Nebraska Public Power District’s Tom Kent. He said he was concerned about “volatility in the market,” but that staff have been “very helpful.”

The Market Working Group (MWG) has also taken up the issue.

Rew said unit trips and outages on the neighboring MISO South system during a Jan. 2 cold weather event “created extra flows on our system that were quite challenging.”

When the meeting ended, Rew handed out lapel pins celebrating 20 years of SPP’s reliability coordinator (RC) function.

“It would not have been a pretty picture two weeks ago, but for the consolidation of balancing authorities, the regionalization of the Tariff and the Integrated Marketplace, that has enabled us to commit units in the day-ahead [market],” SPP CEO Nick Brown said. “I think it’s most appropriate we mark 20 years as an RC.”

Stakeholders Remember Gerry Burrows

Stakeholders opened the meeting with a moment of silence for SPP Regional Entity Trustee Gerry Burrows, who died of cancer on Jan. 9. Burrows had a long industry career, much of it with Kansas City Power & Light. (See “SPP RE Trustee Gerry Burrows Dies,” Company Briefs.)

“No one understood the importance of working together to consensus like Gerry did,” Brown said. “Frankly, it was people like him who made me want to come and work at this corporation and help drive people to consensus.”

“This organization is going to miss Gerry, and we already are,” Trustees Chair Dave Christiano said.

Board Clears 13 Revision Requests

The board approved a Supply Adequacy Working Group revision request (RR251) that addresses three issues FERC cited in rejecting SPP’s resource adequacy package last year. (See FERC Again Rejects SPP’s Resource Adequacy Revisions.)

The working group said the measure responds to FERC with numerous changes, while maintaining the previously approved foundational policy. It also moves the planning reserve margin percentage to the SPP planning criteria and keeps the study process for determining the margin in the Tariff.

Westar Energy’s Kelly Harrison and Brent Baker abstained from the members’ vote.

The board also approved an MWG proposal (RR257) that responds to a FERC compliance requirement (EL16-110) obligating 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.)

The board and members approved 11 other revision requests on the consent agenda:

• • BPWG-RR250: Documents market import service (MIS) as a transmission product in the Tariff (it has been offered in SPP’s Integrated Marketplace since 2014) and places all information related to reserving and scheduling MIS in one location as a new business practice.
  • 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 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-RR245: 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 and recover true variable costs.
  • 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-RR253: Changes how dispatchable variable energy resources (DVERs) provide regulation down service. 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-RR256: Cleans up language in RR116 to eliminate a potential gaming opportunity and make clarifications necessary to implement the new quick-start logic correctly and with its true intent.
  • 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 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.

The consent agenda’s acceptance also resulted in the approval of a sponsored upgrade study for Central Power Electric Cooperatives, several staff recommendations on transmission projects and adjusted baseline costs for three previously approved projects. (See “North Dakota Sponsored Upgrade Study Approved,” “MOPC Agrees to Pull Basin Electric Project’s NTC-C” and “Consent Agenda Clears 10 Revision Requests,” SPP Markets and Operations Policy Committee Briefs: Jan. 16-17, 2018.)

— Tom Kleckner