SPP’s Markets and Operations Policy Committee on Friday approved two revision requests related to resource adequacy requirements that members had set aside during their regular quarterly meeting earlier this month.
The special conference call became necessary when MOPC deferred action on the RRs after several late changes were shared with members the night before the January meeting began. The committee directed SPP staff and the Market Monitoring Unit to re-engage with stakeholder groups to ensure members still agreed with the changes. (See “Members Defer on PRM Deficiency RRs,” SPP MOPC Briefs: Jan. 17-18, 2023.)
“We’ve kind of taken them on a roadshow,” the MMU’s John Luallen told MOPC during the call.
Taken together, RR536 and RR537 would provide load-responsible entities with a short-term, non-punitive alternative approach to deficiency payments for the summer resource adequacy requirement (RAR). Staff have been working on the mitigation strategy since July, when SPP increased the planning reserve margin (PRM) from 12% to 15%, effective this year. That left some members complaining they would not have enough time to meet the requirements. (See SPP Board of Directors Briefs: Dec. 6, 2022.)
The Supply Adequacy, Cost Allocation and Regional Tariff groups all approved the RRs last week by a combined vote of 75-1, with 28 abstentions, making only various non-substantive terminology edits.
MOPC then endorsed the tariff revisions in separate electronic ballots. Solar and storage developer Savion cast the only dissenting vote. The measures will now go before SPP’s Board of Directors and Regional State Committee this week for final approval. Staff hope to gain FERC’s approval in time to accredit resources for the summer season (June 1-Aug. 31).
Stakeholders modified RR536 to clarify that LREs can make a sufficiency payment only when the PRM is increased within the previous two years and the LRE demonstrates it had adequate capacity to meet the PRM before it was changed. A deficiency cannot result from selling accredited capacity to another region after the PRM’s increase is approved.
Under the change, capacity can only be claimed for accreditation by one asset owner in the SPP footprint. Capacity used to resolve deficiencies cannot be sold to another region for the applicable resource adequacy requirement season.
The measure includes the MMU’s proposed sufficiency valuation curve to value capacity in the market. The curve starts at twice the cost of new entry (CONE) at or below the sum of noncoincident peak loads, then slopes downward to a net CONE value when regional accreditation reaches the PRM. When the region has sufficient accredited capacity, the net CONE drops down to zero at 115% of the PRM.
RR537 emerged from the last-minute stakeholder process with revised language that removes a tariff violation when LREs fail to make a resource adequacy payment. As modified, LREs would be deemed sufficient for the adequacy requirement with a deficiency payment.
The change was also modified to clarify that only capacity resolving deficiency is obligated to stay in SPP; the obligation only applies to a specific RAR season; and that a deficiency payment is based on a kilowatt-year.
CRSP Faces Tx Rate Issues
The grid operator is working to address concerns by one of nine entities evaluating membership in its RTO West offering over its restrictions as a federal power marketer.
The Western Area Power Administration’s Colorado River Storage Project (CRSP) in November requested changes to the terms and conditions for RTO membership, approved last July. Those terms were to be effective March 1, but SPP’s Strategic Planning Committee endorsed a four-month extension to July 1 and additional terms and conditions during its Jan. 18-19 meeting.
The new terms include crediting CRSP’s point-to-point (PTP) transmission service and a federal service exemption (FSE) of replacement energy to satisfy its statutory load obligations.
The board will consider staff’s recommendation during its quarterly meeting Tuesday. The changes are contingent upon WAPA publishing its intent to join the RTO West in the Federal Register by Feb. 28.
Bruce Rew, SPP | © RTO Insider LLCAsked what SPP would do should other obstacles pop up before July, Bruce Rew, senior vice president of operations, said, “We would have to see what options we have that point to see if there’s some alternative that we can do to satisfy their situation.”
Rew said that about 88% of CRSP’s transmission obligations sink outside its zone, leaving the remaining 12% exposed to rate increases because of SPP’s treatment of PTP revenues. Low water levels in the Colorado River and the federal hydropower system also pose a risk, as the project’s transmission system was built to move federal hydro, he told stakeholders during the MOPC and SPC meetings.
Staff and other RTO West-interested parties, working together, agreed that CRSP would maintain PTP revenue from its reservations to pay for facilities in its transmission zone. This would apply to service delivered either inside or outside the SPP RTO footprint, with the contractual or statutory load obligations distributed solely to the project.
Because SPP’s tariff won’t allow CRSP’s replacement energy as an FSE, thus subjecting it to additional costs, staff and the other Western parties recommended the replacement energy be delivered to the CRSP zone and be subject to tariff provisions and charges. However, replacement energy delivered from CRSP’s zone will be eligible for an FSE; ineligible transmission purchases will receive auction revenue or transmission congestion rights.
CRSP sells about 5.3 GW of power to customers in Arizona, Utah, Colorado, New Mexico, Nevada, Wyoming and Texas over transmission facilities either owned or leased by WAPA.
SPP is also evaluating options to pull in the implementation schedule for its Markets+ offering in the Western Interconnection, an “RTO-light” market for those utilities not ready for full RTO membership. (See Governance, Resource Adequacy Key to SPP’s Markets+.)
The grid operator has projected an initial phase establishing market rules and tariff language will take about 21 months, followed by another three years to develop the day-ahead market.
The Western Resource Adequacy Program, a key part of the Markets+ offering, has attained funding commitments to move the program forward, and SPP has replied to a FERC deficiency letter over its tariff filing, the RTO’s Antoine Lucas told the SPC. Operations and forward-showing programs and systems will be implemented later this year, he said.
The SPC also approved a task force’s recommendation to add changes needed to include competitive upgrades to project monitoring processes as part of its business practice related to transmission projects.
The Transmission Owner Selection Process Task Force has reviewed 19 key areas to improve the competitive project selection process. It has reached consensus on 12 areas.
