RUC, Shortage Pricing Practices Challenged
LITTLE ROCK, Ark. — Mike Wise, Golden Spread Electric Cooperative’s senior vice president of commercial operations and transmission, once again argued against a revision request funneled through the SPP Market Working Group that replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.”
Wise told the Board of Directors and Members Committee that with MRR173, part of a compliance package responding to FERC Order 825, procuring rampable capacity through the reliability unit commitment (RUC) process “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”
“We’re RUCing them left, we’re RUCing them right, we’re RUCing them all the time. [That] dampens prices and dampens the market,” Wise said. “It’s just an advanced form of an [energy imbalance service] because of all the RUCing that’s going on.
“There are so many new resources … that are rapidly coming on that make appropriate price signals even more important. Our main goal should be to allow resources to clear based on market offers, not cost, in the dispatch model itself. The process needs to be improved substantially.”
Not so fast, said American Electric Power’s Richard Ross, the MWG’s chair. He said the claim that SPP is “RUCing things as they see fit couldn’t be further from the truth.”
“We could change the rules and say we don’t even need the reserves, but we’d have more scarcity events,” Ross said. “Being a balancing authority comes with obligations. It is unacceptable to go into real-time operations; not only unacceptable, but it’s not compliant to go in short. This revision is clarifying exactly what staff should be doing.”
Ross said MRR173 and MRR175, which seeks to comply with Order 825 by using shortage pricing for any interval in which energy or operating reserves are short, would address Wise’s concerns. Both revisions are necessary for SPP to make a planned FERC compliance filing in January.
A third revision, MRR188, gives staff the option to include as much as 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market. The revision is a protocol change, so it did not need board approval.
The three revisions “are all tied together,” Ross said. “What’s happening with this change, and the change in 188, is to move that procurement into the day-ahead market. It’s an improvement. We don’t want scarcity events. We want right pricing.”
“I don’t believe there are any cost implications at all. I believe it’s a practice we have to live with at SPP,” said COO Carl Monroe, pointing to the Price Formation Task Force as another group addressing the ramping issue. The task force is expected to wind down its work by year-end and then hand it over to the MWG.
“The entire MWG is sympathetic to you,” Ross said to Wise. “I absolutely feel you should recover all costs for generating energy out of those [quick-start] resources. The answer is to set prices at the cap, frequently, in order to allow that to happen. We think shortages happen and are being priced appropriately, but this is a first step. We need to … be in position to comply with the FERC order and after that, we can improve on it.”
Wise said he was encouraged by Ross’ comments.
“To the extent we can eliminate RUCs, I really want us to get there,” Wise said. “It’s not an issue that’s going away. We should be procuring through the market and the bid-stacking process.”
Still, Wise wound up casting the lone opposing vote against MRR173. He was joined in opposing MRR175 by Dogwood Energy’s Rob Janssen, who said he objected to staff inserting language the week before October’s Markets and Operations Policy Committee meeting calling for a $5,000 spike in the operating reserve demand curve (ORDC) during a scarcity event.
“I look at pricing to have the right price at the right time for the right reason,” Janssen said, paraphrasing an SPP motto. “Going straight to $5,000 in an event like this is unnecessary. The single highest price we’ve seen at our node is $2,000. It’s an excessive change, in my opinion. If we can have further discussion about reducing the number, I’d appreciate that.”
Richard Dillon, SPP’s director of market design, responded that the ORDC will go straight to $5,000 “because it’s a demand curve, and we have run out of ramp at that point.”
“We set it at $5,000 so we don’t choose to do other things and cause reliability issues,” he said. “If we’re short all the reserves in the [load zones] and the region, the prices have the potential to be at $3,400, so we needed this one to be higher than that value.”
The MWG “will make the language as appropriately flexible as we can,” Ross said. “We have some implementation time before the compliance filing is put into effect.”
The board also approved two other revision requests brought forth by the MWG:
- RR183, which updates the violation-relaxation limits’ operating constraint to allow additional redispatch to solve cases with fewer violations, passed with two opposing votes.
- RR193, which adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. The revision received two abstentions.
Brown Says Cybersecurity Biggest Challenge
SPP CEO Nick Brown said during his president’s report that cybersecurity issues will be SPP’s — and the industry’s — biggest challenge in 2017.
“Our ability to rely on the Internet of things is being challenged,” he said. “That makes us rethink how we operate our businesses and how we rely on the Internet going forward.”
Brown said SPP’s organizational groups will all spend time at their next meetings gathering feedback “to decide the appropriate level of cybersecurity for this organization.”
“Our systems are there to serve you,” he said, “but the cost to comply … goes up.”
Brown also talked about several other initiatives. He reminded members and the board that he had labeled 2016 as “The Year of the Audit” back in January. He said SPP completed SERC Reliability compliance and FERC financial audits without findings, and he hopes a Critical Infrastructure Protection Version 3 audit begun in 2013 will be completed soon.
An internal initiative to reward employees for finding disparities between SPP’s 5,275-page Tariff and actual operating practices resulted in 10 self-reports to FERC, Brown said. He said the commission took no action on the reports.
FERC’s recommendations to “improve the appearance of independence” of the Market Monitoring Unit have been “implemented or are in the process of being implemented,” he said. The commission issued an audit report of the MMU in July, saying SPP executives had “inappropriate” involvement in the MMU’s oversight and called on the RTO to “strengthen its independence.” (See FERC Calls for Changes to Protect SPP Market Monitoring Unit Independence.)
The Integrated System’s first year of SPP membership resulted in $67 million in net savings to the RTO’s footprint, including $27 million to original members “that otherwise would not have been there.”
Finally, Brown said revenues are down 3.9% because of low loads. SPP budgeted the 2016 administrative fee using 2015 coincident peak loads, which were projected at 407 million MWh. The peak load forecast is now 394 million MWh.
Directors, Trustees, Members Re-elected
Members and directors re-elected several incumbents to the board, Regional Entity trustees and Members Committee during SPP’s Annual Meeting of Members.
Stuart Solomon (AEP) and Kelly Harrison (Westar Energy) were re-elected to represent the investor-owned sector; Stuart Lowry (Sunflower Electric Power) and Mike Risan (Basin Electric Power Cooperative), cooperative sector; Jeff Knottek (City Utilities of Springfield), municipal sector; Janssen, independent power producer/marketer sector; and Brett Leopold (ITC Great Plains), independent transmission companies.
Directors Julian Brix and Phyllis Bernard were re-elected to new three-year terms on the board. Bernard was first elected to the board in 2003 and Brix in 2008.
Stephen Whitley was elected to an additional three-year term as an RE trustee. Whitley completed former trustee John Meyer’s unexpired term following the latter’s resignation in March over a conflict with the bylaws of Western Interconnection reliability coordinator Peak Reliability, where Meyer is vice chair.
Ross Forgoes Razor for Charity
Ross, an often outspoken presence at SPP and ERCOT stakeholder meetings, has made himself even more noticeable with the recent addition of facial hair.
Ross began growing his beard following SPP’s board and MOPC meetings in July. There, he issued a challenge to his fellow stakeholders: If they contribute more than $1,000 to the United Way organizations of Tulsa, Okla., and Little Rock, he would not shave until Thanksgiving.
“And if you contribute more than $2,000, I will go full Duck Commander,” Ross said, referring to the popular “Duck Dynasty” television program.
Ross was unable to meet the higher goal, but his neatly groomed beard attests to what he was able to raise.
Consent Agenda Adds Working Group, Approves IEP Panel
The unanimously approved consent agenda included chartering the Supply Adequacy Working Group, which will take on tasks from the Generation Working Group and Capacity Margin Task Force; adding the Nebraska Public Power District’s Traci Bender to the Strategic Planning Committee; expanding the Oversight Committee to five independent directors; and accepting the Oversight Committee’s 11 candidates for the Industry Expert Pool that will evaluate and recommend competitive-upgrade projects.
The board and members also accepted the SPC’s recommendations to improve the competitive transmission process, the Project Cost Working Group’s recommendation to reset the baseline for an AEP 345-kV project in southeastern Oklahoma and staff’s recommendations to accelerate one project and withdraw the notice-to-construct for another. (See SPP Panel OKs Changes to Competitive Transmission Process, “AEP Project’s 41% Overrun Approved” and “Members Vote to Cancel 69-kV line in West Texas,” SPP Markets and Operations Policy Committee Briefs.)
Other rule changes approved by MOPC were:
- MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex post
- MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) to ensure long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
- MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
- MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
- ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
- TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with the Western Electricity Coordinating Council.
- RTWG-RR164: Updates Tariff Attachment O to correctly reflect the current near-term planning process schedule, which is now conducted in the April-March timeframe.
- RTWG-RR174: Revises Attachment AQ of the Tariff to eliminate a requirement that transmission customers submit a request for changes in delivery point facilities when there is no corresponding change in load.
- RTWG-RR176: Corrects and clarifies responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
- TRR88: Modifies the time of day when unscheduled firm transmission is released for sale as hourly, non-firm transmission service for those members wishing to coordinate next-day scheduling with WECC.
– Tom Kleckner