Grid Operator Releases Report on Performance During Winter Storm

SPP last week released a comprehensive report on what it said was the most operationally challenging week in its 80-year history: Feb. 14-20, when a winter storm resulted in the first load shed in the RTO’s history.

The report, “A Comprehensive Review of SPP’s Response to the February 2021 Winter Storm, was compiled by hundreds of SPP staff, stakeholders, regulators and the Market Monitoring Unit working together in five parallel workstreams. It recommends 22 actions, policy changes and assessments related to fuel assurance, resource planning and availability, emergency response, market design, operator tools and other critical areas.

It also points a finger at the lack of fuel, saying generation’s unavailability was “the largest contributing factor to the severity of the winter weather event’s impacts … exacerbated by record wintertime energy consumption and a rapid reduction of energy imports.”

The root cause reveals a need to develop policies that improve fuel assurance and resource adequacy and “highlights the need to further assess SPP’s ability to reliably operate the system with more intermittent and fewer baseload resources,” the report said.

The teams’ evaluations found SPP’s market typically has about 55 GW of available generation capacity in February. That capacity dipped to 35 GW during the week of Feb. 14, primarily because of higher-than-usual fuel-supply deficiencies, wind turbine freezing and other operating equipment’s struggles in extremely cold conditions.

The Board of Directors and Members Committee both approved the report July 26 during a joint meeting with the Regional State Committee. They directed staff to work on recommendations addressing the root causes and asked that additional analysis be conducted on the natural gas supply’s failure.

“That will help us to peel the layers of the onion back a little further,” Nebraska Public Power District’s Tom Kent said.

Staff were also ordered to prioritize work on the remaining recommendations, provide a project plan and quarterly progress updates, and issue letters requiring SPP’s generator operators to inform the RTO about their plans to assure generation availability for the upcoming winter.

“I know many of us don’t want to experience this again,” COO Lanny Nickell said. “Many of us around the virtual table truly believe our staff, particularly our operators, and our stakeholders made the best out of a tremendously challenging situation. We will come out on the other side of this event wiser and better prepared for the future.

“Will our best be even better next time? Absolutely,” he said.

The MMU last month released a similar report on the winter event that also zeroed in on the unavailability of natural gas supplies. (See “February Storm Review Nearly Complete; MMU Issues Report,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

Much of the SPP footprint, from the Dakotas to the Gulf Coast, went through several days of record low temperatures. Electricity usage rose to record winter levels as the RTO was forced to shed load twice for a total of almost four hours.

“We were grateful for every single megawatt we could get our hands on,” Nickell said.

“This report isn’t the end of an effort. It’s the beginning of our hard work to improve our ability to mitigate future grid emergencies,” board Chair Larry Altenbaumer said.

He said the “elephant in the room” is the nature of the gas industry’s contracts. Energy prices rose from about $18/MWh to $4,300/MWh as gas prices shot through the roof. SPP plans to coordinate with the gas industry to develop trading practices that give its members access to gas when demand is high.

“We need to find a way to really get into an advocacy mode, in conjunction with the state regulators, political leaders [and] organizations that we are a part of,” Altenbaumer said. “Unless we make that kind of comprehensive effort, this will happen again and again and again.

“That is an industry that just does not learn from the experiences it has,” he said.

FERC and NERC are expected to release their joint report on the winter event in September, while several states in SPP’s footprint are conducting their own investigations.

Last month, Basin Electric Power Cooperative and North Iowa Municipal Electric Cooperative Association filed a complaint at FERC, asking to be reimbursed $77 million by SPP for agreeing to provide energy during the event.

Admin Fee Cap Bumped 8.1%

SPP will raise its administrative fee to 46.5 cents/MWh from 43 cents, an 8.1% hike from where it has stood since 2017.

The board and members approved the Finance Committee’s recommendation after SPP’s 2021 budget forecast found a significant increase in the net revenue requirement (NRR) between 2021 and 2022; that the transmission service billing units are projected to be flat during the entire period; and that the forecast rate exceeds the tariff cap as early as next year.

The cap is calculated by dividing the budgeted NRR, including true-up from prior periods, by the tariff’s estimated amount of transmission service to be provided in the coming calendar year. The committee said setting the tariff rate cap at a higher level than the forecasted rate avoids continual adjustments to the cap and FERC filings.

“Obviously, costs are extremely important to members,” FC Chair Susan Certoma said, acknowledging the committee doesn’t yet know the cost of the winter weather recommendations and other pending initiatives.

“It’s admirable to craft a plan while the sands shifting under your feet,” Oklahoma Gas & Electric’s Usha Turner said. “Our concern is that we are struggling to manage our [day-to-day work] today. Growth is great, but are we managing the priorities we have today as Job 1? Many among your membership are not seeing that same ability to increase their spending and resources.”

Golden Spread Electric Cooperative’s Mike Wise, who sits on the FC, called the increase “more reasonable” than the 50-cent cap the committee considered.

“I don’t think the board [and] the members want to see a 50-cent cap,” Wise said. “We spent significant time and consternation dealing with this particular issue in our meetings. We did have a very difficult discussion, but we reached a collaborative number of 46.5, and it was unanimous.”

SPP is expecting a slight under-recovery for the year as the NRR and fee forecasts are both under budget, the latter because of lower billing units.

Board OKs Western Expansion, GI Queue Plan

The board approved two previously stakeholder-endorsed proposals in affirming recommendations for a policy-level agreement for members interested in joining its Western Interconnection RTO and unclogging the generation interconnection queue’s backlog of requests.

Directors and members approved the Strategic Planning Committee’s recommendation to sign off on the terms and conditions for new and existing members adding their Western transmission facilities under SPP’s tariff. The terms and conditions are only valid until April 15, 2022. Western parties intending to financially commit to the RTO will execute another commitment agreement before that date, with a projected go-live date of March 1, 2024. (See Commitment Deadline Set for SPP West Participation.)

SPP and CAISO have both been working to expand their market offerings in the Western Interconnection. Altenbaumer noted that Arizona, Colorado and Nevada regulators are all considering requiring their utilities to join RTOs.

“Clearly, the level of activity taking place in the West is increasing,” he said. “While the size of this particular RTO West is limited, it gives us a great opportunity to establish a foothold in [the Western Interconnection] … and credibility.”

“Having an option for us to have an RTO is extremely important right now,” Tri-State Generation and Transmission Association’s Joel Bladow said. “We know a good structure will come from SPP.”

The grid operator has created a DC tie task force to reach consensus with its prospective members on cost allocations and policies for the four DC ties between the Western and Eastern interconnections. SPP plans to operate single balancing authorities across the ties, with its Integrated Marketplace solving for a single market solution in both BAs.

The task force is scheduled to present its findings this fall. The expansion project’s expenditures, currently estimated to be about $30 million, are to come before the FC and board next May. SPP hopes to secure FERC approval of its governing document changes in the first half of 2023.

The prospective Western participants include Basin Electric, Colorado Springs Utilities (CSU), Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State, Wyoming Municipal Power Agency, and the Western Area Power Administration’s (WAPA) Upper Great Plains-West region, Colorado River Storage Project and Rocky Mountain region.

Except for CSU, the organizations joined SPP’s Western Energy Imbalance Service (WEIS) market for its February launch before announcing their intent to explore full RTO West participation. The grid operator said CSU expects to join the WEIS in 2022 and is also exploring RTO membership.

Southwestern Public Service abstained from the Members Committee vote.

The board also approved the Strategic and Creative Re-engineering of Integrated Planning Team’s (SCRIPT) plan to resolve a four-year backlog of GI requests by 2024 and directed staff to work with the appropriate stakeholder groups in developing revision requests. (See “Renewable Developers Applaud SPP’s Plan to Reduce GI Queue’s Backlog,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

The GI queue’s backlog dates back to 2017. It comprises 533 interconnection requests for 100.3 GW of capacity, most of it wind and solar generation.

SCRIPT’s strategy is to reduce restudies through development milestones, increase financial commitments, and simplify and reduce study timelines.

“The proposal is designed with the premise that as generation projects become more developed and they are willing to place more at risk, they are much less likely to withdraw from the process,” Antoine Lucas, SPP’s vice president of engineering, told stakeholders.

WAPA’s Lloyd Linke voted against the motion, saying the agency has found the costs of connecting tribal entities to the federal transmission system “substantially larger” since joining SPP.

MMU Briefs Draft Market Report

The MMU reviewed a draft of its 2020 State of the Market Report, which has been delayed a couple of months by the Monitor’s involvement in the winter storm report.

The report will be issued during the second week of August, the Monitor said. A webinar will be scheduled to discuss that report and the MMU’s quarterly spring report.

The annual report’s key conclusions include:

• • Wind generation accounted for the largest percentage of total energy produced, at 31.3%, just ahead of coal at 31%. SPP’s nameplate wind capacity increased to just over 27.3 GW in 2020, up about 22% from 2019.
  • Day-ahead market prices averaged $17.69/MWh and real-time prices averaged $16.62/MWh, a 20% drop for both from 2019 and the lowest since the Integrated Marketplace went live in 2014. The average gas price at the Panhandle Eastern hub was $1.72/MMBtu, down 11% from $1.93 the year before.
  • Total electric consumption was down about 3% in 2020 as a result of the COVID-19 pandemic. The annual peak load of 49,569 MW was also 3% lower than in 2019.
  • Market-to-market (M2M) payments from MISO to SPP jumped to $82.8 million last year, up significantly from $17.5 million in 2019. Most of the increase occurred in the year’s last three months, typically a high-wind period.
  • The reliability unit commitment process’ make-whole payments dropped from $70 million in 2019 to $51 million in 2020. Day-ahead market make-whole payments were up, however, from $32 million in 2019 to $53 million in 2020.
  • The GI process totaled nearly 98 GW of additional resources last year. All but 5 MW are for renewable or storage projects.
  • Day-ahead and real-time congestion costs totaled over $442 million, an 8% decrease from 2019.

Wind energy “plays a significant role in the market outcomes we see, particularly with the volatility of prices and lower market prices,” MMU Executive Director Keith Collins said.

The Monitor made three new recommendations, all unrelated to the winter storm: updating market and outage requirements to improve transmission congestion rights’ funding; improving M2M efficiencies by working with MISO; and raising the offer floor to -$100/MW.

Joint Transmission Study Team Takes on Costs

SPP and MISO staff told the board and members that cost-allocation discussions with stakeholders will continue into August as the two RTOs work together to identify joint transmission projects that might ease their interconnection queues.

Lucas said the study team has completed its initial reliability and economic studies and has already shared background on the grid operators’ cost-allocation mechanisms.

“We want to be flexible around what is always a challenge, and that is developing the cost-sharing proposals that will best resolve that situation,” Lucas said. “As [MISO Executive Director of System Planning and Competitive Transmission] Aubrey [Johnson] always says, ‘The best cost-sharing approach is the one most people agree to.’ We want to get everyone in the room together and have the respective RTO staffs put together a package that facilitates the best solution.”

The team has developed two groups of projects that would best address the constraints identified in the first assessments. The economic analysis revealed downstream congestion entering the models, Lucas said, but an ensuing evaluation indicated “material improvement” in adjusted production cost savings. (See MISO, SPP Name Projects to Help Queue Troubles.)

A final portfolio is expected to be completed in September and a draft report shared in October.

Johnson said the study team has found value in learning more about each other’s processes and “working through challenges.” So close has the collaboration been between SPP and MISO that Lucas, noticing both he and Johnson were wearing light blue shirts paired with traditional blazers, remarked, “We’ve even started dressing alike.”

“I’m glad you got the memo,” SPP CEO Barbara Sugg joked.

SPP Finalizes Strategic Plan

Sugg said she was “incredibly proud” to present a new five-year strategic plan defining how SPP will actively engage with stakeholders as it stakes a leadership position among the RTOs.

The board and members unanimously approved the plan, which envisions SPP “leading our industry to a brighter future while delivering the best energy value.”

“We developed this plan during changing and uncertain times,” Sugg said. “We navigated through these challenges, including the pandemic and historic winter storm, and emerged stronger. Collaborating with our members, we’re finding creative and innovative ways to strive toward a world where people have more accessible, reliable, sustainable, flexible and affordable power.”

Bruce Rew, the grid operator’s senior vice president of operations, said the organization’s first mission statement, approved in April, sees SPP “leading our industry to a brighter future while delivering the best energy value.”

“If we’re sitting around five years from now celebrating our success, what has led us to that point?” he said. “You set a goal and do everything you can to achieve it.”

“Wherever we land at the end of five years, we’re going to be in a better place,” OG&E President and COO Peggy Simmons said.

Altenbaumer said the SPC will go through the plan’s rollout details during its September off-site workshop. He praised the plan’s quality as a result of engagement with the Members Committee, SPC and regulators.

“Those additional levels of engagement were investments that were well worth it,” he said. “There’s been a lot of work done to get to this point, but it has to be balanced with the other things that are priorities to the organization. All of that has to be done consistently with what our organizational capabilities are.”

RSC Meets Briefly

The Regional State Committee briefly conducted its quarterly business meeting before the joint updates began, honoring two of their members who have left the group.

The RSC presented both Arkansas Public Service Commissioner Kim O’Guinn and former Texas Public Utility Commission Chair DeAnn Walker with resolutions recognizing their work and time on the committee. A similar resolution was offered to SPP’s Sam Loudenslager, a liaison to the RSC who is retiring in October.

“It was an honor to serve with each and every one of you,” said an emotional Walker, who resigned from the Texas PUC in February shortly after the winter storm nearly collapsed the ERCOT grid. “Thank you for everything, and I miss all of you.”

Walker gave a special shoutout to Oklahoma Corporation Commissioner Dana Murphy, who called and texted her with frequent supportive messages during and after the storm.

Board OKs Revision Requests

The board approved several revision requests previously endorsed by the Markets and Operations Policy Committee, including a market-based approach for managing uncertainty (RR449); a new methodology for accrediting wind and solar resources (RR418); a recommendation to develop initial effective limits for reliability coordinators based upon previous experience or analysis (RR414); and a white paper on cost allocation for energy storage used as transmission assets. (See “Uncertainty Product Endorsed,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)

Directors also signed off on the consent agenda, which included:

• • the Corporate Governance Committee’s recommendation to add Lincoln Electric System’s Dennis Florom and NextEra Energy Resources’ Matt Pawlowski to transmission-user seats on the SPC, and Lincoln Electric’s Emily Koenig to a TU seat on the Finance Committee.
  • staff’s mitigation plan to ease the burden on transmission planners. (See “Tx Planning Mitigation Gets OK,” SPP Markets and Operations Policy Committee Briefs: July 12-13, 2021.)