DALLAS — SPP’s Resource and Energy Adequacy Leadership (REAL) Team closed out the year by taking two actions related to the long-term planning reserve margin (PRM). 

The team Dec. 18 unanimously approved a long-term policy paper intended as a guide for SPP staff as they continue to develop policy and additional work plans on the subject. The paper outlines the framework for establishing long-term planning horizon PRM requirements to minimize revisions to the requirements with adequate advance notice leading up to the applicable operating season. 

Team members debated whether the paper captures all the risk factors, with some urging a conversation around the possible variances that could occur. 

Natasha Henderson, SPP’s director of system planning, said she received offline feedback that the paper presents a buffer of sorts, to which she responded, “No.” 

“We are really looking at two different types of risks when we move from the long-term planning horizon to the real time in operations,” she said. “What happens if we set something five years out and things change between our assumptions and resource mix and the interaction of the resource mix and load. If something changes that meets the one-day-in-10 [reliability] standard that we were planning to, we may not have actually been planning to that. That’s the nature of risk.” 

She said other comments centered on what the right practice may be, instead of just arbitrarily increasing the PRM. 

“All that the paper is saying is that we need to understand what that risk is,” Henderson said. “The mitigations of that risk would happen later, after a lot of discussion that would include the discussion of affordability.” 

The grid operator recently won FERC approval of a 36% PRM for the winter season, effective 2026/27. It has a 16% margin for the summer season, effective 2026. (See FERC Approves SPP’s Winter RA Requirement.) 

The proposed policy paper includes edits from the Kansas Corporation Commission’s Andrew French, who described another grid operator’s process of setting the PRM as wildly inconsistent. 

“To increase planning certainty, there should be appropriate consideration of risk in setting long-term PRM requirements, so that the need for subsequent adjustments to those established requirements is minimized,” he wrote. “However, all stakeholders should recognize longer-term planning intrinsically involves more uncertainty. SPP can provide best estimates of long-term resource needs, giving [load-responsible entities] more planning information, but LREs share the obligation to plan for the future.”

The REAL Team also endorsed the Supply Adequacy Work Group’s recommendation of 2029 PRM values set at 38% for the summer and 17% for the summer. The SAWG based its recommendations on the 2024 submitted forecasts for the resource and load mix, which used SPP’s 2023 loss-of-load expectations study. 

Changes in proposed load (increased) and the resource mix (thermal increased, wind resources dropped) resulted in different PRMs for the 2029 study year. However, the RTO’s staff said they could support SAWG’s recommendation because it can evaluate 2030 in the 2025 LOLE study and set a 2030 PRM based on the long-term policy paper. 

Nickell Looks Forward as CEO

The REAL meeting came the day after SPP announced Lanny Nickell would become the grid operator’s CEO in April. That gave the team’s lead, South Dakota Public Utilities Commission Chair Kristie Fiegen, an opportunity to invite Nickell to make his first public comments to stakeholders. (See related story, SPP Names COO Nickell to Replace Sugg as CEO.) 

“One of the favorite things about my experience at SPP, and I’ve been here 27 and a half years, has been working with stakeholders. It’s just what I enjoy doing,” he said.  

Nickell added that he cares “deeply” about SPP and its success, lumping employees, members and their customers together. 

“We’ve got a lot of work ahead of us. We’ve got some very real challenges,” he said. “This is the right committee working with the SAWG, working with [state regulators] resolving those challenges, because that’s where the majority of our challenges are. I’m excited to be able to continue to work with you all to figure those things out, and I think we’re going to be successful, and I’m excited about the future.” 

Markets+ Strengthens Participant Engagement

The Interim Markets+ Independent Panel (IMIP), composed of three independent SPP board members, approved two measures Dec. 19 to provide greater cooperation between the IMIP and western state regulators and establish a policy for appeals to the RTO’s board. 

The IMIP signed off on a joint resolution formalizing an agreement with the Markets+ State Committee (MSC) to participate in each other’s meetings, with allocated time on their corresponding agendas, and to host joint in-person and/or virtual meetings to address any issues during the development and operation of Markets+. 

The MSC, a group of regulators from 13 states in the West and the Great Plains, raised the need for ongoing engagement in late 2023. The Markets+ Participant Executive Committee (MPEC) eventually handed it to the Markets+ Interim Governance Task Force (MIGTF). 

“This was kind of dumped in their lap, and they didn’t know what to do with it,” said MSC Chair Nick Myers, with the Arizona Corporation Commission. 

It took a 30-minute conversation between Myers and IMIP Chair Steve Wright to iron out the resolution. 

“This hopefully resolves any concerns that are out there about how we will work together going forward,” Wright said. 

The IMIP also approved a policy brought forward by the MIGTF and MPEC to address interactions between the Markets+ Independent Panel (MIP) and the SPP board. The policy includes a process under which the IMIP and MIP can submit appeals to the board.  

The MIP will replace the IMIP by the time Markets+ is up and running, currently targeted for early 2027. It will be allowed to appeal decisions on the same issue multiple times to the board. 

ACC’s Myers: FERC Order Close

FERC is close to filing its response to SPP’s filing to the commission’s finding that the RTO’s Markets+ tariff submittal is deficient, Myers told the MSC on Dec. 20. 

Myers, part of a recent Western Interstate Energy Board delegation to FERC’s offices in D.C., said that after discussions with staff, he’s hopeful the commission will rule on the tariff in January. SPP submitted its response to FERC’s deficiency finding in September, asking for a response by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

“I impressed upon them that the MSC really didn’t have too much opposition to that tariff, which is the reason why we didn’t necessarily file comments,” Myers said. “They were very receptive of that and thought it was great that the states were in agreement with the tariff overall. I did get … that it’s a top priority and that they’re kind of in the final stages of it.” 

Potential Competitive Upgrades

Two recently approved 345-kV transmission projects potentially meet the requirements for competitive upgrades, SPP said Dec. 16.  

The projects in question — Belfield-Maurine-New Underwood-Laramie River, from the Dakotas into Wyoming, and Elm Creek-Tobias in Nebraska — also include upgrades that don’t qualify as competitive because they interconnect to existing noncompetitive facilities. Those upgrades will receive notifications to construct with conditions (NTC-C). 

The noncompetitive upgrades will require refined cost estimates that will affect the projects’ overall status. Under SPP’s tariff, an entire project could be re-evaluated if the noncompetitive refined cost estimate is out of bandwidth and is not considered fully approved for construction.