SPP COO Lanny Nickell last week pointed to a lack of gas generation as the primary culprit behind the first-ever load sheds in the grid operator’s 80-year history during February’s Winter Storm Uri.

RTO staff is still working to obtain “specifics about the data,” Nickell said during a May 20 technical conference hosted by the North Dakota Public Service Commission, but the lack of gas supplies for fossil plants contributed to the loss of 35 GW of generation capacity.

“The best I can tell, from anecdotal evidence in talking to members, production was the largest reason gas didn’t show up,” Nickell said. “I’ve also been told there were pipeline issues. I don’t know whether the pipeline issues were driven by production issues or something else. I don’t know for sure, but I’ve heard both issues presented as possible drivers for a lack of supply.”

SPP has said gas generation accounted for about 60% of the unavailable generation during Uri’s peak Feb. 15-16. The RTO is working with its members to better understand what happened as it develops a comprehensive report to be released in July. (See SPP Launches Review of Storm Response.)

The grid operator twice reached its maximum energy emergency alert status and called for load sheds totaling nearly 3.3 GW over a four-hour time period. SPP returned to normal operations on Feb. 20. (See ERCOT, MISO, SPP Slough Load in Wintry Blast.)

Nickell reminded the commission that the RTO’s responsibility for grid reliability includes balancing supply and demand and ensuring the grid’s equipment is always operated within reliability limits.

“During this event, there were times when we were trying to do both,” he said. “It appeared the solutions conflicted. At times, we had to dispatch generation down to protect transmission elements, but that goes against the need to make sure we balance supply and demand. We take responsibility … as an organization, we are responsible for protecting the transmission grid.”

PSC Chair Julie Fedorchak asked Nickell who is responsible for the diversity of the fuel mix or ensuring dual-fuel capabilities. Referencing an earlier analogy from Basin Electric Power Cooperative’s Tom Christensen, who pinpointed fuel, not the number of vehicles, as the key to an effective package-delivery system, she said, “If you don’t have the fuel, you can’t run the power plant.”

“We’ve never advocated for fuel diversity,” Nickell said. Like other grid operators, SPP makes a point of being fuel agnostic. “I hope to see this in the final report — that as the RTO, we do need to step up, we do need to show some leadership in determining and assessing the minimum characteristics we need identified in the fuel mix. Right now, it’s entirely on the members to show up.”

He said SPP will have to “step up” and express what types of attributes, such as quick-starting resources, are needed in the fuel mix.

“We’re going to have to inform our stakeholders and the country as to what is needed to keep the lights on, especially as we see this transition to more and more renewables,” Nickell said.

Commissioner Randy Christmann, hinting at the unavailability of wind generation during the winter event, asked Basin Electric’s Valerie Weigel, whether dispatchable resources are not being compensated and “encouraged to disappear.”

“We have a great opportunity to participate with SPP and develop market products that can compensate dispatchable resources for the services they provide,” Weigel, Basin’s director of asset management, said, noting she is involved in the work to build a “multitude of producers … for all various fuel types.”

Christmann queried Weigel about load-serving entities’ responsibility to help SPP meet 112% of the system’s peak load, which is based on peak summer loads. “Does February tell us 112% is too low of a number?” he asked.

Weigel said several working groups are discussing reserve margins for winter peak loads.

“I think we’re going to have to start performing winter seasonal assessments, and maybe spring and fall assessments, about what the requirement should be during those times to ensure the capacity we feel should be there is there,” he said.

The technical conference included two groups of cooperatives’ utilities along with SPP and MISO, who both manage parts of the North Dakota grid. The two grid operators were placed in separate groups.

Fedorchak painted the event as an “informal discussion” as the attendees discussed ensuring long-term reliability and the “major transformation of the electric grid.”

“We can’t go beyond where our technology is able to take us, where our infrastructure is able to take us, where all the pieces have to fit together,” she said. “We have to ensure that we as regulators, you as the industry, are not getting too far in front. We have to be the ones that say this is as far as we go. February is an example of going too far. Yes, it was bad weather, but let’s make sure we keep [the grid] resilient moving forward.”

North Dakota is the ninth state in which SPP has testified about its response to Uri before regulators and legislators, joining Arkansas, Kansas, Louisiana, Missouri, Montana, Nebraska, New Mexico and Oklahoma.

South Dakota Commissioner Kristie Fiegen, who chairs SPP’s Regional State Committee, sat in on the discussion.

MISO Probing Emergency Steps

MISO, spared from having to shed load during Uri, said it’s examining its emergency phases to possibly make them more user-friendly.

“We operate the fleet that is provided to us,” Senior Director of Operations Planning J.T. Smith told the commissioners, adding that the grid operator is trying to gain more insight into its resources’ capabilities.

Smith said it would be helpful if the RTO could access demand response resources without first declaring an emergency and called for a re-examination of emergency declarations, which he said don’t always result in load shed.

“One of the things that’s tough about a capacity emergency is that you can move very quickly … into load shed,” Smith said.

When MISO enacts a second-level emergency, the situation can rapidly devolve into the process’ more severe steps. The grid operator calls for available maximum energy from offline resources at step 1A, with load shed taking place at step 5. The emergency must reach 2A before MISO can direct its load-modifying resources.

The commissioners asked whether MISO is considering ways to give members more warning as emergencies rapidly intensify. Smith said staff has recognized “inadequacies” in the step-based process.

MISO only directed utilities to make public appeals in its Entergy region, Smith said.

“Do I think we saw a lot of reduction? Not necessarily,” he said. “What I didn’t see was major impacts from public appeals.”