By Amanda Durish Cook

NEW ORLEANS — MISO’s most recent maximum generation emergency is yet another portent of its increasing need to rethink grid operations, executives told the Board of Directors last week.

Although it was better managed than the January 2018 MISO South emergency, the event demonstrates how the RTO has come to rely on intermittent resources subject to weather conditions and demand-based resources, which require a maximum generation event to access.

MISO Executive Director of Market Operations Shawn McFarlane said the Jan. 30 event in the Midwest seemed like a repeat of the extreme cold conditions a year ago.

Independent Market Monitor David Patton called the “highly regionalized” event an almost a mirror image of last year’s cold.

This time, however, McFarlane said MISO avoided the need for emergency purchases and was able to stay within the contractual limits of its transmission contract path while still accessing Southern capacity. The RTO estimated that both scheduled and voluntary load modifications, paired with school and business closings, reduced demand by 3 GW or more during the event.

Patton said MISO was able to effectively manage congestion during the event because of improved management of its market-to-market constraints with SPP and PJM.

Wind Forecast Lapse

But executives admitted a blind spot when it came to the RTO’s wind generation forecasting that day.

Last month, MISO pledged more study into generation cutoffs in extreme temperatures and how to account for voluntary load curtailments in load forecasting. It has said that “an earlier-than-expected drop in wind output increased insufficiency risk” early Jan. 30. Wind output during the morning peak was about 4 GW below MISO’s forecast as the worst of the cold struck the Midwest. (See “MISO Researching Generation Cutoffs, Voluntary Load Curtailment,” MISO Reliability Subcommittee Briefs: Feb. 27, 2019.)

Additionally, MISO said failed starts from conventional generation, uncertainty around the load forecast and risk of more outages contributed to the decision to call up about 2.5 GW worth of load-modifying resources (LMRs). Unplanned outages reached 29 GW on Jan. 30.

Patton said MISO’s emergency offer pricing, which defaulted prices to above $600/MWh, was adequate to incent response. In fact, he said, it was even higher than needed because MISO’s extended locational marginal pricing couldn’t model accurately when to ramp up other online resources to displace emergency megawatts.

“Did you get that in the minutes?” MISO President Clair Moeller joked in response. Patton has long panned MISO’s emergency pricing as too low to properly rouse resources into action.

Director Barbara Krumsiek commended the RTO for keeping some less-than-economic units on to cover the failed starts of other generation. She said MISO’s commitment to public safety during the dangerous cold rightly eclipsed a focus on economics.

But she asked if the RTO’s lack of foresight on the cold weather wind cutoffs was a “new revelation” or simply an extreme temperature anomaly, unlikely to be repeated.

McFarlane said that while some turbines have cold weather packages, others must shut off to avoid blade damage, and MISO lacked insight on the specifics. Unfortunately, he said, wind generation in MISO North is clustered where the cold was the most extreme: Minnesota and western Iowa.

“We were relying on our [2014] polar vortex experience … and we expected 1 GW to drop off,” he said.

McFarlane said MISO has since instituted a general temperature cutoff assumption for wind generation. He said it will now hold conversations with wind operators to figure out more precise cutoff assumptions.

Director Baljit Dail asked if the emergency illustrates a need to rethink emergency preparedness altogether.

“Should we be thinking differently about the loss-of-load and reserve margin?” Dail asked.

Moeller said MISO’s ongoing research into resource availability and flexibility is just that — an investigation into loss-of-load risk in every hour of every day as opposed to an annual peak. None of MISO’s last three maximum generation events has occurred in the summer.

A bright spot, McFarlane said, is that half of MISO’s 12 GW in LMRs will be available in two hours or less in the upcoming planning year, thanks to FERC’s approval of rules requiring those resources to provide lead times they can consistently meet. Historically, only about 3 GW of LMRs were ready within two hours, McFarlane said. (See “LMR Registration Steady Despite New Requirements,” LSE Load Forecast Documents Incomplete, MISO says.)

“That will help significantly as we deal with tight conditions going forward,” he said.

Patton commended the better LMR response time. He said LMRs with up to eight-hour lead times are essentially “worthless” in an emergency.

“But in our LOLE [loss-of-load expectation] study, we model them as if they’re available,” he said.

MISO’s average winter load was 77.8 GW from December 2018 through February 2019, with a 101-GW peak occurring Jan. 30. The RTO said that except for extreme cold at the end of January, footprint temperatures were in line with historic norms over winter, which drove down load and congestion. As a result, prices averaged $28.41/MWh, a 6% decrease over the same time last year.

Evolving Resources, Evolving Operations

Richard Doying, executive vice president of market development strategy, said continued turnover in the resource stack and renewables growth will mandate operations changes in MISO.

“You’ve got a combination of factors that gives rise to changes in … grid operations,” Doying said, adding that “once upon a time,” it was much easier to dispatch the system.

“Some of these effects are already hitting us today,” Doying said in reference to MISO’s string of off-peak emergency events. “That flexibility is needed today … [and] we’re already seeing the consequences of these trends.”

To adapt, Doying said MISO has identified three areas of work: increasing the deliverability and availability of resources, bettering system flexibility, and improving its visibility of distributed energy resources.

“We know that there will have to be adjustments made to the market, but exactly what those are, we don’t yet know,” Doying said. He said the many possible solutions will be put to the stakeholder process. Fixes could include scarcity pricing, a 15-minute day-ahead market, more storage integration efforts, modeling smart inverters in planning, and collaboration with distribution operators so MISO can see DER contributions.

Dail asked if MISO was studying whether consumer costs could increase as it changes its market in response to trends.

“We’ve got [members] in economic distress,” he said.

Doying said MISO’s exploration of trends and grid response doesn’t include price effects but offered that market changes needed to maintain reliability would also maintain efficiency.