by Robert Zullo, Kansas Reflector
The deadly winter storm, christened Elliott by the Weather Channel, that tore through much of the United States over the Christmas weekend placed a huge strain on the American electric grid, pushing it past the breaking point in some places.
Frigid temperatures, in some places setting records, drove a surge in electric demand while also causing big problems for gas, coal and other power plants that took electric generation offline just when it was needed most. That forced some southeastern utilities to cut power to thousands of people on a rotating basis, and led grid operators to urge customers to conserve power.
“Supply and demand for electricity have to exactly balance in real time,” said Michael Goggin, a longtime electric industry analyst and vice president at Grid Strategies, a consulting firm focused on clean energy integration. “If not, in a matter of seconds the grid can collapse.”
The Federal Energy Regulatory Commission and the North American Electric Reliability Corporation announced Wednesday that they will open a joint investigation into the power system’s performance.
“There will be multiple lessons learned from last week’s polar vortex that will inform future winter preparations,” said Jim Robb, president and CEO of NERC, the nonprofit regulator that sets and enforces reliability standards for the bulk power system in the U.S.
“This storm underscores the increasing frequency of significant extreme weather events (the fifth major winter event in the last 11 years) and underscores the need for the electric sector to change its planning scenarios and preparations for extreme events.”
But for some experts, a major lesson from the storm is already plain, and it’s the same as learned in past severe winter weather: The U.S. grid needs to be better connected to enable power to be moved easily to where it’s needed in moments of crisis.
“Although this was a massive event that ultimately affected huge parts of the country, there were geographic elements to it,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard Law School. “The attention belongs on the transmission system.”
John Moore, a meteorologist with the National Weather Service, said the storm was unusual in several aspects, including the rapid drop in temperatures triggered by a blast of arctic air pushing down from Canada far into the American South, the rapid strengthening called “bombogenesis,” and the heft of the pressure behind the system, which he said set a record in Edmonton, Canada.
“It’s a very broad system and it’s a lot of impacts associated with it. … The cold air with this one was a little bit stronger than we usually see this time of year,” Moore said, noting that the storm caused temperatures to drop 37 degrees in one hour at Denver International Airport, for example, and set temperature records in Wyoming and Montana, according to preliminary data.
As it moved east, it caused a deadly blizzard in the Buffalo area that claimed at least 40 lives and wreaked havoc on the electric grid.
“There were likely other records set across the South and East Coast,” Moore said.
Though hundreds of thousands of homes and businesses were left without power because of normal storm calamities such as downed power lines, many other customers in the Carolinas and the Tennessee Valley Authority service territory, which includes most of Tennessee and parts of Kentucky, Mississippi, Alabama, Georgia, Virginia and North Carolina, saw outages because of the strain struggling power plants and surging demand placed on the grid.
“What we saw was concerning,” said Goggin, who was monitoring data from many of the major regional transmission organizations hit by the storm. “You saw very high unplanned or forced outages of power plants of many types but primarily fossil.” The extreme cold shut down many natural gas production wells, he said, which limited pipeline supplies that feed power plants.
“We’ve seen a number of events like this where the extreme cold disrupts the gas system which then cascades to the power system,” he said.
On Dec. 23, with demand climbing past 33,000 megawatts (its normal December demand is around 24,000) the TVA for the first time in its 90-year history instituted load shedding — temporary, controlled outages — and urged customers to conserve electricity. The service interruptions ended on Dec. 24, with the TVA saying it had supplied more power over the previous 24 hours than ever before to meet an all-time peak winter demand. POWER magazine also quoted a TVA spokesperson saying that a “limited number” of power plants in TVA’s territory “did not operate as expected during this event resulting in a loss of generation.”
“We at TVA take full responsibility for the impact we had on our customers,” the authority said in a Dec. 28 statement. “We are conducting a thorough review of what occurred and why. We are committed to sharing these lessons learned and — more importantly — the corrective actions we take in the weeks ahead to ensure we are prepared to manage significant events in the future.”
In an email to States Newsroom Thursday, a TVA spokesperson could not say how many customers were affected nor provide any information on why power plants weren’t able to perform, citing the ongoing review. In the Memphis area, where Memphis Light, Gas and Water is the TVA’s largest customer, more than 30,000 customers were affected, WMC-TV, a local station, reported. The Chattanooga Free Press reported on Christmas Eve that the TVA had lost about 6,000 megawatts of generation the day before at coal and gas plants.
“Until the review is completed over the next few weeks, any discussion on individual plants would be inappropriate because it would just be speculation on our part,” TVA spokesman Scott Fiedler told States Newsroom. “As the wholesale power provider, we instruct our 153 local power companies to reduce load. They implement the process to limit the impact to their customers. We expect customers were affected by 15-30 minutes in a rolling fashion as LPCs implemented curtailments.”
Duke Energy, one of the nation’s largest utility companies, was forced to cut power to about 500,000 of its customers in North Carolina and South Carolina on Dec. 24, with the last of them having power restored by about 6 p.m., spokesman Jeff Brooks said.
“The combination of temperatures that were lower than forecast, customer usage that was higher than projected, some reduction in generating capacity on our system and limited options for additional capacity from outside of our service area due to extreme cold weather that impacted the eastern half of the United States created conditions that resulted in the need to conduct temporary outages,” Brooks said.
“We made this difficult decision to protect the electric grid and reliability on our system, and to avoid a potential longer or broader outage to customers.”
Another Duke Energy spokesman told States Newsroom in November, in response to a report by NERC that its service territory might be vulnerable to electric outages in the event of extreme winter weather, that the company was “ready to meet the energy needs of our customers every day, regardless of weather.”
Brooks said the company is still examining generation performance during the storm and assembling information for regulators and couldn’t provide more details on what type of power plants failed to perform.
Duke Energy officials are scheduled to brief the N.C. Utilities Commission staff on the outages on Tuesday.
“It was a combination of generation on our system that was either reduced or unavailable that evening, coupled with the inability to import additional electricity from out of state (which is something we can typically do to add to our native generation) that resulted in the need to initiate temporary outages,” Brooks said, noting that solar wasn’t a factor because it was dark when the outages were initiated. As of 2021, wind, solar and hydroelectric power made up just 7% of Duke’s company-owned output.
“We did believe that we had adequate generation going into Friday evening to meet the forecasted demand for electricity,” Brooks said. “That demand ultimately came in higher than we forecast.”
Faced with plunging temperatures, surging power demand and some power plants struggling to perform, PJM, the nation’s largest grid operator, issued a call for customers to conserve energy a day before Christmas Eve. The call came as a surprise for electric industry experts.
In a winter reliability assessment, NERC said that PJM — which coordinates the movement of electricity for 65 million people in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia — “expects no resource problems over the entire 2022-23 winter peak season because installed capacity is almost three times the reserve requirement.”
But a big portion of that excess electric generation capacity was struggling to produce power, said Michael Bryson, PJM’s senior vice president of system operations.
“We saw pretty significant generation outage data coming in, failing to start or tripping offline, far exceeding our ability to keep up,” Bryson said. In its request to the Department of Energy for a temporary waiver of environmental rules for generation units, PJM said its peak load, or electric demand, exceeded 135,000 megawatts on Dec. 23 while about 45,000 megawatts of generation were out or underperforming. (PJM lists about 185,000 megawatts of total generation capacity)
Bryson said in an interview that the performance problems affected coal, gas and nuclear plants. Wind, which makes up the majority of renewable energy in PJM’s generation mix (though it is dwarfed by coal, gas and nuclear) performed well during the storm, Bryson said. He had not had the chance to review how solar energy fared during the event.
“We’ll be working through those issues unit by unit over the next week,” he said, adding that power plants that failed to meet their performance criteria risk financial penalties.
In addition to participating in the NERC-FERC inquiry, “we’re going to kick off a pretty comprehensive lessons-learned session ourselves,” Bryson said, including examining the organization’s own extreme cold electric load forecasting. He said PJM’s forecast was low by about 7 to 10% on Dec. 23.
Creating a grid ‘bigger than the weather’
Peskoe, the director of the electricity law initiative at Harvard, and Goggin, the energy consulting firm executive, both said too often in the aftermath of major storms that stress the power grid, one form of generation or another comes under fire.
“Extreme weather like this does affect all generation sources,” Goggin said, though he said it appeared that renewables, which don’t need coal piles that can freeze or pipelines that can be curtailed by cold, largely fared well during the storm.
But the real task for the people in charge of the nation’s electric grid, is to grow a transmission system that’s “bigger than the weather,” as Goggin put it.
“When you do that, it allows you to bring in power from areas that are less affected,” he said. “Having a large grid that allows you to move power around as events like this unfold provides a lot of value.”
Goggin said he monitored data from the regional transmission organizations affected by the storm, including the Southwest Power Pool and MISO (Midcontinent Independent System Operator), neither of which had to resort to rolling outages, and noticed that wind electric prices in those markets plunged to very low or even negative levels. That means there wasn’t enough transmission capacity to get the large amount of electricity the turbines were producing to where it was needed.
Southwest Power Pool
The Southwest Power Pool, which coordinates the flow of electricity over more than half a million square miles in all or part of 14 states (Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wyoming), set a record for winter electric use on Dec. 22 of more than 47,000 megawatts, blowing past the previous record of 43,661 set on Feb. 15, 2021.
However, there were no rolling outages implemented, a spokeswoman confirmed to States Newsroom.
The Midcontinent Independent System Operator, which manages electricity across all or part of 15 U.S. states (Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, North Dakota, South Dakota, Texas, and Wisconsin) and the Canadian province of Manitoba, an area that includes 45 million people, declared a maximum generation event on Dec. 23 “due to unplanned generation outages and higher-than-expected electricity consumption.”
Declaring that event involves multiple steps, including directing its members to turn on all available emergency power generation, asking electric customers to reduce energy usage and purchasing any available emergency energy from neighbors. Rolling outages are a last resort, but that never happened.
A MISO spokesman told States Newsroom collection of data from the storm is underway and more information might be available next week.
“That power would have been extremely valuable in locations farther east but it couldn’t get out of the wind-producing areas,” he said.
Simon Mahan, executive director of the Southern Renewable Energy Association, a trade group for large renewable energy and energy storage companies, said the storm showed how critical interconnection between regions is for reliability and that other parts of the southern electric grid are vulnerable to severe winter weather like the catastrophic grid collapse Texas saw in 2021.
“Being connected with our neighbors is exceptionally important,” he said. “If we weren’t connected with MISO and PJM, things would have been a disaster. … Winter Storm Elliott is kind of that storm that showed that the rest of the Southeast is vulnerable like Texas was.”
Mahan noted that the storm raised transparency issues as well, with real-time data on generation and load coming in from areas controlled by regional transmission organizations like PJM and MISO but not so much from areas controlled by the TVA or monopoly utilities like those owned by Duke in the Carolinas and Southern Company in Alabama and Georgia.
“It’s very easy to see where there are problems. But in the Southeast, because there’s so little transparency, it’s hard to see,” he said.
The storm came as FERC is weighing a major proposed rule on streamlining regional electric transmission planning and cost allocation as well as taking into account broader benefits. And it comes less than a month after a FERC-led meeting on potentially requiring a minimum amount of interregional electric transfer capability — electricity that can be moved between regional transmission systems — for public utility transmission providers. Supporters described it as an “insurance policy” in the event of grid crises like extreme weather.
“One thing that I hope is explored as people try to dissect what happened is what would the value have been of interregional transfer capability during this event,” Peskoe said.
FERC Commissioner Willie Phillips at the meeting said better transfer capability can improve reliability and resilience, lower costs for customers by allowing them to access cheaper electricity and accommodate more renewable power.
“Given the likelihood of future extreme weather events and related generation shortfalls, many stakeholders have been asking us to do something,” Philips said. “Both Winter Storm Uri and the 2014 polar vortex, these events have shown that greater interregional transfer capability has a significant reliability benefit.”
Not everyone was a fan of the idea though. Tricia Pridemore, chair of the Georgia Public Service Commission, which regulates utilities, said states like Georgia that are not part of regional transmission organizations, don’t need a new transfer requirement, citing the state’s utility planning process and cooperation with other southeastern utilities.
“Our bottom-up approach maintains reliability and does not put upward pressure on rates by constructing unnecessary or duplicative transmission assets,” she said. “Georgia is better for maintaining a safe, reliable affordable system all while not being told to do so from a top-down governance structure.”
According to the federal Energy Information Administration, Georgia is one of the more expensive states in the South in terms of average residential retail electric price and Pridemore’s commission just approved a big rate hike for the state’s dominant utility, Georgia Power.
“The reality is during the storm and this past week after the storm, Southern Company and Georgia have really relied on imports from MISO and a significant amount of power from Canada that has been brought into MISO,” Mahan said. “It’s pretty incredible how Canada is helping keep the power on in places like Atlanta.”
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