A winter storm that left tens of thousands of megawatts of generating capacity unexpectedly out of service and hundreds of thousands of customers without power as it swept through the central and eastern US just before the 2022 Christmas weekend raises major questions about reliability and resource planning by utilities and wholesale power markets.

More than 100,000 MW of coal- and gas-fired generation were unable to start or knocked offline because of the storm, dubbed Winter Storm Elliott, according to a March 9 report from the Institute for Energy Economics and Financial Analysis, primarily between Dec. 23 and Dec. 24, 2022. As many as 1.6 million US customers were without power at one time during the blackouts, with federal data reported by utilities showing a drop in natural gas and coal energy production the morning of Dec. 24, 2022, according to the US Energy Information Administration.

Organized markets saw large portions of their generating capacity disappear. The PJM Interconnection LLC on Dec. 24, 2022, reported forced outages of nearly 46,000 MW, or 23.2% of total capacity, including more than 32,000 MW of gas and more than 7,500 MW of coal-fired capacity. The grid operator is seeking up to $2 billion in penalties from plant operators that were not able to provide needed capacity during the event.

"Generation outages were unacceptably high, and they occurred at the worst possible time for system operations," PJM Senior Vice President of System Operations Mike Bryson said during a January meeting. Peak load in PJM reached 134,765 MW on Dec. 23, 2022, approximately 8,000 MW higher than forecast.

The Midcontinent ISO saw a sharp increase in unplanned outages as well, from about 30,000 MW of Dec. 22, 2022, to 49,000 MW the next day and 50,000 MW on Dec. 24, 2022, with 38,000 MW of gas and coal resources unavailable.

These outages reverberated through the Eastern Interconnection to regulated markets in the Southeast, leaving some utilities with few options as they looked to purchase additional capacity. The Tennessee Valley Authority (TVA) and Duke Energy Corp. were forced to institute their first forced rolling blackouts.

"Missing forecasted demand, they weren't as prepared as utilities normally are, and then the natural gas-powered facilities weren't able to provide the generation necessary during the most extreme need," Simon Mahan, executive director of the Southern Renewable Energy Association, said. "Those were the two driving forces that led to outages."

Following the storm, utility executives brought before lawmakers and regulators to explain what had happened said the extreme temperatures and how their fleets performed would bolster their strategies to develop diverse generation portfolios.

Despite grappling with outages, exports from MISO and PJM helped mitigate the storm's impacts for some utilities. MISO on Dec. 23, 2022, for example, was able to export to the TVA and Southern Co. regions. Gas supply availability contributed to increased unplanned outages, MISO said in a January presentation, although wind production remained high, at some points more than 20,000 MW.

"It wasn't enough to keep the lights on but it certainly helped prevent a bad situation from getting much worse," Mahan said. "When MISO was able to send power to the Southeast, they were sending a significant amount of wind energy."

Duke Energy

The rolling blackouts instituted by Duke in its Carolinas territories, the first-ever implemented there, serve as further evidence of the need for dispatchable generation during peak load times and are informing the company's resource planning, Duke CFO Brian Savoy said in a recent interview.

"We need assets, capacity that we can call upon," Savoy said. "That is going to inform how we think about our resource plans and will show up in our filings we make later this year in the Carolinas."

Duke's models forecasting adequate capacity and reserves to manage the December 2022 storm were wrong, Sam Holeman, the company's vice president of system planning and operations, told North Carolina regulators Jan. 3. Load forecasting was off by about 10% for Duke Energy Carolinas LLC and about 5%-6% for Duke Energy Progress LLC, compared to the typical 3% divergence, executives said.

Instrumentation lines froze and other malfunctions occurred at Duke fossil fuel plants, including the 720-MW combined-cycle Dan River CC plant, unit 3 of the 2,462-MW coal- and oil-fired Roxboro plant, and the 713-MW coal- and oil-fired Mayo plant. Of Duke's 55 combustion turbine units, 23 had to run on oil rather than gas at some point during the event because of low-pressure issues and because oil was "more economic" at the time, Duke officials told regulators.

Overall, Duke Energy Carolinas lost a total of 1,000 MW and Duke Energy Progress lost about 1,500 MW of generation capacity during the event. The utilities began load shedding when attempts to purchase power did not go through because of high demand elsewhere.

"Relying on even firm purchases needs to be considered as we move to a really high peak that might affect a large region," Savoy said. "We need to take a hard look — can we count on those purchases?"

If not, Savoy said Duke may need to plan to activate other generation that takes longer to come online ahead of severe weather and already plans to redouble winterization efforts.

TVA

The TVA, which also instituted blackouts Dec. 23–24, 2022, reported a winter record power demand of 33,425 MW the evening of Dec. 23, 2022. The storm impacted 42% of the TVA's gas generation, according to a February presentation to Kentucky lawmakers.

TVA President and CEO Jeff Lyash said in January the outages reinforced the need for diverse generation portfolios, including additional gas generation, to meet future demand. Asked if the storm would lead the TVA to reconsider new large-scale gas assets, Lyash said plants that failed during the storm tended to be merchant units from which the TVA purchased power and which, the CEO contended, were "not as robustly designed" as its own plants.

Tennessee lawmakers have filed legislation requesting the TVA address energy issues related to winter weather events "to avoid rolling blackouts and power outages," and a bill requiring utilities to reimburse customers for extended interruptions.

Just to the north of the TVA service territory in Kentucky, PPL Corp. subsidiaries Louisville Gas and Electric Co. and Kentucky Utilities Co. resorted to load shedding for short periods on Dec. 23, 2022.

Southern Co.

Unlike Duke and the TVA, Southern Co. utilities did not implement blackouts or make public appeals for conservation. But during a Feb. 2 Georgia Public Service Commission hearing, subsidiary Georgia Power Co. said it imported a significant amount of power from neighboring NextEra Energy Inc. subsidiary Florida Power & Light Co. and relied on solar generation. Georgia Power said some of its generating units went down during the storm but did not specify which ones, sharing only that about 390,000 customers were without power at some point.

Georgia Power experienced near-record load at 37,577 MW during the event, Director of Resource Policy and Planning Jeff Grubb told state regulators, the highest ever in December for the utility, but sustained sufficient resources for much of the peak load times, which Grubb credited to the company's diverse portfolio and power purchases.

"We ran everything," Grubb said. "To get through this event, you needed everything."

What's next

More details about what transpired over the Christmas 2022 weekend are likely to be revealed when the Federal Energy Regulatory Commission and North American Electric Reliability Corp. conclude a joint inquiry into the bulk power system's performance.

But questions about relying too heavily on gas-fired generation and the need for more transmission linking power providers are already emerging.

Fossil generation provided 95% of additional electricity for peak demand triggered by the storm, according to a report from coal trade group America's Power, though "natural gas plants represented the largest source of unexpected power plant outages due to a lack of fuel availability." Coal performed better than gas during the event since coal plants have onsite fuel, the group said.

A February American Council on Renewable Energy report said that additional transmission capacity would have protected customers from blackouts and price spikes, and experts at a recent NERC summit called for improved coordination between the US power and natural gas sectors during extreme weather events, though that likely requires action from FERC and, potentially, Congress.

More transmission linking neighboring power providers could provide greater support for Southeastern utilities during peak demand events, Southern Renewable Energy Association's Mahan said, adding, "The big problem we've seen with Winter Storm Uri and again here is the ability to connect with your neighbors." Winter Storm Uri is the February 2021 event that left millions of customers within the Electric Reliability Council of Texas Inc. market without power, some for several days.

"It really calls into question our smaller utilities being able to manage their systems in these extreme events," Mahan said. "There needs to be some soul searching about whether these smaller utilities should maintain islanded, much like Texas is, because we've seen the high cost of maintaining that independence."

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