Southeast Shortage

The Grinch Who Stole Power

Southeast Shortage
Photo by Jonathan Hanna / Unsplash
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Following up on prior work on Winter Storm Elliot that covered most of the rest of the U.S., Enersection dug into the Southeast and in particular the Duke Energy Carolinas (Duke) and Tennessee Valley Authority (TVA) regions, where load-shedding occurred

The North Carolina Utilities Commission held a staff conference on January 3rd, 2023 to receive a briefing from Duke Energy on the recent rolling blackouts

Duke and TVA had rolling blackouts for the first time in their respective histories

There is no debate - natural gas and coal outages caused or contributed to the Southeast outages

Electrification may change demand patterns
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Mea Culpas

After instituting rolling blackouts on December 23rd and December24th, both Duke and TVA accepted full responsibility and vowed to learn lessons from Winter Storm Elliot.  A common theme between the two balancing authorities was higher than anticipated demand and generation failures - in both instances from thermal generation.

Duke was asked to provide and overview of what happened to their grid and why customers were cut off from electricity during the holidays to the North Carolina regulatory body on January 3rd, 2023.

Duke officials gave preliminary findings:

  • Temperatures got much colder much faster than the company's regression models predicted and model forecasts were off by approximately ten percent during peak demand
  • Duke's regression models forecast next day demand and next week demand; the model had little history with (i) coldest temperatures since the 1980's; (ii) high wind speeds at low temperatures; and (iii) low dew points
  • Owned generation capacity was de-rated
  • Generation de-rates were mostly caused by frozen instrumentation lines
  • Duke purchased power from out-of-state, but that power was not available as generators in PJM failed or interconnection was unavailable due to grid conditions (some still TBD)
  • Demand exceeded available capacity, forcing Duke to curtail power to its customers
  • Duke's load reduction forecasting tool failed
  • 10 of 11 nuclear facilities were in service as the storm hit; 11 of 15 coal facilities; 8 of 9 combined cycle gas plants; and all 55 simple cycle gas plants
  • Natural gas and coal generation of 3,600 MW was lost due to outages and de-rates
  • Solar performed "exactly as expected", but was unavailable in the pre-dawn morning of December 24th when demand was surging
  • Duke had no gas deliverability issues but did have a gas pressure issue at its Buck CCGT unit, which caused the company to de-rate the plant outside the peak demand period
  • Duke proactively ran fuel oil through 23 of its 55 simple-cycle plants on Christmas Day to manage concerns relating to low gas pressure at its Buck units

Duke Rolling Blackout Timeline:

  • Friday 12/23, 6 pm: expected to meet peak demand with 2,500 MW reserves across two service territories
  • Reserves were sized to cover losing their largest generator units, plus an additional amount
  • Night of 12/23: load outpaced forecasts
  • Midnight 12/23: ¬†Dan River (CCGT) plant was de-rated by 360 MW (half)
  • Saturday 12/24, 2:30am: Roxboro unit 3 (coal) de-rated, losing 325 MW
  • Saturday 12/24, 4:50 am: Lincoln CT unit is lost (100MW)
  • Morning of 12/24: ¬†400MW of firm purchases and 250 MW of non-firm purchases from PJM were cut
  • Morning of 12/24: 350 MW of firm purchases was lost when third-party generation tripped
  • Morning of 12/24: Broad River simple-cycle gas plant lost (175 MW)
  • Saturday 12/24, 6 am: Mayo unit 1 (coal) de-rated resulting in loss of 350 MW
  • Saturday 12/24, 6 am: Firm purchase of 500 MW lost from marketer in PJM
  • Saturday 12/24, 6 am: Duke network customer lost 305 MW
  • Saturday 12/24, 6 am: ¬†Duke was losing the interconnection frequency and the Eastern Interconnection was at risk of uncontrolled loss of the system
  • Saturday 12/24, 6:14 am am: load-shedding event triggered
  • Saturday 12/24, 4:24 pm: all load-shed customers restored

TVA has not provided a similar level of detail to regulators yet, but TVA Chief Operating Officer Don Moul said the company "had to reduce strain on its grid as demand for energy ran nearly 35% higher than expected on a normal winter day, while at the same time a few of its coal and gas energy facilities were down because of the freezing temperatures."

Neither Duke nor TVA have any wind generation.  Solar is minimal at TVA at just 1.5% of trailing 12-month generation.  Unlike the ERCOT blackouts during 2021, there will be no renewable versus fossil fuel debate regarding the cause of these outages.  

The modeling errors on December 23rd and 24th are easily visible.

We have noted in the past that the Southeast has the largest penetration of heat pumps.  Electrification will likely lead to different load patterns requiring new forecasting models, which expect higher power demand during periods of cold temperatures.