- North American power markets will see disruptions lasting at least 18 months due to the spread of COVID-19 and the economic impacts of a shuttered economy, according to a new report from Wood Mackenzie.
- Demand has fallen in all markets as stay-home orders have closed businesses and likely forced a global recession. Loads have declined 5% to 15% with significant regional variation, according to the Rocky Mountain Institute (RMI).
- Fossil fuel generators are running less due to lower demand, based on preliminary data from March and April, RMI experts told Utility Dive. That could potentially set off a new batch of coal retirements, though experts say it may also slow investment in energy efficiency and clean energy projects.
It has now been almost three weeks since the first U.S. lockdowns related to the spread of the novel coronavirus began and grid operators are beginning to get a clearer sense of how that is impacting load. However, there is significant regional variation and figures are complicated by changing weather patterns.
"American power markets are entering uncharted territory," Wood Mackenzie said in a research note this week. The firm said its baseline view "yields lower power demand and power prices across North American power markets" and includes a recession for the remainder of 2020 with a rebound beginning in the first quarter of 2021.
In addition to changes in load and energy usage, operators are also seeing shifts in the timing of demand.
"One of [the] clearer signals from the past few weeks is a changing load shape as people stay home and office buildings, whose lighting and HVAC loads are a big driver of afternoon peaks, have seen their occupancy fall," RMI principal Mark Dyson told Utility Dive in an email. "This has caused an observable flattening of the load curve in many regions, from one with a twice-daily peak (characteristic of normal springtime shapes) to a flatter, lower peak."
The New York Independent System Operator (NYISO) is observing daily peak loads trending about 4% lower than typical for this time of year, officials said.
"We continue to observe a more gradual morning ramping period," NYISO spokesperson Zach Hutchins said in an email. The ramping period declines are more pronounced in New York City and on Long Island, and New York City load is "also lagging historic patterns throughout the day, primarily driven by a reduction in commercial use."
The Electric Reliability Council of Texas (ERCOT) said that while it has seen little impact to daily peaks, morning loads are currently 6% to 10% lower than what forecast models would typically predict.
“The overall load reduction for the ERCOT region has leveled off over the past two weeks,” ERCOT Manager of Load Forecasting and Analysis Calvin Opheim said in a statement. Based on the data from the weeks of March 22 and 29, weekly energy use is down by approximately 2%.
In the Midcontinent Independent System Operator territory, the grid operator says its load shape "continued to shift during the last half of March as more states implemented stay-at-home orders. Morning and evening load levels are lower than normal and morning peaks have moved closer to noon compared to 9 a.m. in previous weeks."
The New England Independent System Operator said it is still seeing load declines of 3% to 5%, similar to what it witnessed two weeks ago.
In the Southwest Power Pool (SPP), officials said they are witnessing a 4% to 6% reduction in load, compared to similar days and temperatures for previous years.
"This reduction in load occurs mainly during daytime hours with less impact overnight, suggesting the load reduction is caused by changing work patterns associated with the COVID-19 pandemic," SPP spokesperson Meghan Sever said in an email.
In California, grid operators from March 17 to March 28 saw load reductions of 5% to 8% on weekdays, and 1% to 4% on weekends, with the heaviest impact occurring over the morning peak hours.
"Based on experiences in Italy and Spain, the ISO expects load reductions to level off about three weeks after the [shelter-in-place] order’s implementation," California ISO spokesperson Anne Gonzales said in an email. She also said that load forecasting has "become more challenging, due to a lack of historical statistical data for a pandemic event."
The California grid operator saw day-ahead market prices decline $5/MWh, when compared to before and after March 17, while real-time market prices saw a reduction of $10/MWh.
And in Florida, immediately after the stay-at-home order went into effect last week, RMI's Dyson said there was "a clear drop-off in demand of more than 10%." However, warmer temperatures in the past few days have pushed air conditioning loads back up.
Long-term impacts of coronavirus could slow clean energy efforts
Looking ahead, RMI said there could be changes to the national fuel mix due to the coronavirus shutdown.
"Going forward, we would expect to see coal generation fall faster than gas, as gas fuel prices are depressed due to falling demand and coal plants, especially when gas is cheap, are generally more expensive to operate," Dyson said. "We anticipate that even this temporary, near-term drop in load might lead to long-lasting impacts on coal plants, whose economics get worse as they run less, and set off a fresh wave of retirements."
In addition to changes to load shape, energy usage and the nation's fuel mix, Dyson said the pandemic could have longer-term implications for clean energy projects.
"But what may be a bigger impact is the long-term effect of paused or slowed investment in both generation projects and behind-the-meter efficiency programs," said Dyson. "The present crisis has pushed 'pause' on the investment necessary to meet increasingly aggressive climate and clean energy goals set by states across the US."