COVID-19 drives down electricity demand, puts renewable projects and balance sheets at risk
Energize Weekly, April 15, 2020
The impact of the novel coronavirus pandemic on electricity demand in the U.S. and on the utility industry is becoming clearer with lower loads, changing peak demands, more emphasis on renewable generation and emerging financial risks.
U.S. power usage is set to drop more steeply in 2020 than in any year at least over the past two decades, according to a report by the financial services firm Raymond James & Associates.
Wood Mackenzie, an industry consultant, is projecting that the corona virus will disrupt North American power markets for another 18 months.
Raymond James is forecasting a 7 percent drop in overall electricity demand for 2020, while the latest U.S. Energy Information Administration (EIA) projection is 3 percent. In 2009, during the last recession, demand declined 4.1 percent.
The EIA sees the biggest drop in demand coming from the commercial sector. It forecasts electricity sales will be down 4.7 percent for 2020 as a result of the closing of many businesses. Industrial sales will also be down 4.2 percent due to a cutback in production. Retail sales to residential customers is projected to be down less than 1 percent.
The regional fall in electricity demand is being measured in a variety of ways.
An analysis by the Rocky Mountain Institute (RMI) found demand dropping between 5 percent and 15 percent depending upon the region from the start of the orders for citizens to shelter in place.
The University of Chicago Energy Policy Institute estimates a nationwide drop of about 5 percent since February. A separate University of Chicago analysis puts the drop in demand in New York City since February at 15 percent.
In one comprehensive exercise, Enverus, an energy industry analytics firm, ran its load forecasting model for the major grid operators across the country as if there were no COVID-19 virus and compared that with the reported demand.
The New York Independent System Operator (NYISO) was the epicenter of the drop in electricity demand, down 10 percent to 15 percent, or as much as 2,400 megawatts (MW) on Enverus’ April 9 model run.
The New York metropolitan area has also been the epicenter of the outbreak of the disease, accounting for about 40 percent of the 535,000 cases reported as of April 12.
“Most of the demand destruction is happening in New York and California, but appears to be stabilizing and while there wasn’t much loss in Texas and the Midwest in the middle of March, demand destruction has increased from late March through early April,” said Rob Allerman, senior director of power analytics at Enverus.
The Enverus analysis also found the losses stabilizing for ISO New England at about 7 percent to 10 percent and the PJM Interconnection, the country’s largest grid serving parts of the Midwest and mid-Atlantic region, at about 8 percent to 12 percent.
The Electricity Reliability Council of Texas (ERCOT), which operates the state’s grid, has posted a 3 percent to 5 percent a drop in demand in March. It rose to 5 percent to 7 percent, or as much as 3,000 MW, in early April.
Wood Mackenzie is projecting the biggest demand drop among the regional power grids for this summer from ERCOT, 4,600 MW lower than the initially projected 71,864 MW, equal to a 6.4 percent loss.
The Midcontinent Independent System Operator (MISO) also saw demand losses grow to 11 percent to 15 percent, about 8,000 MW, in early April from an 8 percent to 12 percent range in March, according to Enverus.
There have also been significant shifts in use during the day with morning peaks coming later, the load curve over the course of the day flattening and the evening peak coming earlier.
PJM said it has found the morning peak shifting from 8 a.m. to between 9 a.m. and 10 a.m., with the evening peak 5 percent lower than expected.
“The load curve also is flatter, without the same fluctuations usually shown by morning and evening peaks and valleys, when people are preparing for work in the morning or dinner at night,” the PJM statement said.
In MISO, the evening peak is also coming earlier, likely the result not having to wait for commuters to return home.
“Businesses aren’t starting up in the morning, schools aren’t opening, people aren’t commuting,” Allerman said. “People working at home are starting their day a little later.”
The drops in demand are also sharpest during the “peakier” periods, he said.
The drop in demand and the shifts in electricity use during the day present challenges for utilities.
“The thing they are struggling with is that internal load forecasts aren’t panning out,” Allerman said. “They trying to figure out when and how much generation is needed … We are seeing things we’ve never seen before.”
With the drop in revenues from electricity sales, utilities are relying more on their least-cost generation, which in many cases are wind and solar, which have lower operating expenses and no fuel costs.
“Renewables are poised to gain more share in 2020 than ever before,” the Raymond James report said. “This is not despite the tough industry backdrop – in fact, it is because of that backdrop.” The emphasis is Raymond James’.
The EIA is projecting that renewable generation will grow by 11 percent in 2020 while coal-fired generation falls 20 percent. “Renewable energy is typically dispatched whenever it is available because of its low operating cost,” the agency said.
Preliminary data from March and April indicate that both coal and natural gas are running less due to lower demand, according to Mark Dyson, a principal in RMI’s electricity practice.
“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 in an email.
“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,” Dyson said.
The loss of revenues will place at least short-term financial pressures on utility balance sheets.
S&P Global Ratings has lowered its outlook for the North American regulated utility sector to negative from stable. “The North America regulated utility industry’s credit quality was already weakening prior to COVID-19,” S&P Global Ratings analysts wrote.
Dyson said, “In the near term, utilities will face revenue shortfalls, but it’s too early to tell the extent or impact of that drop, and how it will affect utilities at the end of the day.”
In the longer term, however, RMI said COVID-19 has slowed the growth of new clean generation projects and behind-the-meter energy efficiency programs. “The present crisis has pushed ‘pause’ on the investment necessary to meet increasingly aggressive climate and clean energy goals set by cities, states, and corporates across the U.S.,” Dyson said.