New England’s grid operator is investigating the most likely threats to power generation from future winter storms and heat waves, as climate change fuels more severe weather.
The analysis from ISO New England Inc. and the Electric Power Research Institute — called the “Energy Adequacy Study” — will land dead center in a nationwide debate over how to ensure electricity reliability in extreme weather as the U.S. transitions to a low-carbon grid.
“We’ve got to change the way we plan the power system,” said Arshad Mansoor, CEO of EPRI, a nonprofit research group that investigates grid operating issues for utilities and other clients.
Grid operators around the country are grappling with how an evolving mix of power — from commercial renewables to home-based rooftop solar — will fare in everything from a fierce blizzard to a record-breaking heat wave. The New England project will dig into that question, looking at the potential fate of the grid in 2027 and 2032, based on past weather and future climate scenarios.
Stephen George, ISO-NE’s director of operational performance, training and integration, said he hoped the study’s results would help policymakers and grid planners in the six-state region reach a consensus on how to cut carbon emissions while keeping the lights on. ISO-NE’s grid serves Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island.
“We’re trending toward a highly renewable resource mix driven by state goals,” George said. More customer solar, more electric vehicles and more heat pumps are coming, he said, along with efforts to reduce and shift customers’ electricity usage.
“And we know the weather is more variable and tougher to forecast,” said George, who heads the research study for ISO-NE. “All those things are changing simultaneously.”
That makes it hard to meet minute-by-minute shifts in electricity demand, he said.
If a two-week stretch of severe summer heat comes with overcast skies and low wind, for example, renewable power may be limited as electricity demand for air conditioning peaks. Another dangerous situation would be a long spell of cold weather, where rising demand for heat comes with poor wind and solar availability that also leaves gas generation short of fuel.
Grid officials have also warned that New England remains precariously dependent upon imported liquefied natural gas to meet heating and power generation demand in severe winter storms (Climatewire, Dec. 13, 2022).
It’s a juggling act that is familiar to electric utilities across the country.
“Managing the transformation and proactively preparing for the role that the grid will play is the greatest challenge to reliability over the next 10 years,” said John Moura, director of reliability assessment and performance analysis for the North American Electric Reliability Corp., in releasing the grid monitor’s long-term outlook assessment last year (Energywire, Dec. 19, 2022).
Elliott’s surprise impact on gas
Winter Storm Elliott, whose plunging temperatures created grid emergencies in several states during Christmas week, highlighted the need for better preparation for extreme weather.
System planners anticipated that cold, gray skies and low wind would dampen renewable output. They counted on natural gas-fired power plants to step up, delivering predictable, around-the-clock energy to meet a surge in electricity demand from heaters.
Instead, some natural-gas-generating plants failed to operate in the cold, while a few gas pipeline deliveries suffered weather-linked breakdowns, according to initial analyses of the storm’s impacts.
Elliott’s effect on power generation also stunned the PJM Interconnection LLC, the grid operator in 13 Eastern and Great Lakes states and the District of Columbia.
PJM had gone into the Christmas week expecting to have about 156,000 MW of generation available, which would have been adequate to meet a peak demand of 135,000 MW during the storm, according to a fact sheet PJM recently issued.
But 46,000 MW of generation could not or did not operate when called on, PJM said. About 70 percent of all outages were natural gas; 16 percent were coal; and the remaining 14 percent were a mixture of nuclear, solar, wind or “other.”
“The storm and the rapid onset of cold temperatures heavily impacted natural gas production, particularly in the Marcellus and Utica basins,” PJM said in the fact sheet. That led to a “significant loss of gas supply” to generators.
PJM called the overall outage rate “unacceptably high” and said around 95 percent of the plants that had unplanned outages had accepted payments to be on standby in emergencies. PJM officials expect to impose fines totaling between $1 billion and $2 billion on plant operators for nonperformance (Energywire, Jan. 12).
The Tennessee Valley Authority, the nation’s largest government-owned utility, also saw its power supply come up short.
The utility faced its highest-ever winter electricity demand on Dec. 23, at nearly 35 percent greater than planners expected for a typical winter day, TVA said. Short of power, it was forced to curtail energy deliveries temporarily on Dec. 23 and Dec. 24, causing rolling blackouts in its service area.
Simon Mahan, executive director of the Southern Renewable Energy Association, said shortages of expected power from coal- and gas-fired power plants were mainly responsible for emergencies in TVA and Duke Energy Corp.’s system.
“Coal, oil and natural gas resources struggled,” Mahan said in a recent online briefing.
Preparing for the onslaught
A recent analysis by Evergreen Action and the National Resources Defense Council said expectations must match reality in deciding which resources can be counted on when brutal weather conditions hit.
Many planning scenarios assume fossil generation will always be there, “when time after time it has been shown that they struggle in extreme heat and cold,” the report said.
The country should assess the ability of all types of generation to perform during periods of high risk, according to the Energy Systems Integration Group. The nonprofit, which conducts technical analysis on grid operations, released a report recommending new methods of assessing how each resource contributes to the grid’s reliability.
“We spend a huge amount of time on what is the likelihood of wind and solar not showing up when we need them. We should really broaden that work to other resources – [including] gas and coal,” said Derek Stenclik, the report’s lead author and founding partner of Telos Energy, a grid engineering services and analysis firm.
EPRI’s Mansoor agreed on the need for new strategies for a transition that “will continue whether we like it or not.”
But he warned against debating which power resource is more likely to fail. Instead, he said, more analysis can help chart a path to reliability as the grid and the climate change.
“The transition that we are in will continue whether we like it or not,” Mansoor said. But ensuring the system has adequate reserves might mean keeping certain gas power plants going until 2029 and weatherizing them, he said.
“People will say, we need to retire gas plants as quickly as possible,” he said. “For planners, it’s like, ‘No. We need to keep them until we are assured the system has adequate reserves.'”
New research from the Energy Department’s Argonne National Laboratory lays out how climate change is likely to threaten almost all parts of the grid. The report is the first phase of a three-year project with Commonwealth Edison Co. and EPRI, focusing on the utility’s power facilities serving greater Chicago and more than two-thirds of Illinois (Energywire, June 16, 2022).
The climate conditions at midcentury would hit the entire system, not just renewables, the researchers said.
“Higher temperatures create a number of stress points within the system, such as overheating of lines and equipment,” they wrote in the report, adding that conditions could reduce the output of critical transformers. “[T]hese climatic changes must be managed, or they are likely to adversely affect the frequency and duration of service interruptions.”
EPRI’s study with ISO-NE will look at the much nearer future, producing scenarios of operational threats for two target years: 2027 and 2032.
The analysis will combine past weather history with future climate change assessments developed for the Intergovernmental Panel on Climate Change.
ISO-NE’s George said estimates of severe weather conditions will be linked with other factors including the expected availability of natural gas and oil for power plants, the ability to import power from outside the region, and surges in fuel prices that could shrink fuel delivery.
“We’re not saying there’s going to be a hurricane on Aug. 15, 2027. We’re saying if you take the [past] weather and project it forward, this is what Aug. 15, 2027, could look like,” George said.
Initial results from the study from ISO-NE and EPRI are due in a few months. Once complete, the results will feed into a longer-range planning project by the independent system operator that aims to unite the six-state region on a common climate action plan while managing the most perilous risks of supply disruptions, George said.
The first step is understanding how much the region’s leaders and the public are willing to spend to harden energy infrastructure against extreme weather onslaughts, he said.
“Then, given some consensus on that, you can start to talk in a well-informed manner about the best approaches for solving the problems over the next five to 10 years,” George said. “This is really the just the beginning.”
