Tony Alexander, CEO of the largest utility company in the U.S., has both a financial and a philosophical problem with the direction that the nation's electric grid is heading.
Instead of building new power plants to handle spikes in electricity demand, the grid is counting on people to turn off their lights.
“In parts of the country, the electric system is now being designed under the assumption that customers won’t use electricity,” Mr. Alexander, chief executive of Akron-based FirstEnergy Corp., said at a U.S. Chamber of Commerce Foundation event this month.
He was talking about so-called demand response — electricity jargon for hitting the off switch when the grid sends you a signal to do so.
When executives like Mr. Alexander make investment decisions looking decades into the future, they are competing for space on the grid (and dollars) with utility customers who agree to shut down in the event of an emergency so power can reliably flow to the rest of the grid's constituents.
The cost of a new power plant — hundreds of millions of dollars — stands no chance against the demand response system, which is being used more and more to fill holes in power generation.
FirstEnergy has closed half a dozen coal plants over the past two years that competed against demand response in the grid's annual capacity auction and lost. Mr. Alexander suggested demand response is one of the mechanisms distorting the market to the detriment of iron-in-the-ground generation plants.
He's not alone.
While demand response has a role to play in the energy portfolio, it can give a “false sense of security,” said Pam Witmer, a Pennsylvania Public Utility Commissioner.
“Where I get concerned is [with] folks who may think it’s a legitimate baseload substitute, and it’s not,” she said. “You at least have to be built to be called upon” in an emergency.
When the polar vortex catapulted several days in January to the highest electricity demand on record, PJM Interconnection, a Valley Forge grid operator that coordinates the flow of electricity for 13 states including Pennsylvania, was able to get its demand response customers to cut use by up to 2,379 megawatts.
While they weren’t obligated to shut down, PJM has a pool of demand response customers (users who total more than 7,000 megawatts) who get paid a monthly retainer to be on call to shut down in an emergency between June and September.
The ones who rallied in January were volunteers responding to a very high price signal — they were paid, on average $1,294 per megawatt hour, while the average price of electricity during those January days is typically around $90 per mwh.
That surely drove up the price of electricity for all market participants at that time, but it kept the lights on across PJM’s territory even as 40,000 megawatts, or 20 percent, of all the tangible assets were unable to feed energy into the grid.
Some power producing assets had mechanical problems. Some were natural gas power plants that were competing for fuel with heating utilities (and losing). In one example, a transformer blew at Beaver Valley’s nuclear plant in Shippingport, knocking a 911-megawatt reactor offline.
The demand response that PJM was able to marshal on those days in January substituted for two and a half such reactors.
“It has shown itself, time and again, historically, to be a reliable resource to meet peak demands,” said Stu Bressler, vice president of market operations at PJM.
January presented an unusual occasion for the grid to ask customers to curtail use outside of the summer temperature peaks, and that experience has made the operator rethink the way it plans for emergencies.
“You could also look at it as saying, if demand response were available mandatorily year round, you would have been in better shape in January,” said Ray Dotter, a spokesman for PJM. “Yes. We recognize that. That’s why the rules are changing.”
Starting next month, when PJM holds its annual capacity auction to determine which resources will be available three years from now, energy users will be able to offer themselves up as baseload providers year round — not just during the summer peak. And they’ll receive a higher price for that than they would for limited availability.
They also will get fined if they don’t comply.
Last year, demand response providers paid $24.9 million in penalties for not coming through when asked to shut down, with $19 million of that resulting from the crunch on Sept. 11, 2013.
During an intense heat wave that September day, PJM asked customers representing 6,000 megawatts — the equivalent of six or seven nuclear plants — to come offline. The grid operator said the event constituted the largest demand response event in its history and “potentially in any organized market in the world.”
“Actual performance was very good,” a PJM report said, with 96 percent of promised load coming offline. That’s more than 1.1 million electricity customers.
But various utility territories responded differently. Some had customers who curtailed more than they were asked. Some came up short.
Only about 80 percent of the load in Duquesne Light’s territory that was committed in the demand response program actually shut down that day.
Overall in 2013, PJM estimated that 94 percent of the load that promised to disappear from the grid when called upon actually did so.
PJM’s independent market monitor, Monitoring Analytics LLC, came up with even lower estimates — 85 percent to be exact.
Monitoring Analytics has recommended that demand resources should be treated the same as generation plants. That means they should be expected to offer their resources daily, be called upon year round and at any hour.
Their price cap should be the same as for a coal plant, for example, and the advance notice they receive to deploy should be more in line with that given to power plants.
The consequence of such changes will be felt not only in buildings that go dark by agreement, but in boardrooms of energy companies where investment decisions about compete with more and more promises to turn off the lights.
“We don’t see demand response going away,” Mr. Bressler assured in March. “It has been a valuable component in that economic mix to maintain reliability, and I think it will going forward.”
Anya Litvak: firstname.lastname@example.org, 412-263-1455; Michael Sanserino contributed to this story.