San Antonio Express-News (Sunday)
ERCOT changes may mean a rise in the cost of electricity
Unilateral changes made by the Public Utility Commission and state’s grid manager have fundamentally altered how the state’s power market functions, potentially costing Texans an estimated $1 billion since July 2021 and as much as $2 billion by the end of the year.
After two decades of relying on market mechanisms, namely prices, to bring power on and off the grid, the PUC and the Electric Reliability Council of Texas are instead ordering generators to keep plants running — even when the electricity isn’t needed — to ensure a comfortable supply cushion. In addition to adding costs for users, power generators say they’re losing money and damaging aging equipment to meet the new requirements, signaling they may mothball some plants, or shut them down for good, due to wear and tear.
The changes put in place by the PUC and ERCOT have distorted the market, undermined pricing and created uncertainty, analysts said, making it unlikely investors would pour millions of dollars into building and expanding generation while it remains unclear how the power market operates and how it may change in the next year.
Residents and businesses in San Antonio get their power from municipally owned CPS Energy rather than retail electric providers, but CPS participates in the wholesale market.
The PUC was charged by the Legislature to redesign power markets following the catastrophic grid failure during the winter storm of February 2021. The agency is not expected to publish its final proposals until the fall, and those changes likely won’t go into effect until 2023 or 2024.
PUC Chairman Peter Lake defended the measures taken in recent months as temporary reforms designed to increase reserves and move away from a model in which generators are rewarded when power shortages reach crisis levels and wholesale prices spike 100 times or more above average prices. Lake pointed to the recent stretch of 100-degree days that drove record power consumption to alltime highs without disruptions to the power grid.
“We know the reforms are working,” Lake said. “We’ve seen it in action. We’ve faced test
after test early this summer and have seen benefits of our refocus on reliability.”
But it’s still unknown how much more reliability the PUC and ERCOT have bought and at what cost, said Alison Silverstein, an Austin-based energy consultant who worked for the PUC from 1995 to 2001 and with the Federal Energy Regulatory Commission from 2001 to 2004.
“We have no proof or analysis, other than assertions by the PUC and ERCOT, that these measures are in fact improving reliability,” she said. “They have not been clear or straightforward in accounting for the full costs of reliability.”
‘Less competition’
Since laws deregulating the power market passed in 1999, Texas’ market has depended solely on price signals to attract the electricity the state needs. The Legislature, in fact, has consistently rejected efforts to create a capacity market, which pays companies to keep idle generation available in case it’s needed, and stuck to the concept that prices alone should balance supply and demand.
In Texas, the vast majority of power, nearly 90 percent, is acquired and priced set through contracts, but two inter-related markets are responsible for responding to short-term supply and demand: the real-time and day-ahead markets.
In the real-time market, when the demand for power approaches the amount of power available, wholesale prices spike, providing the incentives for generators to crank up units to sell electricity at healthy profits. When demand falls below available supplies, prices sink, leading generators to take production offline.
The power sold in the realtime market supplements the electricity committed by generators in the day-ahead market. When generators bid into the day-ahead market, they tell ERCOT that they will provide electricity for a certain number of hours at a certain price. If ERCOT does not receive enough bids or offers to meet projected demand, ERCOT officials can order units to come online and wait in the wings in case they are needed, through a process known as Reliability Unit Commitments, or RUCs.
Historically, forcing units to come online for reliability’s sake happened rarely as ERCOT adhered to the philosophy that prices, not regulators, should drive market operations. But last July, with the memories of the February freeze still raw, the use of RUCs began to skyrocket.
The number of hours units were forced to hum on the sidelines in 2021 exceeded the time they operated as backup in the previous six years combined, according to Carrie Bivens, ERCOT’s independent market monitor. In July 2021 alone, the hours in which power plants operated in backup mode jumped to more than 1,200 from 374 the previous month as ERCOT and the PUC agreed to operate in a more conservative manner that emphasized bigger cushions of available power.
The direct cost of having those units on backup has been relatively low — about $6 million so far this year to cover generators’ cost of operating and fuel costs, plus profit, according to Bivens. But the process can create artificial scarcity on the market and lead to higher prices.
While units operate for backup power, they are not counted as reserves by ERCOT, making it appear that less generation is online than there actually is, Silverstein said. In addition, it means fewer units can bid into the realtime and day-ahead markets because they’re being kept on stand-by.
“There is less competition and prices could be higher,” Silverstein said.
Bivens has estimated the cumulative costs of buying more electricity before it’s needed, and the resulting distortions to the wholesale market cost about $400 million in the last six months of last year. So far this year, she estimated it cost between $685 million and $860 million from January through the end of May, and that those could rise to $1.5 billion by the end of the year.
That would total nearly $2 billion since the conservative operations began a year ago.
Lake, however, characterized Bivens’ estimates as “an academic, hypothetical exercise speculating what the potential impact” has been. He said bringing more backup power online, and flattening price spikes ultimately lowers costs. He said the additional costs for running plants as backups is closer to $1 per household per month, compared with Bivens’ estimate, which works out to about $12.60 per household per month.
“Ask any generator how furious they have been since this was enacted,” Lake said. “It cut into their revenue.”
Beyond the market
The issues related to ERCOT’s operating posture extend beyond market distortions, touching not only the long-term impact of running aging plants for extended periods while delaying maintenance, but also politics.
Generators say most of the units that ERCOT is forcing to operate are among the oldest, in some cases 50 or 60 years old. Keeping them running only adds to wear and tear and makes them more likely to break down in the future, said Amanda Frazier, senior vice president of regulatory policy with the merchant power company Vistra of Irving.
Soon, it might not be worth doing the maintenance needed to keep them up and running because some plants are operating at a loss with the new market operations, she told the State Energy Plan Advisory Committee.
Frazier added the conservative operating measures also do not provide incentives to build new natural-gas-powered generation — both because of uncertainty with how the market will be redesigned in the future and the current move away from scarcity pricing. Vistra has no plans to build more natural gas generation in Texas, she told the State Energy Plan Advisory Committee.
State Sen. Nathan Johnson, DDallas, said the operating changes imposed by the PUC and ERCOT were made to enhance short-term reliability but may have long-term consequences. Older units could break down or get shut down if they operate at a loss.
Johnson said the recent decisions, which include fundamental changes to the power market created by the Legislature, have been made by a small group of officials with little consultation with lawmakers, who have the ultimate authority over the the state’s deregulated electricity system.
“The safety margins we have right now on our grid are in part due to a conservative approach to make sure that consumers don’t lose power, and partly to make sure that there’s not political backlash,” he said. “There’s some concern that we’re putting generators in a difficult position, and we are artificially keeping electricity prices higher than they have to be in order to protect people from political fallout.”
Lake said he’s aware of frustrations among generators and other market participants. He said the relatively low costs of having backup power ready to go is a worthy tradeoff to keep the lights on and air conditioners running. The old model, he said, would have already pushed the system to emergency conditions, which would have only benefited generators.
“Participants are accustomed to doing the old way of business — getting as close to the brink as possible. Those are the times when revenues come in for those companies. We’ve turned that on its head, 180 degrees, in the opposite direction” Lake said. “That is absolutely the point of this entire exercise — to move from the crisis-based business model to reliability-based business model.”