Two months after blackouts paralyzed Texas, most of the people who participate in the state’s 19-year-old electricity market, including producers, sellers and traders, share a similar view. The freeze wasn’t a one-off event. The state’s power market needs to change.
Despite the astronomical prices, few of the major players who are supposed to make the Texas market work made money during the freeze. The promise of such a windfall was designed to be an incentive for producers to be ready to operate when electricity supplies are scarce.
Unhappy power-plant owners, retail power providers and even some traders are now threatening to reduce investment in the nation’s second most-populous state until a market many liken to a casino is stabilized.
“All eyes are on Texas, and they should be, as it relates to electricity-market reforms,” said
chief executive of
, the largest power generator in Texas. “If they just put a Band-Aid on a mortal wound…we’re not going to make it.”
active in the Texas power market since its inception, saw his electricity retail firm, ATG Clean Energy Holdings Inc., crushed that week. “This market works really well most of the time,” he said. But when it fails, “it is a failure of Texas-size proportions.”
Many of those who did turn huge profits played in a different market altogether. Natural-gas suppliers were able to parlay a shortage of the fuel for power plants into a bonanza.
The biggest losers of all were Texas residents, roughly two-thirds of whom lost power. Millions were left in the dark for days, with some resorting to burning furniture in their homes to stay warm. At least 111 died of related causes, such as carbon-monoxide poisoning and hypothermia, according to the Texas Department of State Health Services, which estimates the number could still change.
Fixing the market promises to be as complex as it is costly. The challenge facing
Texas Gov. Greg Abbott
and state lawmakers is how to make the state’s deregulated power market more reliable, while limiting added costs that would make its electricity more expensive.
Texas operates the nation’s only pure “energy only” electricity market, one in which producers are paid just for the power they sell, not the ability to deliver whenever watts are needed. All other deregulated electricity markets in the U.S. offer power generators some form of payment for being ready to produce power, to ensure the market has sufficient capacity to reliably provide an essential resource.
For most of the past two decades, the Texas approach worked. It helped the Lone Star State keep wholesale power prices for much of the past two years at less than $30 per megawatt-hour on average, well below most other regional power markets.
But a Texas grid that valued inexpensive power over reliability failed spectacularly during February’s winter storm and frigid temperatures, leading not only to crushingly high electricity prices, but power and water shortages that virtually shut down the state’s economy, and frozen pipes that caused widespread property damage.
As a winter storm blanketed Texas, more than two hundred electricity generators shut down. Net change in generating capacity from before the storm.
Net capacity of generators, minute-by-minute
Net capacity of generators, minute-by-minute
Net capacity of generators, minute-by-minute
Net capacity of generators, minute-by-minute
Many now agree that the Texas power market needs more guardrails to ensure it can perform consistently, no matter the conditions. That will likely come at a price. Texas lawmakers are advancing legislation to winterize the state’s power plants with taxpayer assistance. It remains unclear how much that would cost, and many market participants believe that step alone wouldn’t be enough to fix the system.
Some are pressing for changes to the design of the market itself, structuring it to better compensate power plants that can respond quickly when demand surges. That could necessitate payments to conventional power plants to operate on standby, or a new pricing structure to help them compete against lower-cost wind and solar farms. Both options would introduce new costs into the market.
Most Texans are insulated against electricity price spikes because they pay fixed rates for power. It is likely, though, that rates will increase over the long term as retailers absorb the costs of the storm and the state considers borrowing billions of dollars to help address those companies’ financial burdens.
“I believe our system works, but we’ve got to rebalance it,” said
a Republican state senator from the Fort Worth suburbs who is chairman of the body’s Business & Commerce Committee. He said there needs to be more investment in electricity generation, such as natural-gas power plants or batteries, that can be dispatched when needed.
The sentiment is bipartisan. “We have a highly efficient but highly fragile electricity market,” said Rep.
a Democrat from Dallas. “I think the 14 million Texans who were without water and the 4.5 million who were without power…would be willing to pay a little more for reliability.”
Berkshire Hathaway Inc.
has pitched an $8.3 billion plan to backstop the Texas market by building power plants that would run only during electricity emergencies. Competitors have criticized the proposal, which would guarantee a return for the conglomerate, as anathema to Texas’ free-market power system.
Across the country, electricity markets try to strike a balance between reliability and affordability, offering a continuum of options between one pole and the other. For years, Texas has fallen squarely on the side of affordability.
Though it hadn’t fully broken down before February’s freeze, the Texas market had been straining as a rapid build-out of wind and solar farms pushed power prices to record lows and created more volatility by changing power generation patterns. The growth of renewable energy and low-cost natural gas helped keep the average price that Texans paid for retail electricity below most states, according to federal data.
Texas deregulated its electricity market in 2002, replacing century-old monopolies with competition among power generators and retailers. State regulators tinkered with the market design a decade later, tripling the price cap to $9,000 per megawatt hour—by far the highest price in any market in the U.S. The Texas Public Utility Commission said the higher price cap, available when demand is high, would provide more incentive for companies to build new power plants to relieve supply crunches.
Texas’ power grid has added a lot of new wind and solar generation, but not much new natural gas, coal or nuclear in recent years.
Since then, the Texas power market has fundamentally changed. Wind farms have spread quickly across the state to generate an abundance of inexpensive power, growing from providing 9% of the electricity in 2012 to 22.8% in 2020. Solar farms are multiplying, too, stepping in to produce power on hot, sunny days when demand is high. That has left fewer hours when coal- and gas-fired plants are needed, eroding their revenue and squeezing margins.
The Texas market was designed to deliver windfall profits to generators during periods of scarcity by allowing power prices to surge. But the state’s four dominant power producers—Vistra,
NRG Energy Inc.
and Calpine Corp., which generate half of Texas’ electricity—collectively lost an estimated $2.5 billion to $4 billion during the freeze.
Many were unable to operate during the cold conditions because their equipment froze, or because they couldn’t secure the natural gas needed to fuel power plants. Some say they paid exorbitant amounts for natural gas on the spot market, while others were forced to buy the limited expensive electricity available to meet contractual obligations.
For Vistra, February’s subfreezing temperatures crippled natural-gas producers and suppliers, driving up the cost of fuel and limiting the amount available for its plants. Near Dallas, Vistra shut down a large gas-fired plant when its pipeline supplier said it didn’t have enough fuel.
Instead of running at full steam, Vistra’s gas plants ran at about 70% capacity, putting it at risk of breaching its contractual obligations to deliver power. The company had to make up the difference by purchasing replacement power on the spot market for $9,000 a megawatt hour.
One of the company’s coal plants east of Waco had the potential to make big profits. Fueling it typically costs about $7 a megawatt hour, giving it a wide profit margin when electricity prices surge. But piles of coal froze, making them impossible to pulverize and burn, taking the 1,800-megawatt plant offline. Vistra drew replacement power from several of its gas plants, which cost roughly $2,500 a megawatt hour to fuel as gas prices surged.
Mr. Morgan, the CEO, said the failure highlighted the difficulty of maintaining grid reliability in a market that has become less lucrative and more volatile. He is pushing for market changes that could reduce the $9,000 a megawatt hour price cap, while enabling gas- and coal-fired plants to collect larger and more consistent revenues, giving them more money for winterization and other reliability measures.
Many renewable-energy developers, who have turned Texas into the nation’s top wind-power state, lost hundreds of millions of dollars during the storm, forced to buy power on the spot market, when their turbines froze up, to fulfill obligations. At $9,000 a megawatt hour, many were walloped.
Multinational power company
said “plant outages and regulatory intervention forced us to purchase electricity at absurd prices,” and estimated it made losses of $476 million, or €400 million, during the week.
Electric retailers—companies that purchase wholesale power and sell it to customers—are equally unhappy. Three have sought bankruptcy protection. Many more are in the process of winding down their business, including ATG.
Created in 2019 by Mr. Woodson, the Texas market veteran, ATG signed up 34,000 customers. His break-even price was about $50 per megawatt hour. If he could secure electricity for less, he made money.
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Heading into February, he had locked in electricity prices for 100% of the electricity he anticipated needing. As temperatures began to drop further than forecast, his customers’ demand doubled, and he needed to secure more electricity.
On Sunday, February 14, he bid $4,000 per megawatt hour for electricity on Monday. He was stunned when his bid was rejected as too low. The market cleared at $7,000. “Oh, no,” he recalled thinking to himself. “This is bad.” To cover his customers soaring electricity demand, he bought power on Monday and lost $8 million. The worst was yet to come.
On Monday, Feb. 15, the Public Utility Commission ordered prices to go to the maximum level of $9,000 a megawatt hour and stay there for the duration of the emergency, in what was ultimately an unsuccessful attempt to bring more electricity to the grid.
He couldn’t pass those higher costs on to his fixed-rate customers. His losses topped $10 million a day the following Tuesday and Wednesday, an enormous sum for a firm whose revenue for all of 2020 was $16 million. By midweek, his line of credit was shot and his company crushed.
In March, he began laying off employees and was discussing options with his creditors. “The business will incur large losses. The creditors will incur losses. And me and all of my investors will sustain 100% losses,” he said.
The utility commission’s decision to intervene in the market during the height of the crisis and set the rates at the $9,000 maximum for days has led to a political backlash. It also is expected to trigger litigation from electricity retailers, utility companies, residents and businesses who suffered the fallout.
“The market was killing people in their homes, and I have lost faith in it, and every decision we made at that point forward was to get the lights on,” commissioner
Arthur C. D’Andrea
told the Texas Senate. A couple of days later, Mr. Abbott, the governor, asked for and received his resignation.
Before February, the market had hit peak prices twice—for three hours in 2019 and 13 hours in 2011. The setting of sky-high prices for days devastated some large customers.
director of operations at Hartman Income REIT Management, which manages 60 properties in Texas, said the electricity bill for one of its Dallas high-rises for the first two days of the freeze was $609,000—more than it spent on electricity for all of its properties in February the year before.
He estimates the final utility bill or all its properties during the weeklong freeze will be $5 million to $10 million more than usual, and will be passed on to tenants.
“Our tenants just came out of a full year of a Covid economy, and they are just barely making it by,” he said. “This could be the last straw.”
The grid’s failure also landed on people like
a semiretired 64-year-old commercial muralist whose husband died last year.
The electricity in her Houston home went off on Feb. 15, leaving her shivering under blankets and huddling with her dogs for warmth. When the power came back on, water from a burst pipe in her attic started cascading down, leaving an inch-deep pool in her living room and kitchen.
The water damage and resulting mold destroyed her home, where she had lived since 2005. The interior of her house has since been stripped to the studs. Everything is either in a dumpster or a temporary storage pod on her lawn.
So far, the cost to remove the water and tear out walls and floors is $60,000—a total set to rise once rebuilding and replacing lost items is included. Although she has insurance, the out-of-pocket expenses are growing.
“If I didn’t have money from life insurance from when my husband passed away, I’d be out of money by now,” she said.
More than a month after the freeze, she is living in an extended-stay hotel which is only half open, because it also suffered broken pipes and water damage.
“Why does everything have to be either California or Texas?” she said. “Why does it have to be either so expensive you can’t afford to live there or so cheap there is no safety built in?”
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