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Energy brokers and consultants told MAGNIFYI this week that retail energy providers (REPs) should prepare to manage the risk of price variation between hubs and nodes caused by congestion spurred by large loads during high demand periods.

The percent of top-quartile net load hours in ERCOT with a pivotal supplier has declined from over 90% in 2022 to 35% in 2025, according to the monitor, Potomac Economics, in the annual update for 2025 released in May.

Potential physical withholding by large suppliers is not a concern, the report said, and price mitigation mechanisms remain effective.

Uncompetitive conditions have trended downward the past three years, Potomac Economics said. The Houston and North zones had the highest prevalence of structural market power during high-load hours.

Anticipated load growth may expose ERCOT to uncompetitive system-level pricing, which could be prevented by system-level market power mitigation. The grid operator’s current mitigation efforts focus on local markets, other than system-wide offer caps.

The offer cap for energy and ancillary services is $5,000/MWh. This transitions to $2,000/MWh when the market reaches extreme scarcity levels.

Load growth in Texas, driven by bitcoin miners and data centers, is considered both alarming and speculative.

New rules approved by the Public Utility Commission of Texas went into effect July 11 for ERCOT to change the interconnection process for loads that are 75 MW or greater from a project-by-project queue to a batch study system.

The base load in the first batch will drive ERCOT’s long-term load forecast, Alejandro de Diego, analyst at Modo Energy, said in a July 9 research note. “The early Batch Zero disclosures show near-term large loads arriving slower than the current queue implies,” he added.

Potomac’s report said that potential economic withholding in the real-time energy market was low overall, but not trivial, in 2025.

The monitor said that the frequency of an output gap is high, over 80% of hours exhibited, but in many hours the gap is relatively small.

The output gap measures the amount of energy a generation unit is capable of producing but is not offering to the market at prevailing prices.

Mitigated offer curves can have a material effect on the gap, Potomac said, particularly in congested areas.  ERCOT current can apply, through its dispatch software, a mitigated offer curve to determine what local prices should be, based on all transmission constraints.

Power market participants frequently examine opportunities in particular load pockets.

For developers siting new projects, the locational premium available on a hub-level average is narrow and temporary, though not on a nodal level, De Diego said.

“Congestion shows up before the transmission catches up,” said Michael Strickland, owner of EnergyBrokerTX, which serves commercial accounts in the state.

A big data center in a local pocket could spike nodal prices while state-wide supply is fine, he told MAGNIFYI. More sophisticated REPs will hedge at the congestion gap with ERCOT congestion revenue rights and not only at the hub.

“Providers need to protect against those location and timing-specific costs, not just the overall price of power,” Strickland said.

He also advised REPs to build into contracts the curtailment provisions for loads greater than 75 MW that are part of Texas Senate Bill 6, adopted last year.

“Programs that let big customers dial back usage during the tightest hours are the cleanest protection against price spikes,” Strickland said. “Paying a contracted amount to a large user to go off line is cheaper than buying scarce power.”

Using this flexibility for data center customers for at most 20 to 24 hours per year changes the outlook for the grid, he said.

Outcomes of load growth may threaten some firms

Potomac Economics said that even a 20 GW increase in new net load in ERCOT will reduce the operating reserve margin considerably and increase the opportunity to exercise market power successfully at the system level.

Contracted loads reported by transmission companies show load growth of 19.5 GW by the summer of 2030, according to ERCOT’s December 2025 snapshot.

Attestations by transmission company officers of additional new load added another 28.2 GW. The Batch Zero results due next month may trim these outlooks.

“The gap is that heat rate management covers normal dispatch and does not cover the scarcity tail that load growth will fatten,” Strickland said.

Most REPs in ERCOT manage energy price risk and heat rates through the day-ahead and real time markets.

“If the supplier generation does not come on line, we are going to have more extraordinary days,” Strickland said. “REPs make money on ordinary days and lose money on extraordinary days.”

Another ERCOT broker, Amerigy, was more direct.

“Expect more frequent five-minute price spikes during tight intervals, more frequent grid alerts and conservative operations notices, and more attention to the few critical hours per year when system stress concentrates,” the company told clients recently. “Customers on the wrong side of that volatility — index contracts without hedges, fixed-rate contracts that don’t actually fix everything — will pay the most.”

Strickland advised REPs to lock in prices further out, while levels are still low. “Today’s market is calmer and competitive, so buying power for future years now is likely cheaper than waiting,” he said.

Keith Collins, vice president of commercial operations for ERCOT, told its board of directors last month that forward prices were trending lower than one year ago.

Modo Energy’s De Diego has forecast that around-the-clock system-wide ERCOT prices climb to $74/MWh in 2028 and to $133/MWh in 2033, with little variation among zones.

Regardless of the direction of forward prices, Strickland recommended that REPs keep more cash on hand. Deep pockets and credit lines are a survival issue.

The providers that failed after winter storm Uri in 2021 did not fail because they guessed the price wrong, he said, but because they ran out of cash to post as collateral.

“You need cash on hand to post as collateral for unhedged positions,” Strickland said. “The [supply] bill always comes before you charge your customer, so you have to be prepared. I can promise you over the next two to five years we will have another event like Uri. These events bankrupt the REPs that ran out of cash.

“You should be solving for those one-off periods where the megawatt jumps to $9,000, and hedge to lock in your cost to serve. Those that are not hedging are laddering out of business because they cannot afford the next megawatt hour.”

Potomac Economics, the independent monitor, appears unsympathetic to the impact of volatility on market participants.

“There has been a pattern of considering programs that price services outside the market,” Jeff McDonald, the firm’s director for ERCOT market monitoring, told the grid operator’s reliability and markets committee in February.

He specifically identified the programs for firm fuel supply service, emergency response service, residential demand response and forward capacity procurement.

“These programs suppress price, which inhibits the market’s ability to signal relative shortage and incent new investment,” McDonald said. “A market needs to experience and price shortages in order to provide the incentives for new investment.”