Texas’ energy market redesign could leave battery developers in limbo

Texas has witnessed the country’s most dynamic grid battery expansion in recent years, thanks in large part to its famously competitive energy markets. Now, a wonky rule change could undermine batteries’ role in the grid.

The Electric Reliability Council of Texas instituted new rules on Dec. 5 called ​“real-time co-optimization plus batteries,” or RTC+B. The idea is to allow ERCOT to reassign power plants between two major categories of grid activities: ancillary services, the rapid-response actions designed to keep the system stable and outage-free; and energy, the bulk delivery of megawatt-hours for consumption.

On paper, RTC+B sounds agreeable, and other grid operators in the country have been co-optimizing markets for years. ERCOT President and CEO Pablo Vegas said the update would bring greater efficiency and reliability to the system. He even called it ​“the most substantial enhancement to the Real-Time Nodal market design since its inception in 2010.” ERCOT leadership has promised more than $1 billion of wholesale market savings each year from the update.

But a major storage developer active in ERCOT is sounding the alarm about the risks these new rules create for storage operators — and initial metrics from Day 1 of RTC+B are consistent with what you’d expect if a bunch of battery owners pulled out of the ancillary service market because of uncertainty.

The problem, according to Aaron Zubaty, the concerned storage developer, is that power plants can now be reassigned unpredictably between ancillary services and energy. That uncertainty, plus additional stipulations around minimum state-of-charge levels for batteries to be chosen for ancillary services, could limit batteries’ ability to compete in those markets, where they had become a dominant force.

Zubaty runs Eolian, which built one of the first 100-megawatt energy storage plants in ERCOT in 2021 and is now building what would be Texas’ biggest battery. He stopped bidding his merchant battery fleet into the day-ahead ancillary services markets when RTC+B took effect.

“Storage is definitely in a different risk world than it was before RTC+B, because of added duration requirements that changed previously negotiated rules, which may not have been widely understood,” Zubaty said.

RTC+B enforces new requirements for the level of charge that batteries need in order to be dispatched for each ancillary service, which now happens every five minutes (these services used to be procured by the hour). Plant owners can still secure a higher payment by committing their batteries in the day-ahead market for ancillary services. But now, they could find their batteries getting reassigned to the energy market based on the RTC+B optimization algorithm, which might leave them with less energy than they need to qualify for ancillary service obligations later in the day. Not showing up for an obligation incurs financial penalties.

“ERCOT is managing Ancillary Service duration requirements more strictly,” a spokesperson told Canary Media in an email, adding that RTC+B considers a battery’s state of charge in the economic optimization calculation. ​“To the extent that the storage resources believe there are deployment risks, they can account for this in their offer strategy.”

After posting his concerns on LinkedIn ahead of the new rules, Zubaty said he heard from several other battery operators who shared his concerns about the new and poorly understood risks.

The behavior on Dec. 5 could prove to be a onetime blip. But if it becomes a pattern, especially on days of extreme demand, it could undo the state’s progress in tapping batteries to make the grid cheaper and more reliable for consumers.

Higher prices on the first day of new storage rules

The good news for Texans is that the grid didn’t break as operators and plant owners adjusted to the new rules. It helped that the weather cooperated, with no unseasonable cold spell to push the limit at a sensitive time. There wasn’t a meltdown, as Zubaty put it, ​“in totally bland weather and market conditions.”

But for an uneventful day, the ancillary service market got pretty spicy.

“Batteries have basically dominated the ancillary services market in the past few years, but they’ve also cratered the prices,” said Joshua Rhodes, a research scientist at the University of Texas at Austin. Batteries can respond almost instantly, and don’t burn fuel, so they are particularly competitive at these grid services.

But day-ahead clearing prices shot up for Dec. 5, especially for a service called non-spin reserve. This service needs to respond in half an hour — ​“glacial compared to how fast batteries move,” Rhodes said. But to participate, batteries must be able to run for four hours, which is a higher bar for them to meet, given their limited runtime.

That day, ERCOT demand peaked at just under 60 gigawatts, with nearly 19 gigawatts of thermal plant outages; evening wind production was meager, barely generating 4 gigawatts as the sun set. Under those conditions, the day-ahead clearing price for non-spin rose to nearly $78.

To pick a comparison from that week, December 1 shared the key characteristics noted above: Load reached 60 gigawatts, thermal outages just passed 20 gigawatts, and evening wind barely passed 6 gigawatts. But on that day, before RTC+B, non-spin maxed out at just $25.

In other words, with major grid-performance metrics held constant, the change to RTC+B produced a tripling of the clearing price for this particular ancillary service. That’s exactly the kind of jump one would expect if the fleet of batteries ceded competition to a smaller group of fuel-burning power plants. Other, more-rapid-response ancillary services — ERCOT contingency reserve service, responsive reserve service, and regulation up — were also raised by 50% at the evening peak on Dec. 5, compared with Dec. 1. But they cleared at about half the price of non-spin.

“If the lowest-value service is now commanding the highest price, there’s probably something amiss,” Rhodes noted.

To be clear, those elevated prices haven’t returned in the days since. This could indicate that storage operators are dipping their toes back in the market after opening-day jitters or simply reflect how the mild weather in Texas is making things easy for the grid. ERCOT releases the details on winning bids 60 days after the fact, so the full picture won’t be clear until then.

Miguel Garcia, who runs bidding strategy for SMT Energy’s 13-project battery fleet in ERCOT, said that short-term pricing dislocations are to be expected with a big structural change like RTC+B. But he isn’t giving up on ancillary services.

“We’re being more deliberate about when and how we participate, based on system conditions, price signals, and state-of-charge positioning,” he said. ​“Ancillaries are no longer a ​‘set it and forget it’ product under RTC+B, but for operators who understand ERCOT dynamics, they remain very viable.”

Another experienced battery owner in ERCOT said they are still bidding into ancillary services, but they expect that the new state-of-charge rules will reduce storage participation in those markets, leading to higher prices. And when ancillary prices go up, energy prices tend to follow.

The real test for this new market design will come when the weather isn’t nice, Rhodes said — when a cold snap hits or if a heat wave strikes in May, when many thermal plants are still offline for spring maintenance.

If that happens, batteries probably won’t bid into day-ahead ancillary services as much as they would have under the old rules, Zubaty said. Then Texans will have to rely on a smaller number of older, more expensive natural gas and coal generators to play those essential grid-supporting roles. Constraining participation from batteries could lead prices to skyrocket unnecessarily.

It looks like that happened on an otherwise normal Friday, but the costs and stakes will be far higher when extreme weather strains the Texas grid.

A clarification was made on Dec. 16, 2025: This story has been updated to reflect that Eolian stopped bidding its merchant fleet into the day-ahead ancillary services markets, not its entire 350-megawatt portfolio.

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