Ercot reforms ace winter but Iran conflict and summer pose bigger test

The largest reform of Texas’s power market in decades passed its first test in late January, with the grid weathering a cold snap similar to those that caused widespread outages in recent years. Now, market participants are waiting to see how well it copes in the face of an extended Middle East conflict, with the high-load summer months being the real test, they say.  

In December, the Electricity Reliability Council of Texas (Ercot), the Texas power grid’s independent system operator (ISO), went live with its Real-Time Co-optimization with Batteries (RTC+B) market design, a major overhaul that synchronises the procurement of electricity and ancillary services every five minutes in real time.

“It’s a huge change that allows Ercot to optimise despatch in real time,” says Juan Arteaga, a principal analyst in power markets research at analytics firm Enverus. “And it seems like, so far, it’s working as intended. People were expecting a lot of blackouts and load-shedding during Winter Storm Fern, and it didn’t happen.”

Arteaga also believes the reforms put the market in a much stronger position to deal with future power price volatility. “The reforms, especially the integration of batteries, certainly improve the ability to suppress price spikes,” he says.

So far, US gas and power prices have had a far more muted response to the Middle East crisis than European gas prices, which have doubled since the start of the conflict. US Henry Hub prices are up around 12% since February 27.  

It’s a huge change that allows Ercot to optimise despatch in real time. And it seems like, so far, it’s working as intended

Juan Arteaga, Enverus

Expectations are for further oil and gas price rises and higher volatility as facilities in the Gulf area begin to halt production, unable to ship it through the Strait of Hormuz. Around 20% of near-term LNG supply is shut in, making this disruption comparable to the drop in Russian pipeline flows from 2021–22, which resulted in US gas and power price spikes.

Although Ercot has large amounts of renewables – accounting for around 30% of generation – it remains sensitive to natural gas prices as this is still the primary source of supply. Gas generates around 40–50% of total power production in Ercot and sets the marginal price. 

However, while gas set the marginal price of Ercot power almost 100% of the time five years ago, that figure has dropped recently due to the increase in batteries. Battery energy storage system (Bess) capacity in Ercot reached 14 gigawatts (GW) at the start of 2026, up from 8GW a year earlier, and just 2GW in 2023, according to Modo Energy. While batteries only supplied on average 1% of Ercot’s power in 2025, they set the price 23% of the time, according to Arteaga. 

This is a significant change from five years ago, demonstrating that the Ercot market is better insulated against high gas prices now than it was during the 2022 energy crisis. 

RTC+B

As well as giving battery operators more flexibility, Ercot’s RTC+B programme is designed to increase efficiency and lower costs across the grid. In a study it conducted in 2024, Ercot estimated that the reforms would reduce energy costs across its system by $2.5 billion to $6.4 billion annually. 

Prior to the redesign, electricity in the Ercot market was traded separately from ancillary services, which could be procured only hourly in the day-ahead market. Now both can be procured simultaneously every five minutes. Importantly, the new market design allows Bess to be modelled as a single, flexible resource, moving between energy and ancillary service roles according to the conditions. 

Before the reforms, Ercot only undertook co-optimisation in its day-ahead market. That meant that, as it balanced supply, demand and the need for ancillary services in its real-time market, it could find itself unable to respond to changing market dynamics as resources had committed to one or other market.

“Prior to RTC+B, batteries that were committed in the day ahead market to provide the ancillary product for a given hour were stranded for that hour,” says Robert LaFaso, director of valuation and forecasting at Ascend Analytics, whose firm operates 4GW of storage capacity across the grid. So, if power prices spiked, Ercot could not call upon batteries that had bid into the ancillary market to supply power to meet that demand at a lower cost than other generating assets, such as expensive gas peaking plants. 

Prior to RTC+B, batteries that were committed in the day ahead market to provide the ancillary product for a given hour were stranded for that hour

Robert LaFaso, Ascend Analytics

The new system has been welcomed by battery operators for the increased opportunities it presents them. “We [now] have the opportunity to trade ancillary services as financial swaps [between] day-ahead and real time, which is not something we could do before,” says Mike Kirschner, managing director USA at Habitat Energy, which provides battery optimisation services to more than 1GW of battery systems in the US.

Before the RTC+B reforms, an operator who had bid into the day-ahead market to deliver energy, say, had to deliver that power if called upon. Now, it can go into the real-time market to contract with another operator to make good on its commitment and instead supply the ancillary services market if it’s more financially attractive. “You can flex the asset in ways you couldn’t previously, and that optionality plays very well to an options-based asset like a battery,” he says. “The flexibility we’re being given [by the RTC+B reforms] to flex in and out of products and services is something we’re excited about,” he adds.

Early spike in ancillary services

While the reforms are expected to reduce overall system prices, the start of the RTC+B programme was marked by a rise in ancillary services prices. Day-ahead, non-spin prices had dropped from an average of $22.49/MWh in 2022 to $3.05/MWh, driven by the rapid growth in battery capacity. However, in December and January they rose to $5.30/MWh, notes LaFaso.

The effect of the reforms on AS prices “is difficult to discern, since knowing what prices would have been without RTC is not possible,” he says. “The storm event in January 2026 makes data difficult to parse. The December and January average price was $3.72, if we remove the storm days.” 

Since then, prices have dropped, averaging $1.51/MWh in Februrary, LaFaso says. “[This demonstrates] a continued learning curve from the market and market participants on how to best utilise the RTC process,” he says.