In February 2021, a winter storm swept across the U.S. and numbed Texas with record-breaking low temperatures. Just as heating demand skyrocketed, many natural gas plants and a handful of wind turbines failed due to the freezing conditions, causing a devastating blackout across the state — 4.8 million homes lost power, and 246 people died. Energy prices jumped 360-fold, with some customers facing electricity bills of more than $5,000 for the five days of the storm.

The Texas power crisis caused such widespread damage partly because of the uniquely isolated nature of the state’s electricity grid. In the rest of the U.S., utilities have more options for buying electricity, enabling them to top up when supply dips or demand surges. Groups of power generators and utilities that trade this way are called energy markets. Various regional energy markets cover California, the Northwest, the Midwest and other parts of the country, but no market encompasses the entire West.

The electricity that powers your home first comes from power plants, which sell that power to a utility; the utility then delivers it to you. (Many utilities also own power plants.) Generally, energy flows from suppliers to utilities regionally, primarily based on long-term purchasing agreements. In the West, only California has an organized market that facilitates energy trade among multiple producers and utilities within the state as well as a sliver of Nevada.

Now, markets are merging across the Western U.S. California’s market is opening up to the entire region, and a competing market based in Arkansas is also recruiting new members. Participants will be able to export and import energy across a larger geographical area — and more competitively, too. In an expanded energy market, utilities can work together to avert straining the grid and buy cheaper energy from a more extensive menu of traders. That economic efficiency is key, said Stephanie Lenhart, an energy policy researcher at Boise State University: “It’s incredibly important for the region.”

The California-based expanded regional market for Western electricity will come online as early as next spring, with trading on the Arkansas-based option expected to start in 2027. Here’s what these changes will mean for households.

Why is the West regionalizing?

Soaring energy demand and the rise of renewables are driving utility market regionalization. Demand is predicted to skyrocket in large part thanks to energy-hungry new data centers. Instead of simply building more power plants to keep up, more trading opportunities allow utilities to use existing plants more efficiently. When power isn’t needed locally, for example, generators can sell it to far-flung utilities. And because renewable energy generation is intermittent, an expanded market can spread out the impact of fluctuations to prevent power interruptions.

Since 2014, the West has enjoyed a partially regionalized power market — the Western Energy Imbalance Market. More than 80% of utilities across 11 states are part of this California-led program. But it’s limited to last-minute adjustments; participants can only buy or sell energy that’s available within the hour, such as by releasing stored power from a battery or activating power plants with short start-up times. Because of that short timescale, it’s called a real-time market.

The newly expanded California and Arkansas markets will be day-ahead markets, allowing utilities to coordinate their resources for — you guessed it — the next 24 hours, according to forecasts in weather, demand and pricing. Compared with the typical 3-to-5% of the resources that market participants can tweak in a real-time market, “you can optimize 100% of your resources and your load” in an advanced-day market, said Michael Wilding, vice president of energy supply management at PacifiCorp. Energy suppliers can better plan ahead, turning power plants on and off, up or down, or engaging spare battery arrays based on the next day’s projected energy price.

So what does this mean for your energy bill?

The main advantage of a more open market is costs savings for utilities, and they can then choose to pass the benefits over to households. Utilities will have further reach in sourcing the cheapest power. Utilities in, say, New Mexico could lock in peak-demand evening purchases from generators located farther West, in California, which would still be basking in solar-energy-producing daylight. “It’s really a win-win situation,” Wilding said. “Without (the day-ahead market), customer bills would be higher.”

Utilities have raked in $7.4 billion in total savings over the 11-year existence of California’s real-time market. For PacifiCorp, the annual savings are $100 million. Wilding estimates that a day-ahead scheme will generate $350 million in annual benefits for the company — meaning a 15% drop in households’ bills, if the savings are fully transferred to customers.

Will West-wide markets enhance energy reliability?

Absolutely. Utilities participating in an expanded market would have more time to plan ahead and commit to energy purchases, so that demand and supply can be more smoothly aligned.

Real-time regional cooperation has already averted some crises. In January 2024, a cold spell struck the Pacific Northwest. Despite reduced hydropower capacity and a coal plant outage at the same time, the region avoided a major grid failure by importing 4,900 megawatts of energy from the Southwest and Rocky Mountain regions. (Many households still lost power when downed trees took out powerlines, however.)

“It’s helpful when the market is bigger than the weather,” said Adam Schultz, the manager of regional coordination for the California Independent System Operator, the organization that manages the Western real-time market.

As climate change brings more extreme heat and cold, spikes in power demand will increasingly strain the grid. Sharing generation and transmission resources through a regional market is one way to make power in the West more climate-resilient.

How will this impact the West’s carbon footprint?

“I see it as more of a positive step for clean energy deployment than anything else,” Schultz said. Renewable facilities generate cheaper electricity than new fossil fuel plants, and the free market favors lower-priced commodities. Moreover, in an expanded market, cooperating utilities can leverage geography and resource diversity to keep the lights on after local renewables wind down for the day. The California Independent System Operator estimated that a West-wide day-ahead trading scheme could eliminate 3 million metric tons of carbon dioxide emissions a year, the equivalent of taking some 635,000 gas-powered vehicles off the road.

Some critics fear that dirty power from red states will reach a wider customer base, keeping the West hooked on hydrocarbons. Certainly, fossil fuels could be deployed during emergencies, such as the Pacific Northwest’s 2024 freeze, to prevent blackouts. But generally, participants will have a greater incentive to consume renewables first, because they’re the cheapest to dispatch.

For the most part, the environmental policies that govern a utility’s carbon footprint are administered at the state level, so local governments hold sway over the emissions profile of energy imports. California, New Mexico and Washington have laws that mandate power providers to phase out hydrocarbons from their portfolios within the next two decades. California also imposes a fee on utilities that import energy from fossil fuels, incentivizing them to rely on renewables instead.

What’s next?

Some companies have balked at joining California’s market. Initially, the managing organization was the same one as California’s real-time market, whose leadership is appointed by California’s governor. Some prospective members feared that they’d have to abide by the state’s rules and prioritize Californians’ needs first. As a compromise, California passed a bill that will create an independent organization to oversee the new day-ahead market. So far, seven utilities, including PacifiCorp and the Public Service Company of New Mexico, have signed onto the California-based market. The Arkansas market includes at least eight signatories, including Arizona Public Service and Colorado’s Xcel Energy.

The larger the market, the greater its resource and transmission diversity, raising the cost savings and energy reliability across the grid. The West’s split market structure unfortunately blunts the benefits of a single, larger entity. Nevertheless, whichever consolidated market Western utilities sign onto, experts say it’s better than operating as an island.