Oil-heavy Texas could be a model for fully decarbonized energy systems around the world, at least in terms of how it handles grid flexibility. While some other markets are paying for spare capacity to make sure the lights stay on, the Lone Star State’s energy-only market is doing fine as renewables soar.

Taking into consideration Texas’ ability to cope with rapidly growing levels of renewable generation, “I question whether a capacity market is the best way to bring forward flexibility,” said Chris Kimmett, director of the power grids business unit at Reactive Technologies, a U.K. cleantech firm.

There is growing evidence, in the U.K. at least, that putting money into just-in-case capacity markets might not be necessary, he said.

The British regulator Ofgem, along with others in some deregulated markets around the world, believes a capacity market should keep generation in reserve to deal with mismatches between electricity supply and demand.

The U.K. capacity market provides support to legacy generation assets including coal-fired plants that would otherwise be at risk of closure. Its existence is predicated on the need for thermal capacity to kick in when the wind drops and the sun doesn’t shine.

There is little doubt that grids increasingly need flexibility to deal with such situations.

In March 2020, for instance, U.K.-based Timera Energy published research that showed that Belgium, France, Germany, Italy, Netherlands, Spain and the U.K. would need at least 25 billion euros ($28 billion) in flexible resources to offset nuclear and coal plant closures by 2025.  

The question is whether capacity markets are the best way to provide this flexibility.

The case for capacity markets is diminishing

In the U.K., the capacity market was introduced in the country’s 2013 Energy Act to make sure the system could meet peak demand, typically in midwinter, by providing a financial incentive to build and maintain plants that would remain idle for most of the year.

Proponents maintain that the market helps avoid massive spikes in wholesale electricity pricing when there is a shortage of energy.

And it is true that in Texas, where there is no capacity market, wholesale prices have soared to eye-popping levels, hitting $9,000 per megawatt-hour last August.

But capacity markets such as that in the U.K. could be even more wasteful, said Kimmett, who sits on Ofgem’s electricity system operator performance panel.

Midwinter power demand in the U.K. is now largely well served with wind, he said, while solar helps cover daytime requirements in the summer. Barring an isolated case, the fear of blackouts in the country has fallen in recent years.

“Since we introduced the capacity mechanism, we’ve seen falling electricity demand on the transmission network every single year,” said Kimmett. “The wintertime is more of a feet-up-on-the-deck time for National Grid. The really challenging time to manage the system is now the summertime. There are huge amounts of solar on the distribution system [and] very low demand. So we’re actually experiencing an oversupply rather than an undersupply.”

National Grid has increased its forecast flexibility costs for this summer from £326 million to £826 million.

The coronavirus pandemic has exacerbated this situation, he said, providing a glimpse of what the grid might look like in a zero-carbon world.

One consequence of this is that those capacity market payments, which were established in annual auctions until the process was halted by a European state aid investigation in 2018, have been diminishing over time.

They are no longer enough to cover construction of additional power projects, said Kimmett, “because we don’t need any new fossil-fuel plants over the winter peak.”

No change for Texas market

The apparent loss of relevance of the U.K. capacity market contrasts with the Lone Star State’s energy-only approach, the only one of its kind in the U.S., which as GTM Squared noted last month “is working well for Texas.”

In 2019, the Electric Reliability Council of Texas (ERCOT) had almost 23.9 gigawatts of wind and 2.3 gigawatts of solar on the grid, versus around 55.5 gigawatts of gas generation.

The grid operator is hoping to add 13.5 gigawatts of wind and 12.7 gigawatts of solar by the end of 2022, while the contribution from gas remains roughly the same.

Although ERCOT will likely need to introduce demand-side measures to maintain stability on the grid, regulator the Public Utility Commission of Texas is in no hurry to change the market.

“At present, the commission has no current dockets addressing the change to a capacity market,” Andrew Barlow, director of external affairs, told GTM.

“Legislators have shown strong support for the energy-only market that has fueled the diversification of the state's electricity generation fleet and yielded significant benefits for customers while making Texas the national leader in installed wind generation,” he said.