Are market constraints hampering the evolution of ​‘last-mile’ grid resources?

Franck Lahaye believes he has found a solution to keeping renewable grids working during the hours or days when there is insufficient sun or wind. Now he needs the energy market constructs to pay for it.

Airthium, the company Lahaye co-founded in 2017 with Andrei Klochko, is developing a hybrid system that uses molten salt for overnight power and renewable ammonia for seasonal storage. The French startup expects to be able to provide up to 10,000 hours of storage at a cost of between $60 and $100 per megawatt-hour for 1000-hour duration storage units.

That sounds perfect for grid operators looking for a low-carbon replacement for coal- or natural-gas-fired power plants to deal with those occasional periods in winter when solar output is low and the wind drops for days on end.

Airthium’s storage units are far from the only option being developed to decarbonize grid reliability. Long-duration energy storage is being worked on by a wide range of startups, from flow battery makers such as ESS Inc. to compressed air energy storage players such as Hydrostor.

And energy storage is only one possible answer to enhancing the flexibility of power supplies. Others include clean fuels such as green hydrogen or even traditional thermal plants equipped with carbon capture and storage.

The missing money problem for low-carbon grid reliability

But the challenge faced by these grid reliability contenders isn’t just proving that their technology is reliable and cost-effective. It’s also creating economic structures to pay them for being there as a ​“last-mile” resource that can allow power grids to move from mostly renewable to 100 percent carbon-free.

In the old days, adding flexibility to the grid usually meant building new natural-gas-fired peaker plants — an established technology with relatively low capital costs. This low cost meant these plants could generate a return on investment even with relatively few hours of operation, particularly selling energy during periods of peak demand. Paying for those power plants in vertically integrated markets was simply a matter of passing the capital costs onto utility ratepayers over their lifespan.

As energy markets were restructured to pit competing resources against one another to deliver power at lowest cost, a number of new constructs were put in place to reward those rarely-used power plants for their value in keeping the grid from collapsing during times of peak energy demand. These constructs are referred to as ​“resource adequacy,” ​“capacity” or ​“scarcity” structures.

For startups such as Airthium, though, the capital costs are much larger because the technology has yet to be commercialized at scale. That creates a chicken-and-egg conundrum where promising technologies might never get off the ground because they are perceived as too costly.

At the same time, as wind and solar power have grown to become significant resources on many grids around the world, they can challenge traditional market structures that have allowed reliability resources to earn back their costs.

This same dynamic may well undermine the economics for long-duration storage resources — or drive regulators and policymakers to design new market structures to reward resources that can offer both flexibility and long-duration reliability for increasingly renewable-powered grids.

Today’s markets aren’t the answer

At the heart of the problem is the fact that most competitive electricity markets are set up to procure energy as cheaply as possible, not to reward assets that may sit idle most of the time, even if they are absolutely essential. The various structures to deal with this also have their problems, which the shift to renewable energy has begun to reveal in increasingly dramatic fashion.

One example is the capacity market constructs in the markets of Eastern U.S. grid operators PJM, ISO New England and New York ISO. These capacity markets have provided grid reliability for decades, but they have ​“all sorts of problems,” Mark Dyson, a principal at nonprofit research organization RMI, said in an interview.

The main problem at present is that capacity markets ​“tend to over-buy the wrong thing,” he said, such as natural-gas power plant capacity well in excess of the level of reserves established to be adequate to meet the grid’s most dire supply shortfalls. At the same time, capacity markets designed to provide electricity during easily predicted moments of seasonal peak demand are not ideal for matching the less predictable shortfalls of wind and solar power.

Another option is simply to let an energy-only market dictate the value of flexibility services through electricity pricing. The grid managed by the Electric Reliability Council of Texas (ERCOT), for example, rewards power plants that can supply power during rare moments of sky-high electricity prices.

Until recently, it looked as though ERCOT’s model might be the best approach. But Texas’ power distribution model lost credibility in February when ERCOT experienced the worst grid collapse seen in the U.S. in decades.

“A year ago, people would have pointed to the success of the ERCOT market in Texas as an example of a way to efficiently run a system that has a growing share of wind and solar on it,” said Dyson. ​“I don’t think many people are saying that anymore.”

The disconnect between low-cost and long-duration clean power

Energy analysts generally agree that the answer to these problems is market structures that reward resources that can provide flexibility, that is, the ability to ramp up and down rapidly to meet the increasingly unpredictable supply-demand imbalances of grids served by a rising share of wind and solar power.

But rewarding flexibility is in its infancy, and there is still uncertainty over the best way to do it. One option is to create specific capacity markets for flexible generation. The U.K. adopted this strategy in 2013, and this year Chile and Spain are expected to issue government auctions for low-carbon flexible capacity that can operate at night.

Working out how best to reward flexible capacity is a growing concern, because its absence is not only thwarting the development of new technologies but also leading to the decline of established technologies. Take the example of concentrated solar power with molten salt thermal energy storage.

In places with high levels of direct normal irradiance, this technology can provide gigawatt-hours’ worth of nighttime electricity at a cost of between $126 and $156 per megawatt-hour, according to Lazard’s latest levelized cost of energy analysis. That’s cheaper than most gas peakers and nuclear power, based on Lazard’s figures.

But photovoltaic solar panels are much cheaper in terms of the cost of the energy they produce, and solar PV has largely driven concentrated solar power out of the market. There are no active solicitations for CSP capacity anywhere in the world, and the only likely opportunities for new plant development are expected to be in Chile and Spain.

At the same time, solar PV paired with lithium-ion batteries can cost-effectively provide two to four hours of energy storage capacity, or perhaps a few hours more duration, but can’t match the overnight storage potential of CSP paired with molten salt storage.

California regulators have begun to grapple with this problem as the state’s share of solar power grows, with a proposal that would procure 1 gigawatt of long-duration energy storage and 1 gigawatt of geothermal power resources to meet the capacity needs that will emerge after the Diablo Canyon nuclear power plant closes in mid-decade. But it’s still not clear how those procurements will be structured, and how their value will be rewarded, which will make it difficult for them to be built in time to meet that deadline.

New flexibility market structures are needed

The point at which the value of low-cost renewable energy begins to be outweighed by the value of higher-cost but longer-duration alternatives is as yet unclear. Dyson said there is still no consensus over how best to pay for flexible capacity — or even how much of it might be needed.

Many studies indicate that the U.S. power grid could reach 80 percent wind and solar backed by lithium-ion batteries without sacrificing grid reliability. Expanding transmission infrastructure could allow renewable energy to be shared between regions experiencing different weather patterns, although ​“at some point there’s still a need for resources that will help in the dark doldrums,” Dyson said.

As for how these resources will earn money, ​“it’s probably something like a different capacity market or even an entirely different way of paying assets that reflects the total value to the system,” he said.

For now, Lahaye at Airthium says he isn’t counting on capacity markets to get his long-duration storage concept off the ground.

“Our first clients…will be mining operations and other industrial facilities that are far away from a grid and require constant power,” Lahaye told Canary Media in an interview.

The only way to pay for the technology being deployed on the main grid is if ​“the people who save money on the closedown of coal- and gas-fired power plants are the same ones paying for the system.”

(Article image courtesy of Airthium)