by Julian Spector
September 09, 2019

Humans can’t shake a fascination with things that come in hundreds. 100 percent renewable. A president’s first 100 days. All about the Benjamins.

We played into this latent obsession this week by compiling a list of the largest battery projects that we’ve reported on, what Fluence’s John Zahurancik once dubbed “the 100 Megawatt Club.”

At one level, the proliferation of confirmed projects at or above 100 megawatts vindicates the industry pioneers who said this technology could compete with conventional power plants, back before it had ever been done. It’s not theoretical any more: several of the club members are taking contracts that otherwise would have gone to natural gas burning plants.

At another level, the 100 megawatt threshold is arbitrary and functionally irrelevant. Its significance owes more to the flashiness of triple digits than to an empirical threshold of operational significance. Batteries only matter insofar as they solve a grid need; it is most curious that vastly different customers in far flung parts of the globe all have crunched the numbers and found the exact same 100 megawatt capacity fits the bill.

There’s also a conversation to be had on the merits of lumping all that storage capacity at one site, versus distributing the capacity and serving different nodes. We'll save that for another time.

Arbitrary or not, the 100 Megawatt Club offers a valuable case study of how far the storage industry has come in just a few years, and where it is heading. It takes financial savvy and technical acumen to deliver at this scale. It requires convincing risk-averse utilities and regulators that the new tech can solve a big problem.

It’s worth pausing to examine what these cases say about where big batteries can compete, what kinds of companies can pull them off, and what exactly they do for the grid.

A low carbon, high renewable grid is materializing in many major power markets, and it will demand additional quick response flexibility. These early entrants are setting the model that others will follow.

It's not just for California

Ever since PJM died down, sizable storage news pretty much only came from California. Hawaii had its own storyline around island grid decarbonization, and the Northeast had its little pilots, but there wasn’t much else.

That has clearly changed. California maintains an outsized presence in the 100 Megawatt Club, hosting four of the eight projects I profiled. But the others show that big batteries are not a single state affair.

South Australia kicked it off, of course. Whether that market can sustain another project as big as the Tesla-supplied Neoen plant remains to be seen; Australia has not built anything on that scale since.

Arizona joined the club when utility Arizona Public Service embraced the combination of cheap solar and batteries for the crucial evening peak hours. It has embarked on a campaign to firm all its utility-scale solar with batteries. Only one of those has cracked 100 megawatts in a single project, but the overall buildout is massive.

The more recently announced additions are the most surprising: Florida and Oklahoma. Neither have a track record of large-scale grid storage development, or really any grid storage development of note. But they each have a utility that ran the numbers and decided mega-batteries met their needs more affordably than gas capacity would have.

Small cast of returning characters

It takes a special set of capabilities to enter the 100 Megawatt Club. Not many developers have achieved entry, and the ones that have tend to double down on it.

We have Tesla, which supplied the only existing 100-megawatt plant, and will come back for round two at Moss Landing, supposedly by the end of 2020.

AES, supplied by subsidiary Fluence, will develop 100 megawatt/400 megawatt-hour systems for Southern California and Arizona, both due online in 2021.

NextEra will build two of the eight, via its deregulated arm (in Oklahoma) and its regulated utility (in Florida).

That leaves two players with single entrants into the big leagues.

Strata Solar came out of nowhere to win the 100 megawatt/400 megawatt-hour peaked replacement contract in Oxnard, California. It’s not entirely clear how the North Carolina based solar developer pulled off that acceleration, but it suggests that developers comfortable with large-scale renewables feel confident about translating their skills to storage. Invenergy similarly jumped into large format batteries after years in wind and solar.

That leaves Vistra, which scaled to 100 megawatts after testing out the technology at the scale of 10 megawatts in Texas. That company comes at it from the independent power producer and retailer perspective, and has demonstrated a willingness to swap out older gas plants it owns for speedy new battery plants.

That’s how AES got started in storage a decade ago: it realized that batteries could solve some problems it needed to solve in its legacy power business.

IPPs understand scale and have a sophisticated view on energy markets. On paper, they have a lot of capabilities that bode well for storage leadership. It’s strange that so few have given it a try, although Vistra is unlikely to lament the lack of interest from competitors.

The way to get paid

Asking the question of what exactly these plants will do is instructive for thinking about how more will get built.

In some sense, all of the mega-batteries are performing the role of renewables integration. The rise of variable renewables in South Australia kicked off the chain of events that led the provincial government to call on Tesla to backstop its grid. Arizona is dealing with an abundance of solar power that would be much more useful at night. Florida will use its big battery to store solar production, too, and the backdrop for all of California’s plants is the push for 100 percent carbon-free power.

That said, performing the task of renewables integration does not pay any bills. None of these markets feature a market product tied specifically to shifting solar or avoiding curtailment; renewables integration works as a rhetorical descriptor, but the business case must come from elsewhere.

One model is an anchor contract supplemented by merchant wholesale market revenue; that underlies all the mega-projects in places with wholesale markets.

In the vertically integrated utility territories (Florida, Oklahoma, Arizona), the utility is able to plan more holistically around the values provided by batteries, but they tend to select the battery projects through a capacity procurement mechanism.

Storage developers must work within the market structures that exist. Still, it’s striking that all of these projects made things work in the absence of market rules that specifically compensate the unique values storage can provide.

The rural cooperative in Oklahoma likes storage for capacity in part because it responds faster than the conventional gas powered alternative. But capacity that responds in seconds does not get compensated better than capacity that responds in minutes, even if it serves the grid better.

If grid reforms start compensating more for flexibility, as many observers believe they must, additional big battery opportunities will follow. In the meantime, storage developers still have to compete and win at a game designed in a different era.