When it comes to energy storage, some of the most skeptical entities in the power sector are often utilities.

Most recognize the promise of storage to provide grid services and even help defer some investments as an alternative to traditional grid upgrades. But start talking about batteries as an alternative to generation — such as replacing gas peakers — and many utilities get sheepish.

That’s the case even with utility leaders in energy storage. When Tucson Electric Power signed a breakthrough 4.5¢/kWh contract for a solar-plus-storage facility, executives steered away from comparing its capabilities to gas peakers.

Storage still has some “significant limitations” to peak shaving, “which can easily be longer than four hours,” the duration of the TEP battery, said Carmine Tilghman, the utility's senior director for energy supply. Gas peakers and storage are different products and “should not be compared with each other and as replacement for one another.”

AES seems to be cut from a different cloth. On Tuesday, the utility holding company announced its energy storage subsidiary would enter into a joint venture with Siemens to form Fluence, a commercial- and utility-scale storage provider with more than 460 MW of storage deployed or awarded today.

During a speech in Washington, D.C., announcing the partnership, AES CEO Andres Gluski situated storage as a potential replacement for all kinds of bulk power infrastructure, from transmission to generation. In a subsequent interview with Utility Dive, he said AES’s 10 years of experience in the storage space give him the confidence that other power providers may lack.

“If you look at Southern California Edison, the 100 MW, 4-hour system competed against peaker plants," he said. “We've shown it to be cost effective today. It'll only become more cost effective as time goes on.”

Gluski was touting AES’s 100 MW, 400 MWh Alamitos project, awarded in 2014 in a local capacity RFO from the utility. That project is set to go into service in 2021, and since then the company has won other major projects, including deploying the largest lithium-ion battery in service and contracting for a 100 MWh battery to pair with a solar project in Kauai.

“Now it's kind of like the asset test, if you think about what Kauai is doing. The prices will vary, depending on location and what the competing energy is,” he said. “But in 10 years of experience, I think we've proved that and our systems are still up and operating ... and still making money for us.”

Fluence, the new joint venture with Siemens, will have access to 160 countries. Siemens' SieStorage product focuses on commercial and industrial applications, while AES is a utility-scale specialist, so the venture will allow the company to run “the whole gamut” of large storage offerings, Gluski said.

Moving forward, the Fluence venture helps AES position itself at the leading edge of the energy transformation, allowing storage to optimize its renewable energy assets, regulated utility practices and its generation fleet for deeper decarbonization. But to get all of the benefits to trickle down, Gluski says some regulatory changes may be needed.

“We want to accelerate that new energy future — that cleaner, more reliable grid,” Gluski said. “So this fits in perfectly because we'll be a big customer of Fluence.”

The Fluence venture

Partnering with Siemens allows AES to solidify its position as the current energy storage market leader, with 463 MW of assets in operation or development worldwide. But the impetus for the venture was not only to capture market share, but also help AES sell its Advancion energy storage solution to other companies.

“Utilities were coming to us, saying, ‘Look, we're interested in using your system.’ Then, we started selling it to third parties,” Gluski said. “Now, that's not our core competency … We aren't really a seller of equipment or services, or anything in that form. We looked around to see who would be the ideal partner.”

The combination of Siemens’ more modular storage solution with AES’s utility-scale expertise is aimed at serving a wide array of customers, allowing the joint venture to challenge companies like AMS and Stem in the commercial segment and providers like Tesla in the utility-scale realm.

“From a market view, we see not only utility customers, but we see data center customers. We see industrial customers. We see university campus-type customers,” said Kevin Yates, president of the North American energy management division at Siemens. “All these different customers are interested in this reliable, affordable, sustainable power and how they can get somewhat energy independent, and storage has a role to play in all of those applications.”

Siemens’ global presence as a technology provider gives AES storage access to a number of new markets, and Gluski expects that will help it put distance between its competitors across the storage spectrum.

“We are the market leader and we're going to be more so,” he said. “We haven't given out any numbers but we expect to at least maintain our existing market share, if not grow it in this rapidly expanding market.”

Gluski expects the Fluence venture to dovetail nicely with AES’s other companies, like sPower, the solar developer and independent power producer it acquired in February.

“With sPower, there will be a lot of opportunities to integrate energy storage into solar. We're already doing that. We were the first in Chile, quite frankly the first in the U.S., the first in the U.K., the first in India ... So we have like eight firsts,” Gluski said. “That also gives us a business opportunity to put it onto our network. So, you see it fits in perfectly with this idea of transitioning to the network of the future.”

Storage at regulated utilities

For all of AES’s presence in the energy storage space, its regulated utilities aren’t exactly at the cutting edge of storage deployment in the U.S. TEP and the three California IOUs all have significantly more storage than the AES subsidiaries in the Midwest.

They are leaders for their region, however. Indianapolis Power & Light deployed the first battery storage project in MISO last year, a 20 MW project at the utility’s Harding Street power plant. And Dayton Power & Light deployed 20 MW of storage back in 2013 at its Tait plant in the PJM region.

Both those projects are aimed primarily at frequency control, and the PJM market for that function is largely saturated, while IPL is currently petitioning MISO to change storage tariffs so it can derive more benefits from its batteries.

To build on those deployments at its utilities, Gluski said state regulatory changes to encourage utilities to site storage instead of traditional grid upgrades will be key.

“If you can ratebase a storage facility, you can say, ‘I don't have to spend a billion dollars on this new transmission line. I can spend $100 million on an energy storage system,’” he said.

With traditional grid upgrades, Gluski said utilities often overbuild the size of transmission lines and new plants in anticipation of new demand. But storage, which can be deployed in less than a year without many of the siting issues of plants or lines, can be installed more strategically

“When you build those huge transmission lines, you're always getting ahead of demand,” Gluski said. “You don't build it for like, 'Well, I know there's new shopping malls there.' In most cases, it's like, 'Gee, I think there's gonna be five shopping malls.”

But with storage, “you can say, 'Well, there's one shopping mall. I'll invest for one shopping mall. Second one gets built, I'll put in the second system,'” Gluski said. “So they're not wasting their money. That's better for the utility, that's better for the regulator and that's better for the client.”

Gluski lays the blame for the over-building phenomenon at the feet of the cost-of-service regulatory model, which he says “incentivizes utilities to over-dimension things because you always have to be ahead of demand.”

But reforms to this system, such as the ability to ratebase storage and DER investments, could help utilities optimize their investments. During his Fluence presentation, Gluski highlighted a recent regulatory requirement in Washington state that stipulates utilities must consider storage investments as alternatives to new natural gas peakers.

Beyond the cost-of-service system, Gluski endorsed a move to more performance-based regulatory metrics, efforts that are already underway in some states like New York. By providing new metrics for utility returns based on system efficiencies and customer satisfaction, the CEO says new investments would be incentivized.

But the type of regulatory regime is not as important as how it’s administered, Gluski said. COS, PBR and other models can all work — provided regulators are proactive in changing investment incentives.

“It's really that the system be intelligently designed,” he said. “We have the model company in Brazil, so [the regulators] decide, ‘You’re an urban utility, this is how much it should cost you per customer' … so the system is not crazy, but it depends on how it’s implemented.”

Storage in the generation space

If the Brazilian utility regulatory model isn’t “crazy,” the American merchant market model may be, Gluski said.

“We have seen markets where suddenly you have a flood of investments in, say, solar, all merchant, or wind. Then you don't have the build-out of the transmission, then everybody gets curtailed and everybody goes bankrupt,” he said. “That's really not a good system, because the investor loses and the customer loses at the end, too.”

The market woes extend to conventional generation as well. In the face of subsidized renewables and historically low gas prices, many baseload plants and even some merchant gas generators are finding it difficult to compete in wholesale power markets.

“Merchant markets right now, with the U.S. system, are basically not growing,” Gluski said. “So in a system like that, when you have new technologies come in, you're going to have a lot of obsolete plants, which are just dispatching to cover marginal costs.”

AES began as an independent power producer and has over 6 GW of generation in the U.S. But it has been insulated from many of the upheavals in wholesale power markets because it has diligently limited its merchant generation positions in favor of direct contracts with utilities.

“We don't think that [merchant] is a particularly attractive market,” Gluski said. “80% of our business is contracted. Our average contract length today is about seven years. When we complete these new projects, it'll be 11 years. The same thing even with the renewables; we're going after contracted, long term assets.”

Most recently, AES announced it had completed financing to repower a 1.2 GW hybrid gas and storage plant under a 20-year PPA with Southern California Edison. The battery will provide grid services like spinning reserves and black start capabilities, allowing the plant to burn less gas.

Those hybrid plant applications are a growing market — GE and SCE completed the first gas hybrid this year in California — and AES expects to grow its offerings in the future. It already has experience in the space, as one of its first storage applications was attached to a coal plant in Chile.

Before the battery, “we had to hold back 5% of our capacity for spinning reserve,” Gluski said. But with the battery, “the regulator allowed us to dispatch at 100% and get 100% of the capacity payment, because we had the battery in place. So definitely it’s not just renewables. It can make your existing gas and even coal plants more efficient, because you run them more optimally.”

Hybrid capabilities of new gas-and-storage plants could allow generators to stick around on the system for longer, even as states like California aim for significant reductions in carbon emissions.

“This transition is going to take some time. It's not like in two years, there's not going to be any thermal plants. We're talking 20, 30 years down the line,” Gluski said. But, “even if you put a battery on a coal plant, you will reduce your carbon footprint.”

In that sense, AES has positioned storage as the enabler for decarbonization in each of its business segments. By using batteries to store energy from its renewables assets, provide grid support and peak shaving at regulated utilities, and reduce emissions from its generation fleet, AES is positioning itself for even deeper carbon cuts.

“We try to introduce the technologies that reduce [our carbon footprint], taking into account the local circumstances and local pricing. So what we try to do is provide the best service with lowest carbon footprint possible for that market,” Gluski said. “What we think is going to happen in the future — 20, 30 years from now — is those assets will still be valuable but they'll be used differently."

Correction: This post has been updated to clarify that AES has 10 years of experience in energy storage, not 15, and to indicate that the Tait storage facility has 20 MW of capacity, not 40 MW.