Merger Complete, Invinity Targets Solar-Plus-Storage: Q&A

By Richard Stubbe, BloombergNEF. This article first appeared on the Bloomberg Terminal.

Invinity Energy Systems, the vanadium flow battery company formed in April by the merger of the North American firm Avalon Battery and the U.K.-based redT, is focusing on the North American energy storage market, specifically on solar-plus-storage applications.

Solar-plus-storage, where Invinity hopes to thrive, “has become a huge part of energy storage” not only in California but in mature market-based electricity systems around the world, said Matt Harper, chief commercial officer of the new company.

Vanadium flow batteries, created in the 1980s, work by circulating two tanks of vanadium-based electrolyte solutions and moving electrons between tanks — one direction to charge and the other to discharge. They are best suited for heavy-duty, stationary applications that require frequent cycling.

The combined company has a market capitalization of 70 million pounds ($78 million). The shares have almost tripled since early May, rising to 99 pence as of Tuesday’s close.

Harper took questions from BloombergNEF in a phone interview in early June. The interview is edited for brevity and clarity.

Q: How did the merger come about?

A: I’ve been in the flow battery business for about 15 years now. In 2013 some colleagues and I decided to spin out of Prudent Energy and form Avalon Battery, which is one of the predecessors to Invinity. We had been working with this vanadium flow technology for a long time, and we saw that it had tremendous potential that was not being deployed in the right way.

Q: What do you mean?

A: Vanadium flow batteries up until 2013 looked like huge industrial plants. They had all these pipes and tanks and stuff stuck out in the desert next to a solar farm. Solar plants were being deployed at a rate of tens of megawatts per week, and we couldn’t go to market to partner with those projects when it took months to install one of these batteries.

Q: That’s why you formed Avalon?

A: We formed Avalon to take the fundamentals of that core technology and turn it into a product that was coming off a production line with high reliability and low cost, and to use that product to get into the solar industry.

Q: How did that work out?

A: We read the cards right. Solar-plus-storage has become a huge part of energy storage. There’s been phenomenal growth.

Q: What led to the merger?

A: Avalon had done a lot of good work in optimizing that flow battery module. We are on our second generation of that product; last year we shipped 160 of these units. We were looking to expand our commercial reach. RedT, based in the U.K., had the opposite problem. They had good commercial capabilities but they didn’t have the product to stand behind it. So there was a natural fit.

Q: Now what?

A: We’re looking at where to go in terms of the markets we’re trying to serve. In the western U.S. and increasingly in the U.K., solar-plus-storage is becoming a more and more important conversation about decarbonizing the electric grid and achieving ultra-low cost in the energy supply.

Q: How has the Covid-19 pandemic changed your thinking?

It’s giving us a window into what high solar-energy markets are likely to look like in the near future. Especially in California and the U.K., you see the hourly prices of electricity are getting extremely low because of excessive zero-marginal-cost production from renewables.

Q: How do you deal with that?

A: It’s a tremendous challenge and a tremendous opportunity. The challenge is in being able to run the rest of your electric grid when you’ve got a capex-heavy group of equipment that can generate electricity at essentially zero marginal cost, but not when the sun isn’t shining and the wind isn’t blowing. That presents a tremendous economic challenge because the non-renewable electricity is going to become a lot more expensive.

Q: What about technologically?

A: It presents a huge challenge because there’s an excess of solar and wind generation available to be absorbed by our batteries at very very low cost. Our view is that the long-run answer is to take batteries like ours that take that excess generation and start to use it to fill the needs of the grid 24 hours a day.

Q: Just shifting the generation to match peak demand?

Exactly. California has the classic duck curve — one of our customers calls it the devil’s horns — where you get the spike in demand. The ability to take that $5-a-megawatt-hour electricity generated in the middle of the day and address those evening demand peaks is a massive benefit. You can do it for much less than it would cost to build one more peaking plant.

Q: Where is the company focusing, geographically?

The business case is becoming most abundantly clear in California, but the fundamentals underpinning it exist all over the world, especially where you’ve got fairly advanced and mature market-based electricity systems. It’s happening in the U.K. and in Australia.

Q: Lithium-ion batteries are dominant. What’s the case for vanadium flow?

In a lithium-ion battery, an individual cell provides both the power and the energy coming out of the array. In our technology, they’re separated, which allows us to contain the charge and discharge reactions. You can charge and discharge these batteries continuously for weeks and years on end without any degradation.

We can also do much higher cycle counts than a lithium-ion battery. We can charge and discharge it multiple times a day, and there’s no marginal cost to cycling these batteries. The operator of a lithium-ion system has to factor in the decrease in battery life that you get by using a cycle.

Q: Who are your customers?

We’re focusing on two segments — commercial & industrial electricity users and smaller-scale grid service. For a C&I customer, we’re trying to ensure that our customers can save their self-generated electricity and redeploy it to offset their loads when it’s economical to do that. These are big-box retailers, distribution centers, manufacturing shops, wineries, cold-storage facilities.

Q: This all happens behind the meter?

Yes. The distribution of electricity customers is a sort of inverted U. Residential customers are low-volume, and big industrials pay a low rate. In the middle is the industrial or commercial customer who isn’t getting the rate that a bigger user might, and we’re focusing on them.
Grid services providers are using the batteries and bidding to provide needed service on the grid in particular markets.

Q: Length of duration is an issue in California. What’s optimal?

That’s a chicken-and-egg question. Twelve years ago, people talked about pay-for-performance and 15-minute regulation requirements. Five years ago, it was demand charge management. Now the problem is those devil horns — how do you take power out of the middle of the day and deploy it when demand peaks. There’s definitely a role for longer-duration storage, and that’s a place we play well.

But regulators set up markets based on what’s available. Right now, that’s lithium, which plays well up to that four-hour mark. After four hours, the situation is less clear, and the curve is starting to change. The California Energy Commission has issued a solicitation for non-lithium batteries to provide 10 hours of storage. We think there will increasingly be a place for longer-duration solutions.

Q: Where on the cost curve is vanadium flow technology?

We’re looking for individual projects where lithium just isn’t up to the task. For example, we’re looking at a project with a wind owner right now. Because of the interconnection characteristics, they need a battery with regular backflow to get the best economics out of their wind generation, and that will require three to four cycles a day. With a lithium battery, they’d have to replace the entire system every three to four years.

We think of ourselves as the first widely available battery that is optimized for serving the electric grid. As we march our way down the cost curve, we are going to see more opportunities and become even more competitive.

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