Masked surprises

Michael Fuhs (pv magazine): I have the impression that in the storage community the discussions are repeating themselves. On the one hand, there is news of fast growing markets, and on the other, companies frustrated by regulation. We also heard this message last year at Energy Storage in Düsseldorf. Have there been developments since then that have surprised you particularly?

Ravi Manghani (GTM Research): One of the most surprising things that I came across in the last few months is very recently Xcel energy in Colorado released their requests for proposal that are currently ongoing, all-source solicitation. The surprising element was that they had 100-plus bids for either standalone or renewable paired storage. We don’t know details of each one of those bids, but what was explicitly reported in their document is that all of those 100-plus bids were with lithium-ion batteries, except for the one separate category for compressed air energy storage.

And what makes it all the more surprising in terms of industries, technologies and landscape perspective, is that there were a few bids in there that were six, eight and ten hour storage bids.

Fuhs: Which could, according to common sense, favor redox flow chemistries ,for example.

Manghani: As we start to move to longer duration storage there is scope for other technologies, like flow batteries or some other chemistries, or electro-mechanical based technologies. And yet we did not see a single bid for these. All these projects have a completion date of 2023. If we read between the lines, the developers who bid into these projects don’t expect by 2023 that we will have competitive flow battery technologies that they can trust.

Florian Mayr (Apricum): Regarding the general choice of lithium-ion batteries over flow batteries: How long was the PPA or the guaranteed remuneration in the request for proposals? That is also important, as if you have, let’s say only a five-year PPA, then flow batteries that have very long lifetime and low degradation cannot fully play out their advantages.

Manghani: The contract duration was left open. But most of the bids are going to be in the 20 or 25-year range, which again speaks to the contrary that flow battery technologies are better suited to last so long.

Mayr: An explanation could be bankability. There are only a few huge corporations, such as Sumitomo, in the flow battery business, while a lot of lithium-ion batteries are coming from big companies like LG Chem, Samsung SDI and Panasonic. This could lead to higher financing costs for flow batteries.

Matthias Leuthold (RES): Why were you so surprised? I would say it is a common disbelief from three to four years ago when we thought everything beyond four hours is the home turf for redox flow. We cannot find cheaper redox-couples than vanadium – the only reliable redox flow technology we know is vanadium redox flow – I haven’t seen any major installations in other technologies. Now, one can buy a low power/high energy lithium-ion battery for capacity prices well below €300/kWh, and for very large projects soon below €200/kWh. In contrast, I see that manufacturers of redox flow batteries proudly present that they can get below €350/kWh storage capacity. I don’t understand how they get business. With the small volume redox flow battery suppliers, the cost reduction potential is too small. We also have to be aware that lithium-ion batteries are not only high-power batteries. The low power branch has made significant progress and there are dedicated manufacturers for pure energy cells, which are big enough to have bankability, which is a serious question. We had a project where a customer decided on redox flow and it was only bankability that didn’t make it possible.

Mayr: Matthias made an important point. To assess future competitiveness, decreasing costs due to economies of scale and technological improvements have to be taken into account. In this context, the upcoming massive growth of e-mobility will drive down costs of lithium-ion batteries independently from the development of the stationary energy storage segment, something flow batteries cannot benefit from. On the other hand, I’m seeing increasingly low CAPEX for vanadium flow batteries on a DC level. In our close work with storage technology providers around the world, we are getting first hand insights on prices that translate into about $190/kWh for the energy components plus $890/kW for the power components achievable already today. Based on these prices we conducted an LCOS analysis (see page 23) in order to understand how competitive a top-of-its-class vanadium flow battery can be today, compared to lithium-ion and what the resulting duration time threshold is. I am hearing a lot about six, seven and eight hours as a threshold beyond which redox flow is competitive. According to our calculation it is closer to three or four hours. However, please note that the analysis does not include bankability or any residual value, which both impact LCOS as well.

Fuhs: What do the others think about CAPEX assumptions?

Julian Jansen (IHS Markit): I think that is quite an aggressive and optimistic CAPEX assumption. Part of the problem we have really seen for flow batteries comes back to what Matthias said. It is not just about the cost factor and capital; it is about longer-term risk and the bankability, and possibly a lack of faith in the warranties that can be provided. Another issue is that as a customer do I actually have any security that the company that I am buying this technology from will still be around in three years’ time? I still believe in the potential of flow batteries. But I think companies really need to do a much better job at finding their niches and segments where they are not competing with lithium-ion batteries, but where they have a clear place in the market. It is not just the storage duration that counts, but also the location, cycling requirements and the types of application being provided. By focusing on their strengths, some flow battery players are doing quite well finding these niches. Those simply competing with lithium-ion on a cost by cost basis will struggle in the foreseeable future.

Jonathan Gifford (pv magazine): I know the Australian company Redflow from South Australia and they are very much looking for telecommunications in Southeast Asia. What are the other use cases that you think play to the natural strength of flow batteries?

Manghani: Flow batteries can last much longer than lithium-ion batteries and typically require less O&M, which again points to applications that are remote in nature, that do not require the level of TLC that deep cycle batteries or lithium-ion batteries may need. So we are talking about applications like microgrids. Much like telecom, in microgrids again there is a different variety of application, arguably some island nations, some island type applications, even in mainland, developed countries or even developing countries. I think there is a huge variety of energy access related applications, that flow batteries could target.

Fuhs: What do you think about the cost assumptions of $190/kWh for redox flow?

Manghani: I stand in the same camp as Julian who thinks these cost estimates seem fairly aggressive. I am not saying that these costs are not achievable. Some of the flow battery vendors that we spoke with are confident that they could get to fairly low prices. The question is whether there is a market big enough for flow battery companies to scale up. If there was a market for vanadium flow or any other kind of flow batteries, we would see investments by flow battery vendors or their financiers into building up gigafactories. But we haven’t seen that yet, excluding one or two vendors now looking to build facilities in China.

Fuhs: How concrete is this huge 800 MWh redox flow project in Dalian, China?

Jansen: It is a little bit of a mystery. The latest I heard was that it is going ahead, but as with many projects in China it may be built in several phases. Then the case will be reevaluated, and the next phase goes ahead. So I think it is unlikely that 800 MWh will be commissioned in one go. But I do think China is serious about all types of battery technology and it will be quite interesting to see what impact they have on the global market. If they want to make it happen, they make it happen; they do not sit around on regulations for years.

Fuhs: Regulations and market growth is related to business models. Has anybody been surprised by recent developments?

Jansen: If you would have asked me a year ago, I would not have expected the size of the pipeline in Australia, neither for utility-scale solar nor for utility-scale solar plus storage, for which the pipeline has reached more than 27 GW and 2 GW respectively. These expansion plans have taken me and lot of people by surprise. Another interesting trend can be observed in smaller markets. They are not as big an opportunity as any of the major markets, but I think the developments in the Czech Republic, Austria and Sweden are worth watching.

Fuhs: As far as I heard, the inspiration to build the 100 MW big Hornsdale storage plant was a blackout. Is this really the business case, and how is this service rewarded?

Manghani: The Hornsdale project was developed with some funding provided by the South Australia government that basically looks to be a resiliency contract, which of course does not cover the entire cost of the project. So the plant has the ability to participate in the Australian national electricity market.

Fuhs: Business model beyond frequency regulation is one of the big topics we defined as being of enhanced interest this year. A lot was written about the gas peaker replacement by storage. Peakers are plants that mainly serve peak load in the grid and are, for example, rewarded by capacity markets. However, isn’t it often the case that experts are spending lots of time discussing it, but it hasn’t happened so far?

Manghani: Peaker replacement opportunity is definitely getting more and more real. Again, some of it is being driven by some progressive-thinking regulators. In early January the California Public Utilities Commission ordered that the utility PG&E should look at storage and other distributed energy sources, rather than renewing a contract for three gas plants, two of which are peakers. Some of the development is being driven by the policy makers. But if we look at pure economics, we come to the conclusion that in certain markets peaker plant replacement as an application starts to get competitive in the next four years, especially in markets with a significant delta between the off-peak and peak wholesale prices, e.g. in the west coast and northeastern markets in the U.S. We assumed that four-hour energy storage is sufficient, knowing that this duration doesn’t necessarily replace peakers. Some of the peakers are required to run six or eight hours, and there can be weather events that require peaker plants to run for an entire day. If we assume that the cost reductions continue until 2027, about half of the new peaker plant capacity that’s expected to come on line could be addressed [with storage].

Fuhs: What can we learn from this, particularly for Europe?

Jansen: I agree with Ravi’s expectations regarding U.S. peaker plants, which are very much in line with our team’s modeling. European energy markets are fundamentally structured in a different way. We don’t have utilities procuring ­peaking capacity. The closest we might get is the capacity market mechanism in the U.K., which regulators realized that the structure did not necessarily incentivize the right type of resources, hence the de-rating of energy storage within those tenders. I think capacity as such will not become a primary revenue stream in any European market. It may serve as a secondary revenue stream, at least with the right incentives or market mechanisms. A different perspective could be the combination of thermal generation with battery storage as part of hybrid power plants being able to serve more than one use case. It can be gas turbines, gas engines, or in remote locations diesel gensets.

Leuthold: It is something we also see coming. You have the option of adding thermal storage to batteries, which is making power generation and heat generation more flexible. We see that in several places in Germany now (see page 16). Generally, I am pleasantly surprised that we do see some early movers going in the direction of using storage as peaker replacement or peaker supplement. But one fundamental difference between Europe and the U.S. is that in Europe we have a fantastic grid. The renewable penetration in countries like Germany is largely balanced by the grid and cross border transfer. Therefore, these applications of long duration storage may not happen in Europe.

Fuhs: Another driver, particularly for C&I storage applications in the U.S., is high demand charges. IHS Markit just published a study that the annual installations in this segment will increase from 50 MW in 2017 to more than 400 MW by 2022. The basic driver is also overload in the grid, the same as for peaker plants. So are we not likely to see such a development in Europe?

Leuthold: That is what I think.

Mayr: I agree with you. One reason is that each region is facing different challenges. In many regions in the U.S. the grid is weak, or “all duct tape and bubblegum” as I am told. At the same time, there is more and more renewable energy fed into the grid. On top of this you have resiliency issues that became particularly obvious through the various natural disasters hitting the U.S. in the last few years. So there is an increasing urgency for action to keep the lights on. Well-known initiatives such as the Self Generation Incentive Program (SGIP), as well as high demand charges and time of use pricing reflect the strong intention of both policy makers and utilities to incentivize customers to consume power in a more grid-friendly way, and to contribute to a more resilient infrastructure. Energy storage is obviously part of the solution here and benefiting from these frameworks.

In continental Europe, the grid is typically in a much better condition, and it’s much more densely meshed – we are literally sitting on a copperplate here. That causes high flexibility and reliability of the grid. For instance, in Germany, the mean non-availability of power in 2015 was just about 13 minutes. Hence, the perceived urgency for action to adjust frameworks or create new schemes is in general much lower. Having said this, energy storage can of course add a lot of value in continental Europe if allowed to, for example by providing frequency response or by helping owners of rooftop PV systems to increase self-consumption. But I would not expect that improving market conditions for storage is high on the policy makers’ agenda right now.

Jansen: We see great potential in the U.S., based on a number of core drivers around the economics of peak shaving and demand charge management. One fundamental disagreement I have, is to say that some states in the U.S. have tariff structures that enable C&I storage just because they have a less stable grid than continental Europe. One of the big issues I see in Germany is that it is rapidly falling behind. Implementing the energy transition goes beyond just installing renewable energy and infrastructure. In Germany, politicians completely underestimate future customer powers, both residential and commercial, and do not look to enable distributed energy to become a valuable resource as part of the grid. Especially in Germany, policy makers are putting up road blocks to proper implementation of a distributed, digitalized and consumer-centric energy ­system. Other countries like the U.K., the Netherlands, Switzerland and the Nordics are much more advanced in exploiting the opportunities from flexibility and enabling customers to support the grid.

Fuhs: Would it also make economic sense to change regulations in the wake of what is happening in the U.S.?

Jansen: It doesn’t need to be a demand charge. That doesn’t necessarily make sense in European countries. What may be more likely are effective time-of-use tariffs that commercial customers can take advantage of. And it also goes back to the ‘level playing field’ discussion. In most European countries you cannot aggregate distributed generation and small-scale storage without overcoming vast barriers. Look at the U.K.: It faces many challenges, but it is creating a framework that is future-oriented and enables different technologies to provide a range of services in a non-discriminatory nature to the system operator and the distribution network operators.

Mayr: I agree that in the U.K. regulators are showing a much stronger will to provide market access to energy storage than in most other European countries. But building on my argument before, there is also a much higher urgency for action than in continental Europe. Great Britain is an island with far less interconnectors to adjacent countries that could provide flexibility than, let’s say, Germany. And there is the phase-out of coal-based generation that comes along with a loss of inertia that eventually triggered the energy-storage friendly EFR scheme, for example.

Fuhs: We see that there are several dimensions, and it could make sense that Germany moves more slowly. But from the U.S. we see almost daily announcements that will push energy storage. Just recently, in one day we learned that Hawaii’s legislature is considering income tax credits for energy storage, and that in California energy storage systems connected at customer sites are able to provide services at the distribution or transmission level. This is something we wait for in Europe. Do politicians everywhere just do what makes economic sense, or has it more to do with being conservative or progressive?

Leuthold: Germany is the most conservative and protectionist country. If you look at the design for frequency regulation, only German transmission grid operators have managed to get the German government to request the 30-minute duration for frequency service, which reduces the competitiveness of batteries. Also, if you talk to the German ministry for economic affairs they’re quite defensive for any change. I think this is because they got burned by the cost for the energy transition. If we look at this historic aspect and the higher pressure in the U.K., it is clear that other countries are moving more quickly.

Manghani: The important fact is that the energy transition is beyond just centralized infrastructure. We are in a continuum of market development. Customers are more willing to go with decentralized and distributed energy choices. Be it solar panels on the rooftop or electric vehicles. If you look at the regulators’ standpoint, they know that the market is going to be more distributed and that customers are going to be more empowered in their choice of energy or mode of transportation. One pathway would be to just continue with the existing market structure, which could soon lead to a situation where utilities lose revenue because their energy sales are going down. The other pathway is utilizing this transition and putting the right kind of mechanisms for revenue models in place. As a result, the reliability of the system is maintained or improved. There are a bunch of reasons to experiment with different ways in which the distributed resources can be part of the overall energy system.

Fuhs: Even if it’s not all about infrastructure, technology and costs play a significant role. Many in our industry wonder whether there are other technologies to come soon and whether there will be a game changer. What do you envision?

Mayr: There are some interesting new technologies out there. But in the short- and mid-term we have a set of mature lithium-ion and flow battery technologies that compete in the market and will constitute the majority of installations. This is mainly because electrochemical systems are very complicated, and it takes a lot of time to bring a technology to the market and to scale it. And scaling is key to cost reduction. This said, there are a lot of interesting developments within the lithium-ion space. For example, there is the move to silicon-based anodes to increase the energy density or the move to solid state electrolytes with improved safety. Also very interesting is the shift to higher nickel content in NMC cells to increase energy density and to decrease the cobalt content, which might help to prevent potential bottlenecks in supply. Last but not least, the gradual improvement of separators to allow for thinner separators and higher energy density without compromising safety is a promising development.

Leuthold: On a regular basis we’re asking ourselves this question. I don’t know when solid state batteries will come. Generally with these technological developments I trust our colleagues from the automotive sector that they will drive this development. My personal favorite is the organic redox flow battery, where we have cheap materials. But this will take years. The decade to 2025 is the decade of lithium-ion. The interesting question will be what will be coming after the middle of the next decade.

Jansen: It is astonishing to see what manufacturers of lithium-ion are doing to change the composition of different lithium-ion chemistries to reduce costs. This is also why I don’t believe that we’re running out of resources to produce lithium-ion batteries. Very few people know what kind of new battery will come into the market, but we won’t be running out of batteries any time soon. Also the long-term trend for cost reduction will continue, which can be linked to the continued growth in production capacity across the supply chain.

Fuhs: How about short-term price reductions in 2018?

Jansen: For smaller battery modules we recently saw a plateau in price reduction and even some reporting of small increases in pricing. In 2018, there will certainly be a slowdown in battery module price reduction, and potentially for smaller orders a very minor increase. But overall, we do not expect a huge sudden swing to batteries becoming expensive and making current stationary storage projects uneconomical.

Manghani: One thing that may make significant impact on cost reductions are second life batteries. In 2023 and 2024 when there will be a huge stock of used EV-batteries coming back into the market. That may have some implication for economics of stationary storage applications.

Fuhs: Many people wonder what will be the residual value of batteries in 10 or 20 years. What are your forecasts?

Leuthold: As battery costs fall, the residual value will fall just the same. The packs sold in cars today, when they get back to the market in 10 years they will not only have been used for 10 – 12 years, but will also be 10 – 12 years-old technology. They will then have to compete with new cell technology that has seen 10 years of development. On top of that you will have the cost of integrating used packs with differing states of health into one storage system. The question about a more exact value is very hard to answer. Also, recycling costs and value of recycled materials go into this consideration. It is hard to predict but we don’t think it will be a massive value to reuse batteries. I prefer recycling materials and making new cells out of them.

Fuhs: What is the pure material cost of a battery?

Leuthold: Two to three years ago we considered $100/kWh the long-term limit for the material of lithium-ion-cells. Today we are discussing material prices of around $60/kWh and, depending on chemistry, as low as $25/kWh. That’s purely material though; you know how it goes, cheaper materials tend to be more expensive in manufacturing.