How storage will grow

How storage will grow

June 19, 2019 | By Keith Martin in Washington, DC

Energy storage is a solution to a range of problems. Different “use cases” are getting traction. Storage has not yet reached a tipping point in the United States, but adoption is accelerating. A panel of storage industry experts talked at Infocast Storage Week in San Francisco about the opportunities in the evolving US market. The following is an edited transcript.

The panelists are John Zahurancik, chief operating officer of Fluence, a joint venture between AES Storage and Siemens, Randolph Mann, president of esVolta, a utility-scale energy storage developer, Holly Christie, assistant general counsel of Invenergy, a large utility-scale project developer, and Brian Knowles, director of energy storage business development for Cypress Creek Renewables, a solar company. The moderator is Keith Martin with Norton Rose Fulbright in Washington.


MR. MARTIN: A solar CEO told us recently that storage is getting traction mainly in markets where people don’t do math. It is getting traction in the rooftop solar market, but not as much elsewhere. Do you agree?

MR. MANN: No. The utility-scale projects that we are doing are economic for our utility customers, and that’s why they are signing contracts with us.

MR. ZAHURANCIK: I think there is a new math. For a long time in the solar development field, the math moved in one direction: every year, a megawatt hour of electricity has had to get cheaper. Now we are finding some people are focused on value. It is not just about lowering the cost of energy, but it is also about supplying a range of new services that become possible with a combination of solar and storage. When you put those two things together, the project costs more, but it provides greater value to customers.

MR. MARTIN: The longer the sales pitch, the harder it is to sell. If you are trying to sell people on the additional value, I imagine it takes time to get traction.

MR. ZAHARUNCIK: It is definitely easier to say my megawatt hour costs less than your megawatt hour yesterday. I think people are starting to realize that it matters what time of day the megawatt hours are delivered. If I can’t do anything other than pile megawatt hours on top of each other at the same time of day and in the same basic sunny locations, then I have a problem. I need to move them to the places where people actually have load, and I need to supply them at times of the day when people want to consume power. That is the challenge that we can solve with storage.

MR. MARTIN: At the annual ACORE/Euromoney Renewable Energy Finance Forum in New York a number of years ago, a panel of wind and solar CEOs talked about the addressable storage market. There was an opportunity at the time to build standalone storage facilities in PJM, but it seemed like there was a need for only a handful of such storage facilities. The addressable market seemed small. Has something changed in the last five years to make the addressable market much larger? If so, what is it?

MR. ZAHARUNCIK: The price of storage has fallen dramatically in that last five years to a point where we are starting to use storage to do capacity and energy jobs. Five years ago, it was used primarily for frequency regulation and ancillary services.

I started in storage in 2007. We viewed ancillary services and frequency regulation as a beachhead for getting into the broader market. It was a place where we could prove the technical capability of storage in a very challenging job that requires a speedy response. As the cost of storage has fallen, now storage can compete on price for a lot of other jobs. We are seeing people use storage instead of gas-peaking facilities in places where it is difficult to get permits to build new gas peakers. We are seeing solar combined with storage where the solar part brings the energy generation and the storage brings the firming and flexible capacity. The core economics have gotten better over time as storage has matured, and more people are assigning value to the flexibility it provides.

MR. MARTIN: Storage may already have reached a tipping point in places like California, where the grid must keep the electricity price high to keep gas peakers interested for the few hours a day when they are on call. Batteries have been able to come in and steal the lunch of the gas peakers.

MR. KNOWLES: People are starting to look at storage as a viable solution for a lot of traditional problems. For example, National Grid decided to put 48 MWh of batteries on Nantucket rather than build a third underwater transmission line to the island. Storage is a better way to serve the summertime peaking capacity.

MR. MARTIN: But these are all niche applications.

MR. KNOWLES: There are Nantuckets all over the grid. There are widespread congestion issues. I don’t think we will rebuild the grid like we did in the beginning of the last century. It is hard to see the same level of investment in things like transmission infrastructure going forward, so I think we are starting to see asset managers and utilities think about storage as an alternative.

MR. MARTIN: So storage companies should look for places where the grid is congested. That is your best opportunity?

MR. MANN: We start with the niches and the beachheads, but as the cost of storage continues to decline and as the different potential use cases are recognized and valued by utilities, storage will become a very big market.

There are something like 100,000 megawatts of gas peakers in the United States. Storage can do a lot of those jobs. As wind and solar penetration increase, storage will be essential for shifting electricity to the time of day when there is the most demand for it.

MR. MARTIN: Is there a tipping point where renewables are X% of the local power supply when storage becomes essential?

MR. MANN: I don’t know the answer, but we see utilities are valuing storage as peaking capacity that is fast ramping and that enables them to integrate more renewables into the grid.

Standalone Storage

MR. MARTIN: The conference program says this panel is about standalone storage, which obviously includes large standalone batteries. What else falls under the heading standalone storage?

MR. MANN: Right now, it is lithium-ion battery storage, because that is what is scalable, it is commercially proven, it is bankable, it is financeable, it is developable. We are technology-agnostic to the extent that other technologies can displace lithium-ion, but for now, we are pretty busy developing lithium-ion battery projects.

MR. CHRISTIE: We are doing a number of projects that we call standalone or that we pitch as standalone when we look for interconnection. But they are paired with solar or other assets, so standalone storage is not like that lonely guy who never gets chosen on the dating app. There is no lonely standalone storage.

MR. ZAHURANCIK: I don’t know that I would go quite that far. We are building a 100-megawatt facility in California that is contracted as a standalone asset. It is under a PPA. We are in a partnership to build another 100-megawatt facility for Arizona Public Service. It is a standalone capacity and energy management facility. We have built similar facilities in the past for San Diego Gas & Electric. We have built them in Australia, Germany and the United Kingdom.

These are all facilities that are not intrinsically tied to any other power generating unit. They function as standalone resources. They register with the grid. They are managed as independent power resources. This year, we have seen more solicitations for large-scale standalone energy storage systems than we have ever seen in the past.

MR. MARTIN: Let’s put this into perspective. How much standalone capacity is there currently in the US? How much more is under development or construction?

MR. KNOWLES: We are close to 1,000 megawatts of operating assets. Things have changed a lot over the period it took to get to this level. PJM kicked everything off in 2012 with a Reg D market. Nearly half of the installed capacity today is really serving that market. Those are short-duration, 30-minute or one-hour batteries.

MR. MARTIN: There are 1,000 megawatts, with 500 of those in PJM. Any idea of how much is under development or construction?

MR. KNOWLES: Every day, a new biggest project is announced that would double, triple or quadruple the existing installed capacity. We saw more than 1,000 megawatts contract two years ago. Last year, I think we saw about 1,500 megawatts of new contracts or transactions around the world. A good part of that is in the United States. The US has been the biggest market.

We are in that phase of storage where it is starting to pick up speed. I am in my second decade in this industry. We saw mainly niche applications over the last decade. Now we are starting to see larger players do their second, third or fourth large system and opportunities opening up in more countries around the world.

MR. MARTIN: Some in the audience may be here because they are looking for another career path. Looking at you, John Zahurancik, it must be an easy career path. You have no gray hair. [Laughter]

MR. ZAHURANCIK: It’s all in my beard.

MR. MARTIN: Any idea what the breakdown is between independent ownership and utility ownership of the 1,000 megawatts?

MR. ZAHURANCIK: Historically, it was independently owned, but the new projects are increasingly utility owned. In the last few years, the utilities have started to look at storage as a rate-based asset. In some cases, they are doing it for transmission and distribution purposes, so it is like a traditional rate-based asset. In other case, they may be doing it through a deregulated part of the business. We continue to see large solicitations for independents.

Vistra is a good example, out with a 300-megawatt project that it is looking to build. Some large systems are a mix of utility-owned and independent-owned. It depends on the regulatory regime in each state.

MR. MARTIN: So it varies by state.

MR. ZAHURANCIK: We probably saw a couple dozen RFPs last year from utilities, and at least 75% of them were looking for PPA-type projects instead of rate-based projects. As an independent, we can bring some advantages to the utility in terms of nonrecourse financing and in terms of absorbing some technology, development, construction and maintenance risks. We can also sell the utility the particular product it wants, which in some cases might just be capacity, and then monetize the rest of the value of the asset on our own. I think utilities in organized markets will eventually gravitate toward that type of model.

Regulatory Drivers

MR. MARTIN: But the model does not help the utility grow. It grows by putting things in its rate base.

Switching gears, Randy Mann, what are the most important federal and state regulatory policies that are driving the storage market? Let’s start with the most important.

MR. MANN: I think FERC order 841 is the most important in terms of opening access to new markets. At the state level, the inclusion of storage in integrated-resource plans that various states are adopting is helping utilities be more thoughtful about what can they can do with batteries and how to think about solicitations for batteries.

MR. MARTIN: That’s two. Anybody want to add to the list?

KNOWLES: The California mandate and the expected New York mandate are big drivers. Moving the renewable portfolio target in Hawaii to 100% is big.

MR. ZAHURANCIK: Add federal environmental standards that are forcing closure of old existing capacity. As utilities look at retiring older power plants that sit in places where it is hard to build new capacity, they still have to meet reliability concerns. There is an opportunity for storage to replace existing generating capacity.

MR. MARTIN: Does the federal government have the right policies in place at this point?

MR. CHRISTIE: The current federal government does not have anything in the right in place. [Laughter]. But we are moving in the right direction. The government is starting to think about how the grid should look in the future and what we need to do to access the whole grid as an entire unit.

MR. MARTIN: What does that mean, “access the whole grid as an entire unit”?

MR. CHRISTIE: I mean thinking about it in terms of we have a certain amount of asset here and a certain need way over there. When I have a whole lot of alcohol in my house, but I’m alone and there is a party down the street, I have to bring the alcohol to the party or the party will not be a lot of fun. [Laughter][Applause]

MR. KNOWLES: Or the party to your house. [Laughter]

MR. CHRISTIE: Or the party to my house. One or the other. Exactly!

MR. MARTIN: Anybody else want to comment on federal policies? What is missing at the moment? Is it what Holly said, “The alcohol is in the wrong place”? [Laughter]

MR. ZAHURANCIK: At the moment, storage qualifies for a federal tax credit only if it is paired with a renewable generating facility, in most cases solar. If storage qualified on its own, that would move the industry forward more quickly.

We talk to grid operators and utilities who say they would like ideally to put a storage asset smack-dab in the middle of a city area, but they can’t build a wind farm or a solar facility there, so the storage asset ends up being paired with a wind or solar facility in a rural area. There is still a benefit, but the utility would get more locational advantages if it could put storage closer to the load. The tax credit forces less-than-optimal siting.

MR. MARTIN: The story so far is storage is getting traction, and not just in markets where people do not do math. If this is true, then why do we need a tax credit? Is it only getting traction when paired with solar projects?

MR. CHRISTIE: I started in the oil-and-gas sector, and that sector still receives a tremendous amount of tax incentives and credits. If my brother gets a pony, I should get a pony, too, especially since he’s the lower-achiever of the family. [Laughter]

Storage is a new and developing industry. There are a lot of hurdles still to overcome. As the technology continues to develop and we continue to look at issues around decommissioning risks and things like that, it helps to have a tax credit to push the industry to a point where it can reach scale. Scale brings down costs.

MR. MARTIN: How important is the fact that a tax credit can be claimed currently by pairing storage with solar? Is most of the standalone storage paired with solar to qualify for the tax credit? Randy Mann, you are shaking your head, “No.”

MR. MANN: We have nine projects under PPAs. None of them is paired with solar or wind. They are all what I would call truly standalone storage, front-of-meter and utility facing. That is the most efficient way to build storage because two assets do not have to be tied together. Storage can provide a service to the grid where it is most needed.

My vote would be to levelize the playing field. I don’t think that adding a new tax credit for storage is the way to go. Let the market evolve. Costs are coming down quickly. The banks are interested in financing storage. The ability of utilities to rely on the capacity coming from storage is improving quickly.

Revenue Streams

MR. MARTIN: Let’s shift gears and drill down into economics. Where standalone storage is privately owned, what are the current revenue streams? There is a capacity payment. There is an energy payment. What else?

MR. MANN: Our projects usually have a utility PPA. In some instances, it is a full-tolling PPA where the utility pays for capacity and also pays a variable usage charge. It also pays for electricity, which is effectively the cost of the fuel, much like in a gas-tolling agreement.

But the more typical PPA that we have — the more common structure — is an RA-type PPA where we are paid only for the capacity we provide the utility.

MR. MARTIN: What does “RA” stand for?

MR. MANN: “Resource adequacy.” You could think of it as capacity. The battery is also dispatched into the ISO for ancillary services, for energy payments, to the extent we can optimize the use of the battery.

MR.MARTIN: So you have up to three revenue streams: a capacity payment, an energy payment and an ancillary-services payment.

MR.MANN: Correct.

MR.MARTIN: Does anybody see any other revenue streams in the market currently for privately-owned storage facilities? [Pause] None?

Randy, what is the breakdown, by perf the three current revenue streams?

MR. MANN: It depends. The way we think about this is what capacity payment do we need to make our numbers work. Capacity payments are the easiest part of the potential revenue stream to finance. We try to make that number big enough that we are comfortable with the returns on the overall project given the variability of the other revenues.

MR. MARTIN: What are we talking about: 30% of the total revenue, 40%, 20%? Too hard to say?

MR. MANN: It is really hard to say, but it is a function of how are you bid for the capacity PPA.

MR. ZAHURANCIK: It varies by local market circumstances. We built a few systems in Australia recently where there is a very high premium on energy and ancillary services. Capacity payments in such a market are a relatively low percentage of total payments. In other markets, we find it harder to monetize the non-fixed revenue streams so we look for a higher fixed payment to get over an investment hurdle.

MR. MARTIN: Randy, do you have a number for me?

MR. MANN: No. [Laughter]

What John just said is right. There are so many different value streams coming from the storage asset. A lot of those value streams depend on how you dispatch the storage asset and trade the services in the market. If you are going into the storage business thinking, “I can only do this if I have fully contracted revenues,” it is probably not the right business, because you are going to reduce the value of your assets. You need to be able to participate in the market as broadly as possible.

MR. MARTIN: You have two operating projects. Were they both paid for entirely with equity?


MR. MARTIN: What revenue will the banks give you credit for in deciding how much to lend?

MR. MANN: Clearly the capacity piece of revenues is much easier to finance, but we have been able to finance a portion of the variable revenues. Obviously, the percentage of required equity is high in a new market. That may change over time as banks get more and more comfortable with the market participation of these assets.

MR. ZAHURANCIK: The tenor of the debt also makes a difference. In the UK market, banks have been willing to finance 50% of the project cost, but with five- to seven-year tenors.

MR. MARTIN: With cash sweeps.

MR. ZAHURANCIK: The banks have some visibility into the revenue streams for the next few years, but it gets more opaque after that, as they know the technology will continue to improve and new entrants will have an effect on prices. There is a fair amount of change going on now, and not necessarily around the asset as much as around the possible use cases and revenue streams.

MR. MARTIN: That’s a good bridge. Randy Mann said there are three main revenue streams: capacity payments, energy payments and ancillary-services payments. Are there other revenue streams in other countries that are not yet present here and, if so, what?

MR. ZAHURANCIK: In the UK, there are locational transmission and distribution tariffs. Generators may have to pay a fee because they are putting power onto the grid at a time when, and in a place where, it is disadvantageous to the overall stability of the transmission system. If you can put storage in a place where the grid needs the power, then some of that revenue will come to the storage owner. That’s an example of another stream.

MR. KNOWLES: We are starting to see a similar pricing scheme come to the US. That is part of the New York REV process: the value of distributed energy resources tariff has a locational benefits component to it, which looks at adjusting the capacity value of an asset based on where it is located. That should drive quite a bit of storage in New York.

MR. CHRISTIE: In some of our projects in Japan, we see a value-add from tacking storage to an asset. The interconnection costs will come down.


MR. MARTIN: I am interested in the elevator pitch that Randy Mann uses to persuade banks to lend. When you are financing a merchant wind or gas project, the project is pretty much assured of being dispatched by the grid. It is just a question of price, and you can put a floor under the price through a hedge. How do you get a bank to lend where there is no hedge and there is no certainty of being dispatched?

MR. ZAHURANCIK: It is a good question. I think that uncontracted revenues from a storage asset are easier to understand and price than from a power plant. The price of our fuel is equal to the price of our product — give or take a little bit — so I think it is a situation where we really can act as a price taker in the market and be assured of dispatch most of the time. Then it is a question of market prices.

MR. MARTIN: Banks are interested in branching out and doing new things. What percentage of the capital stack is debt where you can find it? John Zahurancik, you mentioned 50% in the UK under a seven-year mini-perm structure. What about in the US?

MR. ZAHURANCIK: It feels like 60% loan-to-value is where we start to feel resistance.

MR. MARTIN: That level of debt suggests a high overall cost of capital, because you have to use a lot of equity. Is the current cost of capital a significant impediment for storage companies?

MR. MANN: When you are building a utility-scale independent power business, cost is what counts. That is cost of capital, cost of equipment, and cost of balance-of-plant construction. We are seeing improvements in all of those areas. The cost of capital will improve as the market matures. We are seeing banks becoming much more comfortable with lending to storage from a technical perspective, from a market perspective and from a contract perspective. We will start to see the cost-to-capital come down for sure.


MR. MARTIN: Let me shift gears again. When you connect an independent power project to the grid, the grid does a study, and it may require you to pay for network upgrades to accommodate the additional electricity. When you connect a utility standalone storage facility, are there network upgrades? Are you helping relieve congestion? Do you get money back? What happens?

MR. KNOWLES: You don’t get money back. [Laughter] That is a truism. [Laughter]

It is a really good point, actually. We found in some of the projects that we worked on with partners that the project did not get money back, but it avoided upgrade charges or it helped mitigate charges that the network was facing overall.

We do find, though, that because storage is pretty flexible in its footprint, you can generally find a location where you do not have to make network upgrade payments. For example, if storage is put where older power plants are retiring, the grid was already built around the idea of having a resource there, and it usually already has the existing infrastructure to accommodate a large-scale storage project.

MR. MARTIN: Any independent generator would have been in the same position.

MR. KNOWLES: Not in practice because the reality often is you cannot get a permit to build a new power plant or to repower the existing power plant.

MR. MARTIN: What happens when storage does not replace an existing power plant? Are you charged for network upgrades?

MR. KNOWLES: That’s a good question. In every case where we would have had to pay for network upgrades, we just went to a different site. The siting flexibility was enough that you could find an alternate location that did not have those costs, if they were more than nominal in amount. You obviously have to pay to connect. There is some physical infrastructure that must be built. But if you are talking about upgrading huge pieces of a line or big central-system costs, generally another location can be found that does not require payment of such costs.

Data Points

MR. MARTIN: How long does it take a build a standalone storage facility? I am looking for data points. For example, wind projects on land take six to eight months of actual construction time.

MR. CHRISTIE: How much do you want to pay us? [Laughter]We can build it that fast. [Laughter]

We have done smaller projects in just a matter of a month or two. The issue is getting the equipment to a site. Larger projects, of course, are going to take more time. Most of the equipment is coming from Asia.

MR. ZAHURANCIK: Six to eight months is a typical timeline for a large-scale project. Often it is the transmission or the interconnection that is the gating item on the timeline.

MR. MARTIN: What is the cost per installed megawatt?

MR. ZAHURANCIK: It depends on how big the project is and how many hours of duration of storage capacity it will have.

For a project above 20 megawatts in capacity and an hour in duration, we are probably talking in the range, fully installed, of $600 a kilowatt, something in that ballpark. For a four-hour system, depending on the year the installation will occur, we are probably in the $1100 to $1200 a kilowatt range. Those numbers will vary depending on site conditions, what the project will connect to, and what it actually has to do.

MR. MARTIN: If you view yourself as competing with generators, you should be able to compete easily at those numbers in the current market.

MR. ZAHURANCIK: That is why I am still in it in the second decade. [Laughter]

Best US State

MR. MARTIN: Are there any questions from the audience?

MR. SANKARAN: Ravi Sankaran with Romeo Power. We are a battery technology company. Demand for storage is growing fastest in regions with robust incentives: for example, California and New York. This is the same thing we saw with solar. How far away are we to having more widespread adoption without such aggressive incentives? How far away are we to having more growth in the heartland and rust-belt states where there are no incentives?

MR. MANN: At least half of the RFPs we saw last year were in places where there was no mandate. The utilities putting out the RFPs were usually looking for all-source peaking capacity, in which case storage is competing against gas and other forms of generation and, in many cases, competing effectively as John’s numbers would indicate. So I think we are pretty close to there, if you value it properly.

MR. MARTIN: Regulatory policies tend to drive whether storage will be owned by utilities or be independently owned. Which state has the best business model?

MR. CHRISTIE: California. It is a state that has long looked at renewables and is doing what is needed to jump-start these businesses.

MR. KNOWLES: The big criticism about California is that the resource adequacy process is not transparent, and so you do not necessarily know at what price utilities are procuring their resource adequacy. New York would say what it is trying to do with the REV process and VDER tariffs is to more closely associate locational value and environmental value with each type of asset being deployed.

MR. MARTIN: So you like the New York approach.

MR. KNOWLES: It is super complex, for sure, perhaps even overly complex, but it is thoughtful. New York is really trying to get it right.

MR. ZAHURANCIK: I would just say about New York that Audrey Zibelman has done more in Australia in a short time as head of the grid operator than she was able to do in all of her years as head of the New York Public Service Commission. New York is incredibly complicated and its approach has not led to a lot of actual installations. The state that I think is doing a lot right is Arizona.

MR. MARTIN: What is it doing right that others are not?

MR. ZAHURANCIK: The major Arizona utilities are all in the process of procuring storage for various needs. The Arizona Corporation Commission has done a good job of forcing the utilities to look at all the alternatives and really consider what’s the best option today rather than what might have been the best option historically. Some very large projects have been put out for bid. All of the utilities are pursuing storage in one way or another. They are pursuing it for generation alternatives and also within the network. They are doing it on the basis of economic merit.


MR. MARTIN: One of the issues in the market is where will storage land? Is it a transmission asset so that it best resides with the grid? Is it best behind the meter? Advanced MicroGrid Systems in California put a lot of storage facilities at florist shops, grocery stores and other commercial sites, and then offered the storage capacity to Southern California Edison. At the same time it earns other revenue from managing energy usage for the commercial hosts. What do you think is the long-term viability of that model versus the type of projects you are pursuing? Randy Mann.

MR. MANN: Both models work. There will continue to be a behind-the-meter storage market as energy users look to reduce their energy costs, but storage also fits on the utility transmission system, it fits on the utility distribution system, and it fits in the utility generation stack as well. If I had to say where we see the biggest opportunity for growth, it is in providing peaking capacity for utilities.

MR. MARTIN: It is stealing the lunches of the gas-fired generators.

MR.MANN: Providing a slightly different product and hopefully at a cheaper price, which is particularly valuable in a place like Arizona or California where there is a ton of midday solar electricity that does not fit the shape of the system load. Storage may be the right asset.

MR. MARTIN: So displacing peakers, dealing with the duck curve in California. Another opportunity is to use storage to address congestion on the grid. Are there other opportunities besides these two?

MR. ZAHURANCIK: The other one is commercial entities that are taking a stronger role in procuring or managing energy for themselves are also starting to look at storage as part of that mix.

Commercial customers are driving the PPA market for renewables to a large degree today. They are now starting to look at adding storage as a way to balance the renewable electricity they have procured and better manage it, or at using storage to reduce demand charges or to protect factories from interruptions in the electricity supply. They are building it into the whole system. It is a version of a microgrid.

MR. MARTIN: We heard from Randy Mann that a basic business model is the storage owner has a PPA, and it earns three revenue streams: capacity payments, energy payments and payments for ancillary services. How do you see the business model changing over time?

MR. ZAHURANCIK: In California, you have a resource adequacy contract with the utility and then access to wholesale markets. I think that can be replicated in other markets.

In PJM, there is talk about reforming the capacity market and thinking about a fixed resource requirement, which would essentially mimic the California resource adequacy process. There again you could have a market with a direct contract with a utility like Dominion, but if the storage asset is not being called on by the utility, it can participate in the PJM frequency or capacity market.

The hybrid structure is important. The markets in which you are participating differ from one place to the next. Maybe in the northeast it is a regulation and capacity market, and in California it is a day-ahead versus real-time energy market.

MR. MANN: Where storage can access fairly and fully the wholesale markets, it allows for a lot more experimentation with different contract structures. The utility can buy what it really wants, and the market can buy the other pieces that it wants. This creates a more economic and valuable asset.

Audience Questions

Those are the limitations I see. I don’t have anything against pumped storage and think we should build as many such facilities as we can do economically. For places where we need something in a load center or we need something more modular and lack the required geographic conditions, battery storage is a very flexible alternative.

MR. WIENER: Jeff Wiener with Eos Energy Storage. I heard your comments about lithium-ion, and I understand that it is financeable and easy to install, but how easy will it be for another technology to break into the market, and what are the critical factors that you would look for in an alternative technology?

MR. KNOWLES: It is tough actually. If you are trying to sell to utilities or project developers, it is a very tough market because we are dealing with critical infrastructure, and it needs to work at a very high level of reliability and predictability. That usually means the technology must have a track record at commercial scale.

Batteries have taken a long time to get there. We are only just now seeing an acceleration.

The other challenge of dealing with utilities is each has its own service territory and lots of stakeholders. Instead of selling once as an economic solution, you really have to convince engineers and every utility as you go along that this is something that will add to, or at least not take away from, the reliability of their systems. There are a lot of barriers. That said, good ideas that address real problems eventually get traction.

MR. ERICKSON: Dave Erickson with New Hampshire Electric Cooperative. Realistically, do you see any competitor to lithium-ion in the next five years, and what MR. might that be?

MR. MARTIN: Flow batteries in China?

MR. ZAHURANCIK: You have to take the data from China with a lot of grains of salt.

We have a proven technology today in lithium-ion that is built at volume with deep-pocket balance sheets behind the core technology. It is financeable. Those are advantages that other technologies then have to overcome or at least match to come into the space. Within a five-year time period, I don’t think there is much. As you start to move beyond that, there will be variants of lithium and other improvements. A lot of people are working on improvements to electrolyte, anode-to-cathode material, just to get away from cobalt, if nothing else, that I think we will see in that window. But I don’t know that we will see a wholly new proven solution within that time frame.


MR. ZAHURANCIK: Lithium-ion-phosphate batteries are a variant of lithium. We have done a lot projects with LFP. The biggest problem sometimes is cost and size. They have a different footprint.

MR. HSIEH: Nathan Hseih with The Mobility House. How do you set your expectations for performance of these assets?

MR. KNOWLES: They do need to work, for sure. The expectation is that there will be similar performance in line with what you would expect from a solar project. Obviously, as a newer technology, there will be things that go wrong. That is what differentiates the good suppliers. They are willing to put a balance sheet behind a guarantee that the projects work. As John suggested, you can find lots of things in China right now — really cheap batteries — but it is really important to find an integrator that will warrant the batteries, warrant the inverters and warrant that they all will work together.

MR. BRYAN: John Bryan, EPC Power. What are your greatest supply-chain risks at this point?

MR. CHRISTIE: Trying to get very large amounts of battery cells from Asia. Often, especially for our larger projects, we tend to buy individual components where we can find them, then package everything together and ta-da, there it is. It’s a fruit basket. A fruit basket is not really a fruit basket unless you have bananas.


MR. MARTIN: Here is our exit question. Panelists, tell us one thing that you think most people new to storage don’t know about it? You have been in this market for a while. What important lesson did it take time to learn?

MR. CHRISTIE: One huge challenge for me in contracting with utilities for these projects has been that there are no standard contract forms. A counterparty will often provide a form that has nothing to do with the technology. “You can stick it into this purchase-of-a-bus contract, right?” It’s like, “No.”

There is a huge amount of risk around such an approach to contracts that people don’t seem to understand. Storage projects go through several phases: development, procurement, construction, operation. You can’t throw everything into the mix and hope it turns out right. Each phase must be considered on its own. This can be a struggle.

MR. MANN: I agree with that, but to me the biggest challenge is learning how to deal with market participation, managing assets day-to-day in the market, and also thinking about forecasting and projecting how those assets are going to look in the future.

MR. MARTIN: It is a very different market than what you are used to as a generator.

MR. MANN: It is much more complicated.

MR. KNOWLES: Definitely the complexity of building a storage project, whether it’s a lithium-ion battery or a flow battery. The relationship between the power electronics and the storage medium is very complicated when building a fully integrated project. People tend to say it is a box with a refrigerator on it; it should be fine. There is a lot behind the scenes that goes into to building these projects.

MR. ZAHURANCIK: It is a complex system that you are building, and it needs to operate in a certain way over time. People that come, particularly out of the renewable energy field where we have had a long time to develop standards and interfaces and disaggregate the pieces have gotten comfortable with buying panels from him and inverters from her, and somebody does balance of plant, and everything works together. We have had 40 to 50 years to get this right.

When we put the fruit basket of energy storage together, the bananas and the apples don’t like each other, and the grapes just get soggy, and none of it really works unless somebody is actually making it into a fruit salad instead of a fruit basket.

Making everything work together takes discipline, diligence and investigation. It is not plug and play, and it is certainly not plug and play into all of these different market structures and market rules automatically on day one. It takes hard work
to shape the technology in a way that will make it a useful substitute for power plants that have historically served
these markets.