Emerging storage business models

Emerging storage business models

April 06, 2017 | By Keith Martin in Washington, DC

It is important in any new market like electricity storage to get the business model right, as that is what helps such markets get traction. For example, development of a third-party ownership model was key to the rapid growth of the solar rooftop business in the United States. There is a lot of curiosity about the business models with which energy storage companies are experimenting. Three panelists talked about them at the Infocast Storage Week in Oakland in late February.

The panelists are Katherine Ryzhaya, chief commercial officer of Advanced Microgrid Solutions at the time of the panel discussion, Karen Butterfield, chief commercial officer of Stem, and Craig Horne, vice president for energy storage at RES Americas and a board member of the Energy Storage Association. The moderator is Keith Martin with Chadbourne in Washington.

MR. MARTIN: Karen Butterfield, Stem has a pilot project in Hawaii that involves 29 batteries put in places like Whole Foods, Albertson’s, a florist and an auto body shop. Many of the customers have solar panels on their roofs. This network of 29 batteries will experiment with making at least one megawatt of capacity available to the Hawaiian Electric Company in 15-minute intervals when the utility needs additional capacity on short notice to balance the grid. How do the economics work?

Aggregated storage models

MS. BUTTERFIELD: The program started a couple of years ago when an energy accelerator kicked in about a million dollars to get the project going and, as you said, it is a pilot project. We offer commercial customers a subscription service. The customer signs up for three years of storage services. This is not unlike a power purchase agreement or an energy savings performance contract. HECO gets control of the capacity. We have handed over to API . . .

MR. MARTIN: What is API?

MS. BUTTERFIELD: It is a software portal where a dispatch team can check how much capacity is available from this aggregated network of batteries. There are times when that capacity on those 29 batteries is at 30% of potential capacity, and there are times when it is at 90%. HECO has the opportunity to control what is there.

MR. MARTIN: Does Stem own the batteries?

MS. BUTTERFIELD: We do. We own them through a project finance structure. The owner is a partnership between Stem and another party.

MR. MARTIN: The customer pays the partnership a percentage of its savings on electricity. How does the battery allow the customer to save?

MS. BUTTERFIELD: We install a powerful software platform on the customer premises to manage energy use and costs, with intelligent storage in the background to automate savings. The software predicts when a customer’s onsite load will peak, and discharges to obviate the peak, thereby mitigating utility demand charges that can be 70% of a customer’s monthly bill.

MR. MARTIN: What percentage of the savings does the customer pay?

MS. BUTTERFIELD: Sometimes the customer saves twice as much as it pays and sometimes three or four times what it pays. It depends on the load shape of the customer’s battery. Unless the customer will save at least twice the subscription fee, then you probably cannot engage the customer because the proposition is not of high enough value.

MR. MARTIN: You said Stem owns the batteries through a project finance structure. Lenders will not usually lend against a revenue stream that is uncertain. The lender will determine how much if any, of the revenue is certain and lend only against that. How are you able to borrow in this case?

MS. BUTTERFIELD: We guarantee the lender that it will be made whole. The customers are also creditworthy. They include Safeway and other Fortune 500 companies. The florist you mentioned is the largest maker of leis on the island. We charge customers a fixed subscription fee for our storage subscription service as part of every contract.

MR. MARTIN: What do you receive from the utility?

MS. BUTTERFIELD: In this case, we receive grid service payments. In some other cases, we receive capacity payments.

MR. MARTIN: So this is a three-year experiment. You are two years into it. You have two revenue streams: you receive a share of the energy savings from the customers, and you receive something from the utility. What percentage of the cost of the storage device is covered by the two revenue streams?

MS. BUTTERFIELD: Keep in mind that we installed the batteries a couple years ago. Batteries were much more expensive then. So maybe the revenue streams cover two thirds of the cost, and the rest is paid by an energy accelerator. To be very clear, we do not pursue a shared savings model. We offer customers a subscription service where they pay us a fixed subscription charge.

MR. MARTIN: What have you learned from the experiment so far?

MS. BUTTERFIELD: First, customers see it as a no-brainer. The uptake rate has been amazing, especially among customers who were already early adopters of rooftop solar systems. Second, we found we were providing other value to customers, such as the florist you mentioned. Its solar system inverter was not working properly. We alerted it to the problem. It was amazed that we were on top of such things, but we spotted it through our close monitoring of battery-related data.

On the utility side, we learned two things. One is that instead of just discharging electricity when the utility needs additional capacity — instead of acting solely as a type of spinning reserve — we can also offer to take surplus power from the utility during periods when the utility has a lot of back-feeding of solar from its other customers.

The other thing we learned from aggregating battery storage is we have become a lot better at predicting what will happen to the batteries. We started off hedging how much capacity we can offer. For example, we would say to the utility that it can have 600 kilowatts today or, perhaps, 700 kilowatts at this moment. With machine learning and predictive analytics, we have been able to hedge less and provide more capacity to the utility.

MR. MARTIN: You have another aggregated storage system in the Southern California Edison service territory. You won a contract from Edison in 2014 to provide 85 megawatts of storage capacity. As of last November, you had turned on something like one megawatt or four megawatt hours of storage capacity. Does the business model in California work the same way as your pilot project in Hawaii?

MS. BUTTERFIELD: It is almost exactly the same. In November, we turned on our first small tranche. We turned on another tranche in December or January. We are at four or five megawatts now. We took our own batteries and synchronized them with other storage devices that Edison already has in place. We passed the test. Some of the early data scientists that were trying to develop the predictive analytics and algorithms were jumping up and down and high fiving as the test results came in. It was the first aggregated battery dispatch for California and maybe in the world.

The way we look at storage is we build it based upon the economics and then you add other value streams. The value stream that we just added in southern California is what we call demand response assist. You take the capacity that Southern California Edison is paying us to provide, and take the demand charge management that the customer is paying for in its subscription, and you layer on another program, which is a form of demand response. Eventually we hope to layer on two or three more as time goes on.

MR. MARTIN: So you will retain ownership of the 85 megawatts of storage devices and finance them in the project finance market?

 MS. BUTTERFIELD: We are using project finance nonrecourse financing. We have two financiers. We bring them in in stages as tranches of storage devices are put into service.

MR. MARTIN: Your revenue streams are unpredictable. How do the lenders decide on an advance rate?

MS. BUTTERFIELD: The revenue streams are pretty predictable because Southern California Edison has a capacity contract with Stem to pay us for capacity as long as we deliver it. We end up arguing with the financiers that the revenue stream on the customer side is also predictable because we charge our customers a fixed monthly subscription fee and based on how our systems have performed to date.

MR. MARTIN: Is the utility also paying an energy charge for the electricity it uses?

MS. BUTTERFIELD: Yes. In this case, Southern California Edison pays an energy charge.

MR. MARTIN: A bank will lend against the capacity charge. Will it lend against anything else?

MS. BUTTERFIELD: Our financiers are lending against the capacity payments from the utility and the customer payments. These are creditworthy offtakers.

MR. MARTIN: Katherine Ryzhaya, Advanced Microgrid Solutions also has a contract from Southern California Edison to provide 40 megawatts in aggregated storage capacity. All of the storage is behind the meter, meaning it is on customer properties. Will your storage system operate the same way that Karen Butterfield described?

MS. RYZHAYA: Yes. We actually have two contracts with Edison that sum to 90 megawatts of storage capacity.

MR. MARTIN: How much is already operating?

MS. RYZHAYA: Probably about five megawatts. Probably about the same amount as Stem.

MR. MARTIN: How did you finance your five megawatts?

MS. RYZHAYA: Our development partner, Macquarie, owns the project and provides the capital to build the system.

MR. MARTIN: Are your contracts with the customers and the utility the same as Karen described?

MS. RYZHAYA: Our contracts with Southern California Edison are 10+ years in duration, which to a financing entity looks and feels like utility power contracts that they know and love. The contracts are also heavily capacity-based versus energy, which shows firmness of revenues coming from the utility, which again is attractive for financing. Our customer contracts are also 10 years in duration.

MR. MARTIN: How are the capacity and energy payments determined?

MS. RYZHAYA: The capacity payments were set in our original bid in response to the utility solicitation. The energy payments are bilaterally negotiated and are performance based.

MR. MARTIN: Can you give us some order of magnitude?

MS. RYZHAYA: I would say it is in line with what any new peaker infrastructure would cost.

MR. MARTIN: Is the amount of the payments public information?

MS. RYZHAYA: It is confidential.


MR. MARTIN: Massachusetts is toying with imposing a storage mandate or something like 600 megawatts in service by 2025. The mandate amounts to about 5% of peak load. To put it into context, the mandate in California is about 2% of peak load.

Do you expect Stem and AMS to use the same business models in Massachusetts that you described in Hawaii and California?

MS. RYZHAYA: The AMS business model is almost entirely centered around the utility. We do not offer the utility incremental capacity when the system is not in use by the customer. We dedicate the initial capacity to the utility and if the customer would like to receive demand charge savings in addition to coincident benefits during utility dispatch, we will upsize the system.

MR. MARTIN: How does that work? These are behind-the-meter systems that you are planning in Massachusetts, but the utility has first claim on the storage capacity.

MS. RYZHAYA: Correct.

MR. MARTIN: This is where the software is very important if the customer also wants to use the battery. What does the customer have to say to you to be able to use it?

MS. RYZHAYA: In California, each battery must meet a four-hour performance requirement under our contract with Southern California Edison. Therefore, we will install four hours of storage capacity at the site, and those four hours are exclusively dedicated to the utility. There are coincident benefits to the customer when the utility dispatches the system. The benefits are quite robust. But, suppose Edison does not dispatch until 2 p.m. and the customer’s peak is at 8 a.m., then we will have to add additional kilowatt hours to the system to make sure that if and when Edison actually calls on the system, the capacity it requires is there.

MR. MARTIN: Karen Butterfield, will Stem use the same model in Massachusetts that it uses in Hawaii and California?

MS. BUTTERFIELD: Not exactly the same. There is latent value in the system, so our job is to extract all of that value from the system. Sizing the system is critical and choosing either a two-hour, four-hour or six-hour battery is critical to how we run our algorithms and what capacity we have available for the utility.

For example, we come in at 85 megawatts for four hours. It is our job to make sure that is available or we will be penalized. We are using software to maximize the value we can extract from the battery.

MR. MARTIN: Craig Horne, RES is focused mainly on utility-scale storage. How do you see Massachusetts? What sort of market will it be for you?

MR. HORNE: We have a distributed segment to our business that, like Stem and AMS, is looking at behind-the-meter storage.

We see Massachusetts as a great opportunity. It will open the door for the northeastern US. In terms of front-of-the-meter, the capacity value that storage can provide, much like in California, is to avoid having to build new peakers by getting more use out of the existing fleet.

Other business models

MR. MARTIN: I believe there are only three states with storage targets. We talked about California and Massachusetts. The other one is Oregon, which has a target that is about 1% of peak load. Are there any others?


MS. RYZHAYA: I think a bill is moving through the Minnesota legislature.

MR. HORNE: Arizona requires 10% of new capacity procurements to be reserved to make storage cost effective.

MR. MARTIN: Will the business models be different in these other states? Karen Butterfield, you are nodding yes.

MS. BUTTERFIELD: They have to be, right? We have 50 states, and the bane of our existence is trying to find business models that fit each one of these regulatory constructs. Storage is the hot topic currently among state regulators. They are trying to determine whether it should be in front of the meter and rate-based by the utilities, or it should be behind the meter and treated as a distributed energy resource, or whether it should be a combination of them, and under what circumstances ratepayers are helped or harmed by these different structures. Some states will adopt structures that favor in front of the meter, and some will favor behind the meter, and some will be in between.

MR. MARTIN: In the behind-the-meter storage, it sounds like you are installing the battery for the customer without requiring any up-front payment. You receive a revenue stream from the customer over time that is a percentage of savings. You receive payments from the utility in the best case that are predictable capacity payments and you may also receive separate energy payments. The fact that Macquarie has gone into this market suggests that not only is the revenue covering the cost of the batteries, but also there is already a healthy return possible from these projects.

Do you think what I just said about the return is true in most cases or is the industry still in the experimental phase trying to figure out how it can get the economics to work?

MS. RYZHAYA: No. I do not think it is true in all cases and states, and the truth is you need that long-term utility capacity payment in order to get players like Macquarie into this market. That is the beauty of the contracts that we were able to secure early on. The challenge is to secure additional such contracts going forward. If you look at 2016, it was a great year for new projects, but most of them were pilot sized and, going forward, likewise or behind-the-meter.

Potential opportunity

MR. MARTIN: GTM Research says that the annual revenue in virtual power plants, which is what storage is, worldwide could grow from $1.5 billion in 2016 to $5.3 billion in 2023, with the US taking about $3.7 of the $5.3 billion. Do these figures sound right?

MS. BUTTERFIELD: Bloomberg New Energy Finance has a similar number. Many of you will remember the early age of solar in 2005 and 2006. Our first project at Nellis Air Force base was a 14-megawatt project that cost more than $6 a watt to install. By the time we reached the third tranche, the installed cost had come down to $1 a megawatt.

In 2005 and 2006, everyone asked us the same questions. How do the economics work? How can the project be financed with an unpredictable revenue stream? We had to barter our first and second children to get the deal done. Some of the same things are happening now. It is great if you can get an incentive payment from the state or the utility regulator. It is great if the utility will make capacity payments. It is great if you can get an investment tax credit, which you can only get today if you pair storage with solar. It is the combination of all those things and the incredibly fast-dropping cost of lithium-ion batteries that are driving growth in this market.

MR. MARTIN: In which states is the industry getting capacity payments currently?

MS. RYZHAYA: Probably in around 25 states there are capacity payments or demand-response program payments of some kind. But those payments are roughly $60 per kilowatt year, a number that does not always inspire a customer to cut its demand. In other words, demand response-based capacity is not as reliable, as firm or as fast as battery storage.

The storage industry wants to be paid for the storage attributes. Direct capacity payments for storage are available in very few places today.

MR. MARTIN: Craig Horne, RES is putting a lot of effort into utility-scale storage, not just in the United States, but also in other countries. Does the projected growth of $1.5 billion today to $5.3 billion worldwide in eight years sound like what you are counting on to justify the effort?

MR. HORNE: I think the opportunity is larger given the way costs are declining across the board, not only for the battery, but also for installation and related items. The rapid decline in costs speaks to the ability of the market to accelerate.

MR. MARTIN: How many people attended the Energy Storage Association convention last year?

MR. HORNE: Around 1,600. We are expecting around 2,000 this year.

MR. MARTIN: The frequency regulation market in PJM has not been in play for very long, but it seemed to fill up almost immediately. How much potential is there really with utilities for standalone storage?

MR. HORNE: If you look at the benefits curve in PJM, the more fast response you get, the less storage you need. When you get to something like 40% fast response, storage becomes, on a megawatt-to-megawatt basis, equivalent to the slower-responding resources.

As storage becomes less expensive to install, it becomes a way to diversify your portfolio. It is an alternative to installing another gas peaker. Storage offers shorter settlement times of five- to 10-minute intervals. This makes the choice to have storage as part of the portfolio even more compelling.

MR. MARTIN: Didn’t you just say that the more storage you have, the less need there is for additional storage?

MR. HORNE: That is the kind of fast-responding benefit at current installed costs, but as storage becomes more cost effective, there will be more room for it within the existing market context.

MR. MARTIN: Let me ask the question this way. I moderated a panel discussion among CEOs at the Wall Street REFF conference two years ago. The panelists were renewable energy company CEOs. They were all turning their noses up at committing time and money to standalone storage to provide ancillary services to utilities after seeing the market in PJM for such services reach capacity quickly in a single auction. Are they wrong? Are they missing the opportunity?

MR. HORNE: I think they are focusing on what storage has been rather than what storage will become. The benefits from storage can be both on the uptake and discharge and can be controlled precisely. Those are benefits whether you are designing a high-powered, short-duration storage system or optimizing for longer duration.

The longer duration systems are becoming more and more competitive within the existing market frameworks. As more such systems are deployed, storage will become a special category. It will be considered just another option along with everything else. It will not rely on shallow markets. It can be deployed within six months at a scale of tens of megawatts. It can solve problems on the grid on a real-time basis. It will be very hard for traditional thermal resources to compete.

Installed cost

MR. MARTIN: Karen Butterfield, what do you think is the installed cost per megawatt of battery capacity today? Start with utility scale and then move to distributed applications?

MS. BUTTERFIELD: I am not able to speculate on that. Our model does not go down that road. It focuses on the customer’s load and available incentives to put together a value equation for the customer.

MR. MARTIN: But you have to pay the cost of the battery.

MS. BUTTERFIELD: We do. We made a really big mistake in solar. Solar rooftop companies talked in terms of dollars per watt. What does that mean? We are about to make the same mistake in storage. We are financing storage based on an economic starting point, and then value streams are added on top of it. I think we do ourselves a disservice if we start saying, “Storage costs 10¢ a kilowatt hour” or “It’s a million dollars a megawatt.” What we are really trying to do is find economically viable propositions for the customers.

MR. MARTIN: But there are two sides to the coin. Someone has to pay the cost. You are asking financiers to advance money to do so. Why is it a disservice to try to pin down what is on one side of the coin?

MR. HORNE: Storage is multidimensional. You can look at the cost in two ways: dollars per kilowatt installed or per kilowatt hour installed. It is important when looking at dollars per kilowatt also to look at the duration of the power charge.

The key thing when looking at either metric is to understand that it is just setting a foundation on which various value streams can be built. Unfortunately, the truest metric, the levelized cost of storage, which is the total value you are bringing to the customer, is complicated to calculate and is highly situational.

When looking at capital expenditures, it is important not to lose focus. At the end of the day, the key is how many megawatt hours of AC electricity the storage device can dispatch and for what duration. To give you an example, one company might have a 10-megawatt AC four-hour project. Another company might have 60 megawatt hours of nameplate storage capacity behind it because of the way the technology behaves over time, and another might have 50 megawatt hours, but the cost of that 50 might actually exceed the cost of 60. This makes it hard to compare based on a single metric.

MR. MARTIN: Katherine Ryzhaya, did you want to add to that?

MS. RYZHAYA: I am going to give a number.

We are a three-year-old company. We do not have as much experience as Stem and RES at doing these projects, but we have significant capacity. Our current operating assumption is $560 per kilowatt hour, and the breakdown between that is roughly $400 for hardware, for batteries essentially, and another $150 for installation.

And this is an important point: when people talk about the cost of lithium ion, the cost of batteries is falling, but the installation costs are not falling and often they are a significant part of the overall cost.

MR. MARTIN: That is a very interesting ratio. Is the 400 DC or AC?


MR. MARTIN: Craig Horne, any other data points?

MR. HORNE: Yes. For utility-scale storage, there are obviously economies of scale, both on the purchasing side for the hardware and then installation. The value streams are different, as well, so I caution against trying to do a straight comparison to the numbers that Katherine just offered. A front-of-the-meter utility-scale storage system would be 20% less expensive for batteries going in currently.

This is on a four-hour system, so you normalize the cost of the interconnect and the other front-end items. For a four-hour system, you can be on a $1 per kilowatt basis installed at the level of the feeder.

MR. MARTIN: Name and affiliation?

MR. ELLIS: Erik Ellis, APS. This information is not secret. It might be for some suppliers, but you can go get Tesla’s costs from its website. Tesla is transparent about them. The Tesla power pack comes in 200-KW building blocks. The cost is around $350 a KWh for a four-hour system. That includes the inverter. You still have to pay installation costs on top of that, but anyone can visit the website and get that information.

MR. HORNE: We found that there is a pretty big difference in cost between a power conditioning system that is basically just doing straight AC-to-DC conversion versus one that is also providing Black Star-grade performance capability. That alone can account for 25% to 30% variation in costs, depending on the manufacturer.

Customer arrangements

MR. MARTIN: Let me now move in another direction. The solar rooftop industry started to get real traction when it came up with a third-party ownership model. Solar rooftop companies offer to put solar on people’s roofs for free. The customers pay for the electricity they use or to lease the systems over 20 years.

We have also seen companies like Mosaic and PACE loan programs get traction by making loans to homeowners who want to buy solar systems for their roofs. In the case of PACE programs, the homeowner repays the loan over time through special property tax assessments. I read that both Stem and AMS have been raising funding to enable them to offer financing to customers who want to buy batteries. Starting with you, Katherine Ryzhaya, how will the financing you are making available to customers work?

MS. RYZHAYA: It is similar to the solar rooftop model, except where the customer sees value really is in the demand component.

MR. MARTIN: So you enter into a contract with the customer. Are you actually selling the battery to the customer or are you retaining ownership and merely providing a service to the customer?

MS. RYZHAYA: We use both models. Some customers have very cheap capital — municipalities, for example — and they like to own infrastructure on their own sites. In that case, we sell the system and remain involved as an asset manager and contract operator. In other cases, we may own the system and merely provide services.

MR. MARTIN: In the third-party ownership case, is the contract with the customer for 20 years?

MS. RYZHAYA: We have contracts that range from seven to almost 20 years.

MR. MARTIN: Does the customer have to buy out the back end of the contract if he or she wants to get out?

MS. RYZHAYA: If that is how the contract is structured, yes.

MR. MARTIN: Karen Butterfield, same models?

MS. BUTTERFIELD: Largely. Our customer agreements run five to 10 years in length. Our customers pay a subscription fee. They pay hell or high water. And contracts have a termination clause.

MR. MARTIN: Are you offering these arrangements to people who have a solar system on the roof? For example, if someone has a contract with SolarCity or Sunrun to supply electricity, do you act as a separate storage company?

MS. BUTTERFIELD: We do not support the residential market, but if a commercial or industrial customer has solar, we do a system site analysis to determine whether we can save the customer enough on its bill for demand charges to make storage worthwhile. Often you can do so with solar. We look at whether the savings on demand charges more than offset the cost of the battery. In cases where a company is installing rooftop solar and wants a battery at the same time, we may own the battery and claim the investment tax credit. We go in together with the solar rooftop company and make a joint installation.

MR. MARTIN: You are teaming up with the solar rooftop companies. You are not in competition.

MS. RYZHAYA: It is the same with us. We are not in the residential market. We are in the largest C&I space, so our average installations are 500 kilowatts to multiple megawatts in size. We are working on our first solar-plus storage project now. It will be online by the summer with a partner, but we are the lead.

MR. MARTIN: SolarCity says it is getting 10 times annual growth in battery installations in the residential sector. What growth rates are you seeing in the C&I sector?

MS. BUTTERFIELD: I think Stem grew around five or six times last year. When you start with a small number, a 10-times growth is not as large a number as it sounds. I think we will to continue to see three-times growth in our industry at a minimum as new states open to storage.

Utility-scale models

MR. MARTIN: Craig Horne, let’s move to utility-scale storage. You said RES works in both, but it is the one company on this panel that has a large stake already in utility-scale storage. I read that you have 47.6 megawatts in operation, 77.5 megawatts under construction, and another 200 megawatts in development, and your facilities range in size from two to about 20 megawatts. You own some batteries. Some you have sold to utilities. How do the economics work in cases where RES retains ownership?

MR. HORNE: I have updated numbers. We now have about 90 megawatts in operation and a little more than 55 megawatts under construction. We have two 55-megawatt projects in the United Kingdom that are enhanced frequency response.

We have a pretty flexible business model. We retain ownership of some of the operating projects, and we finance them on a nonrecourse basis: for example, senior nonrecourse debt from Prudential Capital.

MR. MARTIN: What is the revenue stream against which Prudential is lending?

MR. HORNE: The underlying arrangement is actually a hedge. The projects are both just a notch under 20 megawatts. The Jake project is in Joliet, Illinois, and the Elwood project is in west Chicago. The projects have a hedge contract for part of their revenue stream, and the debt is a borrowing against the fixed payments on the hedge.

MR. MARTIN: It is a hedge of what?

MR. HORNE: I can’t go into the details. The business model is still pretty new. The customer is a utility.

MR. MARTIN: So the utility is the one using it as a hedge. It makes a fixed payment in exchange for floating payments of some sort.

MR. HORNE: Yes, that’s it.

MR. MARTIN: The UK and Canada are two other countries in which RES is doing storage projects. Do the business models differ from what you are doing in the United States?

MR. HORNE: We have a project in Canada that has been in operation for about two years. It is a 4-MW project that provides frequency regulation services in Ontario. It is the largest battery project to date in that province. We won the right to build it through a tender. It is our second project providing such services in Ontario.

We have an operating project in the UK called Hired Hill. It is a 300-KW two-hour project. It is tied to a 5-MW solar photovoltaic plant in the Western Power Distribution network. The solar plant and battery are a demonstration project that is providing nine different services.

MR. MARTIN: So nine revenue streams.

MR. HORNE: Yes. Ramping, time shifting, some capacity, things like that.

MR. MARTIN: They are all forms of ancillary and capacity services to the utility?

MR. HORNE: There are some energy payments, as well.

We worked with National Grid to define a nice droop curve for storage that provides certainty of service, but that also lets us minimize the duration we have to build behind it. In places like PJM in the US, you need 20 to 25 minutes of duration behind every megawatt if you are participating in the frequency regulation market. In Germany, it is an hour and 20 minutes.

If you look at the droop curve that we worked on with National Grid, it is actually a band and the band gets narrower as the frequency diverges from its ideal point. The band allows you then to adjust your state of charge without dropping out of the market.

We have a 20-megawatt bilateral contract with National Grid to test some of these advanced droop curves. National Grid plans to add 200 megawatts of storage in each of the next five years. It awards three-year contracts.

Warranties and debt coverage

MR. MARTIN: Most of you are using lithium-ion batteries. For how long are the warranties you are getting from manufacturers?

MS. BUTTERFIELD: The warranties are 10 years. We supply data to the provider and it determines the worth to longevity. We have been doing batteries for almost six years. We have a lot of real-time data. Several battery manufacturers have asked us for the data because it is one of the few ways to track six years of operating history.

MR. MARTIN: Craig Horne, are you also being given 10-year warranties in the utility-scale market?

MR. HORNE: Yes, but those are considered extended warranties. You have to pay extra for them. The free part is two to three years depending on the manufacturer.

MR. MARTIN: Name and affiliation?

MR. LEWIS: Craig Lewis with the Clean Coalition. When you think about the capital structure for financing any tech project, you generally want to include as much debt as possible because it is the cheapest capital. A lender will usually require a debt service coverage ratio of something like 1.4x, and that is where the cash flow on which it is based is really stable and predictable. This might be a silly question for Craig Horne, but if you look at the ISO markets today, what percentage of the cost of the battery can be covered by debt, assuming you need a predictable cash flow stream and a 1.4x coverage ratio?

MR. MARTIN: We are down to the last 30 seconds, so let’s just have a percentage if you have one.

MR. HORNE: You can cover at least half, if not more.

MR. MARTIN: That is true today or what you hope to see in the future?

MR. HORNE: That is for bids going in today.

MR. MARTIN: Karen Butterfield, do you have a percentage?

MS. BUTTERFIELD: Since he did that without the benefit of a calculator, I will take a similar flyer: 31.2%. [Laughter.]

MS. RYZHAYA: I think I am closer to Karen.