Energy Storage Economics
The storage business is about to take off. A total of 363 megawatts of storage projects were announced in 2014. Investment in storage is expected to be running at $5 billion a year by 2020. But has anyone figured out the economics?
A panel discussed this and other storage questions at the Chadbourne global energy & finance conference in early June. The panelists are Glen Davis, CEO of Renewable Energy Systems Americas Inc., The Honorable Carla Peterman, a commissioner on the California Public Utilities Commission and author of the key ruling setting storage targets for the California utilities, Peter Rive, co-founder and chief technology officer of SolarCity, Kevin Sagara, president for renewables of Sempra US Gas & Power, and John Zahurancik, president of AES Energy Storage. The moderator is Todd Alexander with Chadbourne in New York.
MR. ALEXANDER: Extravagant claims are being made about energy storage. It will be a game changer. It will be the greatest thing of all time. John Zahurancik, what is the real opportunity in energy storage over the next five years? Is it possible to make money?
MR. ZAHURANCIK: AES started its energy storage business in 2007 and 2008 when we put our first large battery project on line. We have done several since then, so we have been finding ways to make money in energy storage for a while now.
The most interesting near-term development is the California program. The state is looking for ways that storage can be beneficial and valuable to the grid and to put storage on a comparative basis with the other things that we buy as part of the electricity we receive. In the next five years, storage should begin to substitute for some of the things we are currently buying but of which we will no longer need as much, such as peaking power plants and transmission and distribution upgrades. Storage has the potential to relieve grid congestion and mitigate reliability concerns. Storage is an alternative to some of the things we buy today.
MR. ALEXANDER: Glen Davis, where does RES see opportunity?
MR. DAVIS: Energy storage facilities provide anywhere from a dozen to 20 different services from the point of view of the grid. Most of those are related to reliability. For instance, storage can help integrate renewables on a system-wide basis by allowing a particular renewable energy facility to smooth out its electricity deliveries to the grid. Storage can provide frequency regulation; we all know of several frequency regulation machines.
The combination of these types of potential benefits, facilitated by lower technology and installation costs, is creating a growth potential in the market.
MR. ALEXANDER: It is tough to make money in frequency regulation in today’s market. Are there ways to make money by doing peak shaving and smoothing out electricity deliveries?
MR. DAVIS: The conventional wisdom among those of us in the energy storage market is that an arbitrage play, peak shaving or anything that relies on a difference between peak and off-peak pricing, will not pencil out by itself. It can be part of the revenue from a storage project, but it is not enough to carry the project.
Revenue from providing frequency regulation depends on the rules of the local market and whether you have consumers of frequency regulation who are willing to take extended positions. For instance, in Ontario, we have a four-megawatt, two-megawatt-hour battery that benefits from a three-year contract with a system operator. We have two projects under construction that will go operational this year in Illinois that have three-year hedge contracts.
MR. ALEXANDER: Peter Rive, SolarCity is putting batteries behind the meter, so you probably think differently about storage than our other panelists. How do you convince customers to pay for batteries as part of rooftop solar systems if peak shaving will not be enough to pay the cost?
MR. RIVE: We actually see our customers saving a lot of money from peak shaving. We have customers, like Walmart and Yahoo, who are buying a product that we call Demand Logic. The peak period varies by utility service territory. It may be noon to 9 p.m., noon to 7 p.m. or 2 to 7 p.m. If you try to take advantage of the difference in rates between peak and off-peak periods with a stand-alone battery, it is expensive, but combining a battery with a solar system is more cost effective; you can intelligently discharge the battery when the sun is setting or the solar system is not producing.
The customer is buying power from us at 12¢ a kilowatt hour instead of the 16¢ retail rate, so the customer is seeing additional savings, and it has backup power as well. So if you are a Walmart or other retailer, you will save 4¢ a kilowatt hour on your peak demand charges, and you have the additional benefit of keeping the registers going when the power goes out. It is a great value proposition. We are getting incredible traction with it.
MR. ALEXANDER: How does the math work in states that have net metering? If you can deduct the high retail rate for power, is it worth installing the battery?
MR. RIVE: I have been talking entirely about commercial and industrial applications.
For residential installations, all of the solar energy goes directly into the battery. There is no plan to have the battery export any energy that did not come from the solar power system, but one could look at time-of-use rates, as an example, and there are ways in residential applications to offset the costs of a battery. For example, in our current offering, which is around $5,000 to the customer for back-up power, the customer will be able to realize about $500 in time-of-use benefits over a 10-year period, depending on the usage pattern. This will not pay for the battery completely, but it helps to offset the cost of having a back-up power source.
MR. ALEXANDER: Kevin Sagara, how does adding a battery enhance the returns from a utility-scale project?
MR. SAGARA: Let me comment first on some of what has already been said. The most interesting thing about storage is the range of potential applications and technologies. There are many different types of batteries. Each has a different chemistry.
We have a battery in Maui. We have a 21-megawatt wind farm there. Maui is an island grid, and it only has an average daily load of about 200 megawatts, so the intermittent output from our wind farm can really disrupt the local grid. Our power purchase agreement with Maui Electric requires us to install an 11-megawatt battery, with a 4.4-megawatt-hour storage, to control the ramp rate from our wind farm. When the wind farm trips off, the battery helps to ramp down the power supply in a gradual way so that we do not damage the grid. It also modulates the intermittency of the wind, on a minute-by-minute basis, by helping to smooth out the rate at which our electricity is going into the grid. That is one of many possible applications for batteries.
We are very early in the storage business. No one has really figured out all the potential business models and how to make them economic. At the same time, the costs of storage devices are falling rapidly.
MR. ALEXANDER: Does the Maui battery pay for itself? Do you receive a higher power price in exchange for installing the battery? How you justify the additional capital cost?
MR. SAGARA: Our battery was required under the PPA. We would not have a project without it. The project with the battery is economic at the contract electricity price.
MR. ZAHURANCIK: Let me ask a question of the panel. People talk about an amazing array of possible battery and other storage technologies, but I suspect the reality is everyone here is using lithium ion batteries.
MR. DAVIS: Lithium ion, thermal storage through air conditioner control and fly wheels.
MR. ZAHURANCIK: But the majority of it is lithium ion. I am just trying to simplify because, although there are many possible applications and technologies in theory, there are not 20 business models in practice. There are a few business models.
I go to these conferences and I find storage being described as the unknown of unknowns. We call it the holy grail because we think true storage projects do not exist in real life because the economics do not work, and yet there are real projects that you can visit. Everyone on this panel has a project that you can come see. The point is we need to move beyond the holy grail to another analogy. Storage has been found. [Laughter.]
MR. ALEXANDER: So tell us in which markets storage projects are currently economic. Is it PJM? California? Or just island grids?
MR. ZAHURANCIK: We are all aware of California. There is a lot of activity here. California has had a very successful initial launch.
We went very quickly from a view that we did not know how to tackle storage to solicitations where we are seeing a huge amount of competition from bidders. Storage is competing with the traditional electricity generators.
We have a whole range of projects in the PJM market. What PJM has done very effectively is to create a transparent pricing mechanism for storage, and other markets are looking at what PJM has done. PJM figured out how to take something that benefits it and send the right price signals so that the developers, the technology and the financiers show up to provide storage. Those are just two places in the US. ERCOT is doing a lot now. We just announced a project in MISO in Indiana. Around the world, we are working on projects in The Netherlands, Northern Ireland and The Philippines. We already have a project in Chile. These are not isolated events.
MR. ALEXANDER: All of the projects use lithium ion batteries?
MR. ZAHURANCIK: Yes. We say we are technology agnostic, but highly opinionated. [Laughter.] That is the technology for now, I guess.
MR. ALEXANDER: Carla Peterman, California is trying to encourage use of batteries to allow for greater use of renewable energy. The two go hand in hand. It is true, as John Zahurancik just said, that some large batteries have been deployed, but people are not that sure exactly how to do it or how to recover their costs. How do you regulate in a market like that?
MS. PETERMAN: Carefully, is the short answer.
Good morning. Let me comment first of what John said. There is a continuum of technologies and applications. John is right that most of the companies bidding into the California solicitations are proposing a handful of business models, but we expect to see more technologies, more applications and more business models over time.
We are focusing on how to make the rules for the next few years. It was two years ago this month that I issued an assigned commissioner ruling proposing energy storage targets. There were a wide range of reactions. We had people urging us to set the targets at zero and others asking for the targets to be 6,000 megawatts. So we have come a long way in terms of organizing around a goal.
The next couple years will be busy. We had the first storage solicitation by the utilities, and we will be issuing a proposed decision early next year. We are seeing procurement happen through the long-term procurement plan process. Edison and SDG&E did a preferred resources pilot to meet some local reliability needs. That brought more storage for the system earlier in time than we expected. There has been significant interest among developers and financiers in the storage solicitation.
We expect to issue four decisions related to storage in the next year and a half because there will be the 2014 solicitation results, and then we have to decide on the 2016 solicitation plans. Two decisions will come out of our newest proceeding, which is moving ahead on two tracks: track one is focused on what are some of the policy and rule changes we need to make in advance of the investor-owned utilities submitting applications for 2016 and track two will focus on other outstanding issues.
The California Independent System Operator is also working separately to develop rules and answer your initial question around revenue opportunities.
I see my role as a regulator at the California Public Utilities Commission and the role of the ISO to make sure that rules are in place to allow companies to take advantage of potential revenue opportunities. For example, one issue that has come up recently is multiple use applications for energy storage. A storage facility might be used to supply services to different entities or different markets. What would it look like to have shared or communal storage, providing storage, for example, to multiple electric vehicle customers. We need to make sure our rules are flexible enough to accommodate new potential applications.
We are talking this morning about the revenue opportunities in the next couple years, but ultimately I think this is a long game. Where we are moving as a state is toward more renewables and time-of-use pricing. These trends, plus wider adoption of electric vehicles, should make storage more attractive and valuable.
MR. ALEXANDER: So now is your chance guys. We always hear about how the market is not assigning enough value to things like renewables and storage by fully recognizing their contribution to reducing carbon emissions. What should the state say in its regulations to make storage more attractive? Peter Rive, you seem anxious to answer.
MR. RIVE: Yes. Storage equipment provides a lot of benefits to utilities if they were to take advantage of them. For example, including smart inverters and batteries as part of solar rooftop systems allows the systems to provide reactive power and voltage control.
Traditionally, utilities have solved these problems by procuring their own equipment because that is the only way they can earn an income. The current regulations stipulate that they can only earn a rate of return on additions to rate base. If instead they could earn income on procuring services from distributed resource providers, that would encourage them actually to use those as alternatives.
An analogy is if you want to try to host a website. One option is to procure it from Amazon instead of buying a whole bunch of servers. That is a common approach in the larger business world, but it does not work in the regulated utility sector. Utilities have no incentive to take the cheapest path by paying something like a dollar a month to a distributed solar provider and passing through the cost.
The regulations could be amended to allow this approach. The only objection I have heard from the ratepayer advocate is that a utility should only buy the service rather than the equipment if doing so is the cheaper approach.
That is one minor change the state could adopt and it would make a huge difference.
MR. ALEXANDER: Glen Davis, what will you tell Carla Peterman when you walk out the room with her after the panel?
MR. DAVIS: Good job! [Laughter.]
MS. PETERMAN: Good answer! [Laughter.]
MR. ALEXANDER: You guys can leave now. [Laughter.]
MR. DAVIS: The regulations should recognize the value embedded in storage services across the board. PJM has recognized that frequency regulation is a service that has value and a market can be formed around it. Other regional transmission organizations have not done that yet.
Storage units provide various services and benefits to utilities. There is no pricing or transaction mechanism built around them. While the PPA model covers most of them, a generator simply hands over the right to all the services to the utility. What we need is more transparent pricing for each of the services.
You also want to create other areas in which transactions can occur that bring benefit to utilities. It can be as simple as develop and transfer a storage facility. At RES, we have both an EPC shop and a development shop, and we are less concerned about owning the facility in the end, giving us the ability to be very flexible in terms of commercial structures.
MR. ALEXANDER: Carla Peterman, how do you respond to these types of requests?
MS. PETERMAN: We did an energy storage road mapping exercise last year with the ISO and the California Energy Commission focused on the question of what are the barriers for energy storage and what we can do to remove them. For example, interconnection for stand-alone storage facilities can be a regulatory barrier. What we did was identify which agency was responsible for each issue. Some issues are more specific to the ISO. Some are more specific to the California Public Utilities Commission.
We are working through the issues on the list. We always want to hear what will help facilitate storage, but we also have to be consistent with the other resources that we regulate. Some of the challenges going forward will be making sure that our rules for storage do not get ahead of rules for other areas and that any new rules work across technologies.
We are in the midst of a distributed resource planning process where our utilities will submit next month resource plans about how they will incorporate different types of distributed resources.
Taking on a question like how to aggregate energy storage and have that be a resource that can bid into the wholesale market is a larger question than just storage. Thus, one of the things we are doing is identifying common issues that we can address for all resources instead of just doing it piecemeal for storage.
We remain open to all suggestions.
MR. ALEXANDER: Let’s shift from the regulatory side to the finance side since most of us are involved in finance. How can you structure battery deals so that they are financeable even though the battery may be used to provide services to different people? Does a utility-scale battery need to be co-located with a wind or solar project?
MR. SAGARA: You need an offtake contract with a creditworthy counterparty to provide a revenue stream that can serve as a basis for the financing. In California, you would be looking for some kind of capacity contract around your storage project plus an O&M charge. It gets trickier when you get into other kinds of revenue models.
MR. ALEXANDER: We saw at least one lithium ion battery catch fire, literally.
MR. SAGARA: It was not a lithium ion battery, and ours did not catch on fire. [Laughter.]
MR. ALEXANDER: Okay, so not totally accurate. [Laughter.]
There was a project that caught on fire, and people who are less technologically sophisticated may be a little bit concerned about technology risk and the inability to get a full wrap and long-term warranties. Some of the leading developers are out of China and may not offer the long warranties as we have seen offered in the solar business with some modules. How do these issues affect your ability to raise financing?
MR. SAGARA: If, as John Zahurancik suggests, everyone is using lithium ion, then there are some suppliers who are providing substantial warranties that could underpin a financing. Financeable projects will probably trend toward proven technologies. It will be interesting to see who is willing to bet as an offtaker or lender on some of the less-proven technologies like flow batteries.
MR. ALEXANDER: Peter Rive, SolarCity has a close working relationship with Tesla. Tesla has made a huge bet on a particular battery technology. How do you see that battery becoming financeable?
MR. RIVE: It is pretty straight forward. On the commercial side, the customer is leasing a battery and SolarCity is providing a guarantee. The battery is considered to be part of the solar system as long as at least 75% of the energy stored in the battery comes from the solar system, so the battery is eligible for an investment tax credit, with the amount of the credit tied to the percentage of solar energy above 75% stored each year during the first five years of use.
MR. ALEXANDER: John Zahurancik, you have done utility-scale battery projects on a stand-alone basis. Have you found commercial banks willing to finance them?
MR. ZAHURANCIK: There is a lot of appetite to do things. We have financed some batteries on a project finance basis, but they were part of another asset, like a wind farm or conventional power plant. We have been able to help educate the financial community to some degree on what to care about within this energy storage facility.
The market has gotten comfortable with equipment like solar panels that scale and have a predictable rate of degradation, as long as there is a balance-sheet behind the supplier warranty. The other side of it is having enough visibility into the revenue side to feel comfortable with the revenue projections. That is where California is trying to ensure fair access to the same kinds of contracting structures for storage that we have used for conventional and renewable energy generating units in order to mobilize low-cost capital.
At some point, we will get to a portfolio of storage assets with some variability in pricing and still be able to do a financing around that. We will see the cost of technology come down as the market reaches scale. That will allow storage to be deployed in more places and to serve the customers more effectively. We will see lower-cost financing that will further reduce the cost of installed systems.
Beating the Competition
MR. ALEXANDER: Who is your competition? Is it peaking natural gas power plants?
MR ZHURANCIK: Yes. Peaking facilities are built with the idea of running them maybe 7% a year. Storage is a better option. We can get a lot more use out of it. We can put it in a place where we can take better advantage of the existing transmission infrastructure. It is much more complimentary to all of our long-run goals.
One of the challenges for policymakers is to make sure we are getting the best value. The challenge is to place the right value on some of the other attributes we care about in bid situations. If we want to move toward a lower carbon future and are supporting renewables on the one hand, we need to make sure we are not buying resources on the other hand that crowd out our ability to take energy from renewables. We see this in a number of markets. For example, we are actively bringing wind to Northern Ireland but trying to keep the thermal power plants running for system reliability, with the result that we end up chasing our tail.
It is a challenging policy environment because you want the least-cost asset for this particular use, but you have to look at the bigger picture.
MS. PETERMAN: I agree that all-source solicitations have been helpful, and we have seen more storage bid and procured in such solicitations than we expected.
I want also to acknowledge the role that government plays in financing less proven technologies. California has had public interest energy research for decades. It has had 10 years of experience doing research and development around energy storage. That made me comfortable as a PUC commissioner to say we can set targets as the technologies are there. We are continuing to fund new commercialization of energy storage projects through EPIC, short for an Electric Program Investment Charge. That is the best place for any new technology because those projects are then grandfathered into our storage target.
MR. ALEXANDER: Glen Davis, there are news reports about the declining cost of batteries. This has some parallels to what has happened in solar. Some developers bid low electricity prices into solicitations for power contracts, figuring that by the time their projects had to come on line, solar panels would have fallen enough to make the projects economic. To what extent is this a sensible strategy for batteries?
MR. DAVIS: It is a good analogy. In solar, you had manufacturers giving you their forward cost curves and then it was a question of whether you wanted to go further down compared to what the technology providers were telling you.
MR. ALEXANDER: What has the cost curve looked like over the last few years?
MR. DAVIS: The costs have been falling more rapidly than the manufacturers have been telling us. What we have not yet seen is the effect of the Tesla giga-battery factory on costs. One of the things that drove down the cost of solar panels was everybody driving toward larger and larger factories.
MR. RIVE: The full system cost versus just the cell cost is actually pretty bad right now. You can get a cell for $350 per kilowatt hour of storage, but the full cost of the battery after installation is between $500 and $700. One of the big breakthroughs that has to happen is you have to try to design DC-compatible batteries so that they can use the same inverter as the solar system.
I think we saw that with solar systems as a whole. Panel prices were initially driving the overall cost. Those came down rapidly. The focus has turned since then to the balance-of-system cost. You have to look at the architecture of the storage system. It has to be complete. It has to do what you need it to do on the power grid. It is not just putting a box of batteries somewhere. It has to work to do the jobs that we need it to do at a very reliable level. When we talk about a kilowatt hour, battery guys get very squishy about what a kilowatt hour is. You start to get into things like amp power and c-rates and similar items. We need to simplify it. Useable kilowatt hours, useable kilowatt and a complete system. I totally agree the balance of plant is where we will be chasing gains over the next few years.
MR. DAVIS: One of the things in solar that allowed people to make money off of falling technology and overall system costs is the time between when they committed in a PPA to a price based on current market conditions, and the time when equipment had to be ordered. The lag could have been 18 months to years, depending on whether you were in the permitting process.
That float is less likely to play out with batteries. In some markets, you may have a PPA, and California may be one of them. The utilities do not want delivery until 2018 or 2019, so you have a long enough time frame, but, more often than not, you are talking about a simpler permitting process and a very short construction period. It is not a PPA. It is just a bill of transfer. You may not have the opportunity to harvest as a developer the falling technology cost the way people did it in solar.
MR. ZAHURANCIK: I think what we will find is that we will average our way down. We do not have to worry about every project being the ultimate end point cost. The project cost that we are seeing today is the result of projects that we did years ago and the effort to get the manufacturing and financing com-munities interested in doing something forward.
When we started going to some of these events and talking about this in 2007, 2008 and 2009, we were talking to battery companies that were small and working on novel products, even on the lithium ion side. We started working with A123. A123 had to go through the life cycle of a battery company, which seems to involve bankruptcy at some point. [Laughter.]
Now we are talking about LG, Samsung and Panasonic. These are significant, large sophisticated players who represent the global supply chain.
Part of the reason we have made a leap in cost is we have gone from these early guys to big guys who already have manufacturing scale and even they are talking about moving to the next level of manufacturing scale.
MR. ALEXANDER: Glen Davis, what size storage market do you see in the near term for your own company? Does it have the potential to grow as rapidly as solar has grown?
MR. DAVIS: I do not have hard figures, but my general sense is that the growth path is quite interesting and obviously that is why we are in it. The overall potential is probably not a match for solar. Despite all the growth in solar, it is still only 1% of generating capacity and it still has lots of room to grow. The frequency regulation market in PJM has not been in play for very long and it is already not far from being saturated.
MR. ALEXANDER: Peter Rive, how many batteries are you expecting to add this year to your systems and what growth do you see going forward?
MR. RIVE: We are seeing something like 10-times growth in our battery business year on year; it is crazy, crazy growth. Our goal has always been to deploy a battery with every one of our solar power systems within the next five to 10 years. It our goal to make solar the best energy source — period. And it just isn’t right now. The fact that solar is intermittent and not available at night leaves one saying, “Guys, it is nice, okay, and it offsets a lot of carbon dioxide, but it is not the best source of power.” It is our goal with Tesla to firm up solar with batteries at every single one of our solar power systems when the costs are low enough to do so.
MR. ALEXANDER: We have time for one more question.
MR. MCCREADY: Dan McCready with Double Time Capital. Peter Rive, I am not very familiar with the economics of batteries in a residential or commercial setting, but I thought I heard you say earlier that the cost is $5,000 for a battery and then the offsetting expense reduction may only be $500 over perhaps a decade. I am not sure if that factors in any benefit from the investment tax credit, but how is it with those economics that the business is still growing 10 times year on year?
MR. RIVE: I was talking about the residential application and only time-of-use arbitrage. That is not what I think will be the long-term economic opportunity in batteries. The primary reason why the residential customers are buying the battery is for back-up power. The backup generator market is bigger than the solar power market. Roughly 2 1/2% of Americans have a backup power source. A solar battery has a lot of benefits above and beyond a natural gas co-located generator.