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NOTE FROM THE EDITOR

California’s reputation as a bastion of progressive, climate friendly ideals is well deserved. At 25 GW, its solar fleet is unmatched by any other U.S. state. By 2018, most of its utilities had already met the state’s 2020 renewable portfolio standard. Gov. Jerry Brown then signed SB100, a bill that set new, higher targets. Under this law, 50% of California’s electricity must come from renewables by 2026, rising to 60% by 2030. And by 2045, all of the Golden State’s electricity must come from “carbon-free” resources. 

While this last goal raises questions about the operational life of gas-fired assets in the state, including some that were only recently financed, like NRG Energy’s 500 MW Carlsbad Energy Center outside San Diego (could carbon capture technology have the answer?), it will only encourage developers of solar and battery storage projects, and maybe even offshore wind. 

Battery storage will be sorely needed, thanks to the much-discussed duck curve phenomenon, but it is on its way. It is no surprise that California was the site of a landmark non-recourse financing of battery storage projects in the U.S., Electrodes, in 2017. Whether this serves as a blueprint for future deals remains to be seen, but we will soon find out, as the Californian utilities have been handing out battery storage contracts with abandon.

So far, so good. But just a few months after SB100 was signed into law, Pacific Gas & Electric filed for Chapter 11 protection as it braced itself for massive liabilities stemming from its role in devastating wildfires. This triggered technical defaults across dozens of project finance transactions linked to PG&E through power purchase agreements, and tense conversations between project owners and lenders.

Those project owners, and many financiers, are remarkably sanguine about the long-term prospects of their PG&E contracts, but even so, this unhappy chapter in PG&E’s history may accelerate more fundamental changes to the Californian market that are already taking place. Community choice aggregators are spreading throughout the state and steadily, one by one, obtaining investment grade credit ratings as they position themselves to sign offtake contracts with the next generation of renewable energy projects. 

Clearly, this is a market to watch very closely, and this roundtable discussion offers enlightening insights into the thinking behind some of the people that are going to shape it.

Richard Metcalf

Editor
Power Finance & Risk

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Participants

Cary Vandenberg, Managing Director, Solar Frontier Americas

Jimmy Chuang, Chief Capital Markets Officer, Strata Solar

Shravan Bhat, Reporter, Power Finance & Risk (moderator)

CJ Hummel, Managing Director, Capstone Headwaters

Melinda Baglio, Chief Commercial Officer and General Counsel, CleanCapital


PFR: The main issue hanging over California for a while has been PG&E and its bankruptcy. How will this flow down to lenders who have that exposure?

Jimmy Chuang, Strata Solar: I talk to lenders on a daily basis and while nobody is happy about this event, it is not without precedent. This is not the first time PG&E filed for bankruptcy, so assuming the underlying banking relationship is sound, lenders will work with sponsors to manage the situation. Moreover, lenders have forbearance in place for precisely this scenario, so no one is foreclosing on a sponsor. In certain situations, I have heard lenders asking for additional collateral postings as an additional risk mitigant. When an offtaker files for bankruptcy, the creditors have a few options: they can trap cash, they can put the borrower in default, they can foreclose or they can ask to replace the offtaker, which is, in effect, a new revenue contract. However, you can’t just tear up the existing revenue contract, because the merchant price in California is $50/MWh and PG&E’s average contract is $150/MWh. I have personally done deals in the past at rates of $250/MWh and higher. So, even if you transfer to a merchant revenue stream or contract with a new offtaker, the existing lender is going to lose money on the deal anyway. The best bet for a lender is to preserve the existing contract and wait for PG&E to come out of bankruptcy okay. Don’t foreclose on the asset right now. Just wait it out.

CJ Hummel, Capstone Headwaters: It’s best they co-operate. To put the borrower in default, you can collapse the tax equity structure.

Chuang, Strata: There are just too many big companies involved, like NextEra, ConEdison, Clearway, etc. Warren Buffett owns Topaz—PG&E’s not going down. That’s my view.

Cary Vandenberg, Solar Frontier Americas: Ultimately, the courts are going to decide. I guess it’s ‘wait and see’. I’m with you. I think ultimately they won’t terminate those PPAs but that’s still in play via the courts, whether they allow renegotiation or termination. People are watching that with a lot of curiosity. I think cash traps are the common way people are dealing with this. Moving forward, I think the implications could be that offtakers will have a little more scrutiny from the lenders, but that’s even muted in California, because the traditional offtakers were investor-owned utilities, and that’s now morphed into community choice aggregators. And CCAs don’t have transmission assets, so it’s a different review of the risk. Because the fire risk was around the transmission side of the business.

Melinda Baglio, CleanCapital: A lot of people were talking about it at the beginning of the year. Actually one of my colleagues in particular wrote a really interesting blog post talking about how utilities aren’t as reliable as they used to be. There’s a lot more liability there. This isn’t going to be an isolated incident. We think things like this are going to continue to happen. CleanCapital is in mostly the C&I solar space, so the way we make investments attractive is by bundling assets into large portfolios. We manage currently about 100 MW of assets and we’ve got one small project that has PG&E exposure out of the entire portfolio, so it’s just one little piece of the puzzle. And typically our financing structures are set up a little bit differently because we’ve got these tiny little projects where you can replace a project if you need to. It affects us less because of the diversity of our portfolio than it would, for example, for a utility project that is relying entirely on PG&E.

PFR: Do you think that in some ways this may spur the transition toward C&I solar or CCAs or community solar? 

Baglio, CleanCapital: Yes. I think there are a lot of reasons why people are going to start focussing more on things like CCAs and community solar and C&I and microgrids. There are so many new technologies coming out and this is a huge issue of utility liability, and how much can we rely on utilities going forward, but there’s more than that. There’s energy efficiency, there’s resilience. You know everyone’s really focussed on that, especially as we have more and more climate-driven extreme weather events happening around the country. I think there are a lot of drivers that are going to move people in that direction, and that’s great. I think that’s the future of our energy grid.

Chuang, Strata: This is a natural and positive expansion of the available market. All of a sudden CCAs are getting rated right now and few even realize it. These are creditworthy offtakers with sizeable customer bases. I’m a part of two CCAs now because I live in the Bay Area. It’s so easy, you don’t even know you’re part of one!  

Vandenberg, SFA: So, you’re part of Peninsula Clean Energy, right?

Chuang, Strata: Exactly. People were concerned about how we finance CCA for a couple of years, but now Marin Clean Energy and Peninsula are investment grade at BBB or BBB+, so people are financing this now. Multiple tax equity investors are ready to deploy capital for these deals. At Strata, we work with leading tax equity investors like U.S. Bank, Regions, Wells Fargo and others. Some of them have already invested in CCAs.

Vandenberg, SFA: I think that trend is really important, because the opportunity, at least in California, is CCA-related. And PCE actually achieved a credit rating faster than the original plan I heard about. That’s a really good indicator and shows the pathway for some of these other CCAs to become creditworthy in due course, and then there’s no problem getting lenders and tax equity
comfortable.

Chuang, Strata: Even with PG&E already in bankruptcy, there was no problem getting rated at all.

PFR: Let’s look at the knock on effect from PG&E to the other big California utilities. What do you think is going to happen to Southern California Edison and San Diego Gas & Electric?

Vandenberg, SFA: Well, credit ratings have already come down on some of those entities, so that’s the near-term fall out. Any large utility has some risk of fire. PG&E probably had the most risk because it’s got a lot of remote areas, a lot of highly forested areas and content for burning, but SCE, they’ve got greater density of population. So, when you’re looking at the liability of higher density populations, there’s a possibility there too, although they do have a lot of deserts, which mitigates some of that burning capacity.

PFR: And I guess all of this would depend on the courts now and whether they find the other utilities to have been materially liable. Is that how it works? 

Chuang, Strata: Yes, and that’s where the inverse condemnation starts. And that’s one thing that’s unique to California versus a lot of different states.

Vandenberg, SFA: That’s a long-term solution, if they reduce liability there. Governor Brown was already talking about that at the end of his tenure, and I don’t know where Gavin Newsom’s going to be on this point, but ultimately somebody’s going to have to reduce the liability for these big IOUs because it is significant.

Chuang, Strata: Based on the conversations I have had with my lenders, general consensus is that they are monitoring the situation, but still continuing to finance these projects in California. Banks have obviously stopped financing PG&E for now, but for SCE and SDG&E, they’re okay, since both are still investment grade.

PFR: Do you think ratepayers in California will continue to prop up some of these top-down pushers toward renewables, toward storage? What do you think will happen on that front?

Hummel, Capstone: I suspect, with the reduction and the cost of these energy initiatives, it’s not as impactful to the individual payer. It’s more a case of education to be able to push the initiative through. 

Chuang, Strata: Since PG&E filed for bankruptcy, the retail rates have gone up. The PPA rate for residential was $180/MWh, and it went up to around $250MWh, so it’s almost a windfall for residential loans right now. 

Vandenberg, SFA: Wholesale prices have come down substantially, so that’s the comparison with residential. I think you’re going to have to look at it in the context of traditional versus renewable generation and the conditions that these segments operate within and the influence on pricing. Renewables are driving lower and lower prices and have been a real success story. And then you look at political will. SB100 was passed recently, so now there’s a lot of things that go well beyond the federal programs in California that continue to get support in the state. CCAs are a good example. They have programs where residential offtakers can get 75% clean energy or even 100% clean energy and there’s a significant portion that are opting in for the 100%. I think that just underscores the dynamics in the California market. 

PFR: Although the ITC and PTC are set to be phased down, there are still calls to have those extended. Other folks say, no, we’ve managed to bring down the cost and we don’t need these anymore. Do you think we need them still, or for newer technologies?

Hummel, Capstone: Incentives are critical for newer technologies. Lenders don’t fund first time units—that’s an equity bet. Equity needs incentives to fund new technologies to help mitigate the risk profile of the project. Historically, tax incentives are renewed, which naturally creates the boom and bust in the development cycle.

Chuang, Strata: I’ve been transacting in this space for over 13 years and the ITC never dies. It was set to expire in 2008, 2016 and now 2021. There was the cash grant, subsequently it was extended and safe harbored again. However, the ITC uncertainty does make equipment procurement much more challenging. 

PFR: Which technologies do you think need it still? 

Chuang, Strata: I think storage can use ITC. 

Baglio, CleanCapital: Yes, I agree with that sentiment. I think a lot of folks still don’t really understand how we can utilize storage to benefit the individual customers and the grid, so there’s a lot of learning to do. And because of that, lenders may be skittish without the technology having enough of a proven track record. 

Hummel, Capstone: There are a lot of viable technologies out there. When you think about biomass, for example, there were approximately 40 biomass facilities in California and today there’s maybe 22 that are operating. These are baseload facilities ranging from 12 MW to 50 MW given the fuel shed that they pull from, ranging from a 50 mile to 125 mile radius, which is inefficient. In contrast, we see several developers with viable technologies for smaller modular-build 5 MW units that are close to the fuel source. To support investment for these smaller units utilizing new technology or processes, tax incentives are required to offset the risk profile. I think it’s two things. One, they don’t like that fuel supply risk—both volume and price volatility. On wind, you don’t have the credit risk of wind blowing. You do on the fuel supply side. And a lot of people for tax planning purposes, they know a year, two years, three years in advance what their tax appetite is. The PTC is a much longer bet. I think the only way you help prop that is through the
ITC.

PFR: You mentioned, Cary, about getting into CCAs. In your conversations in the last couple of years, how have you gotten lenders comfortable with financing projects that are on CCAs? 

Vandenberg, SFA: Marin really started the trend. I think creditworthiness has been the biggest development in terms of the financial community getting comfortable with CCAs. It’s reflected in what we’ve seen with PPA lengths. Originally it was 25-year PPAs, 20-year PPAs; now 15 is pretty typical, going to 12. So, it’s the same sort of evolution of comfort with the financial community and, let’s face it, there’s a lot of capital out there looking for a home. They’ve got that incentive as well to be maybe a little bit more open-minded about these opportunities, and if you want to do something in California, there aren’t a lot of choices. You’ve got some municipalities maybe, and you’ve got CCAs. The IOUs are long and there’s a bit of a premium on the CCAs, but people are getting comfortable with CCAs and unrated CCAs. So 25 bp to 50 bp is maybe what you’re seeing as a premium over a creditworthy muni or IOU. The dynamics of tax equity is that they are still in a pretty strong situation, and they pick and choose, to some degree, the types of projects they like, but they’re getting comfortable with CCAs as well. 

Hummel, Capstone: The reduction in the term of the PPA generally reduces the amount of leverage a project can support as merchant risk is an equity bet. 

Chuang, Strata: Debt might price in for the merchant tail, but they will sweep and refi before that happens… 

Vandenberg, SFA: …with the right developer, with the right sponsor… 

Chuang, Strata: …precisely. Lenders will give you five- to 10-year tenors on the merchant tail. So if it’s a 15-year PPA, some banks will provide up to 25 years of debt, but they will make sure the sponsor can refi at year six or seven, and if the sponsor couldn’t refi, the banks will sweep cash and make sure they can be paid out in a P99 case. But financial institutions have been financing community solar projects since around 2013, and both debt and tax equity have been using similar structures. CCAs were harder at first because they were not rated, but now more and more CCAs are investment grade, so they will definitely get financed. There are a lot of new CCAs coming up now, just in the process of getting rated, but they can still get financed from the banks and investors because they know CCAs are likely going to get rated. Additionally, banks have also figured out a downside scenario if the CCA, ultimately, is not rated.

PFR: Who do you think will be the next CCAs to get rated? 

Chuang, Strata: There are quite a few in California, like Apple Valley Choice Energy... 

Vandenberg, SFA: You’ve got Silicon Valley Clean Energy… there’s a lot of them. 

PFR: Sonoma Clean Power is another name that we keep hearing about. 

Vandenberg, SFA: They’ve been around for a while and I think they would be on the fast track to that. 

PFR: Is there not a risk that if wholesale power gets cheaper, then the customers may actually pull out? What are the downside risks? 

Vandenberg, SFA: I think the biggest risk they face is opt-out rate, but that has just not proven to be the case in terms of the track record they have. They’re pretty stable on that. But that would get the financial community concerned, and there are covenants around some of that stuff. But banks also want to look at the size of the CCA and some of the demographics and the revenue projections, margin projections, and there’s enough history out there in CCAs that there are some good proxies, and I think that’s
helping everybody get comfortable. 

Chuang, Strata: For a customer to opt out, they actually have to take some action. It is not a process many people contemplate. Plus, lenders have effectively structured around this. For example, if 10% opt out, lenders will start sweeping cash until the debt is properly resized. 

Vandenberg, SFA: It’s a macro risk. I think that’s what they look at. 

Hummel, Capstone: Lenders size and structure the debt under a base case scenario along with downside protection provisions. 

PFR: Are we seeing a trend towards splitting the offtake between multiple offtakers as a way to mitigate against the single utility offtake risk that PG&E has highlighted?

Vandenberg, SFA: Absolutely. In utility-scale, you’ve got to go big, and to get to the scale and the prices to win the PPAs, you really need to go for larger projects. Now, all the off-takers don’t necessarily have the capacity to take one chunk, so there’s an advantage to having multiple bites of the apple on these projects. We’ve got a project that we’re building right now that’s a two-party PPA. One’s a muni and one’s a CCA. We’re right in the middle of this as we speak. And I think it’s a very good strategy that is relevant in California as well as other utility-scale, markets. 

PFR: Is it hard to negotiate with two offtakers because they may want different things? 

Vandenberg, SFA: Well, the PPAs stand on their own, and you have to negotiate those PPAs and you try to get them as standard as possible. But we’ve got an experienced group that understands what’s a financeable PPA. So as long as you’re staying within those parameters, then it’s just part of the due diligence for the financial structuring, but we’re pretty good at doing that. We think that it’s a good strategy. I think it’s a good strategy for developers and it’s a good strategy for the offtakers—maybe the offtaker doesn’t want to do all of their capacity with one developer, maybe they want to diversify their portfolio, and it also enables developers to have a mixed portfolio of PPAs and again, to really allow bigger projects to be developed and deployed. 

Chuang, Strata: And you see many corporate PPAs getting done right now—at Strata we have recently been awarded with several. One of the publicly announced PPAs was with Facebook, which we are very excited about. We are bidding to power data centres, we are doing virtual metering, and we are selling power at different locations. But there are ways to economically finance all of these efforts, and it’s not as if you have one triple-A investment grade customer, the other one is BBB+, then your lender will price them differently. That is not how they think about this. Lenders want to give your project an investment grade rating and that’s how they price the deal. But, having said that, if your portfolio base is 80% investment grade, banks might give you a carve out to allow you to sell up to 20% to non-rated entities, which can provide some portfolio diversification and is really helpful for C&I and smaller utility-scale projects. 

PFR: Have solar PPA prices bottomed out? Project finance bankers like to say it can’t get any lower—what do you see happening?

Chuang, Strata: On the utility-scale side, the PPA price is still going down. I have seen contracts at or below $20/MWh. Sponsors are financing those projects now. Some developers are signing five-year PPAs, which in my opinion can be very challenging and risky.

PFR: Let’s move onto storage and peakers. SCE cancelled the Puente gas-fired plant and held a request for proposals for storage instead, which Strata won. Is this the end of new gas-fired generation in California?

Chuang, Strata: I think this is the beginning of the end for some of the gas-fired generation, and we are seeing a lot of storage opportunities right now in California. Our Saticoy deal is 100 MW with 400 MWh—it’s the largest stand-alone storage project to date and we’re very excited about it. But we’ve got multiple projects like this in our development pipeline in California and neighboring states that are even larger. 

PFR: Natural gas is still cheap, however, and it’s still dispatchable. People know how to build it and like financing it… 

Vandenberg, SFA: SB100, at some point, is going to have its impact on that. You know, gas right now is very important for the grid. It gives balance. It gives reliability. It gives a number of things that are very important for us, so it’s there for quite a while. But when we have to go to 100% carbon free by 2045, the long-term trend is there. So at some point, you bump up against that in terms of timing. Do you really want to do a new project that’s maybe got a pay-back time of 20, 25 years? That becomes challenging. 

Hummel, Capstone: Agree, you’re not going to install a 20- or 30-year asset when it legislatively has 15 years of economic life without the contracted ability to recover capital and return well within that timeframe. 

Vandenberg, SFA: Precisely. At some point it becomes a self-fulfilling prophecy. But it really depends on the BESS [battery energy storage systems] market, in terms of the timing there. If storage continues to go down and the systems work well… I mean, we’re still in the early days of storage but early indications are good. There’s been a couple of hiccups with some fires in Arizona and, going way back, Hawaii. So the lithium technology does have some risks there, but it’s a solid technology and the price curve is moving in the right direction. We’ll have to wait and see how quickly that impacts the gas market. But it’s a challenge to develop gas peakers in California right now. If you’re going to do that, there’s probably states and markets that are better suited. 

Chuang, Strata: I don’t see any new gas-fired generation in California but, for existing plants, as they try to retire, maybe they can partner with developers to construct storage on the existing site. I have been involved in some discussions on how to do that recently. 

PFR: Because you have the site, you have the interconnection? How much space would a 120 MW battery take up? 

Chuang, Strata: It’s not that big—probably six to eight times the size of this room. 

Hummel, Capstone: And where do you think that install cost is going? 

Chuang, Strata: It’s going lower. So, depending on what type of technology you use, for any 100 MW/400 MWh storage project, the cost is generally between $100 million and $150 million, and the return’s so much better than solar. A 100 MW battery in California probably costs about the same to build as 100 MW solar, but you have much more cash flow. Unlike solar projects, merchant is the real opportunity for storage projects. 

PFR: There are folks out there that have equity to go and buy storage assets. What are they looking for? 

Baglio, CleanCapital: I would say it’s very similar to what we look for with solar. We want to make sure there’s contracted revenue to meet our returns and maybe a little bit extra. The other thing is, because it’s relatively new and because no one really has a track record yet, there are really just a couple of players in the industry that do have more visibility and experience. It’s not as robust as, for example, the solar industry, where you’ve got tons of well-known and top-rated manufacturers and developers. 

Hummel, Capstone: We worked on a bid for the Xcel RFP doing a combined solar battery project. For us to get comfortable on our bid, we had to structure a sale leaseback with the OEM on the battery side; otherwise, you just don’t have that visibility on the replacement and maintenance cost they were taking. 

Chuang, Strata: There’s just so much money out there chasing good assets right now. Almost every single infrastructure and pension fund is interested in stand-alone storage. Solar will need storage but storage on a stand-alone basis will be fine, and the investor who will pay the best price is someone who understands the merchant market and how to monetize that market. Storage is not like solar. You can have half contracted revenues, which is great, but you can generate the remaining half of your revenues in California where you can benefit from merchant pricing. We can sign a 20-year resource adequacy contract with a utility and simultaneously work with a different utility to hedge power output for another ten years. You can trade that day-ahead pricing in California. So, the best equity buyers are those who understand how to trade in the merchant market, because there is much more of a merchant component to stand-alone storage and the merchant price in California is looking very attractive right now. Whoever can value the merchant will be the most suited buyer. 

Vandenberg, SFA: If you have a trading desk and a buyer, that’s a good combo. But I mean, in terms of financing, particularly with  solar-plus-storage, you’re getting the same sort of rates you’re getting on storage. It’s a robust market and it’s going to grow. I don’t see the financing inhibiting that growth. 

PFR: Not so long ago, there was a solar-plus-storage project finance deal where the lenders gave zero credit to the storage revenues. Has that changed now, or are they giving credit to the storage revenues, and if so, how? 

Hummel, Capstone: Well, if it’s contracted, it’s just like solar. That’s the core. 

Chuang, Strata: Lenders are actually getting more comfortable on merchant now. 

PFR: What is price talk for debt for, say, contracted storage? Let’s say you have a 10-year capacity contract. 

Chuang, Strata: Even for a 20-year resource adequacy contract, lenders will definitely match the 20-year term. Banks will price it like solar. It’s not too difficult now. You can get bank financing between 125 bp and 175 bp [over Libor], depending on how they size the contracted and merchant revenues. And banks will place great value on the merchant tail as well, but then the spread and coverage ratio may vary. 

Vandenberg, SFA: And how far are you seeing them go the merchant? Three to five years? 

Chuang, Strata: Yes. Lenders will add five years of merchant onto a 20-year contract, even for storage. 

PFR: And is there a multiple that investors are looking at for how to value storage on a price to earnings ratio or is it still too early for that? 

Hummel, Capstone: From a valuation perspective, the proper methodology for a project is the discounted cash flow method, while the proper methodology for a technology developed by a company is a multiple. Did you guys see, when you think about peak shaving versus storage, very different technologies and employments? Do you see a lot of movement on peak shaving? 

Chuang, Strata: We are starting to see some opportunities with munis and co-ops, where we can help them with load management and peak shaving by deploying batteries. A battery can be dispatched just like diesel, but it is faster and more versatile. 

Vandenberg, SFA: The majority of storage application we see is just load shifting. The four hours to offset the duck curve in the evening and it’s a one-to-one ratio. So, it’s a significant amount, and that’s contracted. When you get into the ancillary services, that’s upside. I don’t think you’re going to get much credit for the financial structuring of the project. That’s going to be more on the sponsor. 

PFR: What are the barriers to developers of storage assets in California right now? 

Vandenberg, SFA: Well, the supply chain does have some issues in it. There’s a lot of demand, certainly in Korea, in getting access to the technologies there, which are good technologies. That’s impacting deliveries and has to be considered in the risk profile. I think EPCs are learning how to build this and deploy it. The tier-ones are getting into large projects now. They’re still in the early stages and they will bring a level of competency that we certainly rely on to some degree to get it built properly. We typically do construction management, and we’ve got internal expertise on the technology side. But there’s a learning path that’s ongoing right now on deploying these systems. There’s even trade-offs on these larger sites, whether you do the containers or you do a building. Things like that. Those are lessons to be learned, and there may be a critical point where, at a certain size, it makes sense to have the infrastructure housed within a building. These are things that are coming to bear, in terms of rubber meeting the road. 

Chuang, Strata: It’s exciting, a lot of the big EPC companies are coming in. We have had some large EPC companies bidding to build our various storage projects. I definitely think it’s a good learning experience. We’ll spend top dollar to do this, because everything’s so new. We don’t want to make any mistakes. I’d rather overpay for the best technology and hire the most qualified EPC to make sure we build it right. 

Vandenberg, SFA: And remember it’s a system— there’s integration associated with the software and the cooling infrastructure, and
all that has to be designed right and operated correctly. 

Hummel, Capstone: And are you getting a fully wrapped EPC? 

Chuang, Strata: Yes, that will be ideal if we want to finance this. We are talking to a lot of different system integrators who will do a
full wrap as well as certain technology providers that will wrap performance. 

Hummel, Capstone: And the OEMs are stepping up to the necessary liquidated damages? 

Chuang, Strata: Yes, definitely. 

Vandenberg, SFA: Warranties are an issue you really have to be careful of. You get different types of warranties…

Hummel, Capstone: Are you able to get a long-term service agreement? 

Chuang, Strata: So, we have warranties that match the PPA term to begin with, but because storage degrades much faster than solar, we are having to factor augmentation costs into our operating expenses and we will add more storage to the project over time. 

Hummel, Capstone: What is that degradation curve? 

Vandenberg, SFA: After ten years it gets pretty significant. 

Chuang, Strata: I think 20% in 10 years. 

Vandenberg, SFA: Something like that. So, you’re looking at a full replacement within a 20-year asset. 

Chuang, Strata: Probably 40% to 50% of that. 

Vandenberg, SFA: Just the battery module—however you define that. 

Chuang, Strata: That’s right. So you want to make sure you build that into the O&M expense budget. It’s almost like replacing an inverter, but we actually schedule the augmentation of additional storage as an offset. Every year you add more storage, in a way. 

Baglio, CleanCapital: CleanCapital is not a developer of storage projects, but we do work with our existing customer base to optimize  our projects in different ways. Some folks want more panels, some folks want to extend their PPAs, they want to refurbish. But a lot of folks want storage now added to their system. The problem is that they don’t really understand how it works—our customers are a very diverse group. Those of us in this room who have been talking about it for a long time, I think we kind of get it. And we’re at a point now where we understand how it works and how it integrates into a solar system, but for a lot of our offtakers, there’s an education process. They want it, they like the idea of it, but it’s a little bit tough to get them to understand what it’s going to look like and how it’s going to work. That’s one of the struggles that we run into on our optimization team. 

Vandenberg, SFA: Have you considered doing a service to them and running the batteries? Because there’s great opportunity at C&I from a demand charge perspective.

Baglio, CleanCapital: They move slowly and it takes a little while, but we’re very engaged with our customers. We pride ourselves on that. For example, we’re putting together a webinar to help boil it down for them. Hopefully they’ll attend! 

Chuang, Strata: C&I solar-plus-storage definitely makes sense. Even residential storage makes sense. Previously it was too expensive. Back in 2013, when I was with SolarCity, we were selling batteries together with solar, but only for very limited states. Since then, storage cost has come down a lot, so it is much more viable for many addressable markets. 

PFR: What is one thing that comes to mind that can be done to bring banks in to lend to storage? 

Hummel, Capstone: It’s the modularization and the warranty support of that deployment, so you can scale. I think that those would be the two key points, but warranty has got to be the big one today. 

PFR: Putting a large corporate balance sheet behind those technology warranties? 

Chuang, Strata: Yes that’s definitely a given for right now, for anything bigger than 20 MW at least. And on the policy side, having the ITC apply to stand-alone storage will supercharge the growth of the industry. It would definitely help things scale faster. However, I think the OEM loan guarantee might not be as helpful. 

PFR: Do you really want to deal with tax equity again? 

Chuang, Strata: Do I want to? Well, definitely. For 30% ITC? Absolutely! 

Vandenberg, SFA: He’s dealing with them anyway! 

Chuang, Strata: It will be a game changer. 

PFR: Let’s talk about residential solar. We see two or three residential solar securitizations every year, but they tend to be for only a couple of hundred megawatts. Do you see that continuing on for the near to mid-term or will we see larger volumes? 

Chuang, Strata: Yes. l had the opportunity to work on the industry’s first residential securitization and the reason we did it back in 2013 was because we wanted to make sure investors understood residential is an investment grade asset, just like a diversified investment grade utility-scale project. Back then, this really wasn’t necessarily the cheapest or most efficient option. It took a year to get rated, more than a year actually, because it was so new, but it established a conduit for investors. Since then, I think securitization has become a pretty easy, established process. The reason you might not see a lot more securitizations is because customers are signing fewer PPAs and leases. SolarCity has also scaled back significantly. And customers want to own the solar systems more than financing through a PPA or a lease. Loan products now are predominating. Overall, I think the residential market’s growing rapidly. Residential customers still want solar. But you might see less securitization because companies finance them in very different ways than before. 

Vandenberg, SFA: That’s not our area of focus, but it seems that there’s two elements that are going to drive demand. New houses are going to have solar. In California, that’s now regulated. And then, I think, through lower FICO scores, they are going to figure out a way to finance 5 million new households. A lot of other industries have already done that—automotives, appliances— they’ll figure that out. And I think that will be another set of juice to grow the market in California and other locations as well. 

PFR: We haven’t really spoken about wind because it’s California and there’s so much solar. But an interesting development has been happening off the coast of Northern California, with floating offshore wind. Is this feasible? 

Chuang, Strata: There’s lower hanging fruit. 

Hummel, Capstone: You need to go through a lease procurement process with the Bureau of Ocean Energy Management. You’ve got have incentives to build coastal plants with access to transmission. 

Chuang, Strata: And California’s not the easiest place to do all that. 

Vandenberg, SFA: There are wildlife concerns over protected areas. It looks like a great way to spend a lot of money. 

PFR: A theme across the U.S. is closures of nuclear and gas- and coal-fired plants. Do you think we’ll see more of these in California? Are there one or two in the near term that you think open up a large pocket of supply? 

Vandenberg, SFA: I think we already talked about the gas plants, and they may wind down some nuclear plants in California. I think the trend will continue along lines of SB100, that we hit on before. Solar-plus-storage, the combo, is going be the lion’s share of replacement there. And everything I’ve seen, from CPUC [California Public Utility Commission] data to consultant data and all the material we have access to, all those models— even when you look at the IRPs of the utilities—the dominant portion is solar and storage. 

PFR: But storage is going to need to grow massively to fill that gap. There’s a nuclear plant, Diablo Canyon, in California, it’s huge. It’s great that we have 100 MW storage projects, but some of these nukes are gigantic. 

Vandenberg, SFA: Well, you’ve got to consider all the industries that are driving this. E.V.s not the least. You’ve got consumer electronics—we’ve all got batteries in our phones. Then the electricity market is a large one, too, and I think the combination of that is going to continue to drive capacity and prices down. Those are all intertwined. 

Chuang, Strata: I feel storage is almost like solar back in 2008 or 2009, when we were building the largest solar project in the U.S. It was just a 14 MW project, but we needed five module manufacturers to supply 14 MW! Most of these module suppliers aren’t even in business any more. But once we figured out the first big project, then 20 MW and 250 MW, 500 MW, the solar industry scaled up really rapidly after that. In my opinion, storage will grow in a similar way. Once we complete a few smaller projects successfully, I think companies like Strata operating in California and other regulated and competitive markets can really accelerate the growth of the industry. 

Vandenberg, SFA: Yes, I agree. On storage, I think the one difference between solar and storage is the dramatic decrease in the supply chain on the P.V. side, I don’t think it’s going to be duplicated in storage. I think it’s going to be a more modest decline. So we have to be patient and we’re not going to get that downward hockey stick that we saw in solar. These technologies have been out
there for 20, 30, 40, 50 years. 

Hummel, Capstone: You don’t think the install cost is going to come down drastically? 

Vandenberg, SFA: There have been improvements in that, but when you look at P.V., just the sheer module prices, between the efficiencies and the manufacturing optimizations they’ve made and the scale, really had dramatic price degradation. We’ve all been in the market for a while, and I don’t think any of us got on the whiteboard and predicted how far, how rapidly it would drop. And I think here’s a little bit of different dynamics with batteries and the chemistry and the way you decrease the costs. It will decrease but just not at the rates we’ve seen.

PFR: Lastly: transmission lines. Can these in California actually get permitted? And if so, how will they be financed? 

Vandenberg, SFA: Transmission lines, in a more local manner, we deal with that all the time as developers. Of course, part of a successful project and an unsuccessful project is your network upgrades and the costs that are associated with the transmission lines. And so developers get hit with those, the generators get hit with those costs. And that investment will continue and that level
of transmission upgrade will forge ahead. We’re working on projects right now where PG&E is the transmission provider and they’re continuing to build out and are being given direction to keep on schedule. So, that looks like it’s working as usual. You can look at some historic projects, like the Sunrise transmission from SDG&E to Imperial County and those are unique things. 

PFR: In Texas, one of the key issues around the build-out of wind in the panhandle is congestion in the transmission system. Is this an issue in California, or, because solar can be done locally, can you build solar near your load so that transmission and the basis risk is not that great? 

Vandenberg, SFA: There’s clearly a need for more transmission. There are a number of locations in California where there’s congestion which are prime places to build and develop. The greater Fresno area is pretty impacted right now. Some of the desert communities outside of L.A., there’s congestion there. It would be helpful for to build additional transmission infrastructure in these types of areas. But the system seems to be working reasonably well currently and I think it will continue. I don’t think we’re going to see a major disruption. And then ERCOT is a totally different situation.


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