Financing Utility-Scale Solar Projects
The following is an edited transcript from a roundtable discussion that took place at the Solar Power International 2010 convention in October in Los Angeles among three developers and three financiers about the financing terms on offer for US utility-scale solar projects in the debt and tax equity markets and the challenges developers face in financing such projects. The developers are Fred Vaske, vice president for project finance with Recurrent Energy, Steve Holman, senior vice president and general counsel of Fotowatio Renewable Ventures, and Jack Jenkins-Stark, chief financial officer of BrightSource Energy. The financiers are John Eber, managing director and head of energy investments for JPMorgan Capital Corporation, Gisela Kroess, director of power and environmental global project finance in the New York office UniCredit Bank, and Gavin Danaher, managing director of John Hancock Financial Services. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: Fred Vaske, you have been in the market seeking financing for photovoltaic projects. How would you characterize the current market?
MR. VASKE: For projects in the five- to 25-megawatt range and aggregated projects up to 50 megawatts, the financial market is active with many interested lenders. We are not seeing any stress for well-structured projects.
MR. HOLMAN: I agree. For good projects, the money is still there. There is a lot of interest. Things are better than they were a year or two ago.
MR. MARTIN: John Eber, you told me before the session that you are prepared to provide tax equity to utility-scale projects, but you are not seeing a lot of projects that are far enough along to justify taking a close look.
MR. EBER: There are only a few that are far enough along for serious review at this stage, but there are a lot coming. The challenge for some of the larger projects that use newer technologies will be their size, the fact that they are using unproven technologies and how long an advance commitment of tax equity the projects require. Fortunately, most of what we see in the pipeline is more manageable in size, involves proven technology and does not require a two- to three-year advance commitment. MR. MARTIN: How would characterize the tax equity market at the moment?
MR. EBER: It has recovered from the problems that it had at the end of 2008 and early 2009 and is getting better every day. The recovery is largely due to the Treasury cash grants.
MR. MARTIN: Gisela Kroess, how would you characterize the debt market?
MS. KROESS: Much better than it was a year ago. We have seen a lot of volume this year in terms of transactions—both in wind and solar. A lot of the volume has been spurred by the Treasury cash grants and the need to meet the deadline to start construction by the end of this year.
MR. MARTIN: We have heard from bankers that they are open for business, but they are not seeing the hectic activity this fall that they might have seen in past years when the economy was healthy.
MS. KROESS: There is uncertainty about the political and regulatory environment going forward, but I disagree. We have been very busy recently closing our first US solar financing—a 45-megawatt PV financing of about $210 million in total. We continue to be busy. There are about 30 banks that are active in the market right now, so you have a fair amount of competition among lenders.
Thin Film Versus Crystalline
MR. MARTIN: Gavin Danaher, as an insurance company, you tend to lend longer term than the banks. How do you view thin film versus crystalline in terms of risk and willingness to lend?
MR. DANAHER: We have financed crystalline four times, including two of the three of the largest projects in the US. We made proposals to finance thin film, so we are also open to that. However, the issue with thin film is whether it makes sense to finance such a project in the institutional market. The main attraction of the institutional market is one can borrow for longer terms. We are not prepared to lend longer than 15 to 20 years to a thin film project while the debt tenor for crystalline is 20 to 25 years.
MR. MARTIN: The problem with thin film is that you just don’t think it will last as long as crystalline panels?
MR. DANAHER: Yes. It is a proven technology, but we do not have the long-term data that we do for crystalline.
MR. MARTIN: Fred Vaske, Recurrent is a PV company. Do you use both thin film and crystalline?
MR. VASKE: We look at both. The differentiating factor when I go out to discuss financing is much more who is the manufacturer and whether the manufacturer is perceived as being in the top tier. Both products can be financed. I agree that use of thin film limits how far out the debt can go.
MR. MARTIN: Gisela Kroess, you just heard from Gavin Danaher that the institutional market is offering 20- to 25-year debt for crystalline projects and 15 to 20 years for thin film. What about the bank market? MS. KROESS: The bank market is obviously a little more limited as far as tenor is concerned. The PV project on which we just closed the financing recently was a thin film project. We basically provided a construction financing and 15-year term loan. The construction financing included a bridge to the Treasury cash grant. In Europe, I know we have done PV financings up to 18 years, but I think it is difficult in the US to get beyond 15 years at this point. You might for a smaller facility with the right sponsor, but if you need a club of banks, I think 15 years is probably the limit.
MR. MARTIN: Are there other issues with thin film besides a suspicion that it will not last as long as crystalline?
MS. KROESS: You have to structure around the inverter risk. Make sure that you either have a reserve or extended warranties to cover that risk. The inverters typically last only about 10 years, so at least some portion of them will have to be replaced after 10 years. If do a 15-year financing, then you need to take that into account.
MR. DANAHER: You have that risk with crystalline as well.
MR. KROESS: Yes, that is a general risk that applies both to thin film and crystalline, but there is less operating history with thin film. You need the right manufacturer, the right credit quality behind the manufacturer and a high-quality warranty that guarantees you a certain amount of degradation, and you model that accordingly.
MR. MARTIN: How rapidly does thin film degrade per year?
MS. KROESS: There is a limited amount of data available. If you want to be conservative, you assume 0.8% a year.
MR. DANAHER: These panels either just stop working or they work. At some point, you might have to start replacing them. There isn’t enough operating data to know when that point will be reached. We have been modeling 0.75% annual degradation for crystalline.
MR. MARTIN: To what extent do you worry about the rate of technological change? You are lending money. The loan is secured by assets that may be outmoded within five years.
MR. HOLMAN: It is not a concern because we are borrowing against contracted revenues. We have a contract with a utility or customer that runs 20 years or longer. There will always be something faster, more efficient and better down the road, but it will not affect your project as long as the project is performing. This is no different than in the thermal power sector where there are also technological improvements over time.
MS. KROESS: I agree. We basically lend against contracted cash flow and, as long as the project performs as required under the power contract, we trust the warranty and the quality behind the warranty. One big advantage of a solar plant compared to a wind farm is the modular nature of the solar plant where you can easily replace inverters and modules that stop performing.
MR. DANAHER: I have a question for the developers on the panel about crystalline versus thin film. Do the requests for proposals from utilities and other offtakers distinguish between the two technologies? Clearly, thin film is a cheaper product. Can you still play in crystalline and compete with thin film?
MR. VASKE: I don’t think the RFPs are necessarily driving one technology or the other. It is true that thin film is cheaper by some measures. Weighing against it are technology risks and production efficiency. We take a serious look at thin film, we evaluate it and Recurrent Energy’s view could change in the future, but at the moment we favor crystalline from a financing and technology standpoint. At the end of the day, we know it is financeable, so we lean toward it all other things being equal.
MR. HOLMAN: I agree. I am not aware of any RFP in which we have participated that stated a preference for one versus the other. Our analysis is that crystalline absolutely can compete on price terms and, in many cases, it outperforms thin film from an economic perspective. Crystalline also has some additional advantages, depending on the location. Thin film obviously requires more land. If you are constrained on land, crystalline may be a better solution. The insolation of the project site is also a factor.
Financing Solar Thermal
MR. MARTIN: Jack Jenkins-Stark, there are two or three different types of concentrating solar power projects. There are power towers, troughs and what is third?
MR. JENKINS-STARK: The Stirling engine. It is a satellite dish technology.
MR. MARTIN: Does the financial market distinguish among satellite dishes, power tower and troughs in terms of risk and willingness to do a financing?
MR. JENKINS-STARK: The trough technology is either bankable or approaching bankability. There are examples of tower projects that are not quite commercial scale, so the sense we have is that long-term bankability is yet to be proven. We are fortunate in that we have a conditional commitment from the US Department of Energy to provide the debt under the innovative loan guarantee program. We think tower projects will be eminently bankable in another couple years.
MR. MARTIN: Only one CSP project has been financed in the US since 1991, and that was the Nevada One project three years ago that was financed in the tax equity market. John Eber, what type of technology was it?
MR. EBER: It was trough technology, the same technology that was used for the SEGS projects in California in the early 1990s.
MR. MARTIN: Gisela Kroess, will you do trough CSP at this point?
MS. KROESS: We have financed trough projects in Europe, but banks require a creditworthy completion guarantee. I believe the older deals had not only completion guarantees, but also production guarantees for the first one or two years. MR. MARTIN: So you will require a completion guarantee, meaning a construction contractor must provide a “wrap” guaranteeing that all the parts will work together once the project is built?
MS. KROESS: Either a creditworthy wrap from the general contractor or a creditworthy sponsor guarantee. You need support.
MR. MARTIN: Is a production guarantee for the first two years required or are you now confident enough with the technology?
MS. KROESS: In Europe, some trough deals have been done with production guarantees, but there is a debate about whether they are still required. No CSP deals have been financed yet in the US market other than the Nevada One deal.
MR. MARTIN: Jack Jenkins-Stark, you have the Ivanpah project with tower technology in the market currently. You expect to have a DOE loan guarantee. What pushback are you getting from people whom you are approaching for capital? What sort of guarantees do they want?
MR. JENKINS-STARK: The transaction is likely to involve a number of different forms of capital, and a lot of different players. The two obvious primary candidates are debt, which would be both construction and long-term debt from the US government, and then equity. We have found the parties become comfortable with the technology as soon as they engage with independent engineers. We are fortunate in that the founder and the senior engineering team at our company are the same people who built the SEGS projects that were referred to earlier. This is a group of people who are extraordinarily capable. They understand trough. They were the pioneers in trough. They built all the CSP that existed in the United States up until Nevada One. That said, we have worked purposely through a series of steps from building a demonstration facility through working with Bechtel to develop completion guarantee arrangements that we think address the construction wrap risk. With regard to performance, I think we will see the equity and, to a certain extent debt as well in the case of the DOE, demand certain performance guarantees. We are feeling fairly confident that we will get to a successful financing.
MR. MARTIN: John Eber, give me some data about the state of the tax equity market. The last good year for the tax equity market was 2007. How is 2010 compared to 2007?
MR. EBER: We have seen $4.2 or $4.3 billion committed in the first nine months of 2010 in just wind and solar. In 2007, tax equity committed in those two types of projects was around $5.4 billion, so 2010 is off to a good start.
MR. MARTIN: So the tax equity market may turn out as strong in 2010 as 2007 in terms of dollar volume. How many active tax equity investors are there today compared to 2007?
MR. EBER: We count 16 institutional investors who are active. There are probably another half a dozen who are thinking about it and looking at deals. The strength of the market is due to the Treasury cash grants. There are people who are investing today who could not have done a production tax credit or investment credit deal in 2007 and could not do one today.
MR. MARTIN: Gisela Kroess, do you have data for me on the debt market?
MS. KROESS: We have seen tremendous growth this year. Ignoring two bond financings that accounted for about $900 million, bank financings for the year to date are roughly $6 billion. There have been 28 deals. There have been six bank financings of solar projects for a total of about $600 million. The Treasury cash grants are also the catalyst in the debt market since part of the lending is in the form of equity bridge loans against future cash grants. Bank financings in 2009 were only $300 million in total.
MR. EBER: If you break the numbers down in both the tax equity and debt markets between wind and solar, the bounceback is almost entirely in wind. The solar market has been remarkably constant. For the last three years, it has been about $800 million. It dropped a little last year. This year, it looks like it will be the same as last year. Most of the solar financings have been of rooftop and other distributed solar PV systems.
MR. MARTIN: What are current debt service coverage ratios for utility-scale scale solar?
MS. KROESS: We generally size the debt using a 1.0 coverage ratio on P99 output and a 1.35 coverage ratio on P50 output.
MR. MARTIN: That’s for PV. What about the CSP?
MS. KROESS: I don’t have the data for CSP, but I would think the coverage ratio would have to be higher. It would depend on the support.
MR. HOLMAN: I was going to ask what coverage ratio the Department of Energy is requiring, since it seems to be the only one doing the deals.
MR. JENKINS-STARK: I can tell you, Steve, but then you know what I would have to do. [Laughter.]
MR. MARTIN: What about current rates? The last time I checked, rates on bank debt were between 225 and 325 basis points over LIBOR with a 275 up-front fee. Is that still current?
MS. KROESS: We have seen really a wide range this year on pricing, especially in the first half of the year, but the range appears to have settled in the low 200s to low 300s.
MR. MARTIN: LIBOR is currently just under 1%.
MS. KROESS: You can get incredible swap rates right now. Long-term swap rates for 15 years or longer are below 3%. So even if you have a margin of 250 or 275 basis points, the all-in rate is still pretty compelling. You have to distinguish among construction financing only or a combination of construction and term debt or a bridge to the cash grant. Bridge debt would be priced on the lower end. The price for bridge debt depends on your evaluation of construction risk, but it is pretty straight forward for solar PV and most banks that are active feel very comfortable with the cash grant risk.
MR. MARTIN: Gavin Danaher, are the rates the same for institutional market debt?
MR. DANAHER: We price our products off Treasuries, and so with the 10-year Treasury around 2.5% with a credit spread of 300 or 350 basis points at most, you are looking at 5.5% to 6% coupons on long-term financing. That is a low rate in historical terms. It is down from what has been 7% to 7.5% even in the last 12 to 18 months.
MR. MARTIN: Are the spreads somewhat illusory because the base rate—whether it is LIBOR or the 10-year Treasury rate—is subject to a floor?
MR. DANAHER: There is no floor on our coupon. Some institutions do have coupon floors where they can’t participate in the project financing if the rate is less than 6% or under some other level, but ours is just a credit spread on the risk and whatever Treasuries have triggered, so 5.5% is possible.
MR. MARTIN: The maturity in the bank market is 15 years— perhaps 17 years as a maximum tenor. What is it in the institutional debt market?
MS. KROESS: Of the 28 deals done so far this year, really the majority have been in mini- or maxi-perm range of eight, 10 or 12 years. I only counted about six deals that were really 15 years or longer.
MR. DANAHER: I forgot to mention that we don’t charge up-front fees in the institutional market, so if you amortize the up-front fee charged in the bank market over the debt term, the institutional market is becoming more competitive with the bank market. Two or three years ago, we couldn’t compete. The maturities on institutional debt are 20 to 25 years. We do not finance beyond the life of the power purchase agreement. If you have a 25-year PPA, then maybe we would consider a 25-year term, but we have certainly gone to 24 years.
MR. KROESS: Unless you are worried about the make whole, right?
MR. DANAHER: Yes. That’s right, that’s right. [Laughter]
MR. MARTIN: What does that mean? Gisela explain it.
MR. DANAHER: Here we go. [Laughter]
MS. KROESS: Banks loan are made based on a spread above a floating LIBOR rate. If you prepay the remaining balance on the loan at some point, there may be a small breakage fee if the prepayment is made in the middle of the month, but otherwise there is none. Institutional lenders lock in rates for a long period. If the loan is repaid ahead of schedule, then the institutional lender will charge a make whole, which is the difference between what it would have been able to earn under the loan carried to full term at the fixed rate compared to what it will be able to earn by redeploying the funds in the current market. The amount could be considerable.
MR. MARTIN: So there is some significant fine print in the institutional markets deal.
MR. MARTIN: Fred Vaske, Recurrent Energy does PV projects. Are you trying to raise debt or mainly tax equity?
MR. VASKE: We have spent quite a bit of time looking at debt. I agree with everything that has been said so far. Compared to a year ago, the term of the debt has improved markedly, rates have improved, fees have improved. With regard to the debate we just heard, whether Recurrent Energy finds bank or institutional debt more attractive is a function of what type of a deal we have. Which type of debt fits better? Banks are trending toward longer tenors. Fees are coming down. In the case of our San Francisco Sunset Reservoir project, I had a 25-year power purchase agreement. We worked with Prudential and put 24-year debt on that project. It could have gone to 25 years, but we were limited by the warranty on the modules.
MR. MARTIN: So you paid a higher rate for the institutional debt than you would have paid in the bank market, but you got a longer term. That was a better trade off.
MR. VASKE: I think the rate was fairly competitive. It might have been slightly higher, but the higher average life of that debt when you start looking at the levered equity returns is very material. It was a very big improvement for us.
MR. MARTIN: Explain the concept of average life.
MR. VASKE: It is a way of looking at effectively how long you have the use of the money. The average life of our 24-year debt is well into the teens. For bank debt that you might pay back over 15 to 17 years, it is closer to 10 years. The point is I have that less expensive debt money for much longer into the transaction. It allows me to make a much higher return on the equity I have invested in the project.
MR. MARTIN: Jack Jenkins-Stark, how much debt can one raise as a construction loan to finance a project? Is it 50%, 55%, or maybe you are a special case because you have a DOE loan guarantee?
MR. JENKINS-STARK: I think that you would have to put us in a special case. Ivanpah is a $2+ billion project. We are not out in the construction debt market or the term debt market for that project because we expect to borrow through DOE.
MR. MARTIN: What percentage of the cost does the DOE guarantee enable you to borrow?
MR. JENKINS-STARK: That information is confidential. It is fair to say that DOE is willing, as a result of the cash grant, to lend more during construction and that both the construction and term loans will be sized like a bank loan based on some kind of debt service coverage ratio.
MR. MARTIN: Fred Vaske, what percentage of construction costs can you raise in debt as a PV developer?
MR. VASKE: As a general rule for a well-structured project, we can raise close to 50% and, on top of that, during the construction period get nearly a full advance against the expected Treasury cash grant so that we can pull in close to 80% of the project cost.
Treasury Cash Grants
MR. MARTIN: How do lenders handle risk tied to Treasury cash grant. Gisela Kroess, you said that lenders are pretty comfortable with the cash grant.
MS. KROESS: The cash grant has been probably the most successful government program because it’s simple and banks feel very comfortable with the rules. Most banks lend 90% to 95% of the expected cash grant as an equity bridge loan. We have lent up to 100%. We generally lend without sponsor support. We have had up to 85% in construction debt. That’s why the cash grant is so important.
MR. VASKE: Are you seeing any second guessing by the Treasury on the amount of grant claimed?
MS. KROESS: Not really. In the beginning, grants were paid fairly quickly within three weeks. Even now, they take up to two months, which is still fine. We generally have a six-month cushion. Questions are asked sometimes, but we haven not seen more than a 3% deviation from the original budget.
MR. EBER: We have seen deviations. We have done about half a dozen grant deals. If you do it right—if you have all the right kind of experts involved—you will get what you applied for, but we have had situations where Treasury has come back on the 59th day with a page or two of questions and the clock starts running for another 60 days. It was pretty clear that if we were in a big hurry to get the money, we could have settled for something less than we applied for. However, in each case, everybody involved felt that the grant had been properly calculated, so we had to spend time and money going back and answering all the questions. At the end of that next 59 days, the full grant was paid.
MR. MARTIN: The Treasury released a form last week that developers can use to ask Treasury to confirm that their projects got under construction this year. The only projects that qualify for grants after this year are projects that were under construction by December 2010. Do you expect lenders and tax equity investors to make it a condition in the future to funding that the project have gotten confirmation from Treasury that it started construction on time?
MS. KROESS: Projects that close on construction financing as the year draws to a close require more diligence because the lenders have to feel confident that they are under construction in time to qualify for a cash grant. A project must meet either the physical work test or the 5% rule. That can be done. Banks request an auditor to identify the costs that qualify. It is straightforward. I think the biggest discussion may be around what developer fee the lenders are prepared to assume will be counted as basis for the cash grant.
MR. EBER: If there is a form that developers can use to ask Treasury to confirm their projects started construction in time, tax equity investors are going to require it.
DOE Loan Guarantees
MR. MARTIN: Jack Jenkins-Stark, the DOE loan guarantee program has been torture for developers to get commitments and then to negotiate the terms so that they actually get a loan guarantee. I believe at last count only four loan guarantees have been issued and there are 15 commitments. That’s on more than 400 applications. Projects have to be under construction by September 2011 to qualify. Knowing what you do about the process, would you start down this road again?
MR. JENKINS-STARK: If you’ll indulge me I have three points to make. Number one is I want the transcript to properly reflect that BrightSource does not view the DOE loan process as torture. Number two, how many of you in the audience are US taxpayers? I can tell you that you should rest easy. Your funds are being cautiously dispersed by the Department of Energy and you should be pleased with the discipline and the exhaustive and exhausting nature of the due diligence that is being conducted. The third point is that BrightSource is making it much easier for everyone who comes next. And we should get some kind of fee on that. [Laughter]
MR. MARTIN: Gavin Danaher, the so-called FIPP part of the program where the government guarantees repayment of private-sector debt to projects that use commercially-proven technologies—I believe there have been at least five or six applications for guarantees under this part of the program—John Hancock is the lender in a large share of these applications. What has been your experience? Would you go down this path again?
GAVIN DANAHER: Thank you, Jack, for reminding me that this transcript’s being recorded. [Laughter] We were the first firm to have a loan guarantee issued under the FIPP program just a month or two ago, and we have six other applications in. We have probably been the most active institution under that program. We are a small team managing a pretty large portfolio. The process is time consuming. It is not something we are marketing or that we really want to do a lot of. However, if our customers want us to go through that process with them, we are happy to take them through it. It is a process.
MR. MARTIN: I think the window is closed at this point for additional applications, with the exception of loan guarantees for new factories that will manufacture wind turbines, solar panels and other equipment for the green economy. Just to be clear, there are a lot of very capable people at DOE trying very hard to make the program work. Our own people say that their hearts in the right place. They just have a lot of structural impediments that aren’t of their making. In some ways, the comparisons of the Treasury cash grant program, which has worked exceptionally well, and the DOE program are unfair because the Treasury has a program that is built on existing concepts many of which go back 48 years. DOE was trying to set up a program from scratch.
MR. DANAHER: As Jack says, we are hopefully making this process easier for applicants two, three and four. I think the DOE staff has gone from 25 people a year and a half ago to 125 and so, when you think about the process and the credit approvals that are needed, it is one thing to work with us as an institution and get our credit approvals but a very different thing to work through the process a second time with the US government.
MS. KROESS: Gavin, you said you have made six or seven applications. How long does it take to negotiate with DOE?
MR. DANAHER: It’s a six to nine month process. The longest lead-time item is the NEPA review.
MS. KROESS: We had heard it is much longer than six to nine months. I can say, for our institution, that is one of the reasons we have not bothered with the loan guarantees because our clients need to close the financing for their projects within a reasonable time frame. That’s impossible with the DOE at least on the FIPP program. You need a lot of time and patience to go through that process and, from what I’ve heard, the outcome is anything but certain.
MR. JENKINS-STARK: Our loan guarantee is coming through the innovative technologies part of the program. In fairness to DOE, many of the issues in the BrightSource project were probably questions of first impression. Ours is a complicated transaction. We are not only the developer, but an affiliated company is also the manufacturer of a lot of the equipment. In fairness to DOE, we are cutting a lot of ground that the DOE team has not seen before and is deeply concerned that it get right from a programmatic standpoint. At the same time, the process has taken longer than we expected. Tax Equity Terms
MR. MARTIN: Let’s switch to tax equity terms and rates. John Eber, you never let me pin you down on rates so let me tell you what I think are current tax equity yields in the market and you tell me whether you disagree. Yields for wind farms are somewhere between 8% and 8.5% for the least risky projects with well-capitalized developers using established equipment in markets that are not oversaturated and that do not have curtailment risk. Any disagreement?
R. EBER: No. That sounds right.
MR. MARTIN: Are yields headed up or down?
MR. EBER: They have remained pretty stable for the last year and a half. I think they will continue to be.
MR. MARTIN: Solar PV has been the biggest mystery of the tax equity market. The yields for PV used to be roughly the same as for wind, but they seem now to be all over the map. Why is that?
MR. EBER: Most PV projects have been done as single-investor leases with 15- to 20-year terms. At the end of the lease, the developer has to pay the full value of the equipment at that time if he wants to buy it back. It is difficult to compare perceived yields in a single-investor lease to a partnership flip return, which is an identified eight- or 10-year number.
MR. MARTIN: Fred Vaske, what rates have you seen in the market?
MR. VASKE: I am not going to give specifics because the information is a little too close to home, but I think the range you quoted is accurate. Rates are significantly higher than what I saw two years ago. Recurrent Energy is not satisfied with where rates are today. We are looking hard at the single-investor structures and we are also considering levered equity structures. We are glad that JP Morgan and many of the other investors have been in the market. They have carried it. We would like to see more investors come into the market. There is not nearly enough competition.
MR. MARTIN: Steve Holman, what PV tax equity rates are you seeing at Fotowatio?
MR. HOLMAN: We are seeing high single digits with rates in deals with project-level debt 200 basis points or so higher than that.
MR. MARTIN: Does it strike you that PV yields are unnaturally high?
MR. HOLMAN: Absolutely. [Laughter] But ser