Solar finance outlook
A panel of two sponsors, two lenders and one tax equity investor rolled quickly through a wide range of topics of current interest at the Solar Power International 2019 convention this fall in Salt Lake City. The following is an edited transcript.
The panelists are Meghan Schultz, senior vice president for finance and capital markets for Invenergy, David Shipley, chief financial officer of sPower, Andy Redinger, managing director and group head of utility and alternative energy for KeyBanc Capital Markets, Daniel Siegel, vice president for renewable energy business with US Bank, and Chris Diaz, co-CEO of Seminole Financial Services. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Meghan Schultz, what new developments have there been this year in how solar projects are financed?
MS. SCHULTZ: Banks are willing to take into account revenue beyond the term of the power purchase agreement when deciding how much to lend.
MR. MARTIN: How many years of such revenue?
MS. SCHULTZ: Several.
MR. MARTIN: What does "several" mean?
MS. SCHULTZ: Three to five.
MR. MARTIN: Andy Redinger, new trends?
MR. REDINGER: I'll name a few. Rapid growth in residential rooftop, PACE financing for C&I projects and deal-contingent swaps for utility-scale projects.
MR. MARTIN: We will come back to some of that. David Shipley, new trends?
MR. SHIPLEY: Same as what Meghan said. We do utility-scale solar, and we have seen both the banks and the institutional market not so much willing to lend beyond the term of the power contract, but the banks are doing mini-perm loans that mature typically in five or seven years, and the amortization period extends beyond the contract period.
Also, I think we have moved beyond the simple busbar, fixed-price, unit-contingent contracts. We have some level of merchant risk. We have capacity payments that may be contracted for a short period of time. The combination of merchant, capacity and post-PPA revenues are all being taken into account in debt sizing. That has been the biggest change because historically the banks have been at PPA term minus one or two years for the amortization period.
MR. MARTIN: What amortization period is used?
MR. SHIPLEY: It depends. Meghan touched on it. If you have a shorter-term contract in a very liquid market, you may be able to get the lenders to push to five years. An example is a 10-year contract in PJM where you may be able to get the lenders to take into account five years of merchant revenue.
If the project is in a not-so-liquid market and it already has a 20-year contract, the banks are not going to push the amortization period beyond the contract term to 25 years. It also depends on whether there are other factors. What is the credit risk? Is there a capacity market? If you have a super clean deal with a 10-year PPA, getting banks to go to 15 years for amortization is definitely possible.
MR. MARTIN: What percentage of the revenue needs to be contracted?
MR. SHIPLEY: We don't really think of it that way. It is more a matter of looking at the contract term. If the amortization period runs beyond the contract term, it will create a balloon payment, so there is some sensitivity to that.
MR. REDINGER: David is spot on. Financing for renewables projects seems to be moving in the direction of how banks have been financing merchant gas-fired power plants. If KeyBank is going to provide credit to merchant revenue when sizing debt, we think about the size of the balloon at the end of the contract term and the remaining useful life of the project and estimate the number of years it would take to repay our remaining debt balance.
MR. MARTIN: Himanshu Saxena, CEO of Starwood Energy, said at the REFF conference in New York in June that it is not unusual for the equity investor to get back only 30% of its investment by the end of a 10-year PPA term.
MR. REDINGER: That is good the investor is getting even that. It depends on the deal, but if the investor is getting its money back by the end of the contracted period, then the investor is doing well.
MR. MARTIN: Dan Siegel, new trends?
MR. SIEGEL: Not surprisingly, we are fielding a lot of safe-harbor questions currently around start of construction. We are active in all solar markets, but the most recent trend has been in community solar and in batteries tied to solar projects. In utility-scale solar, we are seeing more corporate PPAs and hedges.
MR. MARTIN: So it becoming a much more complicated market. Chris Diaz, new trends?
MR. DIAZ: Dan Siegel stole my thunder, but we focus on projects that are one megawatt to 40 megawatts in size. We are seeing a lot of community solar transactions. We are seeing a lot more storage as well. Also, it is not a new trend, but REAP loans from the US Department of Agriculture are becoming more prevalent.
You were talking earlier about merchants and longer amortization periods. USDA REAP loans are usually for $600,000 to $25 million in amount, and they can be made with 25-year amortization on a 20-year PPA, and then you have a merchant tail of five to 10 years after that.
MR. MARTIN: One of the biggest challenges for solar companies this year has been how to start construction of as many projects as possible for tax purposes so that the projects will qualify for investment tax credits at the full 30% rate. Meghan Schultz, how are you seeing sponsors start construction?
MS. SCHULTZ: There are obviously two ways to start construction. You can acquire equipment and use the 5% test and you can do physical work of a significant nature. The physical work can be onsite at a project or on certain equipment offsite. From what we hear from different sponsors, companies are using a combination of those methods. That is similar to what has been done in the wind industry.
Wind developers were up against the same deadlines starting in 2016, so there is a well-worn path at this point for starting construction. It seems like there has been more noise around solar this year because the pure solar developers may not have had to go through the process of financing projects where the construction-start date is important.
MR. MARTIN: Are you stockpiling equipment to qualify under the 5% test?
MS. SCHULTZ: We are using a combination of strategies. They include buying modules for use in future projects.
MR. MARTIN: Are you also relying on physical work and, if so, what work?
MS. SCHULTZ: Yes. We are buying transformers for some projects and doing onsite work at other projects. In order of preference, if you could start work onsite at all your projects, you would probably do that because it is the lowest cost approach, but many projects lack permits to start work on site. Our approach varies from one project to the next.
MR. MARTIN: In cases where you rely on physical work on site, how much work do you try to do?
MS. SCHULTZ: There is no dollar requirement. There is no certain percentage requirement. In the wind industry, an example in the IRS notices suggested digging 10% of the turbine foundations was enough. That is what a lot of people did because you could point to a specific example. So, turning to solar, we are putting in a similar percentage of inverter piles.
MR. MARTIN: David Shipley, how is sPower starting construction?
MR. SHIPLEY: Same. The projects fall into two buckets for us. We have projects that are expected to be delivered in 2020 or 2021 where we expect to reach notice to proceed with construction on site this year. Those projects will be truly under construction before year end, although the percentage of work completed varies by project. For other near-term projects, we may rely on offsite physical work: something like 20% inverter skids in conjunction with main power transformers. For 2022 and 2023 projects, we are more focused on the 5% test. We are acquiring modules and taking physical delivery at the end of this year or paying for the modules at year end this year and taking physical delivery early next year.
Our reliance on the 5% test happened somewhat naturally. We have a significant pipeline of development assets. Last year, we were very concerned about the tariffs and uncertainty surrounding trade issues. In order to do some hedging, we found that doing three- and four-year purchase agreements gave us some front-end pricing benefit, and so we ended up being a little long on modules in 2019 and early 2020 which gave us safe-harbor equipment.
MR. MARTIN: Dan Siegel, how comfortable is US Bank with relying on physical work?
MR. SIEGEL: Obviously we work closely with our tax counsel. Most questions we are fielding currently are primarily around offsite physical work. Typically these are companies that are thinking long term about how to safe harbor, aren't necessarily comfortable with the the cost to write a 5% check on modules, so they want to figure out a way to have binding contracts with suppliers on things like transformers or centralized inverters. That is where we spend a lot of our time. We see many different fact patterns.
The utility-scale solar developers know what they are doing. We are more concerned about developers in the non-utility sectors, like residential and small C&I, where it is harder to find non-inventory equipment on which to start physical work and where developers may be less careful. We worry about having to analyze this retroactively after the fact.
MR. MARTIN: Do you have a rule of thumb for how much work you want to see done on transformers before year end?
MR. SIEGEL: No. We commonly see radiators being worked on with transformers. I think the real question is whether the contract to buy the transformer is binding. We spend a lot of time thinking about whether the contract is cancellable for a minimum fee. If so, it begins to look like an option rather than a binding contract to buy a transformer.
MR. MARTIN: Come back to tariffs. Are vendors absorbing the tariffs?
MS. SCHULTZ: I think it is a negotiation, but it is not an easy negotiation.
MR. SHIPLEY: Same. The tariffs are affecting not only the cost of solar modules, but also wind turbines and towers because of the tariffs on steel and other components. We try to negotiate protection. I don't think we are able to get direct tariff protection, but I think we have addressed this through other provisions in the documents.
MR. MARTIN: Like what?
MR. SHIPLEY: I'm going to rephrase that. Less contractual and I think more building really strong relationships with suppliers. Instead of spreading the wealth among suppliers, we create partnerships with particular suppliers where, if things do turn, they will work with you to help cover the costs.
MR. MARTIN: Are export credit agencies helping to reduce the cost of stockpiled equipment purchased from foreign vendors?
MS. SCHULTZ: We have not been using export credit agencies for this.
MR. SHIPLEY: Same.
MR. MARTIN: There was talk earlier in the year about inventory loans to help developers stockpile equipment. Have you seen any such loans close? Why are they so hard to close?
MR. SIEGEL: We have seen a couple developers on the smaller end of the market close on equipment loans. Make sure that you are in close contact with your CPAs and attorneys to do the right things, and then document, document, document. Pictures say a lot especially if they are time stamped. You do not want to get into a situation where you think you did the right thing, but it turns out you did not.
MR. DIAZ: We are making such loans, and I think you will see several of them close in the next 60 days. They are complicated. They take longer to put together because all of the pieces you have to think about.
MR. MARTIN: Why are they so complicated?
MR. DIAZ: We have to believe the value in our collateral will be preserved if we have to foreclose. We want to see some additional collateral value beyond just the bare equipment being financed.
MR. MARTIN: How much additional collateral value?
MR. DIAZ: It depends on the situation and the relationship. Sometimes a little, sometimes a lot. Beyond that, it takes time to get your arms around managing the equipment, the logistics of working in the warehouse, transportation, insurance, tracking serial numbers . . . .
MR. MARTIN: All right, you have persuaded us there is a lot to cover.
MS. SCHULTZ: As a developer, you want to save this equipment to use as late as you can. That is in conflict with what the lenders want. They want as much certainty as possible on day one where the equipment will be used. The complication is how to bridge that gap.
MR. MARTIN: Invenergy is pretty well capitalized. Has it been interested in this sort of financing?
MS. SCHULTZ: Yes, we have. We used such a loan in our wind business. I think there were only two others that were done. We will take a similar approach for solar where I think you probably have a handful of such loans.
MR. MARTIN: Have you closed on such a loan yet?
MS. SCHULTZ: We don't normally comment on that.
MR. MARTIN: You said "normally." [Laughter]
MS. SCHULTZ: . . . .
Corporate PPAs and Hedges
MR. MARTIN: Andy Redinger, the market is moving to a corporate PPA and hedge market. How is it affecting financings?
MR. REDINGER: It puts some pressure on the banks, but lenders are finding ways to accommodate the shift.
MR. MARTIN: You said famously at a past conference that banks should be able to get comfortable with less predictable revenue streams. After all, they finance McDonald's based on hamburger sales.
MR. REDINGER: That's correct. Banks regularly provide loans to many corporate clients without requiring the product to have been pre-sold.
MR. MARTIN: So the answer is that the banks are rolling with this. They are getting less and less contracted revenue, but they are figuring out how to make it work.
MR. REDINGER: Correct.
MR. MARTIN: Do the financing terms change as you get to maybe 40% contracted revenue instead of 100%? You have cash sweeps, shorter tenors?
MR. DIAZ: Yes, all of that depending on the percentage of contracted revenue. We are trying to be constructive so we will come up with a structure with bells and whistles. We may size the loan differently. We may have cash sweeps.
MR. MARTIN: Another new trend is developers are installing more and more batteries. SunPower told us that 25% of its projects at this point have batteries in them. Dan Siegel, how does adding a battery affect the financing? You are doing tax equity.
MR. SIEGEL: We have been going through a process of evaluating storage equipment for some time. Like anything else related to a solar plant, you want to make sure that you are using tier-one equipment. We have been watching things like the Arizona Public Service battery fire, for instance, and trying to learn as much as we can.
That said, transactions are less about the equipment and more about the revenue streams. There are different ways to monetize batteries. We need to understand the different potential revenue streams and which are reliable enough to take into account in sizing tax equity and which are still too speculative.
MR. MARTIN: Adding a battery adds to the capital cost of the project. Does the battery bring in enough additional revenue to cover the cost?
MR. SIEGEL: It depends on the market. We have been doing behind-the-meter batteries with our friends at residential solar companies for some time. The SMART program in Massachusetts has battery adders that provide an incentive to add batteries.
MR. MARTIN: David Shipley, does it feel like we are at a tipping point on batteries?
MR. SHIPLEY: It feels like the early days of solar. Our parent company, AES, has done a lot of storage. At sPower, we have not financed storage yet. It will be interesting to see where the independent engineers and appraisers come out on storage in terms of degradation, useful life and everything that feeds into the revenue forecast.
MR. REDINGER: Depending on whether the battery will be used in a bundled PPA with a fixed capacity payment or some form of arbitrage where you are shaping production to improve the pricing, more analysis will be needed into when you are charging and discharging and what prices you can earn from doing that.
MR. MARTIN: What percentage of projects are expected to have batteries this year?
MS. SCHULTZ: I don't have a number for you. Whether batteries will be part of our projects going forward depends on receiving a clear price signal from the market. We have not seen one yet. We are not planning to build merchant storage. We need some revenue stream associated with it.
MR. MARTIN: Invenergy has standalone storage facilities.
MS. SCHULTZ: That's true. We have about 60 megawatts of operating batteries that we put in place in PJM around five years ago. That made sense at the time based on the ancillary market revenue that was available in PJM.
The mechanism in PJM has changed, so we are not considering any other such projects at this time. However, it is public that we signed an agreement with Arizona Public Service to build storage for it more on a build-transfer-type basis.
Tax Equity Terms
MR. MARTIN: Switching gears again, what are current rates for tax equity? I know tax equity investors are reluctant to say them, so let me put something out and see if you disagree with this.
For utility-scale solar, we see 6.25% to 6.8% as the flip yield in partnership flip transactions. For inverted leases, which tend to price as dollars per tax credit, rates are between $1.09 and $1.14. Do those sound right?
MR. SIEGEL: You are in the ballpark. We see some utility-scale transactions where yields have been a little lower.
MR. MARTIN: In which direction are they moving?
MR. SIEGEL: I can only speak for us. We are holding our pricing going forward. It is an interesting market because it is driven by supply and demand.
I think there will be a rush of projects over the next several years as developers try to beat the cliff on expiration of tax credits. That suggests there will be more tax equity demand than supply.
The effects will not be evenly distributed. Developers who have relationships with particular tax equity investors should find the investors are still there for them. There may be challenges in the C&I market which has always been relatively inefficient. That is the market that is most likely to be affected by any scarcity.
MR. SHIPLEY: Tax equity yields turn on supply and demand, but let's not lose sight of the fact that power prices are going down. Project economics are going to be much tighter. Tax equity investors are motivated to get money out the door, so they are not arbitrarily setting yield.
As a sponsor, if I can't make my project work for the cost of capital on offer, the tax equity investors have to react to that. They have. I think that's why we have seen flip yields come down. The point is yields are not solely a function of supply and demand, but other factors also play a role.
MR. MARTIN: So it is a negotiation at the end of the day.
MR. SHIPLEY: Yes, it's a negotiation. When I did my first wind deal, we got the equivalent of LIBOR plus 600 basis points on a pre-tax basis. That is a really good investment given the risk.
MR. MARTIN: What percentage of the typical capital stack for utility-scale solar is tax equity today? 35%?
MS. SCHULTZ: Thirty to 40%.
MR. MARTIN: What percentage is back-levered debt?
MR. DIAZ: Forty to 50%
MR. MARTIN: Andy Redinger, you said at the REFF conference in June that 75 basis points over LIBOR was down the fairway for construction debt and you were seeing 125 over LIBOR for term debt. Still true?
MR. REDINGER: For down-the-middle-of-the-fairway deals, that is still unfortunately true. The frustrating part is that I am typically back-leveraged, have more operating risk, longer tenor with a negotiated standstill and still have a return that is 200 to 300 basis points lower than tax equity. That doesn't make any sense. I contend that tax equity needs to get cheaper.
MR. MARTIN: Dan Siegel, that's smack talk. [Laughter]
MR. SIEGEL: I can only speak for us. US Bank is a little unusual. So we will put out about $1.2 billion in tax equity this year. Half of that will be placed ultimately with syndication partners.
Most of the partners are not financial institutions. They are retail corporates, tech companies and insurance companies. When they look where to put their cash, they look not only at tax equity, but also at stock buybacks or at opening new stores and doing many other things with their money.
MR. MARTIN: So the yield has to be better than the alternatives.
MR. SIEGEL: I think our peak was in 2015. There was a ton of project pull-in from the anticipated expiration of the investment tax credit that year.
MR. MARTIN: Have any of you seen front-levered debt?
MR. REDINGER: Yes. The debt is effectively front-levered in an inverted lease. The tax equity investor is the lessee. The debt has project-level collateral at the lessor level. The lessor owns the project and is the borrower.
MR. MARTIN: The UK authorities will stop tracking LIBOR at the end of 2021. How is the market dealing with this?
MR. REDINGER: Just language about when we move to a new benchmark.
MR. MARTIN: What does the language say?
MR. REDINGER: It says we'll figure it out.
MR. SHIPLEY: He's right. There is language to the effect that we will adapt. It requires a leap of faith. We will probably get into the institutional market, which is not a LIBOR-based market, to refinance our bank deals.
MR. MARTIN: Institutional market meaning fixed rate?
MR. SHIPLEY: Yes, with insurance companies and pension funds as lenders. It is a fixed-rate market tied to treasury yields and locked in for a term.
MR. MARTIN: Europe has $17 trillion in debt with negative interest rates. Trump would like our central bank to follow Europe's lead. How would negative interest rates affect the market?
MR. REDINGER: We rely on deposits to provide financing. If we go to negative interest rates, we are going to lose that deposit base. It will increase the cost of funding.
MR. MARTIN: Increase the cost, even though people are paying you to take their money?
MR. REDINGER: I don't think we will be paid by people to take their money. The deposit base will disappear.
MR. MARTIN: Where will the money go?
MR. REDINGER: It will not sit in our bank. It will go somewhere else. I am pretty certain of that.
MR. SHIPLEY: I can't say that I spend a lot of time thinking about negative interest rates, but my quick reaction is that it will help with equity sell downs. If we can offer a stable dividend, investors will put their money into that rather than a debt instrument paying a negative return.
The other point of view is that negative rates mean that we will devalue our currency. A lot of money that has come into the US has been attracted to the currency. A weakening dollar would make the US a less attractive place to invest.
MR. MARTIN: The inverted yield curve and the spike in overnight borrowing rates last week are giving the market jitters. What will happen to tax equity and debt if the US economy tips next year into a recession? What happens in these markets during a recession?
MR. SHIPLEY: It may have a bigger effect on debt than tax equity. It was 2008 and 2009 when more investors started thinking about getting into tax equity. They were looking for ways to put their money to work in a market where other investments, like real estate, were not looking so good.
MR. MARTIN: People held on to cash in 2008 and 2009, so anyone with cash to offer was in a good position.
MS. SCHULTZ: I think it depends on what causes the recession. In 2009, you had big financial institutions that still had tax capacity. I don't know that that would necessarily be the case in the next recession. Overall, there will probably be less liquidity in the market, leading to a higher cost of capital.
MR. MARTIN: Next question: tax changes are almost certain no matter who wins the national elections in November 2020. How is change-in-tax-law risk playing out in deals?
MR. SIEGEL: We went through this recently. Congress rewrote the corporate tax laws at the end of 2017. There was a lot of brain damage that went into addressing this risk during 2017 when it was clear tax changes were possible.
Frankly, most of the language used in 2017 remains in our tax equity documents.
MR. MARTIN: For how long are you protected?
MR. SIEGEL: That's a good question. We ask typically for protection for a session or two of Congress.
Electricity Basis Risk
MR. MARTIN: One of the big issues currently is electricity basis risk as the market moves from traditional utility PPAs to virtual PPAs with corporations and other forms of hedges. How are sponsors dealing with this risk? How do financiers view it?
MR. SHIPLEY: It is a component of most of our transactions. Now even the utilities that historically were buying electricity at the busbar under physical delivery contracts are now moving toward basis-type contracts where we are settling at the hub. Corporates are also settling at the hub. It has changed our company. It used to be easy for us to do solar. I did not really need to know a lot about the energy markets, just the fixed price as delivered. The dynamics of our team have changed. We now have a team of five or six people who are expert in strategic pricing in organized markets.
MR. MARTIN: You need a higher-than-average IQ in the pricing department.
MR. SHIPLEY: Definitely. They are all higher than mine. You need the team in-house to evaluate the risk. We are a developer at heart. A lot of times developers focus on what the tax equity and debt will accept, but I don't care as much about what they think as about whether it is good for us. We have to solve for our equity returns and our risk, so we need the in-house team to evaluate it. We need also to focus on markets where we are most comfortable and want to invest our capital. We do our own internal analysis. The banks may rely to a certain extent on us, but they will also have their own consultants. I will let Andy Redinger comment on that.
MR. REDINGER: We rely on consultants, but we are learning that they have been wrong in many instances. If this pattern persists, it will change the market. I think people will be watching carefully for this over the next couple years.
MR. MARTIN: How will it change in the market?
MR. REDINGER: Most likely less leverage, increased pricing and possibly fewer banks participating in the market.
MS. SCHULTZ: It is important to differentiate. Basis risk is not the same across all projects. It is important for lenders, investors and sponsors to evaluate the specific project and its location. All projects and all consultant reports are not the same. We have a lot of experience with merchant gas projects. We think that has put us ahead of the curve in terms of our ability to analyze basis risk. You have to have a strong understanding of how the particular market works.
MR. MARTIN: It has been hard to finance projects in the Texas panhandle because basis risk seems greatest there. Are there any other areas where financiers are reluctant to invest?
MR. SHIPLEY: What I tried to say earlier, but didn't get across, is we are starting to see it everywhere. Basis risk is the differential between where you are delivering and selling power, and where you may be settling under a contract. We are starting to see it creep into our power purchase agreements with utility offtakers while it has always been present in corporate PPAs.
You hear people say in Texas that PJM is a different market, and in Texas there are no barriers to entry. PJM is hard as heck. There are a lot of areas to build projects, but that is not a great thing. It means you might eventually have a level of congestion that you see in Texas where it is super easy to get into the market and build projects.
MR. MARTIN: Are any risk-shifting financial products getting significant traction in the market: for example, tax insurance, solar revenue puts, proxy revenue swaps, balance of hedges, deal contingent hedges, offtaker credit insurance?
MR. REDINGER: We have seen a lot of tax insurance, particularly around safe-harboring strategies. I imagine that it will remain popular with developers and financing parties. We have seen the solar revenue put used in a number of transactions. It makes the parties more confident about the output forecasts and allows lenders to justify a higher loan amount. Some lenders have basically sized their debt differently based on the knowledge that the revenue put provides protection against a worst-case scenario. Then there are some other specialty products. I know Energetic Insurance has a credit wrap for small C&I portfolios. We have not transacted on that. I know others have.
MR. SHIPLEY: We have not done a deal with a revenue put, which is the idea that you could reduce risk on production and the banks are willing to lend at a lower coverage ratio to get to a higher advance rate. As for hedges, I hear a lot about proxy revenue swaps. We are not as big a wind player. I am not sure a proxy revenue swap has been done yet in the solar market, but I think that as this market continues to evolve, you will see more use of structured financial products to address risk.
MR. MARTIN: This has been a very busy year for new solar construction and financings. Do you think things will remain at this pace through 2023 when all projects need to be completed to qualify for a 30%, 26% or 22% investment tax credit?
MR. REDINGER: Yes. We see a big move to distributed solar. Roughly 80% of C&I installations today are not financeable because the customer is not investment grade. There are a couple products to help with this problem.
MR. MARTIN: Meghan Shultz, your company is generating projects. Do you see this pace continuing through 2023?
MS. SCHULTZ: I do. I think 2021 and 2022 are going to be two of the biggest years to new solar capacity additions.