Master Financing Facilities for Solar Projects

Master Financing Facilities for Solar Projects

January 11, 2011

Small solar photovoltaic systems mounted on rooftops or on the ground near houses, big box stores, commercial office buildings and schools are best financed by setting up a “master financing facility” and using it to fund construction of a series of installations rather than trying to finance one at a time. There are three basic structures in use in the US market for doing this. Three solar developers and two bankers whose banks are active both as lenders and as tax equity investors participated in a roundtable discussion on financing distributed solar projects at an Infocast conference in San Diego in December. The following is an edited transcript.

The panelists are Matt Cheney, chief executive officer of Clean Path Ventures, Phil Henson, senior vice president and chief financial officer of Solar Power Partners, Michael Streams, general counsel of Perpetual Energy Systems, Daniel Siegel, a senior representative from US Bank, and Gregory Rosen, vice president of solar finance with Union Bank. The moderator is Keith Martin with Chadbourne in Washington.

MR. MARTIN: Matt Cheney, an interesting article in the business section of The New York Times a week ago talked about the business model that Clean Path Ventures is using. You are offering homeowners plots in “solar gardens.” Explain how that works.

Solar Business Models

MR. CHENEY: The concept is to build distributed wholesale generation in small increments in and around suburban and urban areas. The power is sold to the grid, but each power plant is owned by a group of local businesses and homeowners.

The idea is to find a way for people who live in older neighborhoods with tree canopies who would like to own and control their power plants, but without having to put them on their rooftops, can participate in solar. An example is in Davis, California where the city has spent the last five decades diligently growing a canopy over the community. The city is hard pressed to look at programs that promote individual installation of systems on rooftops to the extent that it would lead to cutting down trees. The temperature reaches 110 degrees in the summer, but it is 70 degrees in the shade. It is a dry heat.

MR. MARTIN: You grew up in Davis, if I read correctly in The New York Times. There were lots of trees. It’s not an appropriate place to put panels on roofs, so you build a 20-megawatt solar power plant outside the tree canopy, and what does each participating homeowner or business owner get? He buys an interest in the power plant?

MR. CHENEY: That’s right. He buys the equivalent of a garden plot in a family farm.

MR. MARTIN: Does he receive the electricity directly from your company or does he buy it from the local utility, PG&E?

MR. CHENEY: He owns that garden plot in the family solar farm and can visit his panels. However, the linkage is through a legislative remedy. In this case, there is a bill credit arrangement in California that allows solar “farmers” to sell power to PG&E and have that power show up as a generation credit to a municipal meter. The legislation in the public utilities code needs to be expanded to include other customers. We think it can be, and we are working to promote that.

MR. MARTIN: The homeowner pays you money for a section of the solar array. You sell the electricity to PG&E. The homeowner receives a credit from PG&E for its share of the electricity?

MR. CHENEY: That’s right. The homeowner would pay us in the case of the Davis project. He would pay us through the city because the city sells services to its commercial and residential customers. The city acts as a central collection agent. There is no separate bill from us to the homeowner.

MR. MARTIN: I imagine such a project could be a challenge to finance. You have lots of individual owners each owning a small piece of a large solar array. Have you tried yet to secure bank financing for such a project?

MR. CHENEY: This gets into the dirty little underbelly of solar finance. The idea is that a single entity through which homeowners and business owners have an interest in the project controls the plant. The plant is repossessible. It can be refurbished. Interests can be sold at the entity level to another customer. That sidesteps the issue of credit. You have the ability to make these assets more mobile to new customers.

MR. MARTIN: We would need a lot more time than we have this morning to dig into this properly, but it is an interesting concept. Michael Streams, Perpetual Energy Systems has installed solar systems for wineries, schools and some cities. How would you describe your business model? You retain ownership of the systems? Do you contract to sell the electricity to customers or do you lease customers the equipment? For how long a term do you contract with customers?

MR. STREAMS: Perpetual has been focused in the past primarily on distributed-scale solar projects, but it is moving to do more utility-scale projects. We develop, own and operate the projects. We enter into power contracts with customers.

The company’s roots are in the low-income housing market. The principals are experienced with use of tax credits to generate capital. The company started in the solar business in July 2008. We currently have 10 megawatts of installed solar capacity. All of the projects were financed using a master financing facility.

MR. MARTIN: How long a term is your typical power contract?

MR. STREAMS: Our typical contract is 25 years, although they have been as short as 15 years and as long as 30 years.

MR. MARTIN: What happens at the end of the term? Do you take back the equipment?

MR. STREAMS: The customer has an option to purchase the system at the end of the term. The exercise price is greater than what it would cost to relocate the system.

MR. MARTIN: You don’t have a choice of customer arrangements when dealing with cities and schools. You must sell them electricity rather than lease them the equipment or you will forfeit the ability to claim an investment tax credit and accelerated depreciation on the systems. However, you do have a choice with wineries. Why use power contracts with wineries?

MR. STREAMS: It works. Our power contract meets the underwriting criteria of banks and tax equity investors. It is a familiar instrument. It produces a predictable revenue stream over time.

MR. MARTIN: Phil Henson, Solar Power Partners is heavily focused on schools, but it also installs systems on grocery stores. What is your business model? Do you use power contracts or leases with customers? How long a term?

MR. HENSON: We use power contracts mostly. We have a mix of distributed systems with commercial and municipal customers and some utility-scale projects. Our strategy has been evolving over time. The earlier projects in our portfolio were more heavily weighted towards the smaller commercial customers like grocery stores. We have been moving toward larger offtakers like universities, schools, water districts, airports and utilities.

In terms of a power contract versus a lease, we offer both forms. We are fairly indifferent. We do not see much difference from either an accounting or a legal point of view. The contract terms are typically 20 years, but with some longer and some shorter.

MR. MARTIN: Going back to Matt Cheney, you told me before our session that the solar garden is a small part of your business plan. What is your main business model?

MR. CHENEY: The main business model is pretty simple. We come in at some point in the development cycle to put everything together, work out all the details and the elements of a successful project, boost it up into construction, and get the thing built. In this case, instead of doing what we have had to do in the past, and that is to operate as an independent power producer to own and operate assets over a term, we use the strong asset management skills that we developed going back 10 years and that we used to build well over 50 projects for MMA Renewable Ventures and then Fotowatio Renewable Ventures.

Clean Path is focusing on representing buyers in the market place to look for assets and act on their behalves to organize projects, derisk them, get them built and then transfer them over. We have a significant amount of obvious expertise but also development capital—we call it shock development cash—pretty much to do every job.

MR. MARTIN: Phil Henson, you said Solar Power Partners is moving toward doing more deals with municipalities. What’s the attraction? I know as a lawyer it can be hard to work through all of the local regulations to get hired, and I imagine it is the same thing for a solar developer.

MR. HENSON: It is. Nevertheless, there are two attractions. One is the system sizes tend to be larger. We end up building a one-megawatt system for a water district as opposed to a 200-kilowatt system for a grocery store. The other attraction is it is a better story for senior lenders from a credit point of view. Most of them can get their arms around a rated municipal entity more easily than a corporate entity particularly if it is a smaller, unrated corporate entity.

MR. MARTIN: Are you worried about the declining credit quality of municipalities?

MR. HENSON: It is certainly a long-term credit issue from a financing point of view, but on the whole, municipalities have stood the test of time, so fundamentally no.

Master Financing Facilities

MR. MARTIN: Michael Streams, you said that you use a master financing facility to finance your projects. What type of arrangement is it?

MR. STREAMS: We group our smaller systems into a portfolio. The financing facility assumes there will be a series of projects with staggered commercial operation dates. Bundling projects together in this fashion reduces the overall risk profile.

MR. MARTIN: Do you raise debt and tax equity in the same facility?

MR. STREAMS: Yes. In fact, Dan Siegel of US Bank and I are in such a facility now. We closed the first few projects of that facility on the tax equity side.

MR. MARTIN: And US Bank is both the lender and the tax equity investor?

MR. STREAMS: In this instance, it is both the tax equity investor and the lender. We’ve done it before where we have used a different term debt lender.

MR. MARTIN: To help the audience follow the discussion, a master financing facility is a financing facility where the financiers agree to finance every project that the developer puts in service between now and some date in the future up to some dollar amount as long as the developer can check off a list of 10 or 12 items on a checklist. Each project is acquired by the master financing entity either at the start of construction or closer to when it goes into service.

MR. STREAMS: Yes, that’s the plan.

MR. MARTIN: There are three different versions of such facilities in use in the distributed solar market. There are master sale leasebacks, master partnership flips and master inverted leases. Which of those three are you using?

MR. STREAMS: We use the inverted lease structure to raise tax equity. We lease the systems to the tax equity investor. The term debt is a distinct and separate facility. We borrow from the lender.

MR. MARTIN: Describe for the audience how an inverted lease works.

MR. STREAMS: Without going into too much detail because the structure has a lot of moving parts, you basically have a lessee and a lessor, and there is a master lease agreement between those two entities. The lessor owns the projects for tax purposes. It elects to pass through to the lessee all the tax credits. The lessee sells electricity to customers, collects revenue and pays most of it to the lessor as rent for use of the solar equipment. The depreciation on the equipment remains with the lessor.

MR. MARTIN: An inverted lease is like a yo-yo. The developer puts the equipment out on a string to US Bank. It leases the equipment from the developer. When the lease ends, the developer pulls the equipment back.

MR. STREAMS: The structure has been used for at least 13 or 14 years. It is the old sandwich lease structure that has seen heavy use in renovations of historic buildings where the federal government provides tax credits. Actually, your firm represented us in our first three transactions, although I don’t believe you gave a tax opinion.

MR. MARTIN: Of the three structures—sale leaseback, inverted lease, partnership flip—why have you gravitated toward the inverted lease?

MR. STREAMS: It allows us to keep some of the depreciation and shed just the investment tax credits.

MR. MARTIN: Phil Henson, which type of master financing facility has Solar Power Partners used?

MR. HENSON: We have used both the partnership flip and inverted lease structures, and we are currently evaluating whether to do a sale leaseback for our next portfolio. We look for whichever approach will give us the best return.

MR. MARTIN: Let’s fill in the rest of the pieces for the audience. In a partnership flip, the developer brings in a tax equity investor as a partner and the two of them own all the projects and deal directly with the customers. In a sale leaseback, the developer sells the assets to the tax equity investor and leases them back. The developer deals with the customers directly.

MR. HENSON: That’s right.

How to Choose

MR. MARTIN: How do you choose among the three structures?

MR. HENSON: It boils down to the numbers.

MR. MARTIN: Is there a difference in the percentage of capital cost that you are able to raise with each structure? For example, a sale leaseback raises 100% of the cost of the systems. A partnership flip raises something less.

MR. HENSON: The sponsor has to put in some equity with the partnership flip and inverted lease, but that is also true these days of a sale leaseback where the sponsor, as lessee, must usually prepay part of the rent.

MR. MARTIN: The return you get as a developer is the key to which structure you choose. Is there another factor that is a close second?

MR. HENSON: We want a structure that is easy to execute and administer. Transactional friction is a huge issue in all three structures. They all are complex structures, and particularly when you are trying to bring senior debt into the structure together with tax equity, the interplay between those two often leads to additional transaction time and cost. The cost to get the deal executed is the other critical factor.

MR. MARTIN: Matt Cheney, you tried a number of strategies while you were heading MMA Renewable Ventures.

MR. CHENEY: The partnership flip structure is more efficient in a general sense; it produces more value out of a deal for us. However, if you try to combine tax equity with debt in such a structure, the tension between the lender and the tax equity investor strips out a lot of the value and, as a result, anyone toying with using a leveraged flip would do well to try to have the leverage come from the same tax equity investor as that will provide a much more efficient solution. I think that’s where pretty much everything is headed.

MR. MARTIN: Why do you feel a developer gets more value out of a partnership flip?

MR. CHENEY: First and foremost, the asset remains controlled and largely owned by us. It is not on the customer’s balance sheet, so there is no friction there. We are in a reasonably good position at some point to cash out the tax equity, restructure the deal around our own ownership and, if necessary, bring in lower-cost capital. With leasing solutions, set payments are harvested every month for the term of the lease period. More of the value remains with the tax equity investor. We don’t completely control the project.

Current Yields

MR. MARTIN: Michael Streams, we have been talking about using both debt and tax equity. What debt and tax equity rates are you seeing today in the market?

MR. STREAMS: They are all over the place. In earlier days, we benefitted from debt rates that were maybe 200 or 250 basis points above LIBOR. Now I think we are in the 350 to 375 -basis-point range.

MR. MARTIN: Is there an additional up-front fee and, if so, how much?

MR. STREAMS: Up-front fees range from 1% for construction financing and up to 3% for term debt. It depends on whom you are dealing with. We have been dealing a lot lately with US Bank and find its terms attractive, but we have also been speaking with several European banks who are interested and have experience with this type of portfolio financing and may be a little more aggressive, especially with regard to tenor.

MR. MARTIN: What tenor are you getting?

MR. STREAMS: The US-based banks have been offering loans mainly of seven to 10 years in length, but we are starting to see tenors going out to as far as 25 years or the length of the power purchase agreement.

MR. MARTIN: In the institutional debt market but not in the bank market, correct?

MR. STREAMS: Correct. Bank tenors are going out as far as 17 years in the case of a couple European banks.

MR. MARTIN: Turning to tax equity yields, do you know how much you are paying for tax equity?

MR. STREAMS: Yes, we know how much we’re paying.

MR. MARTIN: You don’t want to share it with the group? [Laughter] Is it above or below 9% after tax?

MR. STREAMS: Above.

MR. MARTIN: Phil Henson, do those rates sound similar to what you are seeing currently in the market?

MR. HENSON: Yes. We are seeing between 7% and 7 1/2% for debt, which would swap back to LIBOR plus 250 to 350 basis points, and we are seeing some banks willing to go longer tenors as they try to break into this market. It is not just the institutional guys who are willing to go 15 to 20 years.

MR. MARTIN: And the cost of tax equity is?

MR. HENSON: I would say also just above 9%.

MR. MARTIN: Matt Cheney, what are developer yields? John Eber with JPMorgan Capital Corporation was on a panel at the Solar Power International convention that I moderated in October, and he said it is hard for the financiers to see where the developers are earning their returns. That has been a common comment from financiers in this market.

MR. CHENEY: Developers have one essential source of revenue. In the old days you might have had firms gunning for north of 20%, maybe north of 30% as a developer fee. Developer fees of that size are harder these days to get. At the end of the day, there is only so much left.

The Treasury Department has weighed in lately with what it is prepared to accept as the tax basis for calculating Treasury cash grants and, indirectly, how much of a developer fee is acceptable. This is pushing developer fees to a lower level than they might have been historically. We also have heard a lot about “zombie” deals being done in the market at levels strictly to capture market share, and those projects tend to be very lean.

MR. MARTIN: Are developer returns in the current market in the high single digits?

MR. CHENEY: They are probably a little lower than that.

MR. MARTIN: Michael Streams or Phil Henson, any comment?

MR. HENSON: I would say unlevered returns for distributed generation projects in the commercial and municipal sectors are in the 9% to 12% range and much lower for distributed utility projects, perhaps 6% unlevered, which probably translates on a levered basis to 10% and 15%.

MR. MARTIN: Michael Streams, same numbers?

MR. STREAMS: Yes. We attempt to structure our projects in such a way that the sponsor equity requirement is as minimal as possible, and sometimes we are able to achieve that by pulling down developer fees at closing, but it not always possible with capital-intensive projects.

Tax Equity Investors

MR. MARTIN: Let me pull in the bankers, starting with Dan Siegel from US Bank. US Bank pioneered the use of the inverted lease in the distributed solar market. There are rumors that US Bank is running out of capacity to use capital losses, which are part of that structure, and that it is now moving to another structure, perhaps a partnership flip. Is there any truth to those rumors? What is your preferred structure at this point?

MR. SIEGEL: We typically let our customer determine what type of structure is used. It is no coincidence that the inverted leases that we are using also have US Bank as a lender. Inter-creditor terms between third parties tend to be very difficult in inverted leases.

We are still closing inverted leases. Our appetite for capital losses is not really an issue. The issues are who the other parties are in the deal, what are they looking for, and how much are they willing to spend on transaction costs standpoint to get it done?

MR. MARTIN: Why do you put in part of your investment as debt and part as equity, and what percentage is each?

MR. SIEGEL: We typically put in tax equity of anywhere from 38% to 44% of total project cost and the debt makes up the remainder. We do not necessarily need to see sponsor equity. Sometimes depending on the size of the project and the experience of the sponsor, it gives us additional comfort to know the sponsor has some skin in the game.

MR. MARTIN: So as much as 44% of the cost of the assets goes in as tax equity, and that’s really your payment for the Treasury cash grant or the investment tax credit and a 49% share of depreciation on the assets, and then the debt is a loan at a lower rate against the project cash flows, correct?

MR. SIEGEL: Yes, that’s correct from the standpoint of our equity investment. US Bank Community Development Corporation does not provide debt, although we do have lending groups in other parts of the bank with whom we work and good relationships with other industry lenders.

MR. MARTIN: Greg Rosen, does Union Bank have preferred structure?

MR. ROSEN: We are a big believer in the KISS method, which is keep it simple, especially for smaller, distributed solar projects.

MR. MARTIN: Keep it simple—there is a word missing, no? [Laughter]

MR. ROSEN: There is no question that a single project that costs $100 million can add leverage and can get more value than the pain and headache of combining debt and tax equity and working out inter-creditor issues. I was on the sell side for 10 years before joining Union Bank. I set up a tax equity flip partnership at my last job for very small projects that were 200 kilowatts each. It is very hard, unless you have lived through it, to have a realistic sense of the transaction costs for attorneys, accountants and so forth. They can easily overwhelm any return for the developer. The fewer entities involved, the shorter the negotiations, and there will very likely be fewer sticking points.

I think the distributed solar market really lends itself to a single-investor lease, meaning a sale leaseback without any leverage. We have done a number of such transactions. If you can find a lender who will provide construction debt as well as the lease equity to take out the construction debt, it makes the financing a lot easier.

MR. MARTIN: In a single-investor lease, the tax equity investor buys the project at full fair market value from the developer and leases it back to him. The investor pays all equity for the project. Dan Siegel at US Bank is putting in as much as 44% as tax equity in his inverted lease plus the balance as debt. He is offering 100% financing, or close to it, at a blended tax equity and debt rate.

Greg Rosen, your rate is entirely tax equity. It would seem that funding entirely tax equity would be more expensive.

MR. ROSEN: Each institution has a slightly different flavor but fundamentally a lot of these structures end up being somewhat the same. The “equity” return for which we are looking is really a blend of the debt of our back leverage plus our equity. Union Bank is also active in the providing debt financing.

At the end of the day, if I were a developer, I would concentrate first on getting as much contracted cash flow as possible. You know what your power purchase agreement will yield. Try to make a forward sale of SRECs.

Then, in addition to looking at the money, you have to look at the bandwidth, the amount of time that you will have to spend personally, because if you are small shop with just one person or a few people, it is a heck of a lot easier to close a sale leaseback than it is to close a leveraged partnership flip.

Also, look at transaction costs because they can cut severely into the return for the developer.

I want to clarify one thing about the sale leaseback, because typically we look for “skin in the game.” Technically, we are providing 100% financing for a project, but the sponsor prepays part of the rent that is on the order of 10% to 20% of the project cost. It is a form of equity contribution.

MR. MARTIN: As prepaid rent?

MR. ROSEN: It is prepaid rent, and there is a mechanism that’s called a “section 467 loan” that is also employed that allows for uneven rent payments.

Really the big difference between a lease and a partnership flip is that, with a lease, the tax equity investor is looking for basically 80% of the estimated cash flows, and a developer will get 100% of the upside and have to deal with 100% of the downside. Thus, for example, if the cash flow is $100 a month coming in to the developer, the tax equity investor will get $80 a month and the developer keeps $20. If the cash flow increases to $105 a month, the tax equity investor still gets $80 but the developer gets $25. If the cash flow is $90, the developer gets $10. The structure provides a more stable payment stream for the tax equity investor.

Risk Allocation

MR. MARTIN: There is also different risk allocation in a lease versus a partnership flip. In a sale leaseback, the developer has a hell-or-high water obligation to pay rent. If he is having trouble collecting from customers, the tax equity investor doesn’t want to hear about it. He just wants his rent.

In a partnership flip, the developer and the tax equity investor are like two passengers in a car together. They are both on the front line with customers. In an inverted lease, who knows?

Let’s move to another issue. You heard from the developers on the panel that they are doing more deals with municipalities. How do you deal with non-appropriation risk, or the clause that the municipality puts in the power purchase agreement that says the current city or county council cannot bind a future one? It can really only commit to pay rent for the remaining term of the current government.

MR. SIEGEL: We don’t see it as great risk. First, the tenor of our investment is only about five years. From an appropriation standpoint, we see it as keeping-the-lights-on type of risk. We really don’t see it as a critical problem for municipalities, and we actually like them. It is nice to have a publicly-rated offtaker.

MR. ROSEN: I second that. I have done municipal financing for solar projects. The municipalities are petrified that their credit ratings or reputations will suffer if they stop making payments and this will drive up their costs of funds in general.

MR. MARTIN: Dan Siegel, coming back to you, one of the risks dealing with homeowners and big box stores is vacancy risk. The average homeowner in California stays in his house six or seven years. How do you as financiers deal with that risk?

MR. SIEGEL: We deal with it through diversification. Residential solar deals will have certain FICO requirements for homeowners. These are well-diversified portfolios. When you move to commercial systems, you are talking about maybe eight, nine or 10 big-box retailers, so we have to do deeper diligence. We like to see investment-grade offtakers.

MR. MARTIN: So diversification gives you comfort. You are not as concerned about vacancy risks. It all comes out in the wash. Greg Rosen, what do you do about vacancy risks?

MR. ROSEN: Commercial solar is sort of this middle ticket. It is not small-ticket residential, and it is not big-ticket utility. It is the worst of all worlds in a lot of ways, so it is challenging. We look for the sponsor to take those kinds of risks.

MR. MARTIN: The sponsor will keep paying rent?

MR. ROSEN: Some kind of a mechanism. If the sponsor is going to do that, it better have a balance sheet that shows it could be around 17 years from now. That’s how long the tax equity capital is at risk.

MR. SIEGEL: Other considerations are whether the transaction is levered, what the debt terms are, how much debt-service coverage there is and how the particular portfolio is weighted. For example, if one offtaker is providing 75% of the cash flow and that offtaker goes under, then that is a problem for the whole fund. If there are 10 different offtakers with each accounting for about 10% of the cash flow, it is possible for the economics to work even if one or two go under.

MR. MARTIN: Are there special issues in master financing structures that vary by state and if so, what is an example? Are there special obstacles to use of structure X, for example, in Arizona or Massachusetts?

MR. HENSON: The primary differences are the state incentive structures. It doesn’t really affect the choice of an inverted lease versus a sale leaseback versus a partnership flip, but there are peculiarities from state to state that affect how much capital can be raised. For instance, revenues from the sale of solar renewable energy credits or SRECs account potentially for a large share of the projected cash flow for projects in New Jersey.

MR. MARTIN: I read somewhere that the revenue from renewable energy credits could be as much as four or five times the revenue from electricity sales in some states. Does that sound right?

MR. HENSON: That depends on the bidder, but it is potentially a significant portion of cash flow.

MR. MARTIN: Is anyone getting value in these financing structures for future REC revenue or for state tax benefits?

MR. HENSON: Yes. In California, obviously, there are the CSI PBI performance-based incentive programs from which developers benefit. On the east coast, there are equivalent incentive programs that are done through renewable energy credits, but the challenge in those markets is to find a creditworthy utility willing to enter into a contact to purchase a number of years’ worth of credits. Without a contract, tax equity investors and lenders will not take the potential cash flow into account in sizing how much they are willing to invest or lend.

It is hard to get value for state tax credits. For example, we are looking at projects in New Mexico where there is a state tax credit, but there are not many potential tax equity investors with enough tax liability in New Mexico to use them.

Treasury Cash Grants

MR. MARTIN: If the Treasury cash grant is not extended by Congress, what effect do you foresee on cost of capital in this market?

MR. SIEGEL: I can only speak for US Bank. Last year, we closed about $300 million of tax equity in renewable energy projects. This year we’ll probably close about $500 million. Most of that has been solar. Next year, we plan only to invest in projects that qualify for Treasury cash grants and then only in projects that are considered to have started construction in time to qualify for a grant because they incurred more than 5% of the total project cost by the end of 2010. We think we can hit somewhere between $300 and $500 million even with those projects that are just within the 5% safe harbor. Unfortunately for the people in this room, competing areas of our business are growing. Low-income housing is growing. We have targets as a bank under the Community Reinvestment Act that we need