The larger US solar rooftop companies have used various forms of master tax equity facilities to finance their projects. A panel of tax equity investors talked about the market at an Infocast distributed solar conference in New York in June. The panelists are Jeetu Balchandani, head of the global structured tax products group at MetLife Capital, Jason Cavaliere, director of renewable energy finance with Citigroup, Darren Van’t Hof, director of renewable energy investments with US Bank, and Mit Buchanan, a managing director of JP Morgan Capital Corporation. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: Jeetu Balchandani, Metlife Capital is interested in investing tax equity in the rooftop market, but just commercial projects or also residential?
MR. BALCHANDANI: Primarily rooftop commercial. We have done a couple programs of approximately $50 million each where we have multiple commercial rooftop sites. The challenges in getting such deals done are to be able to evaluate each credit, to keep the transaction costs on a manageable scale and to limit the number of separate fundings. Residential solar is still challenging for us. We have not gotten our arms around that yet.
MR. MARTIN: How frequently are you prepared to fund under such facilities?
MR. BALCHANDANI: Ideally once a quarter. However, we are not terribly stringent about that and try to accommodate the sponsor whenever we can. For the two programs we have done to date, we have had four to six fundings in each program over the course of a year.
MR. MARTIN: Jason Cavaliere, I know Citigroup has done at least one large residential portfolio. Are you also interested in commercial rooftop transactions?
MR. CAVALIERE: We did our first transaction in the residential space. We find that more attractive than the commercial space in a number of ways. One is that with a large enough pool of residential customers, you can take a statistical approach to the credit analysis. Commercial projects require looking at each individual credit.
MR. MARTIN: Is a residential pool lower risk?
MR. CAVALIERE: Not lower credit risk but easier to estimate the credit risk.
MR. MARTIN: So then the cost of capital would be lower for a residential deal than a commercial one?
MR. CAVALIERE: Exactly. [Laughter] I know it’s fun to beat up the banks on this, but our regulators are becoming more strict. We may have enough capital, but the hurdle rates that we need to pass to deploy that capital are extremely high. Most banks are adhering currently to Basel II before Basel III takes effect. Basel II does not allow banks to assign retail treatment to the transaction until there are at least five years of historical data. We don’t have five years of recent data yet in this sector, and this lack of data leads to a very onerous capital charge.
MR. MARTIN: Darren Van’t Hof, you have been doing both commercial and residential rooftop. You were one of the early movers. How risky have these deals been, and how many years of data do you have? What has the default rate been for residential customers?
MR. VAN’T HOF: We have about $500 million in residential portfolios under management. The default rate across nearly 20,000 customers has been less than half a percent over three years.
We try to limit participation to customers who qualify for prime mortgages. They own their homes. They are pretty high income earners. They have pretty low debt ratios. All of those things lead to strong portfolios.
MR. MARTIN: Do you have any sense how common defaults are among commercial customers?
MR. VAN’T HOF: We have had no defaults on any of our commercial systems.
MR. MARTIN: What minimum FICO score do you require for homeowners to allow them into the pool?
MR. VAN’T HOF: It is usually around 700. In cases where we have gone lower, we have tried to reduce the risk by requiring the customer to prepay all or part of the rent or electricity payments.
Minimum Deal Size
MR. MARTIN: Mit Buchanan, JPMorgan is a dominant player in the US tax equity market. How interested are you in residential and commercial rooftop projects? Your bio you said you have done one portfolio so far.
MS. BUCHANAN: We are interested on the commercial side. We closed a portfolio that required a $60 million gross investment on our part. We are looking at residential, but have not closed a residential deal to date. What we are looking for in both segments is the opportunity for repeat business because you want to get papers in place and then hopefully replicate them but for the due diligence.
MR. MARTIN: How large a portfolio do you need before a deal is of interest?
MS. BUCHANAN: I would say $50 to $60 million in terms of a gross tax equity investment. Depending on the cost per megawatt, that usually means a portfolio of at least 10 to 12 megawatts. That is still very small for us, but we are committed to solar.
MR. MARTIN: Darren Van’t Hof, how large does the deal have to be before you are interested?
MR. VAN’T HOF: That is the right size for a solar rooftop portfolio. They take a long time and they’re really messy. You will start with five or six assets and, by the time you close, two or three of the customers might have been swapped for other customers. That doesn’t seem like a big deal from a developer’s perspective, but on the bank side it can soak up a lot of time. If you have a lender providing project-level debt at the same time and it is not your own institution, the transactions can get very expensive very quickly. The size is driven less by our need to get capital out the door than by the inefficiencies that we would impose on the developer for anything smaller.
MR. MARTIN: You said if you have another lender. Do you mean another tax equity investor or actually a lender?
MR. VAN’T HOF: A lender.
MR. MARTIN: So you are combining tax equity with debt in rooftop transactions.
MR. VAN’T HOF: Yes.
MR. MARTIN: You would think that the transaction costs would be too high.
MR. VAN’T HOF: They are. [Laughter]
MR. MARTIN: Jason Cavaliere, how large does the deal have to be?
MR. CAVALIERE: For us, $25 million net equity would be the minimum for a residential portfolio.
MR. BALCHANDANI: I think we’re pretty much in the $50 million range. These things do take a lot of work, and you do have projects that fall out, so you might start at $50 million and end up at $30 or $40 million.
MR. MARTIN: In terms of the economics of the deals and the cost of money, is there a difference between distributed solar projects on the east and west coasts?
MR. CAVALIERE: In New Jersey, as much as 80% of your gross revenues come from the sale of SRECs. SREC prices collapsed and while people talked about sponsors having the ability to bridge that SREC risk, financial institutions can’t. We can bank contracted RECs only. There are many deals in New Jersey on which we have had to pass.
MR. VAN’T HOF: The other challenge in a high SREC market is who the offtakers are. Many buyers of SRECs are brokers. From a financial institution perspective, that doesn’t cut it. Investment grade utilities need to be on the other side of those contracts.
MS. BUCHANAN: I agree with that. The economics are very thin in these deals on either coast, but the extra risk on the east coast is the share of revenue that comes from selling SRECs. We have to have a long-term contract with an investment grade counterparty to be able to count the cash flow.
MR. MARTIN: So there is no point in a developer going to some small shop that acts as a go-between, buys SRECs and resells them into the market. Electricity prices are highest in New England, including New Jersey, and then California. One would think that in terms of electricity prices the deals are fairly similar on both coasts?
MR. VAN’T HOF: The incentive structure is different. The PBI rebate program in California was very successful and a lot more bankable. Otherwise, you are right. There is an inflection point where the electricity prices start to get so high that the economics are easier. However, we see a lot of power contracts that are underbid to win market share, and that becomes more of a challenge.
MR. MARTIN: Does it matter if SREC prices collapse in New Jersey and Pennsylvania as far as tax equity investors are concerned? Mit?
MS. BUCHANAN: I think given our criteria of where SRECs need to be sold under a contract with an investment grade offtaker, it doesn’t matter. We will not take SRECs into account unless that criterion is met.
MR. MARTIN: There are three main structures in the distributed solar market. Master sale-leasebacks, master partnership flips and master inverted leases. Does MetLife have a preference for one of the structures?
MR. BALCHANDANI: We have done master sale-leasebacks and are comfortable with that structure. There is no leverage involved. We can keep transaction costs to a minimum. Given the complexities of doing distributed generation in any case, this is the simplest possible structure. So we will probably only do such transactions.
MR. MARTIN: Is the cost of capital for the developer higher in a single investor lease than a leveraged lease?
MR. BALCHANDANI: Possibly. Frankly, we have not done the analysis of transaction costs and how that really layers into it. Also, the complexity of getting a lender involved is too much. It is one thing to get one party comfortable with each customer credit. If you have to get a lender comfortable as well, you’re really taking the highest common denominator. The point is there are trade offs for a developer to consider in the effort to pick up a hundred basis points.
MR. MARTIN: How long will you leave the master lease facility open — for a year, two years — so that more equipment can be added to it?
MR. BALCHANDANI: We have been fairly flexible, but I think a year is about as far as we will go.
MR. MARTIN: And you will commit to a certain cost of money for that year?
MR. BALCHANDANI: For that period, right.
MR. MARTIN: Citigroup has been doing mainly inverted leases. Can you explain what an inverted lease is?
MR. CAVALIERE: An inverted lease is where the tax equity investor, which is usually the lessor in a sale-leaseback, is the lessee and the developer remains the lessor, keeps the depreciation, but assigns the Treasury cash grant or the investment tax credit to the lessee, and the lessee, being Citi, faces the customers directly.
MR. MARTIN: What’s the attraction of that structure to a developer?
MR. CAVALIERE: It is extremely attractive to developers. We prepay some of the rent, so the developer has cash up front. Basically the residual goes back to the developer for free. The developer does not have to pay anything to get the assets back. In the structure, Citi, as lessee, is taking the credit risk of the residential customers, whereas in a partnership flip or sale-leaseback, customer credit risk remains with the developer.
MR. MARTIN: How long a term does a typical inverted lease have?
MR. CAVALIERE: We want the inverted lease to remain in place significantly beyond the terms of the customer contracts. However, there may be some type of walk-away right or purchase option before the end of term.
MR. MARTIN: So how long is the term? 12 years? 15 years?
MR. CAVALIERE: The inverted lease term is usually 20 to 25 years with a right to walk away or a purchase option around year 10.
Percentage of Capital Raised
MR. MARTIN: Jeetu Balchandani, what share of the capital cost of the systems does the sale-leaseback structure raise for the developer?
MR. BALCHANDANI: As much as 100%.
MR. MARTIN: As much as 100%, but developers in the current market are usually required to prepay part of the rent, so what do you end up with on a net basis?
MR. BALCHANDANI: It depends because the developer’s actual cost to construct the systems may be less than the fair market value paid by the lessor in the sale-leaseback. So in certain cases the developer is getting 100% of the construction costs and maybe even making a profit, even after taking the rent prepayment into account.
MR. MARTIN: So the developer is making a profit on the sale part of the transaction before he leases back the solar equipment and sometimes you require all or part of that profit to be paid to you as prepaid rent.
Jason Cavaliere, how much of the capital cost can a developer raise through an inverted lease?
MR. CAVALIERE: It depends on the lease term, the lease rates or electricity prices for which the customer is being charged, and whether there are any local rebates. We can get close to $5 a watt payment which is close to 100% depending on the location. However, it would be safer to assume the developer is raising somewhere in the mid-$4-a-watt range as an upfront payment of rent under the inverted lease.
MR. MARTIN: That is a very significant share of capital costs when the only tax benefit for the lessee is a 30% Treasury cash grant on the equipment. Are you keeping a large share of the customer payments over time to get to such a high percentage?
MR. CAVALIERE: We prepay 100% of the rent for an initial period under the inverted lease, and we keep all the customer revenues during that period. We can structure it where we pay the developer rent over time; however, developers usually want all of the money up front.
MR. MARTIN: So you take the customer credit risk.
Darren Van’t Hof, you have pioneered various structures. The latest one is a partnership flip in which the flip occurs at the end of year five regardless of your return. Are you using that structure in the distributed solar market or is it just for wind?
MR. VAN’T HOF: No, we use it in the distributed solar market, and it is a clean, quick structure. It works for sponsors that can provide a fair amount of equity capital. It does not raise as much tax equity as other structures. We do not take as much cash as Citibank takes in an inverted lease, but we are not providing nearly as much tax equity. The benefit is that we will exit the transaction in five years, and the developer will own the equipment. The developer can refinance it, recapitalize with other equity and get us out of the way. Developers like that.
MR. MARTIN: My understanding of the structure, having worked opposite you on two of these deals, is that you take 2% of the cash before and after the flip.
MR. VAN’T HOF: It is actually 2% indexed to our equity. Sometimes it can be as high as 7% to 10% of gross cash flow.
MR. MARTIN: The main attraction to the developer is he sheds the tax benefits while keeping most of the cash.
MR. VAN’T HOF: That is correct. Actually, the structure also works well with traditional project finance debt at the project company level once we get through the inter-creditor terms.
MR. MARTIN: What percentage of the capital cost of a rooftop solar system can be raised with a fixed-flip structure?
MR. VAN’T HOF: About 40%.
MR. MARTIN: Mit Buchanan, you have done sale-leasebacks and traditional partnership flip transactions. What is JPMorgan’s preferred structure for the distributed solar market?
MS. BUCHANAN: We are agnostic. We will look at both partnerships and single investor leases, but I think distributed generation works very well as a single investor lease. We are trying to get $50 to $60 million out the door per transaction. It is hard to do with such small systems without multiple closings. A single investor lease provides more flexibility to close around groups of systems because the parties have up to three months after each tranche of equipment is put in service to close. In addition, there is typically a prepayment of rent by the developer . The structure is based on the fair market value of the equipment after installation. The developer typically prepays 15% to 20% of the rent, so it ends up having raised about 80% of the fair market value of the equipment.
MR. MARTIN: How large a rent reserve do you require the developer to maintain?
MS. BUCHANAN: We ask for a reserve that holds enough money to fund O&M costs and rent for six to nine months. That and the need to prepay some of the rent are why the developer raises about 80% of the market value of the systems on an all-in basis.
MR. MARTIN: Are the reserves cash or will you accept a letter of credit?
MS. BUCHANAN: We will accept a letter of credit as long as we are comfortable with the letter of credit bank.
MR. MARTIN: Are you also doing partnership flip structures in this market?
MS. BUCHANAN: We will. We have a bid outstanding that contemplates using a partnership, so I expect to close on that basis. However, we are seeing more partnerships in utility-scale solar projects than in the rooftop market.
MR. MARTIN: How do you persuade developers that your product is better for them than Jason Cavaliere’s inverted lease or Darren Van’t Hof’s fixed-flip partnership?
MS. BUCHANAN: It is not necessarily better; ours may be better suited depending on a developer’s objectives. I encourage every developer to calculate its NPV benefit from each form of available financing. Look at every option. To me, the single investor lease has a benefit of providing financing on the fair market value of the equipment after installation. The developer is also getting most of its profit out at inception. The cost per watt must be reasonable, and there must be an acceptable appraisal that supports the profit.
Section 1603 Payments
MR. MARTIN: The developer gets his profit as gain on the sale part of the sale-leaseback transaction.
All of you have been doing Treasury cash grant deals. What has been your experience with Treasury cash grants? Is Treasury paying the full grant for which you apply?
MR. VAN’T HOF: You are looking at me? [Laughter]
MR. MARTIN: Yes, I am. I know you made a trip to Washington at one point. I assume it wasn’t just a sightseeing visit.
MR. VAN’T HOF: We did. We had an interesting and helpful meeting in the basement of the Treasury building. There were a number of kinks to work out in the program as it applied to residential solar systems. The Treasury was not prepared at the start to deal with literally thousands of applications on individual rooftop installations. Residential systems cost more per watt on an installed basis than what the government was used to seeing at larger solar projects, and the people reviewing the grant applications at National Renewable Energy Laboratory, under contract to the Treasury, looked at the cost of silicon and said the bases that applicants were using to calculate their grants were too high. They did not take into account the development activity around each residential system. Since that initial period, the program has been great. It has been a very successful program in terms of encouraging capital to flow into the residential rooftop market, and we give the people running it at Treasury and NREL high marks.
MR. MARTIN: How quickly are you being paid grants after filing applications?
MR. VAN’T HOF: We receive some in as quickly as three weeks and others in as long as six months.
MR. MARTIN: What about others’ experiences? And on what bases are you being paid grants on rooftop solar systems? Is it $7 a watt, $6 a watt, $8, what?
MS. BUCHANAN: I think the bases are trending down. Six to nine months ago, the bogie seemed to be $7 per watt for a typical rooftop deal. The individual facts are important. For example, Treasury understands that installation costs are higher in certain markets. It can be a process sometimes of trying to socialize the cost per watt to see whether you can get any feedback from Treasury before filing the grant application. [Ed. Shortly after the panel discussion, the Treasury posted a paper to its website to let the rooftop solar market know what it considers reasonable values for rooftop installations. The amounts vary from $4 a watt for systems of greater than 1 megawatt in size to $7 a watt for small residential systems. These figures were for systems installed in the first quarter of 2011.] We have seen grants paid in the amounts we requested and, at other times, there have been haircuts. As panel prices come down over time, the grant bases also come down. Our experience is the reviewers at NREL dig into the facts. If the amount requested falls within a range that NREL considers reasonable, the grant gets paid. If not, there is a greater risk of a haircut.
MR. CAVALIERE: We are in the mid-$7-a-watt range, and we just received a grant confirmation last night without any reduction.
MR. BALCHANDANI: We have seen some haircuts around the $7-a-watt level. For the projects that get pushback, sometimes it is possible to explain why the project costs more than the typical project. Sometimes the explanation is the panels were purchased at a time when panel prices were higher.
MR. MARTIN: Have you found Treasury receptive to these types of arguments?
MR. BALCHANDANI: They listen. They may or may not accept the explanation.
Cost of Tax Equity
MR. MARTIN: At the annual Chadbourne energy conference this summer, Ted Brandt, who’s CEO of Marathon Capital, said the cost of tax equity seems to be more a function of supply and demand than any realistic assessment of risk in these deals. He was looking at the fact that interest rates on debt have been falling but tax equity is still 270 basis points more expensive than it was before Lehman went bankrupt. Is he right? And shouldn’t large residential portfolios be the least risky asset classes, even less risky than wind given the diversification you mentioned earlier?
MR. CAVALIERE: I don’t think Ted is right. Ted doesn’t have the same regulators we have. I don’t think he has any. [Laughter] The yields we charge on deals just meet the minimum return the bank regulators require us to earn on the type of capital we are deploying. We are not trying to sack the market.
MR. BALCHANDANI: I think to a large extent it is supply and demand. At the end of the day, we are a provider of capital, and we have a fiduciary duty to our shareholders to get the best return for the dollars we invest. If we can earn a higher return by deploying the capital elsewhere, it will go into those other investments.
MR. MARTIN: Many people think that yields in the tax equity market will increase as the Treasury cash grant disappears. Tax subsidies amount to about 56% of the capital cost of wind and solar projects. At the moment, 30% is being paid in cash. Once the market has to use that 30% against tax capacity, the market will need to find as much as twice the tax capacity as this year to handle the same volume of projects. Are we headed for much higher rates given this problem?
MR. VAN’T HOF: There could be a premium. You are asking a financial institution to put its balance sheet behind your project, and there is a bit of a premium to that. It is a function of supply and demand. We are winning deals at X% yield, and we go to our credit people and they ask whether we would still have won the deals at X+%. If the answer keeps coming back yes, there is no reason to reduce our yield. We have a fiduciary obligation to our shareholders.
MS. BUCHANAN: I agree. There is already a premium if you ask us to take an investment tax credit rather than a Treasury cash grant because we are using up more tax capacity, which is a scarce commodity. There are also alternative uses of capital, so you want to make sure that what you bring to your credit committee is a well-priced good investment for the corporation to make. Another factor is the number of tax equity investor competing against each other in the market. There are perhaps 18 or 19 currently with another four or five on the edge of entering the market. Once you take away the Treasury cash grant, rather than 19+, maybe you have 10.
MR. CAVALIERE: Let’s also remember the lesson we all learned a couple of years ago that there is volatility of tax capacity in each institution. The opportunity cost of using that capacity is going up.
MR. MARTIN: Tax equity for the least risky wind farms costs between 8% and 8.25% currently. Solar PV used to be priced at roughly the same level as wind. In the last year, it has been all over the map. Unleveraged tax equity for solar PV has been in the high single digits to the low teens on an after-tax basis. What is your sense where it is today? Talk about commercial versus residential.
MR. VAN’T HOF: I think it is in the mid-teens, honestly.
For instance, we don’t do sale-leasebacks, although we hope to be in that market by the end of the year. There is a big difference between getting an 8% yield over five years versus 15 years. It is an acceptable yield over five years but not for putting money at risk over a much longer period.
MS. BUCHANAN: It is hard to make a definitive statement about yields. Many factors are at work in particular markets. For example, you want to make sure you are getting comparable returns with other investments with equivalent levels of perceived risk. Ground mounted systems may be different than rooftop. The customers may be different. Sometimes the yield may be lower because there is the potential for significant repeat business if you can land the first deal.
MR. MARTIN: Which is riskier — wind or solar PV?
MS. BUCHANAN: In some ways solar should be less risky because you have fewer moving parts. You don’t have the intermittency. But, having said that, if you do a lease deal and you have a power contract with a term of 20 years and a site lease with a term of only 20 years, and the tenant is a retailer who might last only seven years, those sorts of things have to be factored in.
MR. MARTIN: So your tenant could be a video store.
MS. BUCHANAN: [Laughter] That would not be in our portfolio.
MR. CAVALIERE: Somebody did come to us with a paintball facility and I said, “I can’t take this to the credit committee.” [Laughter] Having an investment grade offtaker is a good starting point.
MS. BUCHANAN: I would start with a return comparable to wind, but then adjust for the fact that you are talking about potentially a 20-year investment through a single-investor lease versus seven to 10 years for the wind farm.
MR. MARTIN: Mit, you said that a developer should compare the NPV benefits of the different financing options. Explain what that means.
MS. BUCHANAN: The developer should look at the presentvalue cost of buying the asset under the different structures. For example, we would not give him a fixed-price purchase option at the end of the lease. He will have to estimate what the market value of the equipment will be at that time and factor in how much he would have to pay, on top of rent, to have the asset for its entire life. Look at the termination value schedule in case the transaction is cut short. In a partnership, while maybe not quite as much capital is raised at inception, our share of the asset drops to 5% or 10% after we reach a target return. It costs less to buy us out after the flip than to take back the asset at the end of a single investor lease. The point is to compare the structures on an all-in basis.
MR. MARTIN: One of the biggest risks in this market is change in law. There is talk of potentially massive spending cuts, and perhaps also tax increases, to allow Congress to increase the debt ceiling. There is talk of corporate tax reform, perhaps pushing the corporate tax rate down to 25% and stripping a lot of these benefits from the tax code. How worried are you about change in law? How do you deal with it in transactions?
MR. VAN’T HOF: So far, there has not been anything really specific on the horizon. I think if there was something specific that was making its way through Congress, then we would want to incorporate it into the financing documents. However, we are not terribly worried at this stage. You need a lot of stars to align before Congress can act on anything today.
MR. MARTIN: Do you fix the corporate tax rate at which you value the tax subsidies at the current rate of 35%?
MR. BALCHANDANI: We do.
MS. BUCHANAN: It’s a negotiated issue for us. We run sensitivities to see how much a change in rates will affect our return.
MR. MARTIN: Mit Buchanan, you said you do single-investor leases but you do not give the developer a fixed-price purchase option. Why not?
MS. BUCHANAN: It creates a compulsion issue in the view of our tax counsel. The market has moved. Several years ago, it was common to give an early buyout option or a fixed-price purchase option at the back end. The market has moved from that.
MR. BALCHANDANI: We have allowed early buyout options in some cases, so I don’t think it is as large an issue for us from a tax perspective.
MR. MARTIN: Do you charge the developer for giving a fixedprice purchase option?
MR. BALCHANDANI: Yes. You strike it at a yield that would achieve a premium for us. Any fixed-price option limits our upside potential to an extent, so we have to get paid for that.
MR. MARTIN: Going back to the cost of capital. Darren Van’t Hof, Mit Buchanan said that if you have to take an investment credit, it uses scarce tax capacity of the bank, and you have to charge for that. What do you think is the premium for investment credit deal over a Treasury cash grant deal?
MR. VAN’T HOF: I don’t know, because we haven’t gotten there yet. We are doing mainly Treasury cash grant deals.
MR. MARTIN: One of your colleagues said on this same panel in San Diego last fall that the only deals U.S. Bank will do next year are Treasury cash grant deals. Is that still the position?
MR. VAN’T HOF: No, that’s not entirely accurate. It really isn’t so much a tax capacity issue as a GAAP accounting issue of how the investment credit versus the grant affects book earnings. One of the ways to solve the problem is to move to saleleaseback transactions. I am spending considerable time this year trying to develop a product within U.S. Bank that can manage the GAAP accounting issues. Developers should be aware that different investors have different sensitivities. We might care about one thing while JPMorgan does not.
MS. BUCHANAN: In terms of premium, it comes down to a market return. We have seen a range of as low as 25 to 50 basis points, but have also seen 125 to 130 basis points to take an investment credit rather than a cash grant.
MR. BALCHANDANI: This year where, for whatever reason, the grant is not available and we have to take an investment credit, we have looked at something like a 100-basis-point premium. That’s today. I think when we get to next year — going back to the supply-demand question — the premium may be higher.
MR. MARTIN: There is a 100% depreciation bonus on most rooftop solar equipment put into service this year. Do you take it or do you make the developer opt out?
MR. VAN’T HOF: We don’t like it that much. We elect regular MACRS depreciation.
MR. MARTIN: So you make the partnership opt out. Does anyone take the depreciation bonus?
MS. BUCHANAN: It is a negotiated point. At times, yes, we will. The problem is that taking bonus depreciation does not help earnings. In fact, because you are getting part of your return in additional tax benefits, you have to take a smaller share of cash to hold your yield constant. It actually hurts book earnings.
MR. VAN’T HOF: It is not as valuable as people think.
MR. MARTIN: President Obama was asked at a press conference yesterday whether he would be in favor of extending the bonus into next year. To you guys, it doesn’t really matter. You are not that keen on it.
MR. VAN’T HOF: It has actually taken some liquidity out of the market. We syndicate to various utilities. They accelerated some of their capital expenditure budgets because of 100% depreciation bonus, and some of them are no longer customers on the sell side of our tax equity investments because of that. It took about $300 million in liquidity out of the secondary market for tax equity positions.
MR. BALCHANDANI: We look at the average life of our investments, and the bonus severely reduces the average life so it is not an optimal structure for us.
MR. MARTIN: We are down to the last queston. What are the two issues that take up the most time for you in rooftop and small ground-mounted solar transactions?
MS. BUCHANAN: One challenge is the amount of diligence that has to be done around the power contracts and offtakers. There is no such thing as a standard power contract or customer lease in this market. The other challenge is the development process is very fluid. Things fall in and out. As an investor, you cannot just do one-time diligence. It is an ongoing process.
MR. VAN’T HOF: When there is debt at the project level, inter-creditor issues can oftentimes burn up six months. Due diligence is also a very real issue. A lot of people want you to start working on their projects maybe a little too early, and it ends up costing the developer if the project isn’t ready because you know your lawyers are going to keep spending until you tell them to stop. The developer pays the legal costs.
MR. CAVALIERE: A big issue on the residential side is servicing — O&M — that has to go on for the full term of the lease. We are not in a position to operate and maintain the equipment ourselves, so you need to have backup servicers or at least know that you can get a backup servicer if the developer falls away. The servicer is important for another reason. It has to collect the monthly lease payments from customers and keep tabs on everything and ensure the accounts receivable are current.
MR. BALCHANDANI: The two biggest issues for us are the pipeline — finding enough transactions that meet the criteria that we have from a credit perspective — and figuring out how to do deals with so many individual properties efficiently so as to keep transaction costs at a manageable level.