Many US solar projects are financed in the tax equity market. Solar tax equity deal volume hit $4.5 billion in 2015, and is expected to increase in 2015 and 2016 as solar developers rush to complete projects before a 30% investment tax credit for solar equipment falls to 10% after 2016.

A panel of three prominent tax equity investors and finance experts at two of the largest solar rooftop companies talked at a solar finance workshop in New York in late February, organized by the Solar Energy Industries Association, about tax equity yields, current issues in deals, the tax bases being used to calculate tax benefits and other subjects. The panelists are Mit Buchanan, managing director at JPMorgan Capital Corporation, Angelin Baskaran, vice president on the global structured products desk at Morgan Stanley, George Revock, managing director and head of alternative energy and project finance at Capital One, Albert Luu, vice president for structured finance at SolarCity, and Jason Cavaliere, vice president for project finance at Sunrun. The moderator is Keith Martin with Chadbourne in Washington.

MR. MARTIN: Three main tax equity structures are in use currently in the solar market. They are sale-leasebacks, inverted leases and partnership flips. George Revock, does Capital One have a preference among the three and, if so, why?

MR. REVOCK: We prefer to use the partnership flip structure. It is a proven structure from a tax perspective, and it is also most trusted by the sponsors. We are happy to do sale-leasebacks as well. Those are a prudent structure from a tax perspective. The one structure we are not looking at right now is the inverted or pass-through lease. We view inverted leases as having more tax risk. There is some guidance that may be adverse to that particular structure, and we prefer to pass on it until there is further clarification.

MR. MARTIN: Mit Buchanan, does JPMorgan have a preferred structure and, if so, why?

MS. BUCHANAN: While we have sale-leasebacks in our portfolio, our strong preference is to use a partnership structure. There are two main reasons. First, we like the fact that with a partnership structure, the developer has some skin in the game.

Second, we also like the fact that if there is underperformance, with the flip structure, the tax equity investor continues to receive an agreed share of cash available each year for distribution until it reaches the target yield, unlike a lease where the transaction goes into default. It is also nice that partnership flips are priced to reach the target yield in six to eight years while, in a lease transaction, the investor receives its yield over a 15- to 20-year term.

MR. MARTIN: Angelin Baskaran, does Morgan Stanley have a preference?

MS. BASKARAN: We do. We also prefer the partnership flip for the reasons cited and because we tend to be a pure-play tax equity investor. We like to be in for the tax benefits and minimize our cash exposure, and the partnership flip tends to be a friendly structure for that approach.

MR. MARTIN: Do you also do sale-leasebacks?

MS. BASKARAN: We do not. We have not done so for a while. We just find that it is a longer-dated exposure than we want. It is more balance-sheet intensive, and we believe sponsors are in a better position to bear residual risk.

MR. MARTIN: You heard George Revock say Capital One is not doing inverted leases because it considers them riskier than the other structures. Do you do inverted leases?

MS. BASKARAN: We do not. We are familiar with the structure because we have used it for historic tax credit deals, but we are waiting for additional guidance from the IRS about section 50(d) income before we use it in the solar sector.

MR. MARTIN: The section 50(d) income is the amount of income the lessee must report ratably over five years to offset part of the value of the investment tax credit.

MS. BASKARAN: That’s right. The lessee must report income instead of reducing its tax basis in the assets by half the investment credit. It cannot reduce the basis because it does not own the assets.

MR. MARTIN: Mit Buchanan, coming back to you. You mentioned sale-leasebacks. You mentioned partnership flips. Does JPMorgan also do inverted leases?

MS. BUCHANAN: We do not.

MR. MARTIN: Let’s move to the sponsors. Albert Luu, does SolarCity have a preferred tax equity structure?

MR. LUU: We are generally agnostic about the structure. Probably half our deals are partnership flips and half our deals are some variation of an inverted lease. We generally let the tax equity investors pick the structure, and if it raises the capital we need on palatable terms, that works for us.

MR. MARTIN: You did not mention sale-leasebacks. I believe there is a reason for that.

MR. LUU: Yes. It is more expensive in a sale-leaseback for the lessee to retain the assets long term. At the same time, we do not think lessors pay us enough at inception for the residual value after the lease ends. We want to be the long-term owners of these systems; we value a long-term relationship with the customer. We did a few sale-leasebacks in our early years, but we have not used the structure much since then. If someone were to offer us 4% or 5% money and assign a reasonable value at inception to the residual, then we would take another look.

Another challenge for the sale-leaseback is you are financing cash flows at higher yields than you can finance them in the debt market.

MR. MARTIN: Jason Cavaliere, which structure does Sunrun prefer?

MR. CAVALIERE: We prefer a structure that gives us the lowest cost of capital.

MR. MARTIN: Okay. Albert Luu, you heard George Revock say that he believes inverted leases carry greater tax risk. Are you indifferent to structure risk because it is borne by the tax equity investor?

MR. LUU: We are not the ones that bear the structure risks generally, but we are still fairly conservative when we think about structure risk.

Keep in mind that there are many variations of inverted leases. Some people are more comfortable with an overlapping ownership inverted lease where both the lessee and lessor are partnerships. The lessee is owned largely by the tax equity investor, and the lessor is a partnership between the sponsor and the lessee. Other people prefer what we refer to as a clean or simple lease structure, where the sponsor is the lessor and the tax equity investor is the lessee with no cross ownership.

Risk Allocation

MR. MARTIN: Mit Buchanan, how do the structures compare in how they allocate risks between the tax equity investor and the sponsor, and how much capital does each raise?

MS. BUCHANAN: People talk about a sale-leaseback as a form of 100% financing, since the sponsor is paid the fair market value of the assets by the tax equity investor. But it is really not.

MR. MARTIN: Because the sponsor must immediately prepay part of the rent to the tax equity investor.

MS. BUCHANAN: It is typical to see a rent prepayment on the order of up to 20%, so it is not 100% financing. Turning to the partnership flip, the tax equity raised in a solar deal is usually about 40% to 50% of total capital, but the percentage depends on the facts of the deal.

MR. MARTIN: And an inverted lease raises what percentage of the capital cost of a project? None of these tax equity investors does those, so Jason Cavaliere, what is the percentage for an inverted lease?

MR. CAVALIERE: It depends on the tenor of the lease. Some inverted leases with overlapping ownership monetize six, seven or eight years of cash flows and, therefore, raise a large share of the capital cost. We have one investor who prefers to monetize all 20 years of cash flows. That leads to an extremely high advance rate.

MR. MARTIN: So are we talking about 9%, 30%, 40%? How much?

MR. CAVALIERE: For the 20 years, it would be approximately 70%.

MR. MARTIN: What is the bottom of the range?

MR. CAVALIERE: The bottom would be a pure tax-break partnership that would raise about 45% to 50%.

MR. MARTIN: Albert Luu, that sounds high to me. Have you seen lower?

MR. LUU: We have seen lower percentages in fixed-flip partnership transactions where the sponsor retains as much cash as possible. In those cases, the percentage might be something like 40%. I think in an inverted lease with a term of eight to 10 years and where the tax equity investor is keeping maybe 20% of the overall cash flow, the sponsor is probably raising between 35% and 40% of the project value.

MR. MARTIN: Angelin Baskaran, does Mit Buchanan’s figure of 40% to 50% of the capital raised in a solar partnership flip sound like the right range?

MS. BASKARAN: I think it does. Those sound like the right numbers for a partnership flip with a preferred return and no deficit restoration obligation.

MR. MARTIN: George Revock, is the allocation of risks between the sponsor and tax equity investor the same across all three structures?

MR. REVOCK: The risk that the structure works to transfer the tax benefits is usually borne by the investors. The risk that the basis used to calculate tax benefits is too high is borne by the sponsor. There is a good trade around whether the depreciation deductions are properly calculated. In some deals, we see the investor take the risk that the depreciation deductions were properly calculated in the base case model. In some deals, the sponsor takes that risk.

MR. MARTIN: Albert Luu, do you think the risk allocation is the same across all three structures?

MR. LUU: Generally yes. When you think about the inverted lease, the lessee really has to be in the business of subleasing the equipment or selling power. The transaction must be a true lease; it cannot be a financing arrangement. So I think you see the tax equity investor in such transactions take more operating risk, or it should take more operating risk in that structure versus a partnership flip where the partnership of the sponsor and tax equity investor is taking the operating risk.

Solar Deal Flow

MR. MARTIN: Mit Buchanan, where is most of the action today in the solar market? Is it in utility scale or rooftop?

MS. BUCHANAN: It depends. In 2013 through 2014, there was rapidly growing interest in the residential rooftop sector. It is a sector with a huge volume of business and a very small investor base. Toward the end of 2014 and now early 2015, there are some very sizeable utility-scale transactions that are coming to market. I think utility-scale transactions may be more dominant this year.

MR. MARTIN: George Revock, where do you think the action is?

MR. REVOCK: Keep in mind that projects must be in service by December 2016 to qualify for a 30% investment tax credit. At some point this year, investors will start to turn away from utility-scale projects with construction periods that are long enough to create risk the projects may not be completed in time. So maybe utility-scale projects will account for a significant share of the market for the first part of the year, but then the market will turn back to solar rooftop projects that are still capable of being installed before the credit expires.

MR. MARTIN: Angelin Baskaran, what is your view? More utility scale? More action in rooftop?

MS. BASKARAN: We see more action in the residential and small commercial and industrial projects, with residential being the dominant part. We saw a lot of utility-scale projects three years ago, and they largely went down the strategic route. They ended up not needing tax equity because they raised tax-efficient cash equity from strategic investors who could use the tax benefits. It would not surprise me to see interest pick up again in the utility-scale projects among strategic investors.

MR. MARTIN: Focusing still on our tax equity investors, will you invest in solar thermal projects? George Revock, I know you are in a power-tower project now, so your answer is yes. Mit Buchanan?

MS. BUCHANAN: We have actually done concentrating solar power, so yes.

MR. MARTIN: You did Nevada One, which was the first solar thermal project since the last SEGS projects in the early 1990’s.

MS. BUCHANAN: Correct.

MR. MARTIN: Angelin Baskaran, will Morgan Stanley do solar thermal?

MS. BASKARAN: We have not done it yet, but we are open to it.

MR. MARTIN: I assume all three of you will do utility-scale solar PV projects, but what about commercial and industrial rooftop projects? Mit is nodding yes. Angelin is nodding yes. George Revock?

MR. REVOCK: We would do them as well, but we have not seen an opportunity yet.

MR. MARTIN: What about residential rooftop? Yes or no?

MR. REVOCK: Yes.

Key Metrics

MR. MARTIN: Let the record show that all three of our tax equity investors are nodding yes. Moving to our sponsors, what are current tax equity yields? Jason Cavaliere?

MR. CAVALIERE: Depends.

MR. MARTIN: You were allowed to give that answer when you were a tax equity investor. Now you are a sponsor. [Laughter]

MR. CAVALIERE: Well, we care mostly about the pre-tax yields rather than the after-tax yields. We try to push for as low a pre-tax yield as possible, whether it is zero or 2% or in some cases negative. As for after-tax yields, we are seeing 8%, 9% or 10% for a unlevered structure up to low teens for a levered structure.

MR. MARTIN: On the pre-tax yield, what do you think is current market? Are most people insisting on 2%? Less? More?

MR. CAVALIERE: Most people are insisting on 2% for the entire term of the contracted cash flow of 20 years. That does not mean that they will have a 2% pre-tax yield on the flip date.

MR. MARTIN: Albert Luu, what are current yields from where you sit?

MR. LUU: Not low enough. [Laughter] I think there is too much focus on yields because the internal rates of return are quirky when you get a large portion of the return on investment in something like 30 to 150 days. We focus as a sponsor more on our overall cost of capital and the retained value of the project — the value to SolarCity after factoring in what goes to the tax equity investor.

The tax equity could earn a high yield, but if we are keeping most of the cash flows and we are able to borrow against the future cash flows in the debt market at 4% or 5%, that is probably a better deal than doing a sale-leaseback where we raise all the capital we need at a tax equity yield.

MR. MARTIN: I was going to ask what your metric is for assessing different proposals from tax equity investors, but you just said overall cost of capital and retained value. How do you do the calculation?

MR. LUU: There are the tangible financial metrics like our internal rate of return, what percentage of the cash the tax equity investor is taking and our retained value. Then there are intangible metrics like is it a partner we want to work with? Is the investor flexible on terms like FICO? Do we think this is a partner that will grow with our business and let us grow our business? These all go into the mix.

All of that said, we generally need capital to sustain our very rapid growth rate, so it is not like we are turning down capital too often. However, these metrics help us evaluate competing proposals and help us decide what terms to ask for in deals.

MR. MARTIN: Is there anybody you would turn down? Lyndon Rive, your CEO, said you need to raise $3 billion this year.

MR. LUU: I think the $3 billion number is probably all-in project costs. We have said publicly that we want to install 920 megawatts to one gigawatt this year. Apply some cost level to that and you get our 2015 project financing needs. The tax equity number will be a little lower than that. The rest will be filled out in debt.

We said on our latest earnings call on February 17 that we have roughly 590 megawatts of un-deployed tax equity. We have a lot of visibility as to what our 2015 year will look like in terms of where our financing will come from and the remaining deals we will have to do this year.

MR. MARTIN: Jason Cavaliere, John Eber from JPMorgan always tells me the fixation with yields is misplaced. The sponsor should look at an all-in cost of financing or its returns after the financing is taken into account. What is your key metric?

MR. CAVALIERE: That’s exactly right. Our main financial metric is day-one cash proceeds after we combine tax equity with any debt we plan to raise. The next most important thing, echoing what Albert Luu just said, is flexibility to be able to grow our business as we would like to do, whether it is being able to offer customers prepaid leases or PPAs or allowing FICO scores to go down, say, to 650. Flexibility in deployment and timing are intangible metrics that are extremely important for an operating business.

MR. MARTIN: Returning to the tax equity investors, George Revock, how many years out do you price to reach yield in a partnership flip transaction in the solar market? The projects qualify for investment tax credits.

MR. REVOCK: Usually in six to eight years to reach the flip yield, but, technically, we are looking at 20 years for a typical underlying contract period.

MR. MARTIN: In other words, you have two different yields. You have one yield that you try to reach in six to eight years and, after that yield is reached, you flip down to a 5% interest. You have a different yield you are trying to reach by year 20, and what is it?

MR. REVOCK: We look for a slightly higher yield by year 20, but it is more of a pre-tax yield.

MR. MARTIN: Mit Buchanan, do you price to reach yield in solar deals in six to eight years?

MS. BUCHANAN: We usually price to reach yield in 6 1/2 to eight years.

MR. MARTIN: Angelin Baskaran, same thing at Morgan Stanley?

MS. BASKARAN: We tend to be on the shorter side, so six years is our average.

“Market” Terms

MR. MARTIN: Next subject, what is current “market” on a number of terms? George Revock says basis risk is borne by the sponsor. Sponsors, do you agree?

MR. LUU: Yes.

MR. CAVALIERE: Generally, yes.

MR. MARTIN: Is there any evolution in the market in how basis risk is split?

MR. LUU: We would like to move back to how basis risk was handled before 2009 when the Treasury cash grant program started, but the market has not really moved in that direction yet. We have spent considerable time working through the appraisal process in determining the fair market value of these projects. The appraisals have been reviewed by numerous law firms. We would not want to be in a situation where we are taking basis risks, but not having input in the appraisal process.

MR. MARTIN: So investors have to use your appraiser. Mit Buchanan, how large a deficit restoration obligation are investors willing to agree to in the current market?

MS. BUCHANAN: We look at the downside scenario and how quickly any DRO to which we agree will reverse. It is hard to give you a percentage, because it really turns on the particular transaction. Our stress case is a P95 case.

MR. MARTIN: One used to see deficit restoration obligations in the past as high as 20% to 23% of the capital the investor put into the deal. More recently, the DROs have been in the single digits, even in low single digits. Is that fair?

MS. BASKARAN: I think that’s right. To highlight Mit’s point, you ask whether you can see yourself realistically getting out of the deficit, and the way deals are structured right now, it is difficult to climb out of a big deficit.

MR. MARTIN: What is current “market” on lender forbearance where debt is ahead of the tax equity in the capital structure? Must the lenders agree to forbear from taking the project assets after a default in order to give the tax equity investors time to reach their yield and, if so, for how long?

MR. REVOCK: Forbearance is usually required for at least the recapture period for the investment tax credit. During that period, the lenders can foreclose on the sponsor interest, but they cannot take the assets and push out the tax equity investor.

MR. MARTIN: That may be more aspirational than what people are actually getting in the market, right?

MS. BUCHANAN: No, I would not say that.

MR. MARTIN: Albert Luu and Jason Cavaliere, you are both smiling.

MR. CAVALIERE: I was smiling during the discussion about the DRO because a lot of our deals have DROs of up to 30% to 35% of the tax equity investment.

MR. MARTIN: What about a sponsor call option when the sponsor can buy back tax equity investor’s interest in the project or portfolio? Are such options always at fair market value? Do you see many fixed-price purchase options? Are the options at the greater of fair market value and a fixed price?

MS. BASKARAN: The sponsor call option in partnership flip transactions tends to be the greater of fair market value and the amount needed to get us to our target yield.

MR. MARTIN: That is for an option exercised before the flip. If the option is exercised after the flip, the price is simply fair market value determined at time of exercise?

MS. BASKARAN: That’s correct.

MR. MARTIN: George Revock, I know you use a greater-of formula, even after the flip. What is your formula?

MR. REVOCK: It is a three-pronged formula: the greater of fair market value, the amount needed to get to the all-in yield and the amount needed to avoid a book loss on sale.

MR. MARTIN: The all-in yield means the 20-year yield, not the flip yield at year six or eight?

MR. REVOCK: Yes. For purposes of illustration, let’s call the flip yield 8% and the full-term yield at year 20 is 9%. We will work to preserve that 9% because the residual is worth something. We use the hypothetical liquidation book value method to value our interest. If we would suffer a book loss were the sponsor to buy our interest at fair market value, then we will need a higher price to avoid having to report a book loss.

MR. MARTIN: Mit Buchanan, let’s move to developer fees. What mark up by the sponsor is tolerable?

MS. BUCHANAN: We work closely with our tax counsel. We read the appraisal carefully to make sure the reasoning is credible. We might feel comfortable with an appraised value above actual cost to construct on the order of 10% to 15%, but the actual number depends on the facts of the particular case.

MR. REVOCK: There may be a higher markup when dealing with the manufacturer or the developer than in a secondary market transaction. We spend a lot of time understanding the appraisal and making sure whatever number is reported is credible.

MS. BUCHANAN: Sometimes the mark up depends on the degree of vertical integration of the developer. The fact that the developer plays more roles in the transaction might justify a higher mark up.

MR. MARTIN: How is risk that the law will change allocated between the sponsor and the tax equity investor? There is talk in Congress about possible corporate tax reform.

MS. BASKARAN: Are you asking about post-funding risk that the law will change or during the period between commitment and funding?

MR. MARTIN: Post-funding.

MS. BASKARAN: I think the only thing that has changed recently is we have been pushing back on sponsors to take risk that the depreciation method will change. Solar projects are depreciated over five years on an accelerated basis. There was a proposal in the Senate Finance Committee a couple years ago to require power projects to be depreciated on a straight-line basis over a longer period. Since then, we have pushed back in all of our deals for the sponsor to take the risk that depreciation has been calculated properly. I think that is the only recent change.

MR. MARTIN: Does anyone see any different risk allocation for change in law in the current market?

MS. BUCHANAN: That is something that is highly negotiated. The risk allocation varies from one deal to the next.

MR. MARTIN: Let me go back to the sponsors. What other issues do you think are currently in play in tax equity negotiations?

MR. CAVALIERE: One of the biggest issues is the mechanism for payment of tax indemnities. Years ago, any cash that would otherwise be distributed to the sponsor would be diverted to the tax equity investor to cover any indemnities. That is not debt friendly at all.

MR. MARTIN: It is not yield co friendly either.

MR. CAVALIERE: True. In the last partnership we did, there was no blanket cash sweep. We agreed to a negotiated percentage of cash that might be diverted. The percentage was low enough so that there is no risk of putting debt service on any back-leveraged debt in jeopardy.

MR. MARTIN: What cash sharing ratio do you tend to see today in the market? Is it 40% to the sponsor and 60% to the tax equity investors? 50/50?

MR. CAVALIERE: Usually 50/50, meaning that whatever the cash allocation is originally may go up by half of that if there is an event requiring payment of an indemnity. Thus, a 60% cash share for the investor might go to 80% until the indemnity is paid.

MR. MARTIN: Albert Luu, what other issues do you see in play?

MR. LUU: We have only seen cash sweeps to cover indemnity payments in the last year to year and a half. We spend a lot of time to ensure the structure leaves room for back-leveraged debt. We are a public company. There is a SolarCity guarantee of any indemnity obligation. We spend a lot of time educating investors that they should really look to that guarantee for payment of the indemnity rather than sweep distributable cash within the partnership.

The scope of the fixed tax assumptions in partnership flip transactions is another subject that is in play currently in the market. The fixed tax assumptions used to be a standard list of five or six things. There is more negotiation today around the fixed tax assumption dealing with depreciation and perhaps other changes in law. The market is pretty well set that the investor bears structure risks like whether the investor is a partner and the transaction has economic substance.

Another thing that we spend a lot of time negotiating is tranching constraints. We are an operating company and we need as few constraints as possible on how we deploy our systems. One of the reasons investors put money into residential solar deals is because they get risk diversification by owning a pool of systems with thousands of customers. They like to have a good mix across the country. But some investors have wanted their portfolios built around certain zip code mixes. That makes it tough for us to run our company, so we spend a lot of time with them explaining that they do not need this and will get a good mix because we operate in 15 states today.

MR. MARTIN: The zip code is a proxy for a high FICO score?

MR. LUU: Partly. It is also a way to ensure they have certain geographic diversification.

MR. MARTIN: Angelin Baskaran, are there other issues besides the list we discussed that take up time in deals?

MS. BASKARAN: I think they are driven primarily by the interest among sponsors in leaving room for back leverage. The cash sweep on indemnities is one such issue. Another issue related to back leverage is who is a qualified transferee. We spend a lot of time thinking through what happens if the back-leveraged lenders foreclose on the sponsor interest. How do we ensure an experienced operator can be found in such a situation to take over management of the solar portfolio?

MR. MARTIN: How important is it to have a back-up service provider when you have a company like SolarCity or Sunrun as the sponsor? When do you insist that someone have another servicer waiting in the wings?

MS. BUCHANAN: We universally require a backup servicer.

MS. BASKARAN: We require that also.

MR. MARTIN: Even for companies with national brands, like these two?

MR. REVOCK: Our credit card business is required to have a back-up servicer, so we figure it is a reasonable thing to ask of solar rooftop companies.

MR. MARTIN: Albert Luu, have you ever arranged for a backup servicer? Do you hire Sunrun? [Laughter]

MR. LUU: Jason can tell us whether he is available to climb on rooftops. We both will have to look into backup servicers for our securitizations. I do not think the requirement is to find a company that can actually get on the rooftop. You are looking for a company that can step into the administrative role and contract out the actual O&M services.

Basis Per Watt

MR. MARTIN: Mit Buchanan, where do you think basis is per watt currently in the solar rooftop market?

MS. BUCHANAN: There is a range, and it varies depending on whether it is residential or commercial and industrial, and it also varies by state. If you look at C&I, I think that you can see numbers in the $3 range.

MR. MARTIN: Between $3 and $4 dollars or right around $3?

MS. BUCHANAN: Between $3 and $3.50, but once again, it varies by state and circumstance. For example, there may be some systems that have above-average installation costs.

MR. MARTIN: In Hawaii, for example.

MS. BUCHANAN: For residential solar, I think the numbers are higher than that. For utility-scale, the numbers are more likely to be in the $2 to $2.50 range. But once again, these figures are not cast in stone. You have to look at the appraisal and the facts and circumstances around the installation.

MR. MARTIN: If someone comes to you with a portfolio of small utility-scale projects with a basis of $3.50 a watt, do you say, “Sorry, we are not interested. We are not prepared to pay more than $2.50 a watt.”

MS. BUCHANAN: I would ask why the number is so high. I would like to look at the detail around it and see what the appraiser says.

MR. MARTIN: George Revock or Angelin Baskaran, do the ranges that Mit Buchanan just gave us sound right to you?

MR. REVOCK: Yes, I think those are pretty fair.

MS. BUCHANAN: I didn’t give you a figure for residential solar.

MR. MARTIN: Please do, since residential solar is a large part of the market.

MS. BUCHANAN: I was focused on C&I. I would put a slightly different rate on residential systems.

MR. MARTIN: And the number is?

MS. BUCHANAN: A little bit higher than $3.50. How about that?

MR. REVOCK: The figures for residential solar really turn on the location. The figures for New Jersey are different than Arizona and California. I think you can see a range of up to 20%, maybe even more, among the states. The figure might also vary depending on the local regulatory regime and whether the local utility is fighting net metering, what changes are expected in local power rates, and similar factors.

MS. BASKARAN: It is definitely geographically sensitive. We have closed on portfolios of from the low $4-a-watt range to the mid-$6 range in residential solar, and the differences are largely driven by location.

The choice of panels is also a huge sensitivity factor. The panel manufacturer, its financial wherewithal and any performance guarantees that come with the panels are all value drivers. So we really tear apart appraisals. We need to feel comfortable that the appraiser has done a thoughtful analysis, the conclusions are well defended and there has been a sensible weighting of the various methodologies that can be used to arrive at value.

MR. MARTIN: When you say $4 to $6.50, I assume that was some time ago, maybe in 2009 or 2010?

MS. BASKARAN: It was within the last couple years.