This panel discussion of project finance heavyweights was held on April 9 in Albany, NY at Infocast’s New York Energy Summit.  The topics included changes in the tax equity and tax credit transfer markets, the underwriting of naked tax credit transfer bridge loans, community solar, offshore wind, standalone storage, challenges in obtaining insurance for projects in New York and Basel III. 

Panelists:

• Julian Erfurth, Executive Director, Capital Markets, Nautilus Solar
• Sergio Garcia, Executive Director, Project Finance, Americas, Rabobank
• Stacey Hughes, CFO, SunLight General Capital
• Trond Rokholt, Managing Director, Investment and Portfolio Management, NY Green Bank
• Rubiao Song, Managing Director, Energy Investments, JP Morgan

The moderator is David Burton with Norton Rose Fulbright in New York.

Mr. Burton: So Rubiao, you get the first question. Some say that tax equity is 200 basis points more expensive than it was in 2022. Is that just a function of the Fed raising interest rates, or have the structures made tax credits more expensive with things like adders, the complexity of having transferability or traditional tax equity and all the new questions that the Inflation Reduction Act (IRA) has given us?

Mr. Song: After the passage of the IRA, energy tax credits became transferable, and there’s various structures being utilized now in the market.  That makes the comparison of tax equity pricing very difficult.  I’m sure there are some in the audience, either on the investor or on the developer side, that can echo that. 

If you look at just the yield level on tax equity, I think yes, it generally reflects the underlying interest rate increase.  We see there’s still traditional tax equity being done in the market – that is a deal that is 100% the traditional tax equity product.  But that’s not the full story.  When you’re looking at a pure transfer deal, you don’t measure that with yield.  You talk about discount, whether it’s 90 cents or 95 cents, so that’s the credit transfer price. 

But more often now we see is what we call a hybrid structure, where the tax equity investor will continue to monetize the depreciation but 50% or even more of the credits are transferred to tax credit buyers.  The credits that are intended to be transferred would be sold at a discount.  The discount to the value of the credit has to be taken into account.  That could have some, value leakage there, when you evaluate those proposals.  But that’s what we see right now.  It’s not just focusing on yield but also the totality of what the tax equity hybrid structure will bring to the table. 

Mr. Burton: And Rubiao, how does depreciation fit into the hybrid structure?

Mr. Song: Majority of depreciation in the hybrid structure is monetized by the tax equity investor.  When the credits are transferred, the investment tax credit  (ITC) or the production tax credits (PTCs) are transferred by the partnership to the tax credits buyers.  The selling partnership will then distribute the cash proceeds to the tax equity investor and the sponsor.  How much each partner gets distributed depends on which contributed to the partnership against those cash payments.  But the tax-exempt income allocation[1] in those partnerships is usually allocated 99% to the tax equity investor,  which increases the tax equity investor’s capital account and outside basis, so the depreciation losses can be absorbed by the tax equity investor.  That’s how the depreciation benefits get monetized.  In these hybrid structures, I think the depreciation monetization can be almost as good as in the traditional structure.

Mr. Burton: Great.  Very interesting.  So, Julian, how are tax equity investors sizing their tax equity investments and how are term lenders sizing term loans?  What do you see?

Mr. Erfurth: Tax equity has been quite up in the air, right?  I mean, there was a lot of movement in the last six months.  So, we certainly saw some downward pressure for us as a developer sourcing tax equity. 

Nautilus is predominantly active in the traditional tax equity market.  We’re raising traditional tax equity right now.  We certainly look at transferability as a great addition to the tool box.  But if it is available, traditional tax equity is still the best option for our projects. 

I think the sizing of tax equity for ITC deals depends on three things.  First, the level of step-up the tax equity investor includes in its pricing.  Second, the project’s operating cashflow, which also determines the term debt sizing.  In New York, I think it’s safe to say it’s not the most cash-rich market for our projects.  And third, any tax credit adders the project qualifies for, like the energy community adder.

Mr. Burton: Right.  Anybody else have thoughts about sizing of loans? 

Mr. Garcia: Sure.  It really depends on the asset class, right?  If you’re talking about offshore wind to generation, you totally scale each asset class will have its own dynamics.  Where banks are also currently struggling is community solar.  While it is still solar, the economics of it are very different than a contracted commercial or utility scale project.  That’s a little bit of where banks are struggling and that’s where you don’t see all major banks coming into community solar. 

The market is growing, don’t get me wrong.  We have so many requests for proposals.  The main difference is the range, right?  So, we have a community solar project that’s able to sell power at almost retail rates, but there could be some volatility in the number of customers buying power, which is in contrast to typical contracted projects that sell at wholesale rates but have a locked in customer or offtaker. That potential for volatility banks struggle with, which is not say community solar is as volatile as a merchant project. 

Right now, concern about regulatory risk comes up. There’s a lot of uncertainty.  The uncertainty just pushes—or pulls—banks back, the banks don’t have enough appetite for some types of projects.  So, like I said, it really depends on the asset type.  Batteries will be sized differently than solar panels.  Not trying to recreate the wheel on any of these, just trying to allocate risk appropriately and mitigate for any factors, especially on the lifespans of these assets.

Ms. Hughes: And just to add on that, this isn’t my question but we did a institutional raise a couple years ago for sponsor equity. The equity providers limited how much community solar we could do.  They didn’t say no.  They said, “Look, what we really want is the contracted power purchase agreements (PPAs) as much as possible, and then we’ll just allow community solar, but we also view it as somewhat merchant-like,” so they just said, “X percentage is how much community solar we can do in the portfolio.”

Mr. Garcia: That’s a polite way of saying we have no clue how to size community solar. But if its part of a portfolio, that makes community solar a lot easier.  If it’s 100% community solar, it’s challenging for the banks.

Mr. Burton: Alright, Sergio.  Another question for you: how are lenders viewing bridge loans to be repaid with the proceeds from the sale of tax credits?

Mr. Garcia: So that’s pretty much what keeps me up awake all the time right now.  The IRA, while it opened up the flood gates for transactions, it got accountants, lawyers, very excited because there’s structures coming out left and right as to how to transfer these tax credits.  So as Rubiao mentioned, these hybrid structures, in some cases they’re actually beneficial to the lenders.  In other cases, they’re not.  Re-training a credit person in a bank is very challenging.  So they were very comfortable with the tax equity structures, right?  And these hybrid structures look like tax equity, but there’s a lot of nuance on who owns what and when and for how long.  Meaning what rights does the bank have, who has the right to the cash when, is there a risk for recapture? 

My personal take is there’s a lot of value in the tax credits, and we should be advancing against tax credits alone.  But tax credits can be sold later in a project’s life than when an old fashioned tax equity investor would have fully made its contribution.  Then you get into nuances of whether a tax credit buyer has a calendar year or a fiscal year end.  These types of issues are why you see 2023 credits trading at a premium at the moment.  Buyers that don’t have a calendar year-end—are looking for 2023 tax credits and are willing to pay a little bit more.  You’re talking about a few cents here and there, whether it’s 92 or 93 cents. 

Right now, the estimate of the tax credit market—and I think Rubiao, you can prove me wrong—it’s estimated to be between $5 and $9 Billion for last year?  It’s hard to tell because a lot of it’s within a hybrid structure.

Mr. Burton: Rubiao, your thoughts on the size of the tax equity market?

Mr. Song: For 2023, we see the traditional tax equity market as around $22 to 23 billion.  That’s a big increase from the ‘22 level, which was about $18 billion, so that’s a $4 to 5 billion increase in the traditional tax equity space for ‘23.  Then there’s the tax credit transfer market.  Few tax credit transfer transactions were publicly disclosed, but we track some of the private transactions; it’s probably close to $4 to 5 billion in ‘23, so that’s a total tax monetization market for ’23 of around  $27 to 28 billion. 

For 2024, the traditional tax equity space will probably have a single digit increase year-over-year.  Clearly the tax credit transfer market is going to expand significantly, which is probably going to be over $10 billion of tax credit transfers either direct transfers by sponsors or transfers with the tax equity partnerships as the seller.  This is encompassing not just the wind, solar and battery tax credits, but also some of the newer technologies —the section 45X manufacturing tax credit being a large component there. 

David, you were asking about lenders are getting comfortable underwriting future tax credit sales without a committed buyer.

Mr. Burton: Yes.

Mr. Song: That’s certainly the new development over the last six to nine months.  I think the lenders are getting comfortable committing tax credit bridge loans without a committed tax credit buyer.  They are taking a very conservative approach.  They’re not advancing 100 cents on the dollar.  They’re also taking further haircuts on advances rate.  Also, they are timing the draw-down of those bridge loans with the progress the sponsors are making in terms of securing a tax credit buyer, such as when the tax credit buyer executed a letter of intent, etc.  The timing of draws is one way lenders are mitigating some of the exposure. 

Mr. Burton: Interesting.  Alright, Stacey, yesterday we heard from the regulators and they all said that New York is very encouraging of solar, wants more solar and has all of these policies in place to make it easier to streamline solar in New York.  Is it working?  Would you rather finance a solar project in New York or New Jersey?  Are the policies working in New York to make it attractive or are other states in the region that still have an easier climate to raise capital for solar?

Ms. Hughes: Sure.  We’ve done most of our projects in New York and New Jersey.  When we first started in 2009 and ‘10, there was nothing to do in New York and it was all New Jersey for a while.  Then New York had this interesting series of investment opportunities where you could do relatively small, remote net metering.  Sometimes even PPAs could work and a lot of sort of smaller stuff got built—which I think is really cool and I’d love to see more of that.  Right now, there’s not much on remote net metering the horizon, but it’s an interesting way to develop smaller projects. 

But then, moving on to where we are now, we’re finishing up 25 MWs or so of community solar throughout New York.  They are mostly projects in low-income areas or that serve low income customers, and we were able to get allocations of low income tax credit adder for these projects.  We were lucky because the low income adder is something of a lottery

The energy community adder is not a lottery, but the problem is that everybody knows that.  A land owner, who has a piece of property right in a perfect energy community knows that, and wants more rent for it, quite reasonably.  So while the tax credit adders are encouraging development they aren’t necessarily making projects easier to pencil, particularly when you don’t know if you’re going to get the adder. 

I think we, like most developers, or maybe all developers, are ultimately agnostic as to what states we develop in, and I like to do things in New York.  It’s the state I live in, but when we look at New Jersey right now, I think things are penciling a little bit better.  And, there’s been times in New Jersey, truthfully, where that hasn’t been the case. 

To some extent in New York right now, we’re in the mode of “let’s wait until things improve a little bit here.” So, I think we’re in that stage right now with New York because there’s some compression on the revenue side and the New York incentives just stepped down, so we’re not investing as much as we were a year or two ago in New York. 

We’re doing somewhat smaller projects, which can be relatively more expensive to develop than larger projects.  The cost of getting a site lease, permits and an agreement for a payment in lieu of property taxes is the same for a large project or a small project. But then on the other hand, the smaller community solar projects have an advantage over larger projects in that they can fit into a community in a less intrusive way.  We heard from some people yesterday about communities in New York getting concerned about having mega solar fields in their backyards; so, you can have smaller ones, which is nice, but then sometimes they cost just as much to develop. 

Over in New Jersey, before looking at a community solar project, we’ve got a better revenue stream.  I would say revenue rates are somewhat higher than New York.  But then on the other hand in New Jersey, you’ve got the problem that there’s a lot less land, obviously, than in New York State. 

Ultimately, I think developers are all just going for particular yield targets.  So we don’t make more money in New Jersey than we do in New York, but I think it’s a little more likely right now in this current environment to pencil in New Jersey. 

We’re still doing classic PPAs in New Jersey: a board of education puts out a require for proposal for solar on  five schools, it adds up to 4 MW.  We are still doing those kinds of projects in New Jersey and I’d love to be able to do that in New York. 

Mr. Burton: Thanks.  Other people have thoughts about New York as a place to finance solar or other technologies? 

Mr. Erfurth: Well, just to add—and I confirm what Stacey said.  Nautilus has done a lot of projects in New York with 100 MWs operating, and looking forward, we still see a lot of opportunity in New York, as well.  New York has one of the most established community solar programs; I think there’s a lot of value to that.  I would echo what Stacey said, in terms of thin revenue streams in New York.  But projects are penciling in New York. 

For us, community solar depends a lot on how the future’s looking, what our lenders anticipate in terms of where the pricing will give out.  It all depends on that, right?  For New York, we have lenders who are interested in doing business in the state.  Others are shying away.

Mr. Burton: Rubiao?

Mr. Song: It’s interesting looking across the country, particularly in the Southwest or Southeast.  You see load growth due to growth in electricity demand across the board.  Many utilities forecast they need to add a lot more capacity to their service territory and a lot of that capacity will have to come from renewable sources.  That’s really a tailwind in that we’re seeing across the board in Southeast and Southwest.  But that load growth hasn’t shown up in New York yet.  The Southwest and Southeast benefit from datacenters and onshoring manufacturing and EV demand for electricity.  New York, in terms of the planned growth in installed capacity, is certainly not in the top ten, despite the good resources that we have here.  You look at the pipeline in New York, there’s 15 GW of wind/solar battery in the pipeline already in the advanced development stage or near construction stage.  Certainly a very big pipeline and lots of very good opportunities in New York. 

New York also has the number one offshore wind development pipeline in the country.  There’s a lot of the policy talks around how to streamline the permitting process and the transmission buildout, et cetera.  Those are what we’re looking for.

Mr. Burton: Great.  Okay.  Alright, Trond, your turn.  So what type of loans is NY Green Bank focused on in 2024?  What are you working on?  What do you need to do that the commercial banks won’t do?

Mr. Rokholt: Well, there are a lot of areas, but I just want to go back to the community solar space for a second, because I think, at least from our perspective on the various straight-forward community solar projects in New York, we feel like there is a lot of capital from other lenders available, so I don’t think there should be a challenge for solar developers to access that type of capital.  However, where it gets a little challenging and tricky, I think, is when you start looking at the various offtakers of community solar.  When you go into some of the low to moderate income areas, or disadvantaged communities, I think that’s a little bit more tricky for traditional lenders unless you have a fairly significant portfolio of projects behind you.  So we feel like there is a gap still in that area, and we are there to help finance that gap; we want to if we can close that gap over time and get traditional lenders comfortable with financing projects for low to moderate income customers. 

But in general for community solar, we feel like there is a very functional market.  Some of the other areas where we see some gaps existing— electric vehicles (EV) and EV charging infrastructure.  That’s still a very challenging area because on the charging side, it’s very hard to get a longer term offtake contracts.  So we are spending a lot of time trying to figure out how to solve that, and we think we’re going to come to market with a couple of interesting projects here over the next say three to six months in that space. 

Battery storage is another area we are focusing on right now.  Especially on financing interconnection deposits, so we can free up that type of capital for the developers. 

We are also looking at financing some of the incentives that come from NYSERDA as well as some of the utilities, and we are comfortable doing that.  Another area that we are focused on today is also energy efficiency, you know, in buildings.  There is a lot of technology being applied to buildings to make them more efficient and we see a number of opportunities there in trying to build—build a mousetrap there as well.  And building electrification, as interest rates have climbed up, many lenders have backed away from multifamily buildings that are becoming electrified for heat.  It’s been a very challenging space.  We’re seeing some opportunities there and spent a lot of time on that.  And if some of these buildings then can also have some geothermal alongside that, we would be very excited to look at those types of projects and see if we can you know, again, transform that market.  And then, as we talked about earlier, the ITC tax equity is also another area, more so on the ITC side.

Mr. Burton: Rubiao, this year, due to the IRA and other developments we had many new types of tax credits coming to market.  So we had the 45X, which is the manufacturers’ tax credit, we have offshore wind coming online.  This year existing nuclear projects qualify for a tax credit under section 45U, if the project’s revenues are below a certain level.  Carbon capture is becoming more common and those developers looking to monetize the tax credits.  With all these new tax credits, are there going to be enough investors and buyers of tax credits to finance it all?  Is there enough appetite out there?

Mr. Song: That’s the billion dollar question, I guess.  You mentioned a lot of the new sectors.  The 45X tax credit is already playing a pretty big role in today’s market.  Most of the 45X credits are on the transfer market.  Albeit in the first five years, the owners of those facilities could actually elect direct pay, but many of them are electing to transfer the credits because the transfer market is providing a very good price to these credits. That’s the time value of money play, and they’re finding value in the transfer market.  That’s a good sign, that there’s robust demand for those credits.  A lot of the section 45X tax credits are being sold by manufacturers with investment grade credits ratings, which certainly makes those transactions much easier. 

The nuclear credits, the 45U—this is the first year it’s become available.  It’s still unclear how much will be available because it’s a subsidy when operating revenue is below a threshold.  Also, 45U regulations have yet to be released.  So that’s a potential wildcard. 

In terms of carbon capture and the green hydrogen tax credits, I think there’s a lot of potential, but it’s probably a few years away.  We do see a lot of large projects in the early planning stage and some of them are targeting financial close probably end of this year, early next year.  Then construction will take another two to three years before those credits will head to market. 

The timelines for most offshore wind projects are generally being pushed out. I think that probably two or three offshore wind projects are targeting financial close for later this year.  Those ITCs will probably be sold in late ‘25 or early ‘26.  Those are mega projects, but near term, most of the credits in the market need to be monetized. 

The projections published by many reputable sources in terms of the total installed capacity for wind, solar and battery in the U.S., are going from 40-50 GW to 60 GW p.a. We can take out the model and the calculator to see how many billions of those credits will become available each year.  A lot of them will elect ITC because the adders swing the project to ITC.  Some of them will continue to opt for PTCs. By our estimation, the tax equity market with the supplement of transferability should be able to provide sufficient tax equity to serve this sector—wind, solar, battery—in the coming few years.

Mr. Burton: Great, thank you.  Sergio, we mentioned offshore wind a couple times.  Will the projects being planned off the coast of New York get the financing they need?  Is that going to work?

Mr. Garcia: I think they will get the financing they need.  I think the expectations have to change a little bit.  I think at that point some of those were first proposed the developers were overly excited, extremely optimistic, and we saw what happened with projects being abandoned and PPAs being renegotiated.  There is a lot of appetite from the banks for offshore wind in New York. 

With offshore wind, it’s the infrastructure that’s needed.  We don’t have the right ports, the right boats, to do the GWs and GWs that our government has in mind.  However, the investment is getting done, so it’s not as fast as we would like it to be, but yes, there is appetite for those types of assets. 

Going back to tax credit transfer bridge loans without a committed tax credit buyer, it’s going to be dependent on the technologies. Technologies the banks know will have an easier time.  We know offshore wind.  We know onshore wind.  Batteries, utility scale solar and distributed generation (DG) solar, we’re comfortable with.  So to the extent that it’s ITC, that’s almost a no-brainer on the bridging to an uncommitted tax credit buyer.  Like Rubiao said, it’s based on a discount.  I mean, we’re not going to give you to underwrite an uncommitted and a committed tax credit sale the sale, but even a smaller loan buys the developer time; and, once you get a tax credit transfer agreement in place, then we can go to our 97-98% advance rate against.  Again, all things being equal, if you have a tax credit buyer that’s investment grade, it easier.  But it turns out there’s not as many investment grade  tax credit buyers in the market, as we hoped.

Lenders advancing against a sale of PTCs it a little bit challenging as PTCs are generated over 10 years. So unless you have Rubiao or one of these banks signing a 10 year agreement, lenders are struggling with taking the risk as to at what price there will be a buyer for the next 10 years. 

Mr. Burton: Well we’ll ask one more question of the panelists and then we’ll shift to audience questions.  So Julian, your company recently raised debt with an investment grade credit rating secured by community solar.  What did that take and what were the advantages of having that investment grade credit rating?

Mr. Erfurth: Yeah, so Nautilus closed a private placement last year in September.  Indeed a portfolio of 58 projects across seven states with investment grade rating, which was a first of its kind for community solar.  I heard that there’s some skepticism about community solar here on Sergio’s side; we also heard some positive views on Trond’s side.  I do think that we can all agree that community solar has come a long way.  It is still challenging to get debt on these projects because they are small with a lot of due diligence involved.  There’s a lot of forecasting in terms of what we all think the market will do.  But what we see is that lenders and institutional investors are getting more and more comfortable with it.  We are as I said, long term asset owners and putting a bond on these projects for 25 years obviously takes out a lot of the risk.  So we will raise another credit placement soon.

Mr. Burton: Great.  Alright, we’ll move to audience questions. We’ll take this first one first.  What is the number one thing you’d like to see that would make offshore wind easier to invest in? 

Mr. Song: I can speak from a tax equity perspective.  It’s hard to rank number one and number two but one of the top concerns is still the supply chain—the timing of a lot of project development depends on such the transportation vessels etc.  Those critical supply chain issues that are still delaying the development of these projects.  And I think we would also need to see a robust insurance market.  When we’re talking about Atlantic coast, hurricane risk is a real issue here and certainly we need significant coverage from the insurers.

Mr. Burton: Okay.  I’m going to go to this Basel III audience question, because it’s a topic of interest to many.  So the question is about the Basel III bank regulatory guidance: why would a prudential regulator assign punitive regulatory capital requirements for tax equity exposure? 

I will answer that question.  Basel III is a sort of worldwide agreement amongst bank regulators to have some uniformity as to how banks are regulated.  The proposed rules in the U.S. assign a 400% capital weighting for non-publicly traded equity.  And then they don’t really address tax equity, so therefore it would appear tax equity falls into the category of non-publicly traded equity.  Currently, tax equity only has a 100% capital weighting.  So if these U.S. Basel III rules come into effect, it would be 400%.

Tax equity investors like JP Morgan and Bank of America and other large banks that are subject to Basel III would have to put four times as much capital against their tax equity investments.  And there’s no grandfathering.  It’s retroactive if it applies.  But the person asks why would a bank regulator sign a punitive rate to it?  The answer is that it was an oversight.  It was not like the regulators—the FDIC and the Fed and such—went out and said “We want to get the tax equity market under control.  Those are a bunch of cowboys we need to reign in.”  They didn’t say that.  But they just kind of overlooked it.  They just didn’t—they didn’t address it, so therefore it fell into the bucket of non-publicly traded equity, and that’s a problem.  There’s been a number of letters from members of Congress asking for this to be addressed and the last time Jerome Powell testified about this issue, he said that they were working on addressing it and intended to address it.  Jerome Powell doesn’t say things lightly, so I take a fair amount of confidence that it’s going to be fixed.  They’ve also just talked about putting aside the whole Basel III and going back to the drawing board.  So, I’m pretty optimistic that it’s going to get solved, either with a carve-out for tax equity or Basel III not moving forward in the United States in its current form.  Let’s see there’s a question here—we didn’t give Trond much time during the formal part.  How is the NY Green Bank terms pricing compared to private lenders? 

Mr. Rokholt: You know, we claim to be a market-based lender.  Since we are there to fill gaps and hopefully transform the market to a point where private capital comes in, we need to price our transactions attractively for private lenders, and they need to get comfortable that transactions can be done at market terms.  So there are some exceptions to that rule, but that’s in general of NY Green Bank approaches the market.

Mr. Burton: Okay.  Stacey, maybe this one’s for you, it is about insurance in New York.  Please comment on insurance risks, difficulty getting natural catastrophe insurance on a national basis.  Should New York be a lower risk—a lower cost insurance due to lower possibility I guess of natural disasters?  So what’s the insurance market like for your projects?

Ms. Hughes: That’s a funny question because we recently redid our entire insurance coverage for our portfolio, and the state we have the most trouble with is New York.  The first pass from you know, a big insurance company, basically said you’re good in 49 states, but we made all these carve-outs for New York.  We found actually that we had to do a separate policy explicitly for two different groups: it was for solar in New York and solar for multi-family housing. 

Oddly enough, when we had to go get a second policy for those, we found workers’ comp to be really difficult in New York.  We’re finding that I think because of New York being litigation friendly—especially in New York City, but maybe throughout the state—where the insurers just feel like they get caught and it’s a more expensive place to do business. 

We did have some issues in New Jersey where there’s a lot of flooding and you know, it doesn’t hurt the panels necessarily, but you know, electrical equipment could be damaged.  And then in our latest package, any place where there might be a flood, they said, you know we’re not going to cover flood.  So that’s the insurance market for you, so you’ve got to kind of fight and deal with that.  But I would like to see particularly, New York City a little easier to insure.

Mr. Burton: Okay.  One last question.  We didn’t talk much about stand-alone storage so let’s take this one.  What is the outlook for financing stand-alone storage in New York?  Anybody?

Mr. Garcia: I think stand-alone storage is here to stay.  It’s growing throughout the country.  There’s appetite.  The expectations—I think it’s all about managing expectations.  People want to do 25 year financings on batteries, but they’re not willing to put in their budgets the augmentation schedules that come with it. 

At the end of the day, you could have a great battery with a brand new manufacturer. Well, we’ve seen new manufacturers with solar panels; historically, a brand new company comes in guaranteeing—gives a warranty for 30 years.  Then the company goes out of business three years down the line. Lenders are not just trying to make your lives difficult.  They are seeing what it takes to maintain these batteries in good operating condition.  It’s super important to keep the augmentation schedules appropriate.  Otherwise, a sponsor is looking at a seven year lending facility, which would have an underwriting assumption of maybe 2% degradation each year.  But there is a lot of appetite from banks for batteries and stand-alone batteries.  There’s plenty of incentives in New York to do that.

Mr. Burton: Okay.  Great.  We’re going to call that a day for the first panel.  Thank you panelists, thank you audience.

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[1] The proceeds of a tax credit sale are supposed to be tax-free to the seller.  When the seller is a partnership that requires an allocation of tax-exempt income to the partners, so that the distribution of the tax credit sale proceeds does not exceed the partners’ outside basis and result in taxable income (or reduce the partners’ outside basis, so that a distribution of operating cash that would have been absorbed by outside basis is instead a taxable distribution in excess of outside basis).  The allocation of the tax-exempt income to the partners must follow how the partners would have otherwise shared the tax credits, which is generally how the depreciation is shared, rather than how the cash is distributed.