Tax Equity Roundtable 2018
In September, PFR and Mayer Brown teamed up to bring together a panel of tax equity experts to review the latest developments and innovations in this fascinating area of renewable energy finance, as well as the outlook for the coming years.
To download a PDF version of the full report, click here.
The full transcript of the roundtable discussion is also provided below.
David Burton, partner, Mayer Brown
Jeffrey Davis, partner, Mayer Brown
Pedro Almeida, director of finance, EDP Renewables North America
Rich Dovere, managing member, C2 Energy
Kathryn Rasmussen, principal, Capital Dynamics Clean Energy and Infrastructure
Marshal Salant, head of alternative energy finance, Citi
Richard Metcalf, editor, Power Finance & Risk (moderator)
PFR: A major theme this year has been the impact of tax reform and the repercussions of that, in terms of investors perhaps leaving the market or having less appetite. What impact has tax reform had?
David Burton, Mayer Brown: I think the two largest effects of tax reform have been, first, that each tax equity investor, on a high level, has 40% less tax appetite than they did before. The second thing—which correlates to that—is that the depreciation benefit is worth less, so instead of a deprecation benefit being multiplied by 35%, it’s only multiplied by 21%, which means that sponsors are able to raise less tax equity than they were before for the depreciation benefit. Tax reform did not impact the tax credits themselves, other than the fact that investors have less tax appetite to offset with credits.
Jeffrey Davis, Mayer Brown: Because of 100% expensing—the so-called “bonus depreciation”—the tax benefits are potentially more front-loaded for any particular deal. So, when you have a taxpayer with lower tax capacity, it has to be a little more careful about either allocating its resources to different deals, or, alternatively, requiring that sponsors elect out of the 100% expensing bonus.
Kathryn Rasmussen, Capital Dynamics: I wouldn’t say that we’ve experienced huge shifts as far as how we’re viewing tax equity. There is, absolutely, less tax equity that we’re getting in our deals—that is partially offset by the fact that we can raise a little bit more debt.
However, we also have a bit of a benefit just from the fact that, post-tax, we have the lower tax rate as well. So it absolutely has decreased the amount of tax equity that we can raise, but not to a point that has significantly moved our view on the projects and the assets that we’re investing in.
Pedro Almeida, EDP Renewables North America: I think that outside of the factual implications on the amount of depreciation benefit, what we’re seeing is that the dynamics of whether investors want to allocate capital more on an ITC [investment tax credit] basis or if they want to invest in PTCs [production tax credits] and 100% expensing are changing. Because their tax capacity has shrunk, they’re more selective in allocating capital to the different alternatives in the market.
That being said, we always felt that there were different types of tax equity markets. We don’t feel that EDPR is affected and we don’t feel that the market has less depth. We just feel that the financial institutions and the typical investors are more selective. So, I think tax reform has mainly changed the dynamics in the market and how investors allocate capital between ITC and PTC and, as a consequence, then between wind and solar.
PFR: So yes, it is having an impact, but it might depend on the kind of sponsor or on the sponsor, to some extent?
Almeida, EDPR: Correct. I think there are projects that will always get the capital that they need, and that capital will be able to be raised very competitively.
PFR: Marshal, you were nodding there. What has been Citi’s response, or how has your activity adapted to tax reform?
Marshal Salant, Citi: It’s a very interesting question. We spent, as well as other people, a massive amount of time during the uncertainty before the bill was finalized, and particularly working with ACORE and other industry groups—literally hundreds of hours analysing scenarios—looking at what could happen.
And we agree with the conclusion David Burton reached. Where has that 40% number come from? If you were a hypothetical corporation and you made $10 billion of income, you used to pay $3.5 billion in tax to the federal government. Now you’re paying $2.1 billion to the federal government. And it’s that difference—when you pay $3.5 billion versus $2.1 billion, you’ve decreased your tax bill by $1.4 billion. That is exactly 40% of what you were paying.
That, theoretically, should impact the overall tax capacity in the market. There were also massive amounts of time spent by various parties in tax equity and a whole lot of other parts of the financial world and the legal and tax world on the so-called BEAT, base erosion anti-abuse tax. And in the end, I would say that it’s still not really clear what the impact is.
After all the analysis was done and we could think about all the theoretical impact that should occur, the reality is that for big developers with well-structured projects, I don’t think it’s really had much impact at all, which is maybe counterintuitive.
There’s a couple of banks that have maybe decreased what they’re doing. There’s others that have said it has no impact. There’s maybe one or two that look to have significantly pulled back. But overall, the amount of time spent talking about and analysing it seems so far to be far greater than the actual impact we’ve seen.
PFR: I’ve certainly heard people say that some tax equity investors, obviously not Citi, may have withdrawn entirely from the market as a result of tax reform, whether directly or because they just decided that it was too complicated and it wasn’t worth trying to figure out.
Rich Dovere, C2 Energy: We haven’t seen investors withdraw entirely. It almost seems like a negotiating stance. Where we sit in the market is different, in terms of project size, but if investor takes the position: “I’m leaving tax equity. I can’t do any tax equity,” to a certain extent, I think the response is: “But what if it were this much per credit? Or what if we did this yield, would it make it that compelling?”
Burton, Mayer Brown: I think a handful of multinationals have exited the tax equity market, reportedly due to BEAT, but that’s been made up by, generally, smaller players entering the market. They’re realizing that the after-tax returns are compelling compared to what they could earn on other types of investment, or for ESG [environmental, social and governance criteria] reasons.
Rasmussen, CapDyn: We’re seeing a lot more first-time, second-time tax equity investors who may be sitting behind a seasoned tax equity investor who is selling down their position on the back end or post-closing or syndicating a piece of it upfront.
Salant, Citi: Anecdotally, we believe there are one or two players that have essentially pulled out. But when you ask them, they typically say, “Oh, that’s not true. For our best clients and the right project, we might still be able to do it.” So it’s very hard to pin people down on this.
It’s certainly not good for the supply/demand imbalance in the market, but it didn’t have the overwhelming impact that people thought it was going to have.
Almeida, EDPR: I tend to agree with Marshal. I feel that, at least in our investor community, the people we talk to, we haven’t heard anyone say they’re out of the market.
PFR: I think might also be worth pointing out that the major impact, if any, on an institution’s ability or willingness to invest tax equity will be much greater on those that are either foreign or have a lot of overseas business. So it may not have affected U.S. regional banks as much. Is that fair?
Burton, Mayer Brown: That’s fair. It would be relatively surprising that it impacted U.S. regional banks. But foreign-owned banks or U.S.-owned banks with big foreign operations, in some circumstances, can have an issue with BEAT. BEAT, also, is going to get more challenging in future years. Currently most of the tax credits are permitted under the BEAT calculation, but that’s going to change down the road.
Davis, Mayer Brown: Another interesting aspect of the BEAT is it’s calculated year-by-year, and therefore, for any given year, a bank or an investor must project what its taxable income, deductions, earnings strippings, payments and so on might be, so it can determine whether it’s going to be in the BEAT and figure out if it can benefit from the tax credits.
It has already set up a difference between PTCs and ITCs, where the ITC, because it’s upfront and determined based on tax basis, is more predictable and an investor can look at its income and expenditures and determine whether it thinks it will be subject to the BEAT in the year the ITC arises. Whereas with the PTC, because you’ve got the ten-year stream based on production, it’s a little more challenging. It’s hard for anyone to predict what their income is going to be next year let alone ten years out.
PFR: Going back to something that Kathryn mentioned, which is syndication and smaller investors coming in behind a seasoned investor, is that something that you’ve seen more of recently?
Davis, Mayer Brown: I’ve seen more new investors taking that very approach. Either they will come in after a tax equity investor that’s more seasoned has signed a commitment, and they’ll take a piece of that prior to funding—and that’s failry common in an ITC deal—or there are some cases where the first investor puts a tax equity partnership on top of the tax equity partnership and sells an interest in that. That’s oftentimes accompanied by risk mitigation features and other things that might make it more attractive to an investor that’s not as familiar with the underlying assets and the risks that are inherent in renewable energy projects.
PFR: Marshal, does Citi sell down tax equity in this way?
Salant, Citi: We act as principal, we also act as agents. The answer is: yes, we do both.
The good news is that if you’re a sponsor looking for tax equity, there are some new participants, there is a little bit more liquidity, we are seeing more almost like secondary trading in PTCs.
The bad news is that the tax complexity has not changed. On the ITC, it’s a very narrow window and you can’t sell down after the deal closes. It’s impractical for that to really work. Whereas with PTCs, you could hold it for a year and then sell off the back nine years. You can’t do that with the ITC, but you do have that window between commitment and funding, or between first funding and second funding. And we’ve been a big player in that market, to the extent it makes sense.
Every large tax equity investor I know has spent the last couple of years, if not five years, trying to develop new investors, with mixed successes. There were a couple of highly successful cases, but in the past there’s been a lot more talk than actual action. Lately, we’ve seen a little bit more pick-up, and that’s been great for the market.
The reality is, for the really big players, who need a couple hundred million of tax equity, getting new entrants or regional banks in who are writing checks for $7 million, $10 million, $15 million, $20 million doesn’t really work for them, because it’s too unwieldy to have ten different $20 million pieces club together trying to do a $200 million deal. So for that market, they’re still dependent on the big players.
There’s a handful—people debate the numbers, but probably between 15 and 20—of large tax equity investors who can lead and negotiate deals, which is good for the tax equity, but it’s also good for the sponsors, because they know what they’re getting. And then there may be another 10 or 20 who come in behind those people, because if you’re a first-time investor, it’s helpful to tell your superiors or your board: “Look, we’re behind Citi,” or behind somebody else who’s been doing this for many, many years. “They know what they’re doing, so they’re going to make sure that the transaction has no surprises.”
That is a logical way to increase the volume, and I think that’s been mostly what’s happening. There are some new entrants that want to deal directly on their own and, hopefully, that will develop over time also.
Rasmussen, CapDyn: I definitely agree—more investors is definitely a good thing, especially on the sponsor side. But there is some hesitancy on our side to deal with first-time investors, so unless there’s a very compelling case, we much prefer having a situation where we have a seasoned provider.
Almeida, EDPR: I agree. Let me start by saying that we embrace new investors. For the last five years, there has not been a year in which we haven’t brought one or two new investors into our portfolio. We’re also fortunate enough that most of our investors, as a rule, like to hold their investments until they’ve flipped, the exception being if we see any syndication pre-funding, which is rare, in any event.
From a sponsor perspective, we need to have certainty on execution. We have our capital commitments and delivery obligations in terms of CODs [commercial operation dates], in terms of megawatts that we want to put in the ground. Last year, for instance, we made a deal, $440 million, with a single investor. Not a lot of investors can do that.
But I understand that syndication makes sense more and more now, because if you have this mix of uncertainty around what is your tax capacity and you pair that with the uncertainty of when will the assets be placed in service, especially if you’re investing ITC—is it this year? is it next year?—that can have a big impact now with the lower tax bills.
Salant, Citi: It’s also important that we remember that when we talk about the tax equity market, that’s difficult to view as one homogeneous market. We’ve been saying this, as have others, probably for at least a year or two now: we’ve seen massive bifurcation in this market.
There are certain big, giant developers who have great relationships with banks—we’ve done deals with Capital Dynamics, we hope to do deals with EDPR—they’re big, well-established players. And when an EDPR, a NextEra Energy, with an investment grade balance sheet, comes to you, there’s one way to deal with transactions like that. They can raise all the tax equity they want. They can get a couple hundred million, they can deal with the big players, they’ll even get oversubscribed if they want to.
The disconnect in the market is, you can go to a conference and hear people like them talking about how they’re oversubscribed, what’s the problem? The fact is tax equity investors are trying to get into their deals that can’t. But then you hear that for every big, giant developer there may be five to ten little developers who are running around going: “I can’t raise a dollar. What’s wrong with this?” And it’s because as of the last year or two, or maybe even three, the tax equity market isn’t one market any more.
Burton, Mayer Brown: I think there’s definitely bifurcation as you describe it, and there’s also bifurcation around structure. There’s the older, more experienced tax equity investors who maybe started in wind, and they tend to use an IRR [internal rate of return]-based flip structure and to structure even their solar deals more like a wind deal. And then there’s, typically, smaller investors in solar, newer investors in solar, who don’t have the wind experience and don’t necessarily have all this sophistication, and they prefer investing based on a time-based flip, where you don’t have to calculate the IRR and worry about getting that just right. That’s much easier for a smaller, newer investor who doesn’t have the sophistication of a Citibank to deal with than the kind of PTC, after-tax, IRR-style structure.
Dovere, C2: C2 definitely falls more into the middle-market developer bucket. The difference being that we started four years ago, with a balance sheet growing organically, but quickly. We view ourselves in another subsection of the tax equity market where there’s the guys running around who can’t raise a dollar and there’s firms like us with $150 million balance sheets who can raise the tax equity that we need.
We were typically doing it deal-by-deal, because it was harder to attract institutional attention without a very large fund or an investment grade balance sheet. And so we have actually been in what I think is a very positive position, where we are able to pick up the smaller opportunities from the guys who can’t raise tax equity and function in an effective aggregation role as well as have our own development assets and balance sheet, and to be able to work with tax equity to a point where we can start to garner more institutional attention.
As relates to David’s comment about the time-based flip, the structures tend to be modelled off of a U.S. Bank structure. And I think that, actually, if they were to stipulate an IRR-based flip, it would be such an egregious number to even put on a document to make it equivalent to a six-year flip that it’s just easier and more polite for them to do it as a time-based flip, because the IRRs that they’re getting are already so high. It looks like a polite way of no one actually having to acknowledge what that cost of capital is.
But I would put us in that middle tier of the market where we can get the tax equity that we need. It’s a lot harder and a lot more time and brain damage, especially for the individuals on the team that have to do the tax equity structuring. So that’s, hopefully, what we’re aspiring to move out of, but that’s where we have also created a business opportunity in the market, because if you’re a developer and you’ve got 3 MW to 5 MW, you’re not getting that thing tax equity-financed unless you’ve got a high net worth contact. We’ve seen deals trade away from us that we would otherwise buy in that size range because there’s a local high net worth individual and they are going to do the tax equity. That’s not a market—that’s a one-off situation.
Salant, Citi: Yes, and to clarify, I overstated when I said they can’t raise a dollar. That’s the extreme case. What I literally mean is there are many smaller developers or new developers for whom it’s just very, very difficult. Hopefully, they get there eventually, but it’s not like an EPDR who can put out an RFP [request for proposals] and say, “Here’s our portfolio,” and send it to the 20 big players who are investors and have 10 of them say they want to be in it. It’s not even close to that. It’s the guys who can spend weeks and months knocking on doors, trying to raise the money that they need. Much harder.
Almeida, EDPR: Yes, I totally agree with Richard. And I think that aggregation trend that you guys are seeing on the lower tier of the market, I think we, to a certain extent, can also play a role in consolidating some of the opportunities in the middle market.
There comes a point in which I think any developer will, more so in the current environment, given the new rules of the tax equity market, ask themselves whether it makes more sense for them to continue developing the project or think about consolidation and maybe bring it to us at a level where we still can have a meaningful say in how the project is structured.
Because I think we don’t raise competitive tax equity only, or probably not at all because we are big. We raise competitive tax equity because we develop our projects and build them to certain standards, and we look at revenues that have a certain pedigree. And for us to be able to package that and bring it to the tax equity market, we need to be involved at an earlier stage.
We foster these relationships with middle market developers that have assets, but why would they continue developing them and feel that they would be squeezed on the tax equity market if they can work early on with sponsors that have the size and the capability to shape the product in a way that it’s more sellable on the tax equity market?
Burton, Mayer Brown: The other thing about smaller deals, D.G. [distributed generation] deals, is that they each have their own contracts. So if you do a deal with EDPR, as you just said, you pretty much know what the PPA [power purchase agreement]’s going to look like, you know what the O&M [operations and maintenance] agreement’s going to look like, the land rights, all that stuff. You do a residential solar deal, right, it’s all pre-baked, it’s “take it or leave it”. Mr. Jones is not negotiating his PPA with the resi solar provider.
But D.G. is in the middle, and most D.G. customers are big enough to have a general counsel who’s like, “I need this to be under Oklahoma law,” or whatever his or her view is, and so they’re negotiated. And they’re different, and that makes the diligence very expensive and time consuming, and then it’s a smaller transaction on top of it. So you have many factors stacked against these D.G. transactions. They are getting done, they are profitable, but it takes a lot of elbow grease on both sides of the table to get it done.
Davis, Mayer Brown: I want to go back to David and Rich’s point about the two different structures that we’re seeing in the market. The suggestion was that the investors that are doing the time-based flips may be less sophisticated. I think it’s also in part a product of their view of commercial risk versus tax risk. Those investors that are doing the time-based flips are oftentimes more willing to take a little more tax risk to minimize their commercial risk.
And I think it’s in part because a lot of those investors may have had a history in either the low-income housing space or the historic tax credit space, and similar structures have neem frequently used there.
PFR: Let’s talk about pricing. If anyone would like to say a figure, they’re absolutely welcome to, but what I’ve been hearing is, this year, around the 6% to 7% range for tax equity. We’ve been talking a lot about the bifurcation into two different markets. Does pricing also come into that?
Dovere, C2: Yes.
Burton, Mayer Brown: Absolutely. But the 6% to 7% range, that’s a quote for a PTC deal or somebody doing a solar deal using an IRR yield-based flip. If you’re doing a time-based flip, there is no IRR, so that 6% to 7% doesn’t really mean anything. They tend to quote in terms of dollar-per-credit instead.
PFR: And can you put any figures on that?
Dovere, C2: It’s a function of how much cash you’re taking. At the highest end, we’ve seen $1.38 a credit, which is not really fair comparison because it’s a different dynamic. And the lowest we’ve seen… You know, at the beginning of the year we were getting $1.05, and that same investor’s now at $1.15, $1.14, and it’s just a function of how much of a preferred return they’re taking. These are all modelled after the U.S. Bank structure, which, I think, prior to tax reform was $1.20 to $1.25 a credit, with a 2% pref.
Almeida, EDPR: Rich, any time I’m asked about pricing, I always say that it’s too high for the risk profile of the investment.
Dovere, C2: I forgot to say that too!
Almeida, EDPR: If you look at, let’s say, a long-term bank project finance or—more traditional in the U.S.—a back-leveraged deal, that can be in the 4% range. If you look at an equity investment where someone comes in, takes equity risk, the unlevered returns are going to be in the 5% to 6% range, if the asset is a quality asset. So if tax equity prices between 6% and 7%, and you’re talking about a preferred return investment, senior to both back-leverage and equity, that can only be explained by the dynamics of the market and the balance between supply and demand.
It’s not as outrageous as it was some years ago. I think everyone is working to make the market more liquid, to bring the supply and demand closer together. But still there is a spread.
PFR: So, still too expensive, in summary. And the figure that I’ve heard is, on a return basis, 100 basis points lower than at some point last year.
Salant, Citi: The discussion of pricing has always been an annoyingly difficult conversation in the tax equity market. Those of us who have been to various industry conferences for ten years, lawyers will ask questions of a panel, and not one person will admit a number, which is crazy. But they’re all private, bespoke, negotiated transactions, so nobody ever wants to quote a number. Once or twice I threw out numbers, and people yelled at me: “Why are you throwing out a number?”
Clearly, for ten years, sponsors have felt tax equity was too expensive, and I can understand why they felt that way. When you look at it from the outside, it’s just the financing cost that looks high, and it is, because of all the complexities. It’s because of the need to use your own tax capacity for the partnership structures, the internal accounting, the GAAP accounting, below the line, above the line, not helpful to earnings… The structure, from day one, does everything it can to make it unattractive for the reporting company to be a tax equity investor, yet we have to provide a tax equity and we have to put massive amounts of capital against it.
So it’ll never be something that people think is appropriately priced, because all the internal machinations banks and others have to go through to be able to do the transactions are very painful.
What you can say is that in the last year, yes, levels have gotten lower. And if 6% to 7% is the right level, where it used to 7% to 8% or even 8% or higher, what is interesting is that just about every debt rate you can think of let’s say, in the last six months, 12 months, they’ve tended to go up a little bit, and spreads have widened. To the extent people felt it was way too expensive, maybe it’s less expensive today, because it doesn’t look quite as bad relative to other things.
Burton, Mayer Brown: The other thing is that within the institution, within the bank, the tax equity does compete with other desks for the tax appetite. So, for instance, if you do low-income housing tax credits, you get Community Reinvestment Act. If those deals are paying, let’s say, 5%, tax equity’s going to have to pay something materially higher than 5% in order to persuade the bank not to just do all the low-income housing tax credit deals.
Dovere, C2: Or, like us, you have solar deals that serve low-income housing. Our tax equity partners were very excited about that.
PFR: I’ve heard quite a bit this year about regulated utilities looking to own more renewable energy assets directly rather than contracting them through PPAs. I’m curious about how that affects tax equity, whether utilities use third-party tax equity to finance projects, or their own tax base, and when you’re developing a project and if you’re going to sell it to a utility company, how that affects the dynamics there.
Burton, Mayer Brown: The first thing is that ITC is subject to normalization, which is a complicated tax issue for regulated utilities, but, basically, it makes ITC relatively unattractive to regulated utilities. The PTC is not subject to normalization, so you have a first fork in the road between ITC and PTC.
If it’s an ITC deal, the regulated utility is probably going to want to do it as a PPA and not own it itself. If it’s a PTC deal, they may very well want to own it themselves and rate-base it. And that can be very attractive to them to both get the PTCs and to be able to rate-base it.
They have to have tax appetite to be able to use the PTC, of course, and a lot of the utilities for a while didn’t have tax appetite because the regulators were typically making them claim bonus depreciation, which would wipe out or exceed their tax appetite.
One of the things tax reform did is that it instituted an interest limitation rule of, basically, 30% of EBITDA, as the limit on your ability to deduct interest. But that rule is not applied to regulated utilities. However, a trade-off for that was that regulated utilities agreed to not be able to take bonus depreciation. So the regulated utilities no longer have their regulator saying, “You have to take bonus and pass through that benefit to the consumer,” so now they have more tax appetite. So them owning wind PTC deals themselves and claiming PTCs themselves is potentially an attractive proposition.
Salant, Citi: Again, it’s part of the supply/demand imbalance. You had all the backlog of transactions, what I call the normal-way business that people already try and do. Add to that the repowerings that people now want to do, which throws a whole new chunk of transactions out there that probably will want tax equity. Coupled with the fact that there are people who have had their tax positions change, or some publicly disclosed situations where people are in the market selling portfolios of tax equity, so you’ve got secondary sales of tax equity that has to find buyers. And we are aware of a couple of utilities that, for the first time, are looking for tax equity investors for their big portfolios, because they may have capacity, but they don’t want to use it all for this and they actually would like to monetize some of it. And then add to that, hopefully, just off the horizon, the offshore wind market finally developing in the U.S.
So the problem is, when you take all the regular-way business and you add repowerings and secondaries and big utilities and offshore, you could have a very significant increase in the need for tax equity. And the question is: are these positives on the investor side going to be enough to absorb all of that new product that may need a home very shortly?
PFR: I’m glad you mentioned offshore wind. A lot of states, especially on the East Coast, are looking at offshore wind. New Jersey just made an announcement on that topic this week (PFR, 9/18). These projects are very large and expensive. What challenges do they present when looking to take advantage of tax credits?
Davis, Mayer Brown: The size and the cost of the projects presents a challenge by itself, because the sponsor has to be able to arrange enough tax equity financing to finance the project. And given the cost of the project and the fact that the wind projects that are offshore typically claim the ITC because of those high costs, there’s a large credit upfront—a big hit in one year. So you need either an investor or, more likely, a number of investors who are able to absorb all of those tax benefits in the first year. That’s why, as Marshal knows, Citi and General Electric were co-investors in the Block Island transaction.
Another complexity that that introduces is with respect to negotiations with the sponsor. The sponsor now has to deal with multiple investors, each of whom is typically a large institutional investor that has very strongly-held positions on certain issues, and they may not be the same issues from one investor to the next, so the developer has to figure out how to address each of those investors’ issues to keep them at the table. So that, obviously, presents a lot of challenges for the sponsor in trying to round up the club of investors for offshore wind.
Rasmussen, CapDyn: I think there’s no doubt that it’s going to be a major part of the North American market. It has been lagging compared to Europe, where it is an established industry, so I think it’s also a new market for tax equity. We do think that offshore is something that we’ll be looking at, and how it’s going to fit into our portfolio, but one of the struggles that we anticipate having is just the fact that it is a new market and you’re dealing with other construction issues, other cost issues, even just tax equity players coming into that market for the first time. So I do think we have some of those hurdles that we would expect to see.
Davis, Mayer Brown: An additional challenge has to do with the development timeline. Because the IRS has basically given you the four-year window from when you start, which could be as much as five years if you start early in year one. And given the permitting and approvals and various hoops that developers have to jump through, they may find that they’re butting up against the end of that four-year period. And tax equity, typically, doesn’t want to invest in deals that aren’t in the four-year safe harbour, notwithstanding the delays may have been because of various things that are permitted in the IRS guidance. So that’s a real challenge.
Almeida, EDPR: EDPR has offshore experience in Europe, and the reality is that offshore projects make sense when they’re big. And so, if we have a capital constraint because of what you are saying, because people don’t want to have ten investors in one deal, they just make the projects smaller than they should be. And that is, from my perspective, hindering the competitiveness of offshore, and there should be a solution for this.
But, interestingly enough, even though the tax equity ticket is large, just because the project is big, the percentage of the tax equity for an offshore project is smaller than for a typical onshore wind project. That is interesting for us, because we can bring more debt into the mix, but it creates different dynamics, because the tax equity investors, the tax equity investors also need to deviate from some of the traditional dos and don’ts of the structure and be able to come up with structures that accommodate a much larger debt component than your traditional onshore wind.
Burton, Mayer Brown: One thing that is hopeful on the tax side for offshore wind is that most of the RFP responses for offshore wind are including storage.
PFR: Battery storage?
Burton, Mayer Brown: Battery storage. And that’s a nice fit with offshore wind, because offshore wind could qualify for the PTC or the ITC, but because of the high cost, the conventional wisdom is the ITC is more attractive because the 30% ITC exceeds the present value of the PTC.
And then if you have an ITC project that charges a battery, you can claim ITC on the battery as well. And conventional wisdom has been that if you had a PTC project charging a battery, it may not qualify. So the fact that offshore wind, for commercial reasons, is going with battery storage, and the tax law conveniently facilitates the pairing of offshore wind and battery storage, is helpful for the projects.
Davis, Mayer Brown: The statute requires that in order for equipment to be eligible for the ITC, it has to be electric generation equipment. The batteries by themselves aren’t generation equipment, but the IRS has some old regulations that say that storage equipment can be eligible—and that has been found to include batteries under private letter rulings—presumably under the notion that they’re part of, or integral to, some generating facility.
However, it may be difficult to get around the literal language of the statute, and for that reason there’s a strongly-held view that you can’t claim the ITC on batteries that are part of a PTC wind farm. In my view, that’s an area where the industry should be pushing the IRS for additional guidance, because the stakes are high enough, and as David points out, with all the RFPs that are looking to include batteries, it’s an issue that we’re going to see repeatedly. Although the IRS guidance project for what equipment qualifies for the ITC has been dropped from the IRS’s priority guidance plan, I understand from an IRS official that it is still open but guidance won’t be coming out until 2019.
Salant, Citi: We’d like to think at Citi that we have good experience here. We did the Block Island deal, the Deepwater Wind deal, as was mentioned. We’ve done a lot of deals in Europe. For example, we did the Walney Extension off the coast of England, which is the largest offshore wind farm. So because of that expertise, we get asked to talk to clients and potential clients about this.
There are all these technical challenges on the tax side. What does continuous work really mean when you’re out in the ocean? And you’re not going to be able to show that you did a lot of work onsite…
PFR: …building roads and things.
Salant, Citi: Yes, there’s a lot of language about roads. Well, that’s not going to apply for the thing you’re building in the ocean. And the numbers are big, and we have to convince everybody about the risks.
I think it’s fair to say, in Europe there’s not a big premium between financing, offshore versus onshore, because they have the history, they’ve proven that they can do it. In the U.S. we’ve only got this one little project that’s very successful, but it’s small compared to the ones that are coming. And when you go to do multi-billion projects, it’s going to require a lot of people participating, with a lot of capital, and we’re going to spend a lot of time talking about the best way to do it.
PFR: So onshore wind-plus-battery-storage, in particular, has this mismatch between the PTC and the ITC. But there’s been solar with battery storage integrated into it, and I guess that’s a slightly simpler proposition from a tax equity point of view. Has a lot of financing been done on that basis so far?
Burton, Mayer Brown: It depends on what a lot is. There have been a number of projects that have combined solar and storage, but it’s not every project, it’s not half the projects, but it has happened.
And even that has tax questions about. An early IRS ruling said, “You just have to charge it with the solar, you’re fine.” And then the most recent ruling, which is still a couple of years old, said, “Well, if you charge it less than 75% with solar in the first five years, you fall off a cliff and you have to pay back the ITC.” The IRS analysis in the rulings has evolved to reach that determination.
Davis, Mayer Brown: The easy case is the battery is built at the same time as the solar project. It’s co-located, it’s under the same ownership, and the battery is charged 100% from the solar—there’s nothing coming from the grid. It becomes a little more complex where, as David talks about, you get into the dual-use property rules, because the battery is now charged by the grid for some portion of time.
Other facts that make it a little more complicated might be the batteries aren’t co-located. They’re not right there with the solar project, they may be located somewhere else, or they may be owned by a different party. And these are things that the IRS has not yet addressed and that the industry’s struggling with, underscoring the need for additional guidance.
Almeida, EDPR: Let me give another example where the current status quo might be hindering innovation. We are looking at hybrid projects, wind and solar, in our other geographies, and potentially those could have storage as well. You would be able to put together an energy product that is shaped more appropriately. You might be able to use the infrastructure that’s just sitting there, and so wind could use it part of the day, solar could use it at another part of the day. How do we deal with that under current tax guidance?
Davis, Mayer Brown: Pedro raises a great point, because the diurnal nature of wind versus solar, you’re going to get solar just during the day, but you get your best wind at night. The so-called hybrid project would allow you to potentially use some pieces of equipment for both solar and wind and therefore cut the cost of having a certain megawatt capacity of wind and a certain megawatt capacity of solar.
In fact, I submitted on behalf of a client a comment letter to the IRS requesting guidance on that very point. There are really compelling arguments that you ought to be able to use that type of hybrid equipment and claim the PTC for the wind production and the ITC for the solar equipment, but we’ll have to wait to see whether the IRS agrees.
Dovere, C2: I would love for that to be the case. But as far as the storage goes, it’s actually something that we think is very exciting on the D.G. side. We’re going to retrofit our projects with storage. We’re only talking about building a couple megawatts of new projects that will have it, but we basically just negotiated that if there’s anything that tax equity has a problem with, we’ll just take the tax credit ourselves, so just allocate 95% to us. There’s obviously a functional limit to that, but it’s still a couple million dollars a year worth of batteries.
PFR: It strikes me that a lot of these difficulties with integrating different technologies will be resolved when the PTCs go away entirely, because there will be no compatibility issue any more. Are people thinking already about the phaseout and how that will affect financing, or is it too early?
Salant, Citi: Absolutely, we’re thinking about it. But right now, for all intents and purposes, as a practical matter, it’s a bit early. I won’t say too early, but a bit early.
Rasmussen, CapDyn: It’s never too early to start thinking about the future and what our future funds are going to look like, where we’re going to allocate our investment dollars in the future. However, if it’s qualified for the safe harbour, you have four years to do it. That’s another five years, essentially, a little over five years from today. And a lot can change in five years. We’ve seen costs dramatically go down. How much more they can go down… We’ll see. But we do expect there will be improvements in production, whether it’s more efficient turbines or more efficient solar panels. A number of things are going to feed into what the landscape looks like in 2023.
Burton, Mayer Brown: In terms of the extension, that’s really a political judgement, and I know my political crystal ball has been not working too well since 2016, but I think there’s a possibility of an extension given the right president and the right Congress. But we’ll have to wait and see.
PFR: And under the existing schedule, there would still be a 10% ITC for solar projects, that there is no existing plan to get rid of that, right?
Salant, Citi: That is correct, yes.
PFR: And, also, there’ll be depreciation, so there may still be a role for this kind of structure beyond the planned phaseout?
Burton, Mayer Brown: Right, I believe so. Ten percent ITCs are much smaller than the current 30%, but it’s still a material number that I think people would want to monetize. The 100% expensing ratchets down over time, but you still have five-year MACRS [Modified Accelerated Cost Recovery System] depreciation, which is still relatively accelerated. And there were always and are tax-oriented deals done on equipment and things that don’t qualify for tax credits. So I think there’s always going to be some structuring and tax planning and tax motivation as long as there’s some level of tax credit and accelerated depreciation available.