Wind tax equity market
Two prominent tax equity investors, whose banks accounted for roughly 30% of the big-ticket US renewable energy tax equity market in 2015, and two wind developers talked to a packed room in October in New York about the current state of play in tax equity. The discussion took place at the annual finance conference organized by the American Wind Energy Association.
The panelists are John Eber, managing director and head of energy investments for J.P.Morgan, Jack Cargas, managing director, Bank of America Merrill Lynch, Dan Elkort, executive vice president and general counsel of Pattern Energy, and Martin Torres, managing director at BlackRock and formerly on the tax equity desk at Morgan Stanley. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: Most wind companies have been focused on starting construction of as many projects as possible before year end to qualify for tax credits at the full rate. Those who can afford to incur at least 5% of the project cost have already arranged to do so. Now is the time of year when companies who lack the money to incur 5% of the cost start thinking about limited physical work at the site on turbine foundations or roads or at the factory on step-up transformers. They want to be in a position to raise tax equity later. What advice do you have for them?
Physical Work Test
MR. CARGAS: The physical work test is challenging to satisfy as there are some grey areas around interpretation of the test. The more work completed before the construction-start deadline, the better. It is important that sponsors keep detailed records, including construction logs and time-stamped photographs, and hopefully have those records verified by an independent expert. We will invest in projects that relied on the physical work test.
MR. EBER: Projects that rely on the physical work test could be more difficult to finance. There will be investors who will not want to take the risk on such projects. I would encourage developers not to be thinking about doing the least amount possible and thinking in the opposite direction, either incurring at least 5% of the project cost or going as far as they can on initial physical work so that they are well beyond what they think might be necessary.
MR. MARTIN: This is the fourth time that the wind industry has faced a deadline to start construction. What lessons should be drawn from the last three times?
MR. ELKORT: We have observed over the four successive extensions that the tax equity market has gotten tighter, the thresholds for establishing start of construction required by tax equity have gotten higher, and the terms of tax equity financing have gotten tougher.
The start-of-construction requirement has not changed, but if you approach starting construction like you did four or five years ago, I think you will meet a relatively unresponsive tax equity market.
I would flip the question that you asked Jack Cargas and John Eber to you, Keith. On some level, the tax equity market responds to the opinions of tax counsel. When we started looking into this in terms of how much physical work we needed to do, we reached out to a couple tax equity counsels and got a sense of how much work they would require in order to write an opinion that construction started in time. So rather than asking them, I think we should ask you: What do you require to give an opinion?
MR. MARTIN: If we are talking about work at the project site, we like at least 10% of the turbine foundations dug to at least six feet. They must be used in the project. You should be far enough along in your planning that you have an idea what turbines will be used and how they will be positioned so that the turbine foundations do not have to be re-dug. Alternatively, we like to see at least a mile of turbine string roads finished to the permanent surface. It is even better if you can do both.
Let me ask another question related to this. The production tax credit will phase out after this year. If you start construction this year, you get the full PTC. It phases down in amount over the next three years 2017 through 2019. The following question is for our tax equity investors: when the PTC starts phasing down, do you think wind companies will be able to compete for your attention with the solar companies who will still have full tax credits?
MR. CARGAS: I think there will continue to be investor appetite for transactions that allow for a single investment of a large amount of capital while spreading the use of tax capacity over 10 years. Therefore, my view is the tax equity market will remain interested in wind projects despite the decreasing importance of PTCs to the economics.
I think the question ought to be to the sponsors: how much value will the sponsors attribute to the PTC after it starts declining in value?
MR. MARTIN: We will ask Daniel Elkort and Martin Torres in a moment. John Eber, do you think wind will be able to compete with solar after tax credits for wind projects start phasing down?
MR. EBER: We probably have about four years before we have to worry about that, given that everyone is out starting construction of as many projects as they can in order to qualify for tax credits at the full rate. I am hoping we do not have to face that question for a number of years.
Competition With Solar
MR. MARTIN: Will wind projects that qualify for PTCs at 80%, 60% or 40% of the full rate be able to compete for tax equity with solar projects that still have several more years to start construction to qualify for tax credits at the full rate?
MR. EBER: That is probably the better question. I think the answer is they will have a serious challenge.
MR. MARTIN: A serious challenge. Daniel Elkort, Jack Cargas asked whether projects are economic at 80% or 60% of the full PTC rate. Where is the break point?
MR. ELKORT: We are starting to analyze what happens to projects with PTCs at 80% of the full rate. We still think they are economic, but keep in mind this is in a market in which PPA prices are also falling steadily, and that is as alarming to a sponsor as the decline in the PTC.
At a certain point, tax equity becomes pretty expensive. It is already expensive capital now and as you reduce the amount of the PTCs, then the percentage of your capital that is coming from tax equity goes down.
MR. MARTIN: Or you have to give more cash to the tax equity investor to raise the same amount of tax equity, which is too expensive at tax equity yields.
MR. ELKORT: Correct. If we are going to maintain ever-increasingly competitive projects, we have to bring in lower-cost capital. So John Eber would either have to reduce his prices or loosen up the restrictions on leverage so that we can replace the reduced tax equity with cheaper debt.
MR. MARTIN: The trend in the solar market has been for solar developers to keep as much cash as possible and then monetize it at a debt rate through back leverage. We have not seen that in the wind market. Why not?
MR. TORRES: Maybe it is just not as visible. We have seen a number of wind projects that have been financed with back leverage. While I was at Morgan Stanley, we participated in a number of those transactions, but the transactions are not necessarily as public as asset-level financings.
I want to go back to the question you asked Jack Cargas whether it makes sense to have tax equity as part of the capital structure at an 80% PTC rate.
It is a math exercise. You can figure out what the incremental cost is from a return perspective to structure the capital without tax equity and carry the PTCs forward to shelter income from the project.
MR. MARTIN: John Eber, you are always looking for new tax equity participants to bring in as co-investors. Do you see more investors coming into the wind market? If so, what kinds: corporates, insurance companies, whom, and how many active tax equity investors do you think there are currently in wind?
MR. EBER: We count 32 investors in the energy tax equity market. Not all of them are investing in both wind and solar. Probably 23 of them are interested in wind. The wind market is probably up five or six institutions from where it was a year ago.
The investors are there. They are big companies. They are putting a lot of dollars out and their participation is part of a trend of a gradually expanding marketplace. Part of the problem for new investors is just getting in on deals. Those of us who have been in the market for a long time have relationships with the sponsors, and we tend to see the deals first. It is hard for some new investors to break in. That said, there is more than enough capital, and it is coming mostly from big financial institutions.
MR. MARTIN: We have heard from some corporates that they earn more by putting their money into their own businesses than they would earn in the tax equity market.
MR. EBER: Yes, we have heard that for years. That is pretty much a standard refrain we get from most of the corporates we talk to about investing.
MR. MARTIN: Martin Torres, Daniel Elkort, you are out looking for tax equity. Do you agree with the numbers we just heard from John Eber?
MR. TORRES: I agree directionally. We have seen a number of new entrants, particularly insurance companies. While it is great to have new investors, execution risk is something that we focus on quite a bit. Tax equity financing is complicated. There is a much greater risk in working with a new entrant unless it is part of a club with more experienced investors.
MR. MARTIN: John Eber, at the REFF conference in New York in June, you said that falling electricity prices mean there is less cash in tax equity deals and that is creating structuring challenges. What are those challenges?
MR. EBER: The primary challenge is with deficit restoration obligations. The DROs are creeping up in amount and they are taking longer to reverse. The tax losses are still the same as before and, in fact, maybe greater, but there is less taxable income to reverse a deficit capital account after the deal turns tax positive. The economics of the underlying deals are a lot weaker. This means tax equity investors have to agree to higher DROs to absorb depreciation. Some investors are less comfortable than others with the size of the DROs.
MR. MARTIN: Let’s focus on that. Would you say today that DROs are getting to 42%, 43% of the original investment? Is this due solely to the paucity of cash?
MR. EBER: I would not say the typical wind deal is at 40% yet. That is the upper end of the spectrum.
MR. CARGAS: The big driver is paucity of cash, as you put it. The paucity of cash has led to a couple of other challenges as well.
One of them is there is more pressure on the pre-tax internal rate of return. Investors need at least a minimum pre-tax IRR. It is harder to get there in deals with less cash. There is also pressure on downside scenarios. It is taking a lot longer to reach the target yield in a P95 or P99 scenario in a deal where there is less wind, less power sold at a lower price, and less cash.
MR. MARTIN: Is it still the case that tax equity covers on average about 75% of the cost of a typical wind farm?
MR. ELKORT: That has not been our experience. It has been closer to 50% to 60%.
MR. EBER: I think that is high.
MR. CARGAS: We have had a couple of deals like that, but they are the exception rather than the rule.
MR. EBER: You can push it up that high, but usually the tax equity would have to take more cash to justify a tax equity investment that large. If a sponsor is trying to optimize the tax equity, it should take the least amount of tax equity consistent with leaving as much cash as possible with the sponsor. Tax equity is usually in the 50% range for most wind deals.
MR. MARTIN: Is it still the case that you do not see project-level debt in partnership flip deals?
MR. EBER: We have not done one in some time.
MR. TORRES: We have not seen project-level debt in wind deals.
MR. MARTIN: Jack Cargas is shaking his head no.
MR. CARGAS: It has been replaced by back leverage. We are seeing a lot of back leverage in the deals we are doing. Most of our clients are looking to bring in bank debt. It is lower-cost capital. They are doing it at the holdco level through a variety of mechanisms.
MR. MARTIN: John Eber, how do you structure a deal so the sponsor keeps as much cash as possible?
MR. EBER: If you keep the tax equity in the 50% range, then there is a lot more cash retained by the sponsor.
You structure the allocations so that they are more accommodating to back leverage, like instead of giving the sponsor practically no cash before the flip and almost all of it after, you have a more constant sharing ratio through the 10-year term. Maybe the tax equity investor is distributed 30% or 40% of cash. The sponsor gets the rest from day one.
MR. MARTIN: How common is it in the wind market to see the tax equity investor take cash equal to 2% of its investment as a preferred cash distribution and some modest percentage of what remains?
MR. EBER: As preferred? I don’t think we . . .
MR. MARTIN: The 2% is a preferred cash distribution. It comes out first. I gather neither Bank of America nor J.P.Morgan does that structure.
MR. EBER: No.
MR. ELKORT: We have not seen it either.
MR. MARTIN: It is not uncommon in the solar market. Next question, what issues are taking up the most time currently in deals?
MR. CARGAS: For us, it is economics, the normal arguments back and forth about after-tax yield, pre-tax IRR, tenor and downside scenarios. We base our pricing on assumptions given to us by sponsors and, from time to time, those assumptions turn out to be rather more rosy than what the third-party experts see. There is a constant reevaluation of what the actual assumptions in the base case model ought to be. That set of conversations continues throughout the negotiations.
MR. MARTIN: John Eber, Jack Cargas said it is economics. What is your biggest current issue in deals?
MR. EBER: I don’t really have one. The market is pretty mature. Most of the sponsors we deal with have been doing these deals for a while. We have established relationships with most of them. I cannot think of any one particular item that causes deals to bog down or eats up an inordinate amount of time in deals, unless it is something unique to a specific deal. Most deals have some unique feature on which you end up spending a bit more time.
MR. MARTIN: Daniel Elkort?
MR. ELKORT: I agree with John. If you did not have a relatively simple 20-year PPA, proven technology, no basis risk, no congestion, no merchant risk, no . . . .
MR. EBER: Bring me that deal.
MR. ELKORT: . . . then it is pretty well established. My view is the tax equity wrap themselves around anything unusual or different in a deal. So if you have congestion, you spend a lot of time arguing about congestion. If you have back leverage, you spend a lot of time negotiating the cash turnoffs.
We did a deal recently where we had a relatively significant fixed transmission charge. We spent an inordinate amount of time getting the tax equity comfortable with that element because it was a new structural feature. Tax equity investors are thorough. They are very careful. They look at everything three different ways to make sure they get it right. So if there is anything new in a transaction, that is where you end up focusing 60% of your time.
MR. MARTIN: Martin Torres, do you want to add to the list?
MR. TORRES: The offtake structure is the one feature of a transaction that gets more focus than any other. If you have a long-dated utility PPA, then not a lot of time is spent focusing on the offtake. But so many deals today have synthetic corporate offtakes, financial hedges and the like, and a lot more focus is being paid to the details or how they actually work and how they are likely to perform over time.
MR. ELKORT: That’s a good point. The new forms of PPAs add risk. When you combine them with low levels of cash, there is not a lot of margin for error. There is more pressure when analyzing deals with new offtake arrangements.
MR. MARTIN: Let’s stick with that. Jack Cargas, Bank of America has done at least one corporate PPA deal. Do you analyze projects with corporate PPAs as if they are merchant wind farms?
MR. CARGAS: We do not. We look at them as if they are corporate PPAs.
MR. MARTIN: What is the difference?
MR. CARGAS: There is a party with a credit behind the obligations to purchase power.
The number one issue for us in corporate PPA deals is the creditworthiness of the corporate offtaker. What is the credit structure?
The offtaker may not be a publicly rated company. It may not be easily judged from a credit perspective and, therefore, there may be a guarantee behind it from a more creditworthy affiliate. In a number of cases, we have also seen downgrade protection. That is not something you generally see with PPAs with investor-owned utilities.
MR. MARTIN: How is the downgrade protection structured?
MR. CARGAS: If the credit of the entity decreases one or two notches, then some sort of credit security is required to be delivered: for example, a letter of credit.
MR. MARTIN: John Eber, are corporate PPAs financeable? How do you analyze them?
MR. EBER: They are financeable. We have done a fair number of them over the last year and a half. I agree with Jack. You focus on the creditworthiness of the offtaker. Fortunately, many of them are J.P.Morgan clients, so we can get to that decision within a reasonable period of time.
What we are having a bigger challenge with is that most corporate PPAs also come with a lot of basis differential risk. That is what we are beginning to worry about a lot more.
MR. MARTIN: Let’s go there. Daniel Elkort, what is basis risk?
MR. ELKORT: It is the difference in electricity price between the bus bar where the project injects its energy into the grid and the pricing node on the grid where the electricity is delivered to the offtaker. When that price starts to separate, it affects cash flow.
MR. MARTIN: Usually the sponsor takes basis risk in a corporate PPA. A utility takes it in a utility PPA. John Eber, why do the tax equity investors care about who takes basis risk?
MR. EBER: It can significantly affect the cash that might be available for distribution to the tax equity investor. The reason we all want PPAs is so that we can get a fixed price for our power and worry more about whether or not the power will be produced than the price at which it will be sold.
When you have basis differential risk, you have to worry about whether or not the net value from electricity sales will be what you thought going into the deal. The basis differential can move around quite a bit. We are finding that in certain parts of the country where there has been an excessive build, the difference between the prices at the bus bar and the node can be significant.
When the wind is really blowing in Texas, all the wind is being delivered and you start to get a greater and greater basis differential, just at the time when you want to be selling your power.
MR. MARTIN: It is an unquantifiable risk.
MR. EBER: Corporate offtakers try to put this risk on the sponsor. With a traditional utility PPA, the utility buys the power at the bus bar. It pays a fixed price and whatever happens between there and the point of delivery is its risk.
Tax Equity Yields
MR. MARTIN: Daniel Elkort, Martin Torres, how would you characterize the cost of tax equity today?
MR. ELKORT: Too high.
MR. MARTIN: I knew you were going to say that. I am looking for details. [Laughter.]
MR. ELKORT: You want details? Way too high. [Laughter.]
MR. MARTIN: Martin Torres, can you do better than that?
MR. TORRES: I would have to second that.
MR. MARTIN: What do you think is the cost of tax equity today in the wind market? What is the range?
MR. TORRES: There is probably more of a range across the spectrum than there was historically. It is probably fair to say somewhere in the 7% range for large, well-known sponsors
and . . . .
MR. ELKORT: For clean deals.
MR. MARTIN: Seven percent seems lower than we see. What fees should a sponsor expect to pay these days on top of the tax equity yield?
MR. CARGAS: Commitment fees are becoming more common. The amount depends on how far forward a commitment is required. Sometimes they are characterized as a structuring fee.
MR. MARTIN: Unused commitment fees paid over time or a flat commitment fee at the start?
MR. CARGAS: We have not seen the ticking fee concept. It is more likely to be paid up front.
MR. ELKORT: We do not usually see fees, but if the tax equity is committing to a fixed price at the start of a long construction period, it may want a fee to hold the price. In deals where a lead tax equity investor has put together a club, it wants a fee on other people’s money to compensate for the work of bringing the club to the table. Otherwise, we have not seen fees on top of the already too high tax equity rates.
MR. MARTIN: How much are the fees?
MR. ELKORT: They are pretty modest. .
MR. MARTIN: .75%, 1%, 1.5%, 2%?
MR. ELKORT: The lower end of that range.
MR. MARTIN: Jack Cargas, how common are developer fees and how much are they?
MR. ELKORT: Way too low. [Laughter.]
MR. CARGAS: They are common. We see them in many deals. Not every sponsor wants to have a developer fee. We always remind sponsors that we need to get a return on investment with respect to that fee as it is included in the cost of the project. So, in some sense, they have to pay us back for the fee at the end of the day. Different sponsors analyze the value differently.
As for the level, we have views, but they are specific to individual transactions and we are happy to talk about them with our sponsors, but it is hard to have such a conversation in a general forum. We need to see an independent third-party appraisal supporting the fair market value of the project, and we usually want to see that from at least two perspectives: discounted cash flow and cost.
MR. EBER: We take the same approach. If the developer fee is supported by the appraisal, we are okay including it.
MR. ELKORT: A developer fee may be helpful in terms of optimizing the tax equity financing. You do not want to be paying for extra equity, particularly if you are paying for it with cash. If you can increase the amount of tax equity raised by stepping up the asset basis and still hold your flip targets, then that is optimal.
Obviously the tax lawyers will have limits on the size of any developer fee. We generally see something in the 10% range as not too troublesome to the law firms.
However, you should consider including a developer fee if it helps optimize the amount of tax equity efficiently raised.
MR. MARTIN: Two more questions from me, and then let’s turn to audience questions. It seems like some tax equity investors are moving to take just 2.5% of the cash after the flip instead of the more typical 5%. Does this seem like a general market trend?
MR. CARGAS: Not from our perspective. In fact, we think it is not a good idea. We would have real difficulty with it. We prefer to stick with the 5% that has been market practice for a long time and is mentioned in the IRS partnership flip guidelines.
MR. MARTIN: A number of tax equity investors are asking lately for withdrawal rights. They want the ability to get out of a deal after a point in time, usually for fair market value, if the sponsor does not exercise the sponsor call option. How common are withdrawal rights?
MR. EBER: They are beginning to show up more often in deals because of the regulatory pressures on banks. Most of us in the banking business are investing under what is called merchant banking authority, and that authority allows us to invest equity for up to a 10-year period.
Thus, from a regulatory standpoint, we are required to exit the deal at year 10. The more assurance we can give our regulators that we will be out of the deal by year 10, the easier life will be. A withdrawal right makes it easier to demonstrate that we will be in compliance with regulatory requirements that are taking on increasing significance in the world of banking.
MR. MARTIN: Sponsors, presumably the withdrawal right would be exercised in cases where you chose not to exercise the call option. Presumably you had a reason not to exercise. How do you feel about withdrawal rights?
MR. ELKORT: We have not had a chance to consider them. We want to control our projects. If there is a way to take over the post-flip interest, that is what we want to do.
I cannot even begin to posit why we might fail to exercise our fair market value purchase option. We might choose to walk away from it if the appraisal value came in ridiculously high, and wait for the next time to exercise the option in the hope of seeing a more rational valuation.
In terms of how we would approach a put, we would probably look at it the same way. As long as it is structured to roll forward if we do not like the price, then it would probably not be too troublesome for us.
MR. MARTIN: Let’s turn to audience questions. Some have been sent by email to the iPad I am holding. One person asked, “Guidance from Treasury clarified it does not matter how much is spent on physical work at the site for PTC qualification. Why are the panelists and the moderator being so conservative?”
MR. ELKORT: Half the panelists.
MR. EBER: What the IRS national office says and what the IRS field might do later on audit are often two different things. I do not think the IRS has said it does not care. The reality is the guidance we have been given by the Treasury and IRS has changed over time, and it can change again when we get to audit.
You cannot be too careful. There is way too much value in PTCs to run any risk by trying to cut something close to the edge in terms of making sure a project qualifies. There is way too much money on the table to do that.
MR. MARTIN: Here is another audience question: “How are wind projects generally performing? Are they coming close to the economics that were expected at closing?”
MR. CARGAS: Our portfolio is performing generally in accordance with what our expected case was. However, our expected case is different from the base case model that we priced and negotiated. We run a number of sensitivity cases for every wind farm, and we also look at a number of sensitivities for our portfolio as a whole. The performance has been in line with the expectations we had, but not necessarily with the P50 base case.
MR. MARTIN: John Eber, you told me in the distant past that your portfolio was performing at a P90 level. Is that still true today?
MR. EBER: I have two portfolios. They are a pre-2008 portfolio and a post-2008 portfolio.
With the pre-2008 portfolio, we took the engineers’ numbers and we were dealing with an industry that was not as mature as it is today. That portfolio performed under expectation on average by about 10%, and some deals performed almost 20% to 25% below expectation.
Since 2008, performance has been much more in line on average with our expectations. That is because the engineers got a little better, probably due to pressure from us and other investors. We also started applying our own haircuts to the engineers’ forecasts.
There is a range. So some deals underperform. Others over perform expectation. On average, we are pleased with the performance.
MR. MARTIN: Next audience question: “The market is now financing standalone merchant wind farms, at least in ERCOT, with hedges. What term must a hedge have? Are you seeing such deals in other markets besides ERCOT?”
MR. CARGAS: We have done a lot of these deals along with our colleagues at Merrill Lynch Commodities, who are the hedge providers. We see 12- and 13-year hedges in ERCOT. We do not think of the deals as merchant. We think of them as contracted with a hedge.
We expect to see hedged wind deals in PJM in the relatively near future.
MR. MARTIN: How common is tax insurance in the current market?
MR. EBER: We have used it in solar, but we have not seen it used in the wind market. I know everybody is talking about it. I suspect we will see it in the future to cover the risk that a project was under construction in time to qualify for tax credits, especially in projects where construction started based on physical work rather than the 5% test. The sponsor feels it did enough physical work to qualify. If the sponsor is not a strong credit, then its promise to pay an indemnity may not be enough for get a tax equity investor to do the deal. I expect such sponsors to offer insurance as a backstop to their indemnity obligations.
MR. MARTIN: Would you do a deal with insurance where you are not comfortable that the project was clearly under construction in time?
MR. EBER: I don’t know.
MR. CARGAS: We have not been seen tax insurance in the wind market.
MR. MARTIN: Sponsors, are you being pitched for insurance and if so, to cover what risks?
MR. TORRES: We have not been, and we have not used tax insurance in any of our transactions.
MR. MARTIN: Here is another audience question for the tax equity investors: “How much does the offtake agreement structure affect the tax equity return requirements?” Think of a corporate PPA versus a merchant or hedged project versus a utility PPA.
MR. EBER: Utility PPAs are still considered to be stronger offtake agreements, and they will attract more tax equity. If you have a good sponsor and a utility PPA, you are likely to get a better deal than somebody with a corporate PPA that may carry basis differential risk or only have a term of 10 or 12 years versus 20 or 25 years for a utility PPA.
MR. MARTIN: The return is a function partly of your assessment of risk.
MR. EBER: It is partly that and also partly the attractiveness of the deal. If you have a deal that is right down the middle of the fairway, every tax equity investor will want to participate in that deal and you will obviously get more competition and better pricing than if it is a deal that will appeal to only half the investors in the market.
MR. ELKORT: A lot of those non-PPA deals are in ERCOT, and certain tax equity investors may bump up against concentration limits. My guess is that is a big driver of the price increases for hedge deals compared to PPA deals.
MR. MARTIN: Here is the last question. Are there any other new developments that we failed to mention today?
MR. ELKORT: We are starting to see a lot more pay-go structures. We considered a pay-go structure on one of our recent deals, and we have been working on manipulating the cash sharing arrangements. This is more tinkering around the edges than something completely novel.
MR. MARTIN: What is driving the interest in pay-go?
MR. ELKORT: The tax equity investors drive the use of pay-go. If they feel the deal has too much risk and there are only a couple risks that they are willing to wait for the flip to protect them on, they will move a portion of the PTC payments into a pay-go structure. This reduces the upfront tax equity investment, but