State of the Tax Equity Market
Many renewable energy projects in the United States are financed in the tax equity market. A panel of four veteran tax equity investors and one veteran advisor talked at the Infocast wind finance and investment summit in San Diego in February about the state of the market before an audience of several hundred people. The focus was on wind projects. The panelists are Jack Cargas, managing director for renewable energy finance at Bank of America, John Eber, managing director and head of energy investments for JPMorgan Capital Corporation, Martin Pasqualini, managing director of the consultancy CP Energy, George Revock, a director at Citigroup, and Jerry Smith, managing director at Credit Suisse. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: John Eber, what was the deal volume in the tax equity market in 2011?
MR. EBER: We saw about $3.5 billion of tax equity raised for wind farms last year in 19 transactions. Most of the transactions used the unlevered partnership flip structure. There were 13 such transactions. There were five partnership flip transactions in which there was debt at the project or partnership level. We saw one sale-leaseback of a wind farm last year.
MR. MARTIN: What percentage of the tax equity transactions in wind last year involved production tax credits rather than Treasury cash grants?
MR. EBER: About 55% of transactions involved production tax credits. That may sound surprising, but it makes sense. The cost of turbines fell significantly and the capacity factors improved.
MR. MARTIN: So given a choice between a tax subsidy tied to output and one tied to equipment cost, wind companies chose output. What deal volume do you expect this year?
MR. EBER: It is hard to say, but I expect the deal volume this year to be as large as last year if not greater. That’s not because of wind financings, but because activity in the solar market is increasing. There were about $2.5 billion in solar transactions in 2011 compared to only $1.5 billion in 2010. Almost all of the solar transactions involve Treasury cash grants.
MR. MARTIN: How did the volume in the market last year compare to the volume in 2007, the last good year before the economy collapsed?
MR. EBER: We saw about $6 billion in total tax equity in the wind and solar markets in 2011. That was a larger deal volume than in 2010.
MR. MARTIN: Does anyone else have a forecast for the year ahead? I read that someone said he thinks the tax equity market for wind will be dead after about mid-year.
MR. PASQUALINI: I think that might have been me. I agree with John Eber. Those who were active in the market in 2011 are extremely busy right now. Wind companies that need outside financing are rushing to arrange tax equity. Construction lenders want the developer to have permanent financing lined up before construction starts. Construction must be completed by year end to qualify for production tax credits or Treasury cash grants. There is not a lot of time left.
However, I think we will see another rush of business late in the year from the larger, balance sheet players. There might be a lull of a month or two at mid-year, and then the larger players will bring their business to market and that business will be fairly significant.
I agree that it will be as big a year as last year if not slightly bigger in terms of overall deal volume.
However, we are going to see different wind companies start to wind down remaining projects unless Congress acts early in the year to extend the deadline to qualify for production tax credits. That will have some effect on the deal volume this year, but a much more pronounced effect next year, even if the tax credit is extended at year end because there will not be as large a deal pipeline as in recent years to finance.
MR. MARTIN: A number of new tax equity investors entered the market in the last half of 2011 or were on the verge of doing so. Is the pool of potential tax equity investors still expanding, and how many active investors do you think there are currently in the market?
MR. REVOCK: There are roughly 20 active investors. There is a lot of interest in the sector, but it is a slow process for new entrants to take the leap. It takes time for them to get to a point where they feel they truly understand the risks. I counted four new entrants last year. Maybe we will get to 25 active investors by the end of this year.
MR. CARGAS: We count 22 active tax equity investors. That counts investors in the wind and solar sectors. But it is a misleading number for a developer because it is not as if each one of the 22 investors will be interested in every transaction. Many of them have esoteric requirements, specific needs or quirks. A developer is likely to find a much smaller number of potential investors in any single transaction.
MR. MARTIN: Federal tax subsidies for wind amount to at least 56¢ per dollar of capital cost of a typical wind farm. Of that amount, 30¢ is in the form of tax credits or a Treasury cash grant and 26¢ is depreciation. Tax equity investors investing in projects on which Treasury cash grants will be claimed do not have to use as much scarce tax capacity. Treasury cash grants are expected to start phasing out this year. Will this mean upward pressure on tax equity yields?
MR. EBER: You are always after that yield question.
MR. MARTIN: I know. That’s my next question. [Laughter.]
MR. EBER: I think yields have been stable for quite a while, and I think they will probably continue that way. A good marker for what might happen to tax equity yields in the renewable energy market is to pay attention to yields in affordable housing deals. Yields in that market are down considerably. They had bubbled up and were higher than wind yields in 2009 and 2010. Affordable housing yields are down dramatically. At least at this stage, I don’t see any upward pressure.
MR. MARTIN: So it sounds like there is downward pressure on yields.
MR. SMITH: I think there are some other factors at work in the affordable housing market that make that market a poor indicator of what might happen in wind. Banks have a legal obligation through the Community Redevelopment Act to put money into that market that they do not have in wind. Production tax credits are a harder subsidy to monetize than a Treasury cash grant or even investment tax credit whose amount is fixed at the start of the transaction. Treasury cash grants made it possible to borrow additional construction debt through cash grant bridge loans that companies do not have with investment credits or production tax credits.
MR. MARTIN: So it is a mixed bag. If you believe tax equity yields are a function of demand and supply, then your last point suggests less demand since developers who are not able to use the prospect of a Treasury cash grant to borrow additional construction money may not build as many projects.
MR. SMITH: That’s right.
MR. MARTIN: John Eber, you said yields have been steady for quite a while, so I take that to mean they are about 8% to 8.25% for unleveraged partnership flip deals?
MR. EBER: Ask Marty.
MR. PASQUALINI: I think best-in-market execution is slightly less than that. Some mini portfolios were done in the last few months at tax equity yields that were 25 to 50 basis points below the figures you quoted. A developer offering a true portfolio to the market can probably get an additional 10 basis points savings on yield.
MR. MARTIN: What is the yield premium in a partnership flip transaction with debt at the partnership or project level? Five such deals were done last year, according to John Eber. The premium used to be 250 to 300 basis points, but it seemed after the economy collapsed in late 2008 to widen considerably. Where is it today?
MR. PASQUALINI: Closer to 725 basis points.
MR. MARTIN: That’s what I was afraid of.
MR. PASQUALINI: The premium has widened for a couple reasons. First, the number of tax equity investors who are willing to do a leveraged transaction is small. Second, there may be 22 active investors early in the year, but as we move through the year, many of them may have exhausted their capacity for 2012.
MR. MARTIN: John Eber, hasn’t there been a slight increase
in the number of transactions with partnership- or project-level debt?
MR. EBER: Before the grant, fewer than 10% of deals had leverage. There has been an increase in leverage in deals with Treasury cash grants.
MR. MARTIN: There are three main tax equity structures that have been used in the renewable energy market as a whole. They are partnership flips, sale leasebacks and inverted leases. We have not seen inverted leases used in the wind market. Is there any place for that product in the wind market, and will the product survive in the solar market, where it has seen the greatest use, after expiration of the Treasury cash grant?
MR. REVOCK: The inverted lease is a good product for the rooftop solar market, but I do not see it being used for utility-scale projects, especially for wind farms with production tax credits. The tax code does not permit leases to be used in projects where production tax credits will be claimed, with the exception of power plants that burn biomass.
MR. MARTIN: Then let’s focus on partnership flips versus sale leasebacks. Jerry Smith, how should a developer choose which one makes more sense for him?
MR. SMITH: The primary question should be how much money can you raise from one versus another.
MR. MARTIN: You can raise more with a sale leaseback, right?
MR. SMITH: So say some.
MR. MARTIN: A sale leaseback raises 100% of the project cost in theory — the tax equity investor must buy the project for its fair market value — but in practice the structure may raise a little less than the full project cost because the developer is almost always required to prepay part of the rent. What is “market” for rent prepayments?
MR. EBER: What little we have seen is in the 20% range.
MR. MARTIN: So 20% of the market value the tax equity investor pays to buy the project comes back to him as
MR. PASQUALINI: That tends to be a cap that is imposed by tax counsel.
MR. MARTIN: Almost all tax counsel are comfortable with zero to 20% for a rent prepayment. A number of people are comfortable with 21% to 49%. Do you know anyone who is comfortable with a rent prepayment of 50% or more? Some of the inverted leases in the solar market have been as high as 80%.
MR. PASQUALINI: Yes, but going back to the main point, I agree with Jerry Smith that it is somewhat misleading to say that a sale leaseback will raise more money for the developer than a partnership flip. People are attracted to leasing on the sponsor side because they like the profile in terms of their own accounting. Some sponsors also thought that it was the most efficient way to achieve a big step up in tax basis for calculating tax subsidies. However, it is buyer beware for anyone trying to maximize a basis step up through the financing structure and planning to apply for a Treasury cash grant. There has been significant push back from Treasury on this point. If you don’t find the accounting more attractive from the sponsor side, then I think even in a cash grant you would be pushed to a traditional partnership structure.
MR. MARTIN: Why?
MR. PASQUALINI: A deeper pool of investors, for one thing. The market has been doing partnership flip transactions because they work, they are efficient, and there is good depth to the market. These deals are by no means easy, but the regular participants understand the moving parts. The deals are relatively efficient to document and close. Every deal has its issues, and they are always too expensive to execute, but when you do what people would call “plain vanilla” or “center of the fairway” transaction on an unleveraged partnership basis, you get excellent execution in this market.
MR. EBER: Don’t forget you cannot monetize production tax credits through a lease, which is why leasing was never popular in wind to begin with.
MR. PASQUALINI: Others were saying that there would be lots of leasing three years ago when Treasury cash grants and investment credits became an option for wind farms. I said we might see a couple handfuls of leasing deals in the wind market. I think we are at nine in total, and I think that the jig is up, so we might not get to the two full handfuls.
MR. CARGAS: The other thing that some sponsors are doing, in addition to looking at the amount of capital they can raise via a lease versus a partnership flip, is they are comparing the net present value cost of the project or their internal rates of return after financing, and they are finding that leases look marginally more attractive or perhaps even significantly more attractive under both metrics.
MR. MARTIN: So the money may be less expensive under a lease.
MR. REVOCK: A lease has a required coverage ratio for rent payments. If that coverage ratio is binding, then it will lead the sponsor to a partnership structure, because he will not have the same constraint with a partnership.
MR. MARTIN: What does it mean to say the coverage ratio is “binding”?
MR. REVOCK: If the tax equity investor requires the project to have at least a 1.5 coverage ratio and the project generates $30X a year, then the project can support rent payments as higher as $20X. The investor may not be able to reach his target yield with rent of $20X a year. This means that the only way to do a lease is for the sponsor to prepay part of the rent. As the prepayment increases, the lease option becomes less attractive to the sponsor and leads him to a partnership flip. There is no required coverage ratio in a flip.
MR. CARGAS: I just wanted to finish my thought before I was interrupted by the guy wearing the Giants cufflinks! As a 49ers’ fan, I don’t appreciate it. [Laughter.] The slight edge in NPV or IRR benefit you might see in a lease may be attractive, but — we come from a leasing background and do literally $10 billion a year in leases including for solar — we have not done a wind lease and we have heard some cautionary tales from the leases that have been done to date.
MR. MARTIN: You have heard George Revock moaning? [Laughter.]
MR. CARGAS: The caution is the time and cost of getting lease transactions done in wind. I assume such transactions will become more efficient, but there are some deals that have taken eight, nine or 10 months to close. And the legal expenses have been . . .
MR. MARTIN: Healthy?
MR. CARGAS: Significant. We have not done one of these deals, but we have heard stories of fees running to $3 to $4 million to close a transaction, which wipes out a good share of any NPV benefit the sponsor hoped to receive from the transaction.
MR. MARTIN: Not a good outcome. John Eber, one problem with partnership flips is people have been having absorption problems. It can be hard, because of complicated partnership tax rules, to get all the tax benefits to the tax equity investor. In the recent past, tax equity investors sometimes dealt with this problem by agreeing to deficit restoration obligations; they agreed to contribute capital to the partnership when it liquidates if they have taken out too much value. A tax equity investor in the past might agree to a DRO of 20% of its original investment. However, lately, DROs seem to be in the 1% or 2% range — not 20%. What happened?
MR. EBER: DROs are most common in partnership transactions where the tax equity investor is being asked to claim a depreciation bonus. In that case, a large amount of depreciation is claimed by the investor in year one. This exhausts his capital account, which is a cap on what benefits he can pull out of the partnership. The only way to get more depreciation is to agree to a DRO. We have seen DROs in such transactions of anywhere from 20% to 40%.
MR. MARTIN: So it is not true that DROs have been squeezed down to 1% to 2% in the current market.
MR. EBER: You can find them in that range if the transaction does not involve a depreciation bonus.
Layers of Capital
MR. MARTIN: Jerry Smith said it is illusory to say a sale leaseback raises 100% of the capital if the sponsor must prepay a share of the rent. A sale leaseback may raise 80% of the capital after the prepaid rent is taken into account. What percentage of capital does a partnership flip raise for the developer?
MR. EBER: It is clearly a smaller number, but that may be a benefit in that you are trying to raise only the amount of tax equity you need to optimize the value of the tax benefits in the deal and then find the rest of the capital from a cheaper source.
MR. MARTIN: That cheaper source being true equity?
MR. EBER: If you have a sponsor who has a lot of capital, but just cannot use the tax benefits, a partnership flip that raises 50% to 55% of the cost of the equipment is attractive because the sponsor can bring the rest of the capital into the project at a much lower price.
MR. MARTIN: And where does the rest of the capital come from? Is it subordinated debt at the sponsor level?
MR. EBER: The larger wind companies can raise capital most cheaply through their European parents. Some US developers have been using back leverage. Back leverage has evolved. We are seeing sponsor-level debt with terms of up to 10 years, which is much longer than we saw in the past.
The partnership flip really did not evolve as a way to raise the maximum amount of capital against a deal. It evolved as an efficient mechanism for monetizing tax benefits. It was always meant to be married with other sources of capital.
MR. MARTIN: So it is just a layer of capital. If you have leverage in a partnership flip transaction at the partnership or project level, then you will need a forbearance or standstill agreement between the tax equity investor and the lender. What are market terms for such agreements?
MR. EBER: There have been only a few partnership flip transactions done with partnership- or project-level debt. We have seen a variety of forbearance agreements, although typically the lender agrees to some type of forbearance through the period the production tax credits will run. The tax equity investor wants an assurance that he will at least be able to collect the PTCs.
MR. PASQUALINI: I think it also depends on the structure. For example, if it is a partnership flip transaction with production tax credits and a pay-go structure, meaning that the tax equity investor does not put all of his capital in up front but rather puts in part each year as production tax credits are received, then forbearance may even be longer than 10 years.
MR. MARTIN: Why would forbearance have to last longer than 10 years in such a case if the PTCs will have run out within 10 years?
MR. PASQUALINI: The tax equity investor in that situation can be viewed as another power purchaser. It is another source of capital to the project over time that the project can use to service the debt. It is almost like a lender foreclosing on a power purchaser. A lender will not do that because it would cut off the revenue stream needed to service the debt.
MR. MARTIN: Do you expect to see a return to pay-go structures in a world where sponsors are opting for production
MR. EBER: We have done a number of pay-go deals in the last two years. They are most attractive in transactions where the wind farm has already been built, is in service and has some financing in place, and now the sponsor has decided that he needs tax equity. Pay-go tax equity tends to get layered in after the fact.
MR. MARTIN: Must a sponsor using a pay-go structure pay the tax equity investor a commitment fee for keeping money on hand that can be drawn over time?
MR. EBER: No. We don’t think of a pay-go deal in those terms. It is more like an annual trade. We have tax capacity, our client has tax benefits he can’t use, and we are trying to help him monetize them for profit.
MR. MARTIN: My recollection is that the last time pay go’s were popular, say in 2006 or 2007, the tax equity investors bidding different structures would charge the developer more for use of capital in a pay-go structure where the money was put in over time than if it was all put in up front.
MR. EBER: That’s true if you look at is target IRR the investor is using for the flip. However, the after-tax book income for the sponsor is about the same.
MR. MARTIN: Jerry Smith, is Credit Suisse doing pay-go transactions?
MR. SMITH: Probably not. We were one of the firms that entered the market in 2009 when most others had abandoned the market. We are focused for now on projects with Treasury cash grants.
MR. MARTIN: Will you remain in the market after the grant goes away?
MR. SMITH: Yes, but it is a battle for another day. We are trying to get as much as we can done this year and then, sometime late this year or early next year, we will move to another structure.
MR. MARTIN: You may prove Marty Pasqualini’s point about a possible cliff as the Treasury cash grant fades away.
Projects that go into service this year qualify for a 50% depreciation bonus. Many tax equity investors have turned their noses up at the bonus. Jack Cargas, is Bank of America willing to take the bonus and, if so, do you give developers any value for it?
MR. CARGAS: Hmmm. [Laughter.] We do take the bonus. We do price it in. We would prefer not to do that but competitive pressures from those on my right and my left here [laughter] are forcing tax equity investors to give the sponsor some value for the bonus.
MR. MARTIN: Other views?
MR. EBER: The structure is sometimes a limiting factor. There just may be no room in a partnership flip structure because of capital account limits for the tax equity investor to absorb much of the bonus. We talked about this earlier when we were talking about DROs.
MR. CARGAS: And that problem is exacerbated in deals with a 100% bonus.
MR. EBER: Really exacerbated.
Life After 1603?
MR. MARTIN: There was a lot of talk in conferences in the last six months about what life will be like after the Treasury cash grant. There was always a segment in these conferences called “Post-Section 1603 Financing Structures.” I am not sure that I heard anything new in those discussions. What are those
Let the record show that all five panelists are looking around for someone else to answer. [Laughter.] George Revock?
MR. REVOCK: I think we return to a world where flip partnerships are the dominant form of financing for wind farms. I think leasing will continue on the solar side, short of a change in tax law.
MR. MARTIN: Let me make this a little bit harder. What will happen in a post-production tax credit world if the PTC is not extended at the end of this year? What will be the financing options? Will we still have tax equity panels at these conferences?
MR. REVOCK: I think at that point you are probably looking at regular leases to get some benefit for the depreciation on the projects.
MR. EBER: Wind farms will be financed in that case in the same way as more conventional power plants. I don’t think there will be much demand for tax equity. You will see a lot of debt financing and, unfortunately, the depreciation benefits won’t get used because that is what most of the country does right now. There are plenty of industries that have lots of depreciation that does not get used, and they do not use lease financing much any more for it.
MR. MARTIN: You have 5-year depreciation that is worth a considerable amount. Is there no market for tax equity based solely on that depreciation?
MR. EBER: You go back to the old lease-buy analysis. It is cheaper to buy when you have interest rates as low as they are today.
MR. MARTIN: “Buy” means own the asset and borrow rather than finance it through a lease.
Is there an after market today solely for depreciation in partnership flip deals with existing wind firms through some sort of 754 step up or otherwise? Jerry Smith, you are shaking your head no.
MR. SMITH: No. Recent experience suggests there is not enough of a market.
MR. MARTIN: Shed a little more light on the recent
MR. SMITH: We explored a number of ways to increase liquidity in our model, and one of those was to bring to market a portfolio of operating wind farms. We figured investors would consider that profile a lot less risky given that you have a couple years of operating history. It comes down to supply and demand. There is a lot of demand today for tax equity. If an investor has a choice of another deal with full tax benefits and the ability to come in at the start and affect the deal terms, he will come in at the start. Things may change if the front-end option is no longer available.
MR. CARGAS: The only meaningful secondary market trades were in 2009 when tax-advantaged investments were being liquidated out of the AIG and Lehman portfolios. The buyers in those transactions received very significant yield premiums to the original deals. These trades are hard to execute. Tax equity investments, including lease equity, tend to be fairly illiquid investments.
New Issues in Deals
MR. MARTIN: Have there been any new issues in the tax equity market in the last six months, or are these structures and the issues pretty well settled?
MR. CARGAS: It is hard to say. One of the mistakes that people sometimes make is they believe the last transaction that was completed in the sector is market. Although the basics of the structures are kind of set, as Marty said earlier, there are always “tweaks” and differences, and every transaction is unique and tailored. There are plain vanilla partnerships in theory. The reality is every one is different.
MR. MARTIN: What further evolution do you see in deal structures this year? US Bank, for example, has been trying to shave the amount of cash the tax equity investor keeps to a bare minimum of 2%. There was talk at one time about guaranteed return structures for tax equity investors that mirrored what is being done in the low-income housing market. What issues do you see people trying to address through changes to the existing deal structures? Jerry Smith?
MR. SMITH: If the people around here are like me, you are sitting pat until you figure out what will happen in the future. There is no use in complicating matters right now when there are structures that work both now and in the PTC world going forward.
MR. MARTIN: You are starting to sound like John Eber. He has said the same thing at other conferences. [Laughter.]
MR. PASQUALINI: One recent change is that the sponsor might be distributed a larger share of cash flow for a longer period of time in a partnership flip transaction than in the recent past. That’s why we are able to get longer back leverage transactions up to nine or 10 years. Before, the sponsor might get 100% of the cash until it got its capital back and then cash would go 99% to the tax equity investor. There have been multiple examples in the last six months of what we refer as a constant coupon model where the sponsor will get 60% or 70% of the cash all the way through a 10-year period and only if the target IRR has not been reached by that time will a large share of cash shift to the tax equity investor.
MR. MARTIN: Sponsors might prefer a steady amount of cash over time to getting their capital back up front.
MR. PASQUALINI: This is particularly appealing to sponsors backed by private equity funds or sponsors who are set up like an income trust. They are not as attracted to receiving all their capital back over three years and then having a dry spell until year 11.
MR. CARGAS: The sponsor is usually better off on an NPV basis to take cash up front, but taking cash over time puts the sponsor in a position to have steadier book income, which is important to some, or a longer term for any back-leveraged debt, which might improve the overall NPV of the transaction once it has been layered in.
MR. MARTIN: Are there some parts of the country where it is impossible to raise tax equity? For example, it used to be that wind farms in West Texas could not be financed in the tax equity market because of curtailment problems.
MR. EBER: West Texas was a problem for us for a number of years, partly because of poor wind forecasts and partly because of curtailment risk. The curtailment problem seems to have gone away. However, power prices in West Texas are extremely low today. No one can get a financeable power purchase agreement as far as we can tell.
MR. MARTIN: So the entire country is open for tax equity in theory except if power prices are too low to support the return the tax equity investor needs in cash as opposed to tax benefits?
MR. EBER: More or less. We still see some unacceptable curtailment risks in some places. It is a local issue.
MR. MARTIN: Jack Cargas, there was a rush to buy new equipment at the end of last year so that projects put in service this year would still qualify for Treasury cash grants. The equipment will be sprinkled on projects in 2012 and convey eligibility for a Treasury cash grant. If more than 5% of the cost of a project was incurred by the end of last year, then a project qualifies for a grant. The US Treasury in December posted two questions and answers to its website explaining that it is nervous about trafficking in stockpiled equipment but describing what is allowed. Have you seen any issues come up so far in 2012 about projects using stockpiled equipment?
MR. CARGAS: We have not seen any deals with proposed transfers of 2011 equipment yet this year, but we do have a concern. The Treasury pulled back in December on its view of what a sponsor had to do in 2011 to “incur” costs. We are going to have to tread with caution.
MR. MARTIN: Has anybody had any 2012 transfer issues come up in his deals so far this year? George Revock, you are leaning forward.
MR. REVOCK: We have not yet. However, we expect this to become a larger concern in deals as we get farther into the year and there are questions about whether the construction work the sponsor said it started in 2011 was continuous or whether more than 5% of the project cost was incurred in 2011 as the Treasury now defines “incur.”
MR. MARTIN: Who bears the risk that construction of the project started by December 2011?
MR. REVOCK: We would expect to see the sponsor take that risk.
MR. MARTIN: Are you aware of any deals that are in audit with the IRS?
MR. CARGAS: I am not aware of any.
MR. SMITH: Some deals have been reviewed in the traditional audit cycle, but no issues have been raised as far as I
MR. MARTIN: The first partnership flip transaction was done when? 2003?
MR. EBER: Yes, 2003.
MR. MARTIN: Jack Benny said life is like trying to learn the violin while on stage. We all learn as we go. John Eber, starting with you and working across the panel, what lessons have you learned by making mistakes yourself or by seeing others make mistakes in wind deals that you are now careful not to make.
MR. EBER: The big thing that has changed in our shop is the way we approach the due diligence. We are a little more skeptical of what the independent engineers say. We spend a little more time looking at the project, thinking about it ourselves, looking at our