Tax equity trends
Three tax equity investors and the lawyer who handles energy issues on the elite tax policy staff at the US Department of the Treasury talked at the annual ACORE/Euromoney Wall Street Renewable Energy Finance Forum in New York in late June about new trends and current issues in the tax equity market. The following is an edited transcript.
The panelists are Adam Altenhofen, vice president for renewable energy at US Bank, John Eber, managing director and head of energy investments at J.P.Morgan, Hannah Hawkins, attorney-advisor in the office of tax policy at the US Department of the Treasury, and Jonathan Stark, managing director for origination at GE Energy Financial Services. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN. John Eber, it seems like everybody took his or her foot off the accelerator after Congress extended tax credits in December. The tax equity market was pretty slow in the first part of the year. Do you see it getting back to a normal pace? Is it there now? What do you see for the rest of the year?
MR. EBER: We see the market looking a lot like it was last year, which was one of the largest years ever for tax equity. There was $13 billion raised last year, and this year is off to the same pace as last year. I am not in the business of predicting, but I think the market will be similar, if not a little bit larger than last year.
MR. MARTIN: Adam Altenhofen, US Bank is a big part of the market. Do you agree?
MR. ALTENHOFEN: Yes. I share the view that it got off to a little slower start. A lot of people, including US Bank, were expecting there to be a major drop off at the end of 2016 as tax credits expired, so we did a lot of investing last year for 2016 projects. We had to do a little recalibration at the start of 2016 after Congress extended the tax credits. We have been focusing lately on bringing additional investors into the market to try to help grow that $13 billion number.
MR. MARTIN: You did $2 billion of the $13 billion last year. What do you expect this year?
MR. ALTENHOFEN: We will probably commit about $1.6 billion this year. We closed a bit more last year in anticipation of a cliff.
MR. MARTIN: Jon Stark, are we back to normal now? It is late June.
MR. STARK: I think it is normal for there to be a slowdown after an extension, in particular a four-year extension. While the beginning of the year has been slow on new PPAs, we hear from developers that they are being shortlisted, and new PPAs are imminent. We expect more wind transactions to hit the market later in the year as new PPAs are executed.
We are seeing a lot of solar right now. A number of solar projects that developers were hoping to close by year end were delayed and are in the market now.
MR. EBER: That was probably the biggest development last year. Solar surpassed wind for the first time in deal volume. A big chunk of that was in the residential sector and right behind it was utility-scale solar. As long as those two sectors remain popular, there will be continued growth in the demand for tax equity.
MR. MARTIN: What was the breakdown last year between solar and wind?
MR. EBER: We estimated about $6.8 billion in solar and $6.4 billion in wind. We can see the entire wind market. The solar market is a little harder to quantify because there are many smaller transactions that are not as readily identifiable as there are in the larger-scale deals.
MR. MARTIN: The solar rooftop stocks have been battered since the SunEdison share price collapsed on July 22 last year. Has this had any effect on how people like you view the solar rooftop market?
MR. STARK: The pressure is healthy. It is good for these companies to try to manage the pace of their growth and to keep the capital markets, and especially the public markets, happy so that they can continue to raise equity as they go forward. So if that is what the markets are demanding, it is healthy.
MR. MARTIN: SolarCity says it needs $1.8 to $2 billion in tax equity this year. Are you as likely to step up this year as you were two years ago?
MR. ALTENHOFEN: I echo what Jon Stark just said. It is healthy. Residential companies are focused on being cash-flow positive at a system level, and some of the publicly-traded companies are getting close to that level. That is a positive for the sustainability of the residential market. We are as likely to invest in the residential market as before. Our view of that market has not changed.
MR. MARTIN: Jon Stark, what other new trends are you seeing this year in the market?
MR. STARK: We see two. Tax equity, particularly in wind, is accounting for a larger percentage of the capital stack. Five years ago, 60% was probably on the high end; now we are seeing deals come in at around 75% tax equity.
MR. MARTIN: Is that because there are more production tax credits, more output, from more efficient wind turbines?
MR. STARK: Yes. The wind turbines are much more efficient. Five years ago, you saw capacity factors in the low 40s. Now they are in low 50s with the same or lower capital costs on a per-megawatt basis.
MR. MARTIN: Is it also true in solar that tax equity is accounting for a larger share of the capital?
MR. STARK: There is more variability in solar tax equity structures than there is in wind. In wind, the target flip is always around 10 years. With solar, there is more variation in the flip date and therefore, more variation in the tax equity size.
MR. MARTIN: If tax equity accounts for 75% of the capital for a typical wind farm today, then what is the range for solar?
MR. STARK: Solar is between 40% and 60%, depending on structure and underlying economics. We have found some sponsors prefer a short-dated flip and they want to maintain a high percentage of the cash, leading to a lower advance rate. A number of sponsors like a longer-dated flip. The reason they want the longer-dated flip is it is more efficient in terms of monetizing the tax benefits, and it can increase the amount of back leverage. At GE, we have the flexibility to offer both shorter- and longer-dated flips to optimize the structure for the sponsor.
MR. MARTIN: Adam Altenhofen, any other new trends?
MR. ALTENHOFEN: Community solar is the big one. We are getting a lot of questions about financing community solar.
MR. MARTIN: You flip on a date certain, while many other tax equity investors flip when they reach a target yield.
MR. ALTENHOFEN: That’s right. Ours is still a time-based flip.
MR. MARTIN: John Eber, new trends?
MR. EBER: Falling prices for wind electricity mean there is a lot less cash in projects with newer PPAs. This creates structuring challenges. Tax benefits are getting suspended and are not used fully, and deficit restoration obligations are getting larger than what they used to be.
MR. MARTIN: The IRS issued guidance in early May about what it takes to start construction of a wind farm or other renewable energy project. The developer must do two things. He or she must start construction by a deadline and then work continuously on the project.
What the IRS said in early May took many people by surprise. It said that it will not make developers prove continuous work on any project that is completed within four years. The four years run from the end of the year construction started. Until now, the IRS has said it will not require proof for any project that is completed within two years, but the two years ran from the latest construction-start deadline.
This new approach is causing a lot of pain. Many developers rushed to start construction in 2011, 2013, 2014, and so on ahead of earlier construction-start deadlines that keep getting pushed back by Congress. This has now come back to haunt them.
John Eber, Mike Storch from Enel said at the Global Windpower 2016 convention in May that he worries people like you will now ask him whether he turned a shovel of dirt on his site sometime in the distant past, and he will be out of luck because four years have run since then. Is that a reasonable fear?
MR. EBER: That is probably one of the bigger uncertainties in the new guidance. The issue is how we are going to prove a negative that the project was not under construction at some earlier date.
It is a concern. I am not sure how it will be addressed. So far, we have had nothing but theoretical inquiries about such cases. We have not been shown a real situation yet where we can try to analyze the facts and make a determination.
MR. MARTIN: Jon Stark, the rubber meets the road with smaller developers who did not have the wherewithal to incur more than 5% of the project cost. They may have ordered a transformer or they may have had a road or several turbine foundations dug on the site several years ago. Are you starting to see this issue come up with developers who are trying to sell development rights to projects?
MR. STARK: I think we are going to see an interesting dynamic over the next four years as sponsors and the financing community work through the most flexible way to qualify projects. Do you begin physical work for projects that might not be completed for four more years? Or do you incur at least 5% of the total project cost by taking delivery of equipment?
MR. MARTIN: Haven’t people already had to address those issues in past runs at these deadlines?
MR. STARK: It is different with a four-year run versus a two-year run. The 5% test may give developers more flexibility to identify projects at which stockpiled equipment will be deployed.
MR. MARTIN: Fair enough. Hannah Hawkins, have you had complaints about how the four-year clock works? Is there any possibility the government will revisit it?
MS. HAWKINS: Complaints and feedback, and this is feedback we expected to hear. So far, to John Eber’s point, it sounds theoretical, but of course, over time, there may turn out to be real substance behind the complaints.
We have no plan to revisit this aspect of the guidance, but one can never say “never.” Since 2013, there have been many clarifications.
MR. MARTIN: So it is possible this may be revisited. Why did the government decide to apply the clock retroactively? To reset the stage, there used to be a two-year clock, but it ran from the construction-start deadline. Now you have four years, but they run from an earlier date. Why do it that way?
MS. HAWKINS: The goal was to put a time limit around the beginning construction standard, and we thought it made sense to look back to the start of the beginning construction universe.
Obviously there are issues. We were aware before we put the guidance out, and we are aware now, that there are issues associated with the way we did this. I hope that we put enough flexibility and enough time into these rules so these issues are manageable.
MR. MARTIN: We see the issue coming up with geothermal, biomass and wind developers who started projects in 2011, 2012 or 2013 and who are now out of luck. The rights to these projects cannot be sold, and the projects cannot be financed because of uncertainty about whether they will qualify for tax credits.
The guidance that came out in early May dealt with everything but solar. You reserved on solar issues. When do you see construction-start guidance coming out for solar?
MS. HAWKINS: We are working on it. We hope to have it out in the next few months.
MR. MARTIN: The next few months?
MS. HAWKINS: That is probably optimistic. How about fall to winter?
MR. MARTIN: That is very good news because I think a lot of people thought it might not be before 2017.
MS. HAWKINS: It is the next thing on our plate.
MR. MARTIN: Have you seen a draft yet from the IRS?
MS. HAWKINS: I would rather not say.
MR. MARTIN: What additional issues need to be addressed for solar that were not already addressed in the wind guidance?
MS. HAWKINS: We are still working through that. I think there could be several issues. For example, with respect to solar, what is a unit of property is not always clear, especially when you are talking about distributed generation. Whether and how the rules for aggregating or disaggregating a single project should apply to solar is something we have to think about. We need to think about how a developer can start physical work on a solar rooftop project that normally takes an afternoon to install. We just need to think about how the physical work rules apply in this context.
MR. MARTIN: Will there be a four-year clock for solar?
MS. HAWKINS: I don’t know.
MR. MARTIN: We will come back to you. Let me go in the meantime to the rest of the panel. PPA prices have been falling, and we are now seeing wind PPAs with prices below $20 a megawatt hour. John Eber, you touched briefly on this earlier. How will low prices affect tax equity deals?
MR. EBER: Low prices are having a big impact on wind deals, especially for projects in the central part of the country. There is less cash to distribute after paying operating expenses. Depending on how aggressive you are in terms of factoring in inflation and projecting O&M and other costs, if you have a flat PPA price over a 20-year PPA term, you can find yourself running very low on cash as you get into the out years. When we run downside scenarios to test how well some of these structures might hold up in, say, a P90 or a P95 scenario, we see some of these deals getting extremely tight on cash as they get out into the later years, even though we might be getting 100% of the cash. There is just not that much cash to look to.
MR. MARTIN: So it puts pressure on your ability to get to a 2% pre-tax yield, which is what most people want?
MR. EBER: You can get to the 2% pre-tax yield, but you may not feel comfortable with when the flip will occur in your downside scenario.
MR. MARTIN: Are there any other issues from low wind PPA prices? Jon Stark, you look like you are about to say something.
MR. STARK: The only thing to add is low PPA prices make it harder to work out of a DRO. There may not be enough income to allocate to the tax equity investor.
MR. MARTIN: A DRO is a promise by the tax equity investor. Each partner has a capital account. The capital account is a way of measuring what the partner put in and what he is allowed to take out. Tax equity investors have too little capital account to absorb the full tax benefits. One way to be able to absorb more is for the tax equity investor to agree to contribute more money to the partnership when it liquidates to cover any deficit in his capital account. The promise to contribute more is called a DRO.
MR. EBER: Taxable income helps increase your capital account, but there is a lot less taxable income in some of these deals.
MR. MARTIN: How large are these promises to put capital back in? 20% of the tax equity investor’s original investment? 30%? 3%?
MR. STARK: It depends on the amount of cash and the structure of the deal. In solar deals, DROs are higher than wind because solar tax equity accounts for a smaller portion of the capital structure. The real issue is whether the investor will be allocated enough income over time to reverse the DRO.
MR. MARTIN: Next question. John Eber, how much sponsor equity do you require and do you let a sponsor borrow from a subordinated lender and count that as equity?
MR. EBER: We are only going to put up the amount of tax equity necessary to monetize the tax benefits. In a solar deal, it might only be about 40%. In a wind deal, it might be currently around 50%.
The sponsor needs to put up all the rest, and we recognize that it is a lot of capital to raise and that it may come from different sources. Some sponsors will partner with investment funds, whether they have their own yield co or are looking to an unaffiliated infrastructure fund to raise true equity, or they may use back leverage to raise part of the capital in the form of subordinated debt.
We don’t set a hard number on the amount of sponsor equity required. The key to us is the sponsor has enough at risk to ensure its interests are aligned with ours to see that the project performs well.
MR. MARTIN: So did I hear that you do not require any minimum amount of sponsor equity? Can the sponsor have only its development spending in the deal and the rest come from a subordinated lender?
MR. EBER: Every partner we have has a different approach as to how it wants to fund its business, and the vast majority of those approaches have worked fine. The only thing about which we are sensitive is we want our partner to remain invested for the full period until we reach our yield.
MR. MARTIN: Let’s shift to corporate PPAs. In the fourth quarter last year, 75% of new PPAs signed by wind companies were with corporations. I was surprised to learn at the Global Windpower 2016 convention that wind company CFOs are not too keen on corporate PPAs because they shift something called basis risk to the sponsor. They also tend to have shorter terms, and the creditworthiness of the offtakers is not as secure as with utilities.
John Eber, have you done deals with corporate PPAs?
MR. EBER: We have done quite a few.
MR. MARTIN: What special issues do they raise?
MR. EBER: We are working on a host of others currently because they are so prevalent today in wind. The challenges are many. One is the term. They have a shorter term than a utility PPA, but the term runs longer than the point at which we expect to reach our target yield.
The credit issues are always there. A regulated utility is nice to have on the other side versus even a well-rated corporate, because the creditworthiness of a corporate could change rapidly.
Having said that, most of these offtakers are clients of our bank and so we know them well, and we are happy to do business with them.
MR. MARTIN: Is the cost of tax equity higher with a corporate PPA?
MR. EBER: I don’t think so. Generally not. Most projects with corporate PPAs are financed as part of a portfolio in which you might have three or four different PPAs, so you get some risk diversification in terms of offtakers.
However, you might find more tax equity investors who would pursue a regulated utility deal than investors who would do a corporate PPA, so having a corporate PPA might thin out the market a bit.
MR. MARTIN: Let’s move to community solar, another trend. In a community solar project, a utility-scale solar facility is built, and the electricity moves to the local utility. But subscribers — apartment dwellers, businesses — subscribe for a share of the electricity, and they are given bill credits by the utility. It is like a utility-scale project, but at retail rates for the developer.
Adam Altenhofen, I think US Bank has actually closed on tax equity for some community solar projects. Is that correct and, if so, how many?
MR. ALTENHOFEN: We closed two community solar transactions so far in Colorado and Massachusetts and are working on three others. We like these types of projects.
We are an investor in the residential rooftop market, commercial and industrial projects and in the utility-scale market, and community solar marries the three together pretty well. So we like it from a risk diversification standpoint. You get a lot of different subscribers that are easily replaceable if one falls out, which is an advantage versus traditional C&I, where if the offtaker defaults and the system is on its rooftop, it is hard to replace the offtaker.
MR. MARTIN: With community solar, you do not have to pull the panels off the roof.
MR. ALTENHOFEN: Correct.
MR. MARTIN: What special issues does community solar raise for a tax equity investor?
MR. ALTENHOFEN: The subscriptions tend to be a rolling nature in terms of how subscribers are found. You may get into the deal at notice to proceed with construction, and the sponsor does not have any subscriptions yet, so you have to create parameters around the types of subscriptions you will accept. You have to have a form subscription agreement. That can create challenges from an underwriting perspective. You don’t know who your offtakers will be. You have to make sure the subscriber mix satisfies whatever requirements there are in the particular state.
MR. MARTIN: The subscribers can disappear overnight or with a short notice period. How do you protect yourself?
MR. ALTENHOFEN: You have to build an adequate buffer over the minimum requirements, so in Minnesota, for instance, there must be at least five subscribers by law to remain qualified as a community solar garden. Requiring some level of the fund to be residential and requiring the sponsor to have a backlog of subscribers can mitigate that short-term vacancy risk.
MR. MARTIN: What mix of commercial and residential do you require?
MR. ALTENHOFEN: No specific mix. We like to see some residential subscribers to mitigate the risk of dropping below the five-subscriber minimum, but we have no specific mix.
In Massachusetts, we have done 100% residential. In Colorado, where residential does not really make a lot of sense, our transaction was mostly C&I and municipalities.
MR. MARTIN: Let’s talk about C&I solar. For the last several years, everyone has said C&I solar has a lot of potential, but the scale of C&I solar companies is small. Somebody needs to do a rollup. How do you view a portfolio of C&I solar projects versus residential? Which is more attractive to you as a tax equity investor?
MR. STARK: Although we are not in the residential market, residential is easier to execute on than a portfolio of C&I transactions.
MR. MARTIN: Why?
MR. STARK: Standardization is the key. It is a cumbersome process to diligence and close a C&I deal with different offtakers and PPAs.
MR. EBER: Residential solar is a lot easier to underwrite, easier to execute, and frankly the residential sponsors can deliver the volume they promise. We are a scale investor. We are looking for large-scale deals. It is difficult in the C&I space to get somebody who can deliver that kind of volume to you within a reasonable period of time.
MR. STARK: We have succeeded in C&I where there is a single offtaker with multiple sites. For example, we closed a deal last year with a strong sponsor who had 60 sites with the same offtaker.
MR. EBER: That’s a rare deal. There are not many like that.
MR. MARTIN: Sounds like Walmart.
Many people are talking about combining PACE financing with tax equity. Municipalities borrow and make loans to individuals or businesses who want to put solar on their roofs. A group of such systems would be packaged together and financed in the tax equity market. Have you seen any such deals done? [Pause] I guess no answer means no.
Next question: one of the reasons people are pushing in this direction is to try to make the cash flow stream more certain. How attractive is it to a tax equity investor to have a more certain cash flow stream or, put differently, less credit risk that the scheduled customer payments will be made?
MR. ALTENHOFEN: Any time you can make something more certain, it will be attractive, and whether PACE accomplishes that is a bit unknown to me.
MR. MARTIN: So one person answered that if you can make the payment stream from the customers more certain, it may be worth the effort. Any dissenting views? [Pause] Okay.
Next question: geothermal and biomass projects are notably difficult to finance in the tax equity market. Do you provide tax equity to these types of projects?
MR. STARK: Sure. We made a cash equity investment recently in an existing portfolio of geothermal projects. We are not opposed to providing tax equity to geothermal or biomass. What we find is the hit rate on such deals is very low, and we have not had many such projects coming into the shop these days.
MR. MARTIN: What is the principal issue that leaves you with a low hit rate?
MR. STARK: The problem is not usually on our side. The developer ends up unable to finish development of the project.
MR. EBER: There are very few biomass deals that come to market. We have done a number of geothermal deals on existing properties, and we will continue to do them if we can find deals of the right size. We have not seen anything in biomass in quite some time. The fuel costs add another risk.
MR. MARTIN: Let me switch topics. There’s been notable tension with the government over the tax bases being used in projects with investment tax credits. One case involving a wind farm went to trial before the federal claims court in May. A decision is expected as early as this summer. A solar rooftop case is headed to trial in the first quarter of next year.
What benchmarks are you using to decide whether the bases used to calculate investment tax credits are appropriate?
MR. EBER: I would like to hear the government’s response on this one.
MR. MARTIN: I don’t think Hannah wants to wade into this.
MR. EBER: That’s the challenge right now with ITC. We do not really have clear guidance from the IRS about how to determine the basis.
MR. MARTIN: So what do you do?
MR. EBER: Hopefully we will get some case law from these two cases on which we can rely. Right now, people are using various methodologies to calculate fair market value.
We saw some benchmarks under the Treasury cash grant program, but the program swung from being generous to conservative. So that has left a lot of us who make a living in this business a bit confused.
MR. MARTIN: Where do you think the basis is currently for rooftop solar? How many dollars per watt? What range? [Pause] This is a notably reticent panel. They were very talkative in the back room.
Next question: how common is tax credit insurance and what is your view of it?
MR. EBER: We are doing a couple deals with it now and it has a place in the market. I suspect it will become more common going forward. It is helpful because it goes right back to your prior question about the right basis to use for calculating the investment tax credit. All of us are getting indemnities from our sponsors to protect us should the government conclude that we used too high a tax basis. The insurance just helps diversify how much of that indemnity exposure we might be building with any one client by substituting an insurance company into the mix.
MR. MARTIN: Any idea what tax credit insurance costs?
MR. ALTENHOFEN: Yes. We have used it as well for the same reason as J.P.Morgan to diversify credit risk. The typical premium is about 4% of the policy amount.
MR. MARTIN: Let me go back to Hannah Hawkins. The government asked for comments on investment credits. The regulations on what qualifies for an investment credit go back to 1982. You received 25 to 30 comment letters. The IRS is now sifting through these.
A lot of people wanted the government to make clear that batteries and other storage devices qualify. Do you see any possibility that batteries will not qualify?
MS. HAWKINS: Right now we are in the process of sifting through 30+ comment letters that, by the way, have been very helpful to us, and we are also having meetings with people who sent in comments to do a deeper dive into the different storage technologies: how they function with respect to the energy property, with respect to the grid, and the ownership structures.
I think the broad view is that there are many situations in which storage technologies should qualify, but it is a matter of identifying those situations and being able to describe them.
There is also the problem, of course, that the existing regulations have a dual-use rule that requires that at least 75% of the energy that a battery uses has to be from the renewable energy resource, and it is a cliff. If you do not meet that, then you are ineligible. So we have to decide to the extent storage qualifies, whether there should be a dual-use rule and, if so, how it should work.
MR. MARTIN: I read a lot of the comment letters, and wrote three of them, and it seems like this is a very complicated area to get one’s arms around. Do you think the government is likely to come out with new regulations before 2017?
MS. HAWKINS: Before 2017, probably not. I think we are hoping to get the proposed regulations out next spring and then maybe finalize them a year later.
MR. EBER: We are going to be seeing a lot more batteries in the residential space. Hawaii already is moving in the direction of hooking up new residential systems only when they come with batteries.
MR. MARTIN: So there is some urgency to have clear rules.
Hannah, there is an effort on Capitol Hill to extend the orphan tax credits: investment credits for fuel cells, CHP projects, geothermal heat pumps. Are you aware of any other tax issues in play either on the Hill, at Treasury or the IRS involving renewable energy?
MS. HAWKINS: On the Hill it is hard to say, but I don’t know of anything other than the orphan tax credits that has any legs.
As for the IRS and Treasury, we already talked about the investment tax credit regulations. We are very close to releasing regulations related to section 50(d) income for inverted lease transactions. [Editor’s note: These regulations were released in July and are discussed here.] It is a discreet issue. In an inverted lease, the lessee has no basis in the investment credit property to reduce by one half the investment credit, so the lessee has to report half the investment credit as income instead. Questions have arisen about how that income inclusion works, particularly when the lessee is a partnership.
Something else that has been brought to our attention recently, and on which we are starting think about whether we want to spend time, is solar installations on federal land. Office of Management and Budget regulations apparently require the government to be given ownership at the end of the power contract. This is making people nervous about whether that blows tax ownership or prevents the power contract from being treated for tax purposes as a service contract under section 7701 of the US tax code.
MR. MARTIN: This is the issue on military bases, for example. The military can throw you off the site, and it will not let you keep your asset on the site after the power contract ends. The issue is whether that affects tax ownership.
Audience, this is your chance to ask questions.
MR. REICHER: Dan Reicher from Stanford. In 2014, Treasury and the IRS issued a proposal to allow real estate investment trusts to own some types of solar. The government received a number of comments from trade associations, companies and others. The president actually announced the move to expand the potential use of REITs at a solar event at Walmart, but we have not heard anything since about what is happening. Do you expect the REIT proposal to be issued in final form and, if so, when?
MS. HAWKINS: We are actively working on that, and hopefully you will see something soon. I can’t really say much beyond that. Sorry.
MR. MARTIN: Do you think the rules will be out this year?
MS. HAWKINS: Hopefully.
MR. MARTIN: There is an unwritten policy at Treasury of not issuing big rulemakings after Labor Day in a presidential election year. Do you think we will see any guidance after Labor Day in these areas we have been discussing?
MS. HAWKINS: It depends on the type of