Tax Reform and Its Implications for Renewable Energy: Transcript of Conference Call with Tax Expert Keith Martin

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Eric Selmon Hugh Wynne

Office: +1-646-843-7200 Office: +1-917-999-8556

Email: eselmon@ssrllc.com Email: hwynne@ssrllc.com

SEE LAST PAGE OF THIS REPORT FOR IMPORTANT DISCLOSURES

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December 22, 2017

Tax Reform and Its Implications for Renewable Energy:

Transcript of Conference Call with Tax Expert Keith Martin

This note provides a transcript of our conversation with Keith Martin, partner and head of projects at Norton Rose Fulbright, and a leading legal advisor to tax equity investors and project sponsors in the renewable energy industry. The conversation was recorded on the morning of December 20, 2017, following the passage by the House of Representatives of the Tax Cuts and Jobs Act (H.R. 1).

Conference Call Transcript

Hugh Wynne: Good morning, and thank you all for dialing in. Our speaker today is Keith Martin, a partner and co-head of projects at the law firm of Norton Rose Fulbright. There, he advises corporations on tax issues as well as project finance and also lobbies Congress and the Treasury Department on behalf of clients on issues of tax policy. Before joining Norton Rose, Keith was for 30 years, a partner at Chadbourne & Parke, where he was head of project finance and editor of the Chadbourne & Parke Project Finance Newswire, which he continues to publish at Norton Rose. Thank you for joining us, Keith, we appreciate you taking the time.

Keith Martin: It’s my pleasure.

Hugh Wynne: Okay, well let’s just dive in then. I think it would be helpful, Keith, if you could first identify the key provisions of the final tax bill in terms of their critical impact on renewable energy and then, perhaps, explain for us their implications.

Keith Martin: Alright, here are the top items. The first item is that the existing tax credits for renewable energy remain unchanged, and that means the phase-out schedule for the tax credits is unchanged, the rules for what it takes to be considered under construction in time to qualify for tax credits remain unchanged, and there’s a 10% permanent investment tax credit for solar and geothermal projects that also remains unchanged.

What is in the bill that has a big effect? Number one, the tax rate—the corporate tax rate is dropping next year from 35% to 21%. That change should make operating projects more valuable. It should, as a consequence, make it more expensive for developers to exercise options to buy out the tax equity once the tax equity reaches its target yield. It could accelerate or slow down flip dates in tax equity financings for projects. Most of these projects use tax equity as their core financing tool. The investor starts with a high interest in the project and then it flips down to usually a 5% interest after the investor reaches an agreed return. That date could be moved up or back depending on the facts of the deal.

Next, most important, is something called BEAT—that stands for base erosion and anti-abuse tax. This is a new tax that could have the effect of clawing back up to 20% of the tax credits that tax equity investors claim between 2018 and 2025, and could result in a clawback of 100% of the credits those investors claim after 2025. That could mean that banks that are affected by this tax will propose investing smaller amounts, as tax equity investors not give full value to any credits that might be clawed back. Only a small part of the banking world is affected by this, so the tax equity market should continue to function. It should just be a question of the participation by this smaller group.

One hundred percent expensing is the next most significant item. Both new and used equipment cost can be written off immediately. This is equipment acquired after September 27, 2017 and through the end of 2022. After that, the expensing percentage phases down over four years. That change is unlikely to affect renewables very much, mainly because renewables developers have not been able to use the 50% bonus depreciation available to date or to get value for it in the tax equity market.

Next most significant, interest will be harder to deduct. This could make some borrowing more expensive; however, I’ve been going back and forth on its significance for the independent power part of the market. Of course, the utilities consider this a very important issue, and they cut a deal with Congress to allow them to continue deducting interest freely, but in exchange for that, they would forego the 100% bonus depreciation.

Sticking with the interest deductions, the way the bill works is companies will have to calculate their adjusted income, and their interest expense for the year cannot be deducted to the extent it exceeds 30% of that adjusted income. Through 2021, adjusted income will be a higher number than after 2021, so the interest limits are less likely to kick in through 2021. The reason is that through 2021 companies can add back depreciation, amortization and depletion to their taxable income, and the multiply the sum [broadly equivalent to EBITDA] by 30%. It’s only interest expense to the extent it exceeds that 30% number that can’t be deducted. The interest is not lost; it is simply carried forward and the taxpayer tries again the next year to see whether there’s room within the formula to deduct it. After 2021, by contrast, depreciation, amortization and depletion cannot be added back to taxable income [causing adjusted income to more closely parallel EBIT].

These calculations get pretty complicated. The interest limits are applied at the partnership level. A lot of projects in the independent power sector are owned by partnerships. Then, if the interest can’t be deducted at the partnership level, the excess deductions are allocated to the partners. They are then limited to using them against a share of the income that they receive in the future from that partnership. It’s just a share called the excess income, which is complicated to calculate. Otherwise, the interest limits are applied at a consolidated group basis.

For utilities, with utility holding companies that have a regulated utility as part of a consolidated group, people are still working through the planning possibilities, where the consolidated group would face a limit on the interest deduction, but the utility subsidiary would not.

Then, another significant provision is one that accelerates when income has to be reported for tax purposes. The government will no longer let people show income on their financial statements or in reports to creditors or shareholders and at the same tell the IRS that the income hasn’t been realized. So, as soon as it’s reported on a financial statement or in a report to creditors or shareholders, it has to be reported for tax purposes.

A related change will make it very hard to use prepaid power contracts. These are common in long-term power arrangements with municipal utilities and coops not just for selling them electricity, but also for providing gas to them. It’s not unusual to see the municipal utility or co-op prepay for a large share of the electricity or gas to be delivered over a long contract term. These arrangements work currently because the supplier of the electricity or gas is able to report the prepayment as income over time as the goods are delivered. The bill puts a stop to that starting next year.

Two other things. Many people labor to try to avoid partnership terminations in this market. If 50% or more of the partnership interests are transferred within a 12-month period, the partnership terminates, and depreciation has to restart. There is some loss in time value of depreciation as result. The bill eliminates this as a concern. Partnership interest transfers will not cause terminations.

Next item — net operating losses in the future will only be able to reduce income by up to 80%, and they cannot be carried back two years as has been true to date. This will make it harder for distressed companies to pull out of their distress.

The final thing I’ll mention is government grants. It’s not unusual to see a town, city, or state offer some help to a power company in order to induce it to build a project nearby. In the future, if the power company is a corporation, not a partnership, this bill will require the power company to report that government help as income. In the past, people avoided this by pointing to a tax code section that has now been amended. A number of people have asked whether property tax abatements fall in this category. I don’t think so.

So, Hugh, that’s a good place to stop.

Hugh Wynne: Thank you very much for that detailed answer. There were a number of provisions in the House and Senate bill that would have very adversely affected the renewable energy industry, including cuts to the renewable energy tax credit, the original formulation of BEAT and the alternative minimum tax. I wonder if you could quickly describe some of the worst bullets that the industry dodged in the final bill.

Keith Martin: There were five of them. Number one is the House wanted to make it harder for projects to qualify for tax credits by saying they weren’t under construction in time.

Second, the House wanted to cut and freeze the production tax credit. Wind developers get a production tax credit of $24.00/MWh currently; the House bill would have rolled that back to the 1992 level of $15.00 and then frozen it, allowing no adjustment for inflation. These are all things that didn’t get enacted.

A third thing—a startling thing, put it in at the last minute on December 2nd when the Senate passed the bill—was keeping the alternative minimum tax in place for corporations at the same tax rate as the regular corporate rate. The effect would have been to shift corporations to the minimum tax, and that would have truncated the ten years of tax credits that wind farms receive to just four years. That’s all that can be used by a minimum tax payer.

The fourth thing that was a challenge, was this BEAT tax. It was well-intentioned. It was supposed to ensure that corporations don’t use cross-border payments to foreign affiliates to zero out their tax bases. But the way it was drafted originally, and still is largely, is that the more tax credits someone has, the more likely he is to have to pay the BEAT. The BEAT operates effectively as a clawback of tax credits.

Finally, bullet five. The way the House bill was drafted, it would have made it more expensive for power plants to connect to the grid. It would have required utilities to report as income payments from independent generators for network upgrades so as to accommodate the additional electricity expected on the grid. That would have required independent generators to pay a tax gross up to the utilities. Fortunately, all of these things were lost along the way, and did not make it into the final bill.

Hugh Wynne: One question that those bullets give rise to is, are there elements in Congress, either in the GOP leadership or at the staff level, that are still somewhat hostile to the renewable energy tax credits?

Keith Martin: Well, the answer’s yes. Joe Kelleher, who’s a former Republican Chairman of FERC [Federal Energy Regulatory Commission], said that there’s this perception among Republicans who got to Congress in the 2008 or later elections, that support for renewable energy started with Barack Obama and therefore, they don’t like it.

However, with every passing year, I think the danger of the current deal on the renewable energy tax credits being unraveled diminishes. Obviously, that faction within the GOP did not prevail this time, which makes me less worried about the future. It’s not even clear it had really much muscle.

I think the politics are okay going forward. There are bigger things on the horizon that the renewable energy industry is looking at. We went 10 months into the Trump administration seemingly okay, because the economics of renewables are so compelling, but as the year draws to a close, it was not only the tax bill that was a threat, but also, the potential for solar import tariffs that Trump has to decide on by January 26th. And then there’s the [Department of Energy Secretary] Rick Perry proposal to FERC to require organized markets like PJM, ISO New England, to dispatch coal and nuclear ahead of other power plants that can supply electricity more cheaply, and to pay coal and nuclear enough to ensure them a profit.

Hugh Wynne: Let’s follow up on a couple of those points. Just to finish up the conversation about Congress, to the best of my knowledge there was no effort made to extend the renewable energy tax credits beyond their current phase-out date. Is the phase-out pretty much on rails now? Do you see the phase-out being carried through to the end or do you think that there’ll be an effort to phase out the phase-out?

Keith Martin: About six weeks ago, at a conference where I was moderating a panel discussion, I asked Tom Kiernan, who’s the head of the American Wind Energy Association, whether the wind industry had given up on any further extension of PTCs [production tax credits]. He said, yes.

I think, just as a practical matter, it’s impossible in the current environment to do anything. Of course, even 18 months is a long time in the political life of this country. If you think about Obama, there was tremendous euphoria in early 2009. By mid-2010, the dynamics had shifted. His ability to get anything further for renewables had turned 180 degrees. So, it’s sort of hard to predict the future, but at least at the moment, they’re not pushing for anything.

Hugh Wynne: Okay. Let’s turn to the Suniva Section 201 filing for a moment. What are your expectations with respect to the Trump administration’s decision on protective measures for domestic solar panel and module manufacturers? Also, can you comment on the implications and how long you would expect it to last?

Keith Martin: Sure. My bet is a tariff will be imposed. It’s a safeguard tariff that applies to the entire world. It’s not directed solely at China and Taiwan, as are the existing countervailing and antidumping duties. Three of the four commissioners on the ITC, the International Trade Commission, recommended tariffs in the range of 30% to 35% to start, but by law, they have to be phased down every year and they can’t remain in place for more than four years. Although, they can be extended for another four years at the end of that four-year period. My guess is that the World Trade Organization will have trouble, ultimately, with the tariffs, which is exactly what happened the last time in 2002, when George Bush imposed a 30% tariff on steel imports. They lasted two years before the WTO struck them.

Bob Lighthizer, the U.S. Trade Representative, asked the ITC for a supplemental report to explain why the increased imports were unexpected. Under U.S. law, tariffs can be imposed just by showing a substantial injury to U.S. manufacturers, but that’s not good enough on the world stage. The WTO requires that the increase in imports be unexpected, and so Lighthizer’s trying to create a record to try to pass muster with them.

It’s hard to predict at what level Trump would impose tariffs. He doesn’t have to do what the ITC recommended. He could put just simple quotas in place, or a combination of quotas and tariffs.

Hugh Wynne: Let’s turn for a second to the market for tax equity and particularly the implications of BEAT. If I heard you correctly, you think that BEAT will affect a subset, maybe a small subset, of the financial institutions participating in the tax equity market. How do you think the tax equity market absorbs BEAT? Does it freeze up, and refuse to take the risk that the credits may be clawed back? Does it accommodate that risk simply by raising the cost of tax equity a little bit? Where do you think things fall out in the tax equity market to adjust for BEAT?

Keith Martin: Well, here’s what I see happening. We’ve heard from five banks that they are affected, although this was before the fix that or put off limits 80% of the tax credits received through 2025, so they cannot be clawed back. To put that number is context, there are 35 tax equity investors altogether, plus another ten that are investing on a syndicated basis. They’re smaller investors investing alongside bigger investors.

Not all 35 are in the market at any given time. I think at the start of next year, some banks will drop out temporarily while they assess the effects. I think they’ll be back in. Their tax equity desks do tax equity. That’s all they do, so they’ll find a way to participate. The BEAT was fixed enough that they should be able to participate, but I think they’ll come back into the market and they’ll offer to size their investments by assigning no value to the 20% of the tax credits that are at risk of being clawed back through 2025 and no value to the post 2025 credits.

They might have a hard time pushing that position, because there is a wall of money chasing deals. Next year, like this year, there will remain a shortage of projects to finance, as there will be more people interested in financing than there are projects. Others participants in the tax equity market, who are not affected by BEAT, will not be holding the sponsors to these terms. So the banks that are affected may have a hard time pushing that position. The sponsors will say, why is BEAT any different than your normal issues with forecasting your tax capacity, say, forecasting whether you are subject to the alternative minimum tax, given this is a form of minimum tax? You’ve always taken that risk in the past.

So, I think the market will function fine. There may be a slight reduction in tax equity from some of the players. The yields have been coming down for the last 18 months. They’ve dropped at least 100 basis points. I could see them going back up by that amount, but I think that’s about it.

Eric Selmon: Keith, where are tax equity yields right now for wind, for solar? Also, what is the size of the tax equity market at the moment? What’s the state of the tax equity market right now?

Keith Martin: Well, yields had been at 8% unlevered for the big balance sheet players in wind and a little below that, maybe 50 basis points, for utility scale solar for a long time. Really, from mid-2009, after the market recovered, until about 18 months ago. They’ve been trending down since then. The dynamics have shifted to a point where the sponsors have more bargaining power. They’ve had more bargaining power in the last year than I’ve seen in any year since 2006.

As an example, we recently did a merchant wind project in Texas. No power contract, and with a developer for whom this was really its first real deal. It got 7.75%. That was earlier in the year in the face of threat of tax reform, and the risk of tax changes. We’ve seen yields in the 7% to 8% range. We’ve seen it even drop a little below 6.75%. That’s where they are today.

Eric Selmon: Okay, and is it higher for wind versus solar?

Keith Martin: Yes, they’ve always been higher for wind than solar. Wind is a little more unpredictable in terms of output than solar. In terms of the size of the market, it was an $11 billion to $12 billion market in 2016, depending on whom you ask. In 2017, no figures yet, but it feels like it was about on the same pace. I know I counted how many deals we did between when Trump was elected in November and May, and we had done 16 deals to that point. I know during the summer, we did a lot and we have quite a large number of year-end deals that were frozen during tax reform, but are now rushing to close.

Eric Selmon: You seem to think that BEAT probably won’t have too much of an impact in terms of the number of affected investors. Overall, then, do you think the effect of tax reform is perhaps that tax equity investors go back to their prior required levels of IRRs, but that the amount of tax equity should still be plentiful? So there shouldn’t be a limit on the ability to access tax equity? It’ll just be a matter of what the cost is going forward?

Keith Martin: Well, I think the market will look a little odd next year. A number of developers have adopted as a strategy for next year trying to seal up as much tax equity as possible early in the year, for fear that it may be harder later in the year to get people’s attention.

The tax reform did not help tax equity. Tax equity today accounts for about 40% to 50% of the capital stack of a typical solar project and 50% to 60% for wind. BEAT creates more acute problems for wind, because they’re relying on tax credits over ten years. Since BEAT has to be calculated every year, and you don’t know until the end of the year whether you’ll be able to claim the full tax credits, it makes it a more uncertain process for wind. With solar, the tax credit is claimed up front and the tax equity investor should be in a better position to forecast their ability to avoid BEAT, or what effect it will have, when they fund.

Wind developers if they find it hard going, can always switch to the investment tax credit and put themselves in the same position as solar, or they can move to PAYGO structures where the investor can invest what it feels comfortable investing up front, but then makes an additional investment in each of the next 10 years, depending on the actual tax credits available given BEAT. So, there are mitigation measures that neuter the potentially harmful effects.

Eric Selmon: With tax reform having introduced a much lower tax rate, what percentage of the cost of solar and wind projects do you think tax equity could now fund?

Keith Martin: You know, that’s hard to answer, because there’s no data on that. The only thing that there is really data on is the volume of tax equity, the breakdown between wind and solar. Solar has eclipsed wind and probably will continue to do so. The volume, I suspect it remained flat. I don’t think it went down in 2017. People were rushing to get tax benefits in before the tax rate came down.

On the broader effects, going back to that question, I think the broader effects will be just somewhat of an increase in the cost of capital for this sector. Tax equity will be somewhat more expensive probably.

More specifically, the lower tax rate means there will be less tax capacity overall in the market. I don’t think that will have a major effect because more than 40% of the tax equity was supplied by just three big banks, and as far as I can tell, they don’t have a limit on their tax capacity and two of the three are not affected by BEAT, they told us. Tax equity will be somewhat more expensive and debt will be somewhat more expensive just because of inability to deduct interest. I say somewhat, because independent power companies are in a net operating loss position anyway, so limits on interest deductions weren’t going to move the needle that much.

Eric Selmon: I’m going to ask one more question before we open up to questions. With the tax equity perhaps shrinking a bit, and with the lower tax rate the deduction being worth less, how does the project finance market get affected by tax reform? Do you think developers will have any issue getting new projects financed?

Keith Martin: I don’t think they will. I think another bullet that was dodged is both the House and Senate bills had pushed away the existing limits on earnings stripping by foreign companies. A lot of the projects involved foreign companies. Both bills eliminated the current limits, but then replaced them with two other proposals—two each in each of the bills. All that survived was this BEAT calculation that limits the extent to which companies can strip earnings. It’s something that didn’t happen that could have had a significant effect.

There are some more subtle effects. For example, Trump wants to move manufacturing into the U.S., but the BEAT provision could have the effect of making foreign companies that were considering putting factories here think twice about that. If they have global supply chains, where they would be paying affiliates for components, the BEAT makes it more expensive to have the final assembly in the U.S. Otherwise, people have asked whether the interest limits will change the gearing or leverage in deals. I don’t think so.

Other subtle things—in the tax equity market, we are kind of reaching the limit of what percentage of the tax benefits can be transferred to a tax equity investor. Eighty percent of the market is partnership flip structures, and the complicated partnership accounting in those deals means that the tax equity investor can really only take as much depreciation as his investment, even a little less in the solar deals. The investors get around this. They try to take more of the tax benefit by agreeing to put in more money when the partnership liquidates if they’ve ended up at that point with a negative capital account. A capital account is a way of measuring what the investor put in and what he’s allowed to take out. I think we’ve reached the limit of how high those deficit restoration obligations can go. Before, they were putting in around 3% to 5% of the original investment. Lately, they’ve been at 50 plus percent, five zero. I had thought the market would therefore move to the other fix for these absorption problems, which was to put debt down at the project level, but the tax bill now raises questions about whether that is a smart move, because the interest deductions that are lost at the partnership level will be much harder to use than if they were interest deductions on back-levered debt.

There are these subtle effects, but overall, but I just don’t see the market changing that much. Let me just pick up on one other point you made, which is an important one, the reason that if 40% to 50% of the typical solar project was tax equity, the percentage would be lower in the future. The main reason is that there are two tax benefits, a tax credit, worth 30 cents per dollar of capital cost, and depreciation, worth 26 cents per dollar of capital cost at the current rate 35%. Once the rate goes down, the depreciation is worth less; therefore, these sponsors will raise less tax equity. The benefits they’re pedaling aren’t worth as much.

Hugh Wynne: We should probably open the call to audience questions. Keith, just while we’re waiting for a queue to form, I’d be interested to get your views on what differentiated impact the tax changes may have across the wind and solar renewable energy industries? Also, across different types of developers—will a certain subclass of developers, say, independent developers that rely heavily on tax equity, be more adversely affected than another subclass, i.e., regulated utilities? Do you see a sharp differentiated impact across industries and categories of developers from the tax bill, or not?

Keith Martin: Well, the most obvious differences are between wind and other renewables. The BEAT provision will make it harder for wind developers to raise the full potential tax equity up front, where solar does not have that problem. Wind can move into a solar role by taking an investment credit. Presumably, it would already have done so if the investment credit were worth as much or more than the PTCs. It’s not. That’s issue number one.

As between regulated utilities and independent generators, it’s very interesting that both sides have been asking for the last month who gains an advantage from this bill. They’re both ultimately competing for the same large industrial customer base, now that the market is moving to corporate PPAs where generators tick off the big customers from the utilities. I don’t think there’s a clear answer, except that both sides fear the other one is getting an advantage. I just don’t see it.

As far as foreigners versus U.S. investors, the biggest issue for the foreigners is another bill that is lurking, and could pass next year with some significant Republican support, to require broader reporting to CFIUS [Committee on Foreign Investment in the United States], a 16 agency federal committee that reviews inbound investment. The bill would bring under CFIUS’s jurisdiction a lot more transactions than are there currently, and require filing fees and mandatory reporting for some types of transactions. That’s a concern that would put sand in the gears for inbound investment. Europeans, Chinese, Koreans, and Canadians account for large share of renewable investment at this point.

Hugh Wynne: Great. Thank you. Operator, do we have any questions on the line?

Operator: Yes, Hugh, I have an Enrique Mendizabal from Calpine. Go ahead, sir.

Enrique Mendizabal: Yes, I have a question with regards to the interest deductions. I understand that the limit is not applied to any business that has on average gross receipts of $25 million or less. How do you define this gross receipts test? Is it at the project level, at the partnership level, at the sponsor level? Can you please elaborate a little bit?

Keith Martin: I don’t think there is a clear answer. What you’re really asking is, if the project is owned by a partnership, do you apply a $25 million test there, rather than to the larger business? Chances are the answer is yes, because the partnership could have different owners and it wouldn’t make sense to look through, but the IRS will have to settle this.

This is one of the challenges of this tax bill, that the IRS has been so cut back on resources that it’s going to be challenging to get any guidance from it. I know things have changed dramatically even in the last two years where we used to get rulings and notices from the government fairly easily. It has been almost impossible to do so in the last couple of years just because of IRS cutbacks.

Hugh Wynne: Eric, have any questions by e-mail?

Eric Selmon: I have a couple of emails. One asks, what are the current terms for project finance for wind and solar? And, as a follow-up to that, is there a limit as to how much leverage a project can get? In other words, is it important to lenders to make sure that the developers have skin in the game when they’re getting so much of their capital back from tax benefits the first year?

Keith Martin: Let me take the second question first. Because tax equity will be a smaller percentage of the capital stack, the sponsors will have to turn increasingly to debt, to the extent it’s available. Almost all the debt in this market is back levered debt. The tax equity investors won’t allow the lenders to be ahead of them in the capital stack. You’ll have to do a debt service coverage calculation to see how much more borrowing capacity there is. Currently in solar and wind, usually you see about a 1.3 to 1.4 times coverage ratio.

This may also create a market for solar revenue puts: insurance contracts that are starting to appear where an insurance company guarantees the output for ten years just as a way of trying to push the debt service coverage ratio down to 1.1 times in order to justify larger debt.

There are 40 to 50 banks chasing deals. They are so hard up for deal flow that some of them have been talking about giving credit to revenue two and three years past the power contract end date, just to increase the size the debt.

But, in general, lenders and tax equity investors require at least 10% equity. I don’t see that changing.

Eric Selmon: I have a question regarding projects that do not rely on tax equity. I think the question you might be looking at with an ITC of 30% and 100% bonus depreciation is that the owner of that project could be getting 50% or 60% of the cost of the project back in the first year. Would the project finance banks require the sponsor to fund 10% of the project cost in addition to that, limiting leverage to only 30% to 40% leverage, or would the bank not look at what the developer is getting back in tax benefits?

Keith Martin: You know, I don’t think we’ve seen banks do that calculation. The banks have been more focused on the potential for taxes to drain cash flow at the project company level. So, if there were a consolidated borrower, they’d certainly take the risk of the sponsor’s tax position into account. In a partnership, the fact that the partnership audit rules are changing in 2018, may factor into some calculations, or at least into diligence, because the IRS can assess back taxes against the partnership directly. So, that’s what the calculus has been.

Eric Selmon: I just want to make sure I understand: the corporate investor can own a project and use the cash benefits, and actually be getting its cash back in the first year if they borrow 70% and get tax benefits on a solar project that are greater than 30% of the project cost?

Keith Martin: What we’ve seen, in fact, is perhaps not what you would expect, Eric. Sometimes in the old days, when sponsors could actually use these tax benefits, is they would try to get value for them, count them toward the cash flow of the project for purposes of calculating the debt service coverage ratio. They would do so by entering into a tax sharing agreement with the project company where they’d agree to contribute the value of the benefits to the project. So, that’s the way it’s come up. It hasn’t come up in recent years, because none of these developers can use these benefits, and they either will end up carrying a tax loss carryforward or else, try to get value for them in the tax equity market.

Hugh Wynne: Keith, I’ve received a question by e-mail. The person wants to know whether you would expect large developers to be sued by tax equity investors who had bought PTCs in prior deals and now fear that they may not be able to recover the full value of those PTCs because of the BEAT?

Keith Martin: No. No way. The reason is the BEAT tax is retroactive, in the sense that if someone entered into a tax equity partnership flip transaction, let’s say in 2011, so that the tax credits probably spill into 2021, with BEAT the tax credits from 2018 to 2021 are at risk of being clawed back, or rather 20% of them are at risk of being clawed back. That is the tax equity investor’s risk in every deal signed before 2017. So it’s the tax equity investor’s risk if he doesn’t have the tax capacity in those years to use the benefit, or he’s caught by the alternative minimum tax where the PTCs can’t be used. That was just something that the tax equity investors agreed to. Obviously, they couldn’t foresee this wrinkle, but the papers are absolutely clear on that.

In 2017, you’d have to look at the documents, because that was the year when people began to expect tax changes; they weren’t always sure what it would be. In a few cases, the papers may have anticipated something like this. Generally, what happened is that the investors in a little more than half the deals invested based on a guess as to where the corporate tax rate would land. Most of them guessed high, and there’s a one-time price adjustment at the end of 2018 in most deals where their investment will be resized. That could require the sponsor to give up more cash in the deal to resize the investment, or make an additional cash contribution. It just depends on the deal.

Hugh Wynne: Interesting. There’s a follow-on question. Do you see the provisions of the tax bill as making the access of smaller developers to the tax equity market more tenuous than it has been in the past, and do you see tax equity investors gravitating towards the larger players, the larger developers?

Keith Martin: Honestly, I don’t see much change there. For one thing, the larger tax equity investors have always been interested in the same handful of experienced, balance sheet developers. Second, the smaller players, while they do have a hard time raising tax equity, that’s always been the case. There are a number of smaller tax equity investors who’ve been appearing in the last couple of years to whom they are going. These smaller investors offer off market terms. The tax equity is more expensive. I just see this pattern that already exists continuing, without a great deal of change. If there’s an inflection point, it would be because I misguessed the effects on the market of shrinking tax capacity overall and of the effect of BEAT, but I don’t think I have. I’ve been talking about the capacity of the tax equity market at industry conferences for the last year, and also in private sessions with a lot of these investors, and none of them has challenged my view that 40-plus percent of the market is just three banks, that this won’t change, and that there’s enough tax equity available from the others to still keep funding at the current pace.

Hugh Wynne: Great. Thanks. Operator, are there any questions on the line?

Operator: Yes, we do have question from Brandon Shaw of Calpine.

Brandon Shaw: Yes, thanks. So I was reading that the net operating losses are restricted to 80% of taxable income, but are no longer subject to expiration. Is that accurate and is it also applicable to NOLs in the past, say 2010?

Keith Martin: That is accurate, but it doesn’t apply to losses that were incurred earlier.

Brandon Shaw: Okay, so those are grandfathered in, and these provisions only apply to new losses?

Keith Martin: Correct.

Brandon Shaw: Okay, that’s it. Thank you.

Eric Selmon: I’ve received another question by email, Keith. It’s about how holding companies would allocate interest for purposes of calculating interest deductibility. Can you just go over the past methods the IRS has used for the allocation of the interest expense at holding companies, and therefore how a utility holding company that has a mix of regulated and unregulated operations might be looking at potentially allocating interest?

Keith Martin: Sure. It’s an interesting question. The interest limit is applied on a consolidated group basis, and a regulated utility is not subject to the interest limit, but is part of the consolidated return, so what do you do about debt at the parent level that may benefit the utility? I can see the IRS following a number of precedents. One is, I think it will ask whether this debt truly is benefitting the utility since utility commissions are pretty careful about keeping the utility as an isolated economic unit so that ratepayers aren’t unfairly burdened with costs of other parts of the business. So, one outcome is no allocation of interest to the regulated utility. Another is, there are a couple of precedents that come quickly to mind. One is in the IRS regulations at 1.861-9. These are rules for allocating interest expense between U.S. and foreign business operations. There are various ways to do it, and there are some special rules. The other is, section 265-2, which prevents anyone from deducting interest on borrowings undertaken to buy tax-exempt bonds, and so the government has to trace how the debt was used. I think these are the three possible outcomes: no allocation or using one of these two precedents.

Eric Selmon: One question on the no allocation option. In that case, the utility debt and the utility income would be removed and you would just be looking at all of the remaining debt and all of the remaining income?

Keith Martin: No, I would look where the borrowing is. If the borrowing is at the utility then no interest limit. If it’s at the holding company, full interest limit.

Eric Selmon: What income would you use at the holding company?

Keith Martin: That’s a good question.

Eric Selmon: Would you exclude regulated income?

Keith Martin: I guess if you went that route, you’d have to calculate the income separately, but there are various reasons already for doing so, and so that should be possible. Going back to the 861 analogy, there the thought is that all borrowing is fungible. Dollars are fungible. If you borrow in the U.S., unless it’s purely on a non-recourse basis where you can trace the debt just to a single project and there are strict rules in the loan to prevent that business from bleeding into anything else, then you basically view the debt as supporting all the business lines, both in the U.S. and abroad. This allocation is necessary to determine how much income was earned abroad. That in turn, determines what percentage of foreign taxes can be credited in the U.S.

Eric Selmon: I have a quick question on the NOL limits. You’ve been talking to investors, developers, sponsors, utilities. Has anybody mentioned the NOL limits as being an issue for them in terms of affecting their tax bills or their planning going forward?

Keith Martin: Yes, there are developers who have net operating loss carry forwards, and also production tax credit carry forwards in the wind market, and their issues are how to maximize use of these assets that are being carried forward. They’re among the issues they are interested in. For instance, what are the ordering rules, which are used first? The answer is the NOLs are used first and then the PTCs. So there are people focused on that.

Hugh Wynne: Well, it’s now 11 o’clock exactly, so Keith, thank you very, very much for your time today, and for a series of very quick, clear and illuminating answers. I hope you have a good holiday season now that you’ve been finished up with your work on taxes.

Keith Martin: Time to get some sleep. So long, and thanks.

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