sponsored by fitch ratingsTo download the PDF version of this report, click here.

Editor's Note

As power and renewable energy project finance evolves, it’s not just the commercial bank lenders that are working hard to keep up. The U.S. private placement market, long a favorite venue for refinancing contracted gas-fired, wind and solar projects, as well as long-lived hydro projects, increasingly has an appetite for deals with a wider range of risks—as long as those risks are appropriately mitigated.

This year, for instance, insurance companies and pension fund managers have participated in the debt financing of Ares Management’s Hill Top Energy Center—a new build gas-fired project featuring a very à la mode gas netback hedging arrangement—as well as the refinancing of a portfolio of merchant peakers in the Midwest for Rockland Capital. What next? Merchant solar in Texas?

Maybe not, but private debt investors are giving the bank market a run for its money, in part because they have hired in power market expertise from the banks.

In this fascinating roundtable discussion, PFR brought together project finance officials from insurance companies, asset managers and a rating agency to explore how these investors think about power markets and projects, and where the private debt market might go next.


Richard Metcalf


pfr private placement roundtable 2019

Charles-Henry Lecointe, head of infrastructure debt, Legal & General Investment Management America

Greg Remec, head of power and energy, Fitch Ratings

Patrick Manseau, head of U.S. infrastructure debt, Barings

Daniel Fuchs, infrastructure debt, BlackRock

Andrew Bloom, managing director, project finance, SLC Management (formerly Sun Life Investment Management)

Fitz Wickham, infrastructure debt, Voya Investment Management

Richard Metcalf, editor, Power Finance & Risk (moderator)

PFR:           I would like to start with a general review of project finance activity in the U.S. private placement market so far in 2019. Has it been a busy year?

Wickham, Voya:        Voya would say that it’s been a comparably busy year for project finance. So far in 2019, the composition of the market has been very good. It’s been a little more diverse than strictly contracted power projects. We’ve seen a volume of contracted projects and merchant—or less contracted—projects, depending on how you like to describe that, with a good contribution from both transportation assets and growing issuance in and around the LNG space. We also look for midstream energy as part of that universe, but haven’t seen a whole lot of flow in midstream, if you exclude LNG, but through July, we were consistently busy. August slowed down a little bit, but the private placement market in general slowed down in August, in the investment grade space. We’re hearing that it’s going to get busier as the year winds up. We’ll see if that works out that way.

PFR:           The amount of project finance that is done in the private placement market seems to depend mainly on supply, because investors will buy as much of it as borrowers will put out. Is that generally how you see it?

Wickham, Voya:        I think there’s more demand than there is supply, absolutely.

Manseau, Barings:    Yes, I think it’s a supply constrained market, but it’s affected by two main factors. One is the supply of financing opportunities generally, and then the other is where the banks are, because they’ve always been the lion’s share—80% plus –of the project finance market. Four or five years ago, when institutional lenders came into the market, it seemed like a big innovation, but I think it was just some of the banks pulling back because of the Euro crisis and cost of capital issues and liquidity. Now it’s still around the 85-15 or 80-20 split, bank-bond. But I think our market still has a strong bid for project finance.

Bloom, SLC:  I’m going to take a different view and say that the market is down a little bit this year compared to previous years. I think we had a healthy June, July, but it was a little quiet early in the year and August was down as well. In terms of the deals that we’re seeing, I think this year we’ve been more selective than we have been previously, both because of price and because of term. So while I think that we’re seeing an equal amount of deals compared to previous years, we’re actually financing fewer.

Lecointe, LGIMA:      I’m sharing the same view as Patrick. I think in terms of number of deals, there have been a lot of financing opportunities, but structures are becoming edgier. As a result, the type of investment that we would usually target is becoming more limited in terms of numbers and size. And then the PG&E bankruptcy had some impact on Californian renewables—there were also some market dynamics explaining why a smaller number of opportunities are coming through. There’s definitely pressure on debt structures. It will be useful to hear the views of the rating agencies and different views looking at certain markets and merchant risk.

Remec, Fitch Ratings:          To Andrew’s point, term has been a key differentiator. Most of the transactions that we’ve been working on have not been new assets. It’s been a recycling, refinancing, repackaging of existing assets that were backed by long-term contracts. I still think that the private placement industry is very interested in contracted projects, but long-term contracted projects are becoming a thing of the past for the most part. The market is evolving and so the demand for investment grade type assets is still there. What we’re seeing, though, is that it’s the same assets coming up in a different package, some that haven’t carried private placement debt in the past. Things like district heating and cooling, university systems. Those are creeping up. There are a few new assets. The LNG industry is one of the bright points, featuring long-term contracts with investment grade counterparties, but I can’t remember the last new wind project, that we worked on at least. I know they’re out there, but they’re definitely mostly leaning to the bank markets.

Fuchs, BlackRock:    Issuers are in a very comfortable position right now: They can tap multiple markets. To be fair—we don’t really track how well the private placement market is doing versus the loan market versus something else—but it’s fair to say that issuers can just pick and choose. There are slightly different structures in the bank market compared to the private placement market and the term loan B market.

                   For example, there’s a lot of demand for double-Bs, so perhaps you want to structure your deal more to what’s a double-B rather than to a triple-B. There is a little bit of picking and choosing, but there’s a lot of demand on the investor side in all these markets.

PFR:           We may come back to the double-B structures in a second. Charles-Henry, this is obviously a very interesting time for you to be relocating to the U.S. These trends that have been picked up, regarding term and structure, and less long-term contracts. Is a similar thing occurring in Europe?

Lecointe, LGIMA:      Definitely. If you look at the U.K., all the FIT [feed-in-tariff] transactions are a thing of the past. You also are seeing all the CFDs [contracts for difference] for offshore wind going down. They used to be at £140/MWh to £150/MWh, and now we’re looking at below £40/MWh, so there’s definitely a trend towards more merchant risk. I think the big question is: renewables projects are becoming bigger and bigger and more expensive but are getting less subsidies, and then you still need to raise a lot of debt to make the economics work. So how do you solve the equation? Because you need to have investment grade debt in order to tap all the insurance money and you cannot only rely on bank debt, which tends to be shorter and non-investment grade. So it’s a big question for the industry. How do you continue to finance these even larger transactions? And if you look at the U.S., the offshore wind sector is just starting to develop and these are huge projects. So the question is going to come very quickly.

PFR:           Daniel Fuchs, Charles-Henry Lecointe said you need to tap investment grade debt to get the insurance company money. You don’t work in an insurance company. Is that why you’re able to look at different structures?

Fuchs, BlackRock:    Yes. We are an asset manager, and we manage roughly $12 billion in infrastructure debt capital. Most of it is investment grade credit and a lot of it comes from insurance companies and insurance clients. But the reality is also that 25% of bonds are trading with a negative yield, globally. So there is a demand for yield, and insurance companies, as well as family offices and other real money investors, are looking for yield. It’s end of cycle, right? So people may not want to play the J-curve as much as they have in the past, and they are looking for something which is income generating. Private infrastructure debt, be it on the investment grade side or the high yield side, is seen as more yieldy compared to public debt or corporates, and it is also seen as something which is income generating. So, yes, there is a lot of demand for both high yield and investment grade from insurance clients as well as from others.

Manseau, Barings:    We’re seeing something similar. Barings is also a global asset manager, with several European offices. We’ve done offshore wind deals in the U.K. and solar deals in Spain, and I’ve heard talk about unsubsidized renewable deals in Europe for the past two years. Nevertheless, the search for yield for all investors is paramount today. We opportunistically buy high yield deals when we see real value. Generally, there has to be more spread than on a term loan B, but we may be able to provide more tenor.

                   In terms of opportunities, we’ve seen more midstream this year because in the U.S., there’s been a chilling effect on renewable bond issuances, for two main reasons. One, the bank pricing has been very, very tight. And two, California was the largest source of renewable project financings. Developers and sponsors are starting to dip their toe in the water again, and trying to seek financing right now for California projects. We’ll see how our market responds to it.

PFR:           There was an announcement this morning about a project in California, with a Southern California Edison offtake, in which Allianz Global Investors has just bought the equity (PFR, 9/10/19). Is that a sign that investors, lenders are getting comfortable again? They have announced a whole load of measures to stabilize the utility companies. Will there be a rush, going into the end of the year, where those projects that would have been financed had it not been for what was going on with PG&E now come to the market?

Manseau, Barings:    I don’t think it’s settled yet, and I think it’s going to be a project-by-project experience. San Diego Gas and Electric is a different rating profile in a project than even SoCalEd, versus a bankrupt PG&E. Even though PG&E was a public policy bankruptcy, not a liquidity bankruptcy. It’s the entire regulatory regime that people have to get comfortable with. I think lenders need to take a merchant view on renewable pricing in California if they really want to be comfortable adding exposure there, because another rating agency, not Fitch, was going to downgrade all of the California utilities if they didn’t come up with a solution.They’ve gotten it through the legislature, but it’s still not done. The insurance fund isn’t set up, and people haven’t gotten their safety certifications yet, so it’s still early days. I don’t know that there’s going to be a rush. I know there is certainly some pent-up issuance that got cut off when the bankruptcy finally happened.

Lecointe, LGIMA:      And there are still some questions about the long term for the sector as well. Even if everything goes according to plan, is the wildfire insurance fund going to be there for many years? So it’s going to be interesting

Bloom, SLC: I think the bigger issue as it relates to the California utilities really isn’t, ‘Are you going to get your money back or not?’ A lot of the fear with insurance companies right now is really the rating and what the rating does to, in the U.S., the NAIC requirements for capital, and, in Canada, our capital requirements. If you take a look at these bonds, even the bonds that are rated C, a lot of them are trading over par. There’s an arbitrage in the market right now, because you have certain investors who have to put aside capital based on NAIC or Canadian requirements because of a rating and certain investors who are not required to put aside capital and make an unconstrained logical investment decision. In essence   these ratings only take into account what the probability of default is and ignore or don’t fully value the loss given default.  Even though there is a default and they’re rated C, the chance of recovery on these is really quite high. That is why they are trading above par.

                   So the fear of investing in these renewables, whether it’s SDG&E or whether it’s SoCalEd or others, is not whether you’re going to get your money back, it’s more the political argument, saying, ‘Are these going to get downgraded, and therefore are we going to get stuck with this high cost of capital again, similar to what happened with PG&E?’

PFR:           So when the PG&E bankruptcy filing came out, and there were already quite a few project finance private placements out there that must have been affected and that were on insurance company books, it sounds like that might have been a good opportunity for someone to come in and relieve them of those at that time.

Bloom, SLC:  Yes, simply because of the arbitrage in the market, because certain investors are bound by certain rules, and certain people are not bound by these rules. Compliance requirements are overriding economic decisions.

Wickham, Voya:        It was interesting because you had deals that had been originated three, four, five years ago, when contract prices were high, and our immediate concern was, ‘OK, what do we think that PG&E may reject? What may they choose to not reject?’ And that exercise went immediately to the underlying price of the contract, the other terms of the contract, in terms of competitiveness versus where projects could clear today.

                   With regards to the deals that may come to the market now, we’ve obviously seen significant compression in power project contract prices, and I think that makes them more attractive, more likely to survive a future process where the offtaker may or may not choose to reject the contract in bankruptcy. Our concern was an elevated contract that may be $100/MWh, expensive relative to stuff that was getting done in the $30s. What was the possible impairment that we were looking at if that contract got rejected?

PFR:           Fitz, you began by talking about how more assets are coming to the market that are less contracted, or uncontracted. It made me think of CCGTs in PJM Interconnection and their various hedging structures, clearly not the same as a traditional power purchase agreement. We’ve seen some activity there in the private placement market. That probably helps with the overall deal volumes, because they are larger projects. Is there going to be more of that? What leads to projects like that getting financed in the private placement market?

Wickham, Voya:        Many things. We would expect one or two more. I don’t know if we expect them this year or next. It’s hard to tell. Sponsors are driven by a number of factors. The ability to get financing completed is just one of them. The conditions in the large capacity markets, specifically New York and New England, appear to be under development.

                   The market seems to have been trying to tell the world that it’s a liquid market, it’s ready to go, you can invest on the basis of how the capacity market functions. And both of these markets still seem to be subject to—I don’t know if interference is the right word, but—modification from time to time by the authorities that oversee the market. That interference makes it difficult for a sponsor to move forward, because they’re not quite sure how their assets may or may not get valued in the market. And that uncertainty flows through to the financing market and makes it difficult to be sure that new assets will continue to enter the market.

PFR:           Greg, are you seeing requests for ratings on CCGTs in PJM or the other capacity markets in the Northeast?

Remec, Fitch Ratings:          We have. We have looked at some, and a central theme here is just evolution. Evolution of the power market. Evolution of financing structures. Evolution of risk tolerance among the investors. I think back to some of the monster solar projects—the Topazes out there that we rated pushing ten years ago now—and they were fully fixed-price with high coverage and really strong studies behind them. And investors were still a little nervous, saying, ‘Is there enough cushion in these projects for an investment grade rating?’ That kind of deal would get slammed today. That would be picked up so quickly and priced so aggressively that any banker would continue to add additional leverage on it. Because now the market has evolved to a point where they’re comfortable with the technology, comfortable with the regulatory treatment—taking out the California aspect. And on CCGTs, for example, ten years ago you had to have a fixed-price, long-term contract with capacity and full pass-through of your fuel costs—a tolling structure—to get to investment grade ratings. Now investors are willing to consider a hedge, for example, in place of a long-term offtake agreement. And those hedges are rarely more than five, possibly seven years. I’ve heard of some that might be longer, but your certainty is much lower and the investors are the ones who have to tolerate a little more risk and price that into their investment.

                   And at Fitch, we’re evolving too, as the structures are changing, as the appetites are changing. We have to realise that how we’ve looked at it in the past needs to change and evolve and it’s something that we’re doing. The CCAs out in California are an example. They’re coming in to essentially replace where the utilities have been, and yet they bring a very different risk profile to them. We just rated our first couple through our public power group, and they’re a different entity. And so we’re learning, as is everybody as the market’s evolving. I’ve been in this business for 20 years now, and it’s just always different. There’s always something new, always something changing, and I think the biggest thing I can point to is just a greater tolerance for risk. Investors are willing to accept a little more risk, I think because they have to. There’s just that much more demand and the bankers and the sponsors and advisers are doing their jobs and putting as much leverage as they can on these projects for their clients.

Fuchs, BlackRock:    I think it’s a little bit more than just evolution, quite frankly. Obviously the days of busbar PPAs are over. You will find that, perhaps, in developing markets, but not in the U.S. and I don’t believe really in Europe, with a few exceptions, perhaps.

                   Besides general evolution, markets are becoming much more complex. You can see it, for example, when you look at renewable sponsors. Back in the day, renewables investment was actually pretty simple: You looked at your PPA, you looked at your PPA counterparty, often it was actually a feed-in tariff in Europe. So you didn’t have to think about market risks. What you’re doing right now is you are taking market risks.

                   And the U.S. is not a single market. You have Ercot, you have PJM, you have all the other markets, you have California, and then you have hedge solutions, you have corporate PPAs, you have basis risk. So it’s not so much about understanding renewables, it’s really much more about understanding power markets. And that is a completely different mindset, and what you see is that some investors have adjusted very quickly to that, and others are perhaps a little bit behind and a little bit stuck in the old renewable energy framework. That’s something that leads to very different valuations at times.

                   We are, for example, very cautious when it comes to PJM. There is still a big gap between cost to build and cost to acquire, and I cannot really make that equation work for me in all circumstances.

                   Ercot is a very interesting market. You see $9,500 megawatt-hours, which is obviously extremely interesting, but there is no capacity market at all. So what do you do with that? It’s just really, really complex!

                   In addition, I believe utilities are going to remain under pressure. PG&E is one example, but you have distributed solar coming up, you have all sorts of distributed generation coming up, which will put strain on utilities. What will that mean? And then you have new technologies popping up, like batteries. So what is that going to do to a market like California? So, yes it’s an evolution, but it’s actually becoming so much more complex, and that really makes finding good investments more challenging.

Manseau, Barings:    I think Daniel makes a whole host of good points there actually.

PFR:           Hard to know which one to follow up.

Manseau, Barings:    Well, two of them caught my ear. The private debt market hasn’t historically been where these assets have been financed. The CCGTs, the new builds, have typically been bank financed deals, and capacity prices haven’t been something that institutional investors looked at, other than in a hydro deal. And merchant pricing, for that matter, has been more of a hydro phenomenon. On hydro deals, lenders can get more comfortable with more energy price uncertainty because they’re financing 100-year assets and, over time, you’ll get your money back. So maybe we’ve all been forced to work harder to find yield and look at more opportunities to deliver a return to our investors. I think we’ve also developed our capabilities. You’ve seen a lot of institutions, all the folks around the table, hire power bankers into their shops, so that knowledge is being cross-pollinated into the institutional investor market.

                   You’re seeing it with the PJM deals being done now in the institutional market. There’s a divergence of opinions on what’s financeable and what’s not in our market, but it is definitely more constructive than it has been in the past, because if it wasn’t contracted or a 100-year asset, it wasn’t getting done. Now you’re seeing PJM new-build deals with balloons get done, you’re seeing fully amortizing deals get done. So I think when you know better, you do better. I think our market is in that transition.  We’re providing more constructive solutions and I think our sponsors are learning that too.

Bloom, SLC:  Where we see the market going is beyond just the PJM market and other markets. We’re seeing new technologies as well, and that’s where we’re spending a lot of our time, in terms of getting the yield that we want, because we can’t just finance the next contracted PPA. Deals that we’ve done this year are things that were mentioned before such as LNG facilities, or European offshore wind farms. We hope to see that offshore wind come to North America soon. We understand that technology, because we’ve done it before. We’ve financed battery storage as part of a portfolio of other assets, but, while doing so, understanding the technology involved in battery storage, so that when that does become economical, we’re able to understand that asset better. And then, as it relates to the merchant market, I would make the argument—and this isn’t just for power, this is for power and infrastructure—that when you’re in a market that doesn’t necessarily have a strong offtaker, it’s often better to do a revenue risk deal on the merchant side than it is to take offtaker risk with a low investment grade or a non-investment grade offtaker.

Manseau, Barings:    Absolutely. You saw that with the airport and the toll road in Puerto Rico. It performed well despite the overall sovereign credit quality.

PFR:           Distributed generation has been financed in the private debt market. I don’t think standalone battery storage has been done. Has anyone presented that to any of you as a possible investment?

Lecointe, LGIMA:      I don’t think this is investment grade right now due to the lack of track record and technology risk.

Manseau, Barings:  We have been looking at it hard and we’ve been talking to equity sponsors to get smarter on it. They too are looking at it hard. We’ve seen it with a traditional combined-cycle plant in California, but you didn’t give any credit to the cash flows associated with the battery. Where we want to get comfortable with battery storage is on questions of whether the use cases match the budgeted opex, the capex as well as the technology. Because when we go to a credit committee, every one of us is going to be asked, ‘Why does my cell phone battery keep dying, and how is that not going to happen here?’ It’s a simple question, but it teases out those three issues.

PFR:           It’s not a 100-year asset.

Manseau, Barings:    It’s not a 100-year asset, so you’d better have cash flow built into the model to replace the battery components.

Bloom, SLC:  And the technology is changing so rapidly that the battery you put in the ground today may be obsolete five years from now. You have this contract to replace with obsolete batteries, while a project 10 miles down the road may just be that much more elegant, and if it is a matter of which one competes in the market, the new one down the road is going to outperform. We’ve been interested in projects for quite some time, because they really hold their value. We want hard assets in the ground, discrete assets that can be sold, so that its loss given default is generally going to be stronger. But you have something like this where you’re subject to much more rapid technological change. That loss given default becomes a much bigger question.

Remec, Fitch Ratings:          But the price curve is working in your favor. It’s like we saw with photovoltaics. They used to be a whole lot more expensive. Now, if you’ve got to go in and replace a circuit or two, it’s not anywhere near the type of capital cost that was required earlier on. I think we’re seeing the same thing on the battery side.

                   But we’re not at the same place where we were with photovoltaics. The P.V. panels don’t explode into flames. And those kind of safety issues are really part of that technology risk around batteries. But they’re coming. We’re seeing batteries being added to any kind of solar project right now. Any solar RFP is going to be asking for a battery component to it. And, as you mentioned in California, the battery tacked on to a larger traditional CCGT project—that’s how they’re going to gain the familiarity and prove themselves, to the point where maybe we’ll start to see them on a standalone basis. But an I.G. standalone project—I think we’re a ways from.

Lecointe, LGIMA:      The difficulty with battery storage is that technologies are changing so quickly. Solar P.V.s, compared to ten years ago, haven’t massively changed.

Remec, Fitch Ratings:          They reached that plateau.

Lecointe, LGIMA:      Exactly, so you need to wait until you reach this point. Technology, looking at the power market or any other infrastructure sectors, is definitely impacting the way you need to look at these projects, because we are lending for 20, 30 years. And, of course, the world is changing extremely quickly, quicker than ever. Even looking at car parking, what could be the impact of self-driving cars, and if you don’t need to own a car anymore? Ten years ago, you wouldn’t have thought about it, but suddenly there is a challenge when you’re being asked to lend for 20 years. It’s definitely on the mind of our investment committees. Could you end up with an asset which is not useful anymore, in a few years’ time? This has become more challenging, to deploy money in this world where technology is changing very quickly.

Fuchs, BlackRock:    One word on batteries. I see the comparison with solar, but it’s just a very different environment. The reason why solar took off, in my mind, is because you had 20-year feed-in tariffs and stability of revenues. How do you finance a technology that is declining massively in price without certainty of revenues? I feel you cannot. So what you do is, you tag it on to something and hope eventually it will work. The big problem with batteries is that visibility around revenues is not there, and there is no feed-in tariff. Many developers are playing around with different revenue streams, but it’s very hard to finance, especially from an investment grade perspective. You have to fix that in order to get it going on a significant scale.

                   Perhaps prices keep dropping because the Teslas of the world are just using so many batteries. Eventually, we come to a point where the economics work out [on a largely uncontracted basis]. I’m not so hopeful that this is going to happen very quickly, though.

PFR:           An area that we haven’t talked about is residential solar. Is that also an area that private debt investors are looking at?

Manseau, Barings:    I think all of our shops probably look at them, but residential solar is more of a consumer credit analysis, with FIico scores. People understand that the P.V. technology is renewable energy, but your cashflows are from individual consumers and it’s an ABS analysis in terms of advance rates and tranching versus classic project finance analysis.

Fuchs, BlackRock:    I wouldn’t fully agree, to be fair. I do believe the market is bifurcated: On the one hand, there are ABS structures out there which are purely consumer finance. On the other hand, there are other structures out there as well, which are 20, 25-year, really small-scale solar plants, highly distributed. You have developers that are servicing these distributed solar plants for a long period of time which makes it much more akin to infrastructure finance.

                   Residential solar is part of a new reality. Eventually, in the future, utilities may not be there, in some parts of the world at least, because you can generate all your power-needs on a distributed basis.

                   Also, you can also look at utilities as a portfolio of consumers. That’s not too dissimilar from a massive portfolio of rooftop solar.

                   I do understand that the residential solar financing structure doesn’t necessarily follow traditional project finance metrics—it’s Fico score driven, you have to look into  consumer financing considerations—but it’s a bit of a cross-over between both markets.

PFR:           Perhaps we’re on safer turf with portfolios of rooftop or ground-mounted solar projects with commercial and industrial offtakers, in some cases unrated counterparties. Does that introduce some extra headaches?

Manseau, Barings:    You form an analytical framework. To the extent information is available, we can all form a credit view.

Remec, Fitch: And what are the prices that they’re paying? Are they massively above the market, or are they somewhere closer to the market? We’ve rated a number of large portfolios of smaller solar installations where we’re dealing with exactly that issue. With an unrated offtaker, in some cases you can form a view on the credit quality of that counterparty, but we always look to what would happen if they fell away. What would happen to the portfolio if that counterparty went, their portion had to go merchant, and see, does it move the needle? Does it really make any difference?

                   And the larger the portfolio, the greater that diversification benefit. But we are seeing more and more of the non-municipality and public entity counterparties and truly C&I, especially in Latin America, for example, where it’s a cement manufacturer or a large car company. Those are different. You just really have to expect more ratings volatility because those companies aren’t constrained to be doing today what they might be doing five or 10 years down the road. Unlike a utility, where we have a little more certainty around how they’ll be operated, how they’ll be financed, and some structuring behind it that gives you comfort that if they’re a triple-B today, they’ll likely still be a triple-B in the future. I can’t really say that about some of these corporates. So the C&I portfolios are just more prone to problems in the future because of the counterparty risk.

PFR:           Another kind of project that has obtained term debt from banks is merchant solar projects in Texas, financed on the basis of hedges or partial hedges. People have talked about similar deals perhaps in California. I’m not sure if those deals have been rated investment grade. Maybe this is a question for Greg, to begin with: Merchant solar projects in Texas, can they be investment grade?

Remec, Fitch Ratings:          Can they be? I’ll say that we haven’t rated any. We haven’t been approached to rate a purely merchant solar deal yet. I think they could, just nowhere near the leverage levels that we’re used to seeing in project finance. And then it becomes a question of economics. Is it worth going to a capital markets solution on something that can only carry 40%, 50% of the capital stack as debt?

Manseau, Barings:    Every sponsor out there just thought to themselves, ‘So you’re saying there’s a chance!’


Remec, Fitch Ratings:          I think there is a chance, and the investors at some point are going to have to ask themselves the same question. Do they feel that it’s possible? How much lower can power prices go? The market will continue to evolve, power prices have been essentially stagnant for the last five or six years. There isn’t any pressing need for new capacity. It’s a game about who’s going to have the lowest heat rate. Who can bump themselves up the dispatch stack by using the latest, cheapest-to-operate technology? I think once the incentives on renewables go away, that will make them somewhat more expensive, but then, incentives might come back again. Who knows? We take a pretty conservative view for an investment grade rating. If there’s a merchant aspect to it, we say, ‘OK, you’ve got to survive the lowest power price in a given market historically on a permanent basis and show that you can break even at that lowest power price.’ But is that even conservative enough?

                   We adjust it for inflation so you’re not using nominal prices from five years ago, for example, but it comes down to how low will natural gas prices go. That’s really what’s driving the clearing prices, and they just keep dropping. There has to be a natural floor, right? Steel costs you so much money. But natural gas prices have shocked us every year, and that’s what’s really setting the clearing prices.

Wickham, Voya:           Greg’s comment goes to the earlier point about market participants making different progress in their understanding of the power markets. The price of natural gas is so important in that, and shrinking demand in numerous portions of the country is so much a part of that. I don’t necessarily want to point my finger at the sponsor and say, ‘It’s your fault, because you’re coming to us with an irrational story’ out of the gate, but it would be more encouraging to more participants in the market if the sponsor market came out and said, ‘OK, we had this consultant study that shows continually increasing power prices and they’re based on continually increasing natural gas prices’—which we, at Voya, just don’t see. I don’t know where you build that case. I mean, there’s this notion of large exports, a notion of increasing costs. We don’t know where that comes from, because we see shrinking energy services prices, we see reserves getting into production the minute that export capacity is available to move them around, we see additional LNG projects getting to FID and LNG and gas prices just don’t seem to care. And so, your point, Greg, is exactly the right one. How badly must power prices perform for this project that you’re showing me to default? But, in the meantime, numerous project offerings show power prices doubling  over a 15- or 20-year period, which we just don’t see as realistic. I think for folks that may not be as aggressively pursuing an understanding of the power market, it may be easier for them to embrace a more steady-state base case than a wildly optimistic one in order to get them to enter the market for the first time and broaden the group of investors that are considering a non-contracted project.

Fuchs, BlackRock:    One thing to keep in mind when you talk about investment grade and non-contracted revenue streams is that in the non-contracted environment, you will see more volatility in cash flows, which doesn’t really lend itself to a mortgage-style or sculpted repayment profile. So, typically, you would structure these deals with some sort of flexibility in the repayment profile.

Manseau, Barings:    Sweep to a target.

Fuchs, BlackRock:    Sweeps, target balances, something like this, right? And these structures sometimes don’t fly well with an investment grade investor.

Bloom, SLC:  It’s more of term loan B style.

Fuchs, BlackRock:    That is more TLB style. An investment grade investor typically wants to have good visibility around the repayment profile and pre-payment penalties—all the good stuff. But that’s very hard to put in place for a fully merchant or non-contracted portfolio.

Wickham, Voya: Fixed-rate insurance investors look at that unpredictable repayment as difficult to digest. Their fixed-rate asset is matched with a fixed liability and so sacrificing a make-whole requirement is a challenge for some in the market.

Fuchs, BlackRock:    The Rockland Capital peaker portfolio was actually an interesting case study in that regard, because they were trying to marry both worlds, and that was, I think, the first one that got done in that style.

PFR:           Which elements of each style did they marry together?

Fuchs, BlackRock:    That was a deal in PJM that was mainly relying on capacity prices. Something like that would typically have been done in the term loan B market, or in the private below-investment grade market, and they managed to get an investment grade rating and fund it in the investment grade market.

Manseau, Barings:    It had term loan B pricing on it, though, to Fitz’s point.

PFR:           So, would it have attracted an unusual investor group or the usual, investment grade, private placement investors?

Manseau, Barings: Yes, the institutional investors that really rolled up their sleeves and looked into power deals certainly understand it. We have a former GE Energy Financial Services underwriter/originator on our team. She spent the better part of her career there analyzing deals like this in the bank and term loan B market, so it’s not unusual. It’s just marrying the capital with the opportunity, and that goes to NAIC capital charges versus bank pricing, and to the fixed-rate nature of the coupon. Some of the variables are, do you do a fully amortizing deal or do you do a sweep? Or do you do partially amortizing down to a reasonable dollars-per-megawatt balloon value?

PFR:           When there is a certain amount of support underpinning a project in the form of a power price hedge, how important are the features of that hedge, like the counterparty on the other side of it, how many years it is and what type of deal?

Wickham, Voya:        It’s just another contract associated with the transaction. It’s not necessarily a PPA but you worry about many of the same things that you are worried about on a traditional power purchase contract. You’re worried about the quality of your counterparty, you’re worried about the market competitiveness of the contract, not just today, but you think that it provides the project and the related parties a reliable economic advantage. The counterparty can find themselves in difficulty for reasons that may not be related to the performance of the underlying project. So you’ve got to worry about that contract surviving, not just in the context of the project that you’re considering, but in the context of what other activities that counterparty may be involved in.

Manseau, Barings:    The sophistication of the sponsor negotiating the hedge matters to us because they are complicated. Basis risk and the node you’re delivering to really matters.

Bloom, SLC:  I think the merchant analysis has to go into it as well, saying that if the contract is not there, does this still make sense on a merchant basis? I think that’s a lesson that we’ve all learned over what’s happened over the last year.

Manseau, Barings:    Hedges do help you get financing, because it means if you’re comfortable with your revenue counterparty, you have visible cash flows. You just have to make sure you understand, when can they not pay on this hedge? In our shop, the infra debt team sits side-by-side with the private corporate debt team. The corporate analysis of your offtaker is a fundamental part of what we do in underwriting.

Bloom, SLC:  I agree with that, but I would still say that two years ago we’d probably do analysis and say how strong is your PPA, how strong is your counterparty. And now there’s an additional layer of due diligence that goes on.

PFR:           We have two asset managers here that are not restricted by the same capital charge regimes as the others. Daniel, you’ve been focusing more than the others on sub-investment grade opportunities. Traditionally, that is the term loan B market. It is dominated by CLO managers. But you are in the infrastructure debt team at BlackRock. What is your strategy?

Fuchs, BlackRock:    Yes, the TLB market is a very visible market in the below-investment grade world, but it’s not the only market we are looking at. I would agree in that it is heavily dominated by CLO players, and it doesn’t always lend itself to infrastructure investors. When you look at what we do in the below-investment grade space, it’s not always suitable for the TLB market, which is really driven by few factors. One, the TLB market is a very quickly turning market, and you do have a fair amount of rating buyers. I wouldn’t describe us as an investor that is buying a rating. Obviously, a rating is immensely helpful in understanding the credit quality, but we always do our own credit analysis. And a TLB deal can take two weeks from launch to close, which is not always enough time to do all that analysis. Quite frankly, we do not even always have access.

PFR:           It’s also very liquid, isn’t it?

Fuchs, BlackRock:    It definitely has the perception of being liquid.

Manseau, Barings:    Until there’s a problem.

Fuchs, BlackRock:    What we have all seen in the financial crisis is that liquidity is the first thing that goes away when you really, really need it. So as a result, more investors are actually willing to invest in illiquid asset classes such as infrastructure.

                   Coming back to your initial question: Yes, the TLB market is a market we’re looking at. However, we focus more heavily on private, club-style and direct deals in the high-yield space.

PFR:           And Patrick, do you at Barings also look at those kinds of deals?

Manseau, Barings:    We do. We have mostly insurance clients, but we have some flexible capital that allows us to buy opportunistic high yield deals. We’ve done a couple this year. Generally, because our clients allocate to high yield, there has to be a good story in terms of the underlying credit plus the return to justify not just putting their high yield in the term loan B market. So we try to deliver real value when we do it.

PFR:           And even though it’s not investment grade, do you need a rating on those deals?

Manseau, Barings:    We don’t need a rating on investment grade or sub-investment grade. We map deals to a rating. An agency rating just provides comfort with regard to the capital charge you’re going to get. I don’t know that project finance ratings are as predictable with our regulator as corporate credit ratings, so you take some of the uncertainty out of the capital charge with an agency rating, but we don’t need one.

Fuchs, BlackRock:    The same here.

PFR:           Would you say that this kind of product, the private, unrated debt product, is a growing area, or an area where there are more opportunities?

Fuchs, BlackRock:    When you look at some of the newer funds that are popping up and that have already been announced, yes, it seems to be a growing market: double-B spreads these days are very close to triple-B spreads. This tells me that investors are looking for yield and are willing to cross over from I.G. into the double-B space. There is lots of capital out there and people may want to get out of riskier equity investments perhaps to move into something a little safer, which creates additional price pressure.

                   Interestingly enough, there is a relatively wide, 200 to 300 basis point price differential between double-Bs and single-Bs.

                   There is also a notion that the cycle may come to an end and people may perhaps shy away from the higher-risk stuff. What we see as a result is a healthy amount of demand for high yield capital.

                   Typically, we like deals in the high yield space to be highly structured. And we like to get involved early and help to develop the structure to make sure it has the right covenant package, that it has the right risk mitigants and that we do understand the credit really well.

Lecointe, LGIMA:      Is it not fair to say that all these new infrastructure funds are targeting more risky investments? Just looking at the investment targets they’ve got, they seem to be more looking at single-B risk when these funds are marketing, you know, between 6% and 8% returns…

Fuchs, BlackRock:    Yes, I think some of them are. The other interesting thing is that it’s an international market. When you look at U.S. insurance companies, they are still very heavily driven by NAIC treatments and external ratings. That may not necessarily be the case for European insurance companies, for example, which typically follow Solvency treatment. That may lead to different risk appetites.

PFR:           The final topic that I wanted to bring up was the competition or complementariness between the private placement market and the bank loan market. How has that dynamic played out this year so far?

Bloom, SLC:  A lot of what we’ve done stems from the Canadian P3 market, where typically you have these hybrid structures of banks financing a short-term piece and bonds financing a longer-term piece. So it’s something that we’ve done for the last 20 years and we’re seeing it more and more in the power space.

                   But what I’d say is that the institutional market, in terms of its competitiveness, has recently taken away a lot of the benefits that the bank market has. We’re able to do delayed draw, which was a big advantage that the bank market had. We’re able to do deals that don’t necessarily have a rating. So there are a lot of advantages that were in the bank market that are no longer there because of changes in structure in the bond market. However, there are still a lot of opportunities where we can see ourselves working together with the bank market, as we’ve done in infrastructure.

Manseau, Barings:    I think the bank-bond hybrid has become much more established, understood and accepted. This year, Barings has seen opportunities to work with a bank-bond solution in M&A deals, where we come in and provide firm fund commitments to execute at closing, which has been demanded by sponsors who want to lock in the return on a piece of it, but maintain some pre-payability. The bank deal provides the pre-payability and flexibility, in terms of the capital structure, and the institutional tranche delivers long-term fixed-rate cash flows for our clients. Sponsors also get an IRR they can bank on. Institutions are getting more nimble in terms of being able to close into an M&A situation, where historically, it was execution risk that sponsors were worried about.

Lecointe, LGIMA:      It is really a big change. Five years ago, I was only working on refinancing. Now it’s become more and more common to work on acquisition financing, running several trees, and, as Patrick said, proving to the market that you can deliver certain funds on a very tight schedule, which I think is a big change in the institutional debt market, but it is not something that every debt investor is capable of doing, only the largest and most sophisticated investors.

PFR:           Running several trees? Would that not be difficult to manage just because a lot of the teams are quite lean? MUFG has dozens of project finance bankers. They can easily support as many bidders on an acquisition as they like. How does that work in private debt?

Lecointe, LGIMA:      We’ve done it many times, in the U.K. and the U.S. It’s been working very well. You need to manage firewall information very carefully. You’ve got people who are only dedicated to this tree, same thing with the credit analyst, and the sponsors are happy with this.

Manseau, Barings:    I’m sure everyone here is asked to run multiple trees. You just have to make sure your firewalls are in place.

PFR:           There are about three months left of the year. How do you expect the rest of 2019 to pan out?

Wickham, Voya:        I think it’s coming full circle. There are a handful of transactions that would love to come out of California. They will each have their own individual characteristics. It will be interesting to see if the market embraces the partially addressed situation in California. That will have a lot to do with how the year plays out, in terms of whether we think it’s been a busy and successful year. Somebody’s got to be first from California. That first deal will be interesting. Obviously there’s a large delta between how the market will perceive different offtakers, but that’s only one component of the situation. But they’ve got very, very large renewable mandates. They’ve got more power they’ve got to build in the state to fulfil that mandate and they need the markets to be open—ours and others.

Manseau, Barings:    It’s always hard to tell how the fourth quarter is going to be. It goes one of two ways. The holidays are actually quiet and you can go and enjoy them… or they’re incredibly busy. The first quarter, Andrew said maybe it was down a little bit this year. The first quarter was down, then it snapped back to year-over-year similar comparables. Normally, the day after Labor Day in the U.S., you see deals launched. We haven’t seen that yet, but I keep hearing that deals are coming in October—midstream deals, power deals, different power and energy deals. We’ll see, because at some point you start running into the reality of the timeline, and then they get pushed to next year.

Bloom, SLC:  We’re spending a lot of our time now bidding for deals that will likely be 2020 deals. We keep hearing about deals that were supposed to come out after Labor Day. That hasn’t happened yet. Now we’re hearing that they’re going to be in October. That may or may not happen. But we do know that there is a decent pipeline of bid situation deals or M&A-type deals, which is frankly where you have to go for value these days for deals in 2020. We’re spending a lot of our time building our book for 2020.

Wickham, Voya:        I think if I was a sponsor, I would be concerned about timing as well. Think about November, December of 2018—very interesting market in Treasurys. We made some deals in late 2018 that looked very different than they were originally intended because of market conditions. I don’t think we would expect Treasury rates to behave the same way in November, December 2019, but markets are very, very uncertain and volatility can come in many forms, as people begin to assemble the way they want their book to look for Dec. 31. It could have any number of potential effects on our market.

Fuchs, BlackRock:    Fitz is making a very good point. There are a lot of macro events coming up as well. Oct. 31 is waiting. End of year is waiting. Which means there are potentially more trade tensions, potentially more tensions in Europe and Great Britain. Hard to predict what that means for deal flow.

                   The other thing which historically has driven deal flow [in the renewable sector] is cliff risk on PTCs and ITCs. I don’t see that this year so much. On the solar side, there is a lot of talk about warehousing panels and doing all sorts of grandfathering, starting construction early or whatever solutions there may be. So, I don’t see a crazy rush on that front.

                   And then there is just uncertainty continuing in California. No real new-build signal in Ercot. Not really a big signal in PJM. I think deal flow in the power sector will kind of chug along for the rest of the year.

Manseau, Barings: We don’t know what’s going to happen in the M&A world either, but we’ll be open.

Lecointe, LGIMA:      I am sharing the same views as the others regarding the rest of 2019. The next few months are going to be very interesting.

Related Articles