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NOTE FROM THE EDITOR

It is to be hoped that project finance professionals have had a restful and relaxing summer vacation and are returning to work for the remainder of 2019 with energy levels fully topped up. They will need all the strength and stamina they can muster if they are to keep up with the frantic pace of activity that is expected, particularly in renewables. 

Looking back, the first quarter of 2019 was the quietest in wind and solar for many years, presumably because project finance officials were exhausted from the onslaught of the final three months of 2018. But the respite was short lived as activity picked up in the second quarter, with more than $4 billion of wind and solar project financings signed, according to data from IJGlobal (see chart below).

Midyear Chart 600x400

This is all the more remarkable given the uncertainty caused by Pacific Gas & Electric’s Chapter 11 proceedings in California, which froze financings not only for projects connected to PG&E but also those under contract with other investor-owned utilities in the Golden State. Imagine what the numbers would have looked like if PG&E had been firing on all cylinders! 

The rush to maximize tax credits ahead of the phase down is so intense that, perhaps for the first time ever, developers are complaining that there are not enough lawyers to go around. And deal watchers say that 2020 and 2021 will be even crazier. 

Will the coming tidal wave be enough to dispel the mantra of recent years, that there is “too much capital chasing too few projects,” and redress the balance of power between borrowers and lenders? 

Alas for the bankers, the consensus is that it will not, and that loan pricing and terms, while they may finally have reached a floor, are not likely to move back in the other direction any time soon. 

And this is before taking into account lending activity for gas-fired projects, which has continued this year with both new build deals and refis. Assuming PJM Interconnection and the U.S. Federal Energy Regulatory Commission are ever able to settle their differences on capacity auction rules, market participants are expecting prices to clear at favorable levels for even more CCGTs there, while low reserve margins and scarcity pricing in Ercot could spur development and financing of peakers in Texas. 

As project finance officials steel themselves for the impending maelstrom of dealmaking, what better preparation than to read through PFR’s Project Finance Mid-year Review Roundtable to benefit from the insights of our esteemed panelists? Enjoy!

Richard Metcalf

Editor

Power Finance & Risk


PFR Project Finance Midyear Review


Midyear Roundtable 600x400


Participants:

Nick Knapp, Senior Managing Director, CohnReznick Capital

Ron Erlichman, Partner and Project Finance Practice Co-Chair, Bracewell

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

Benoit Allehaut, Managing Director, Capital Dynamics

Aldo Portales, Assistant Treasurer, NextEra Energy

PFR:           The second quarter of this year, according to the most recent data from IJGlobal, was the second biggest quarter for North America in renewables project finance out of the last six, with about $2 billion of wind project finance, and the same amount, roughly, of solar. In the last few years, wind and solar project finance activity has consistently peaked in the fourth quarter of the year, so do you think that trend will continue this year? Will we have a jumbo fourth quarter?

Ron Erlichman, Bracewell:  You generally have a trend in project finance that in the fourth quarter there’s a peak and an effort to close out transactions before the year concludes. But I think that the effort to capture the highest tax equity credits is driving the current fourth quarter trends in the renewable space.

Benoit Allehaut, Capital Dynamics:            I think you need to separate solar and wind. Wind is on very precise step-downs, so that’s the biggest driver. It brings us back to the historical PTC [production tax credit] expiration date, where people gave up their Christmases in order to close deals. On the solar side, obviously, we’re in a situation where people are starting construction or making deposits, but there is a delay of sometimes several years before the project finance volume will appear.

Aldo Portales, NextEra Energy:      Yes, I tend to agree. I think the fourth quarter should be an extremely busy quarter. A lot of it is driven by construction cycles and when construction is going to be completed. That would be the time a lot of the tax equity deals close. You try to get them closed as soon after COD as possible or even to coincide with COD. So with a lot of construction occurring in the fourth quarter, I think it’ll be an extremely busy fourth quarter.

Nick Knapp, CohnReznick Capital  Yes, I would agree with that. For us it’s pretty consistent, so I’d say it’s going to look similar to last year, from everything we’re working on. This is the largest team we’ve ever had, this is the busiest we’ve ever been at this point in time, mid-summer, really gearing up for the closings over this quarter and next quarter.

PFR:           The figures that I referred to include not just primary financing of new build projects, but also refinancings. Is primary financing the main part of the activity that you're seeing? How much of it is acquisition financing and refinancing?

Knapp, CRC: I think we’ve seen a fair amount of refinancing activity over the last 18 months. From our perspective, we see less of it now, so I think the wave of activity, the bulk of it, is probably completed. A lot of what we’re looking at now is new financings.

Allehaut, CapDyn:     Well, if you take into account refinancing related to PG&E [Pacific Gas & Electric], it’s going to be a bumper year.

PFR:           We’re going to come onto that later. Sticking with the new builds now, we're told that there are a lot of development shops that have worked very hard to qualify turbines for the PTCs and have a lot of qualified turbines. But not all of them necessarily have enough projects to put them in, or enough PPAs.

As the deadline nears to start construction, do you think that there will be evolving strategies around how to deploy those turbines? Is there going to be opportunity for joint ventures, things like that?

Allehaut, CapDyn:     The general trend is that investors who acquired turbines to qualify projects always did it with the expectation that if they wouldn’t have enough projects they would be able to fit more than 5% into their core projects, and in effect have almost the entire project made out of safe harbored turbines. We are seeing, from time to time, people that are bringing to our attention projects with PPAs and safe harbored turbines. It hasn’t met our investment mandate, but I do believe that the most sophisticated investors, like NextEra, when they purchase safe harbored turbines, have an anchor project where they could wrap up these turbines in case they didn’t have enough offtakes.

Erlichman, Bracewell:          I’d agree that the most savvy investors didn’t get long on turbines. I think that there are a handful that have gotten a little long and that are looking to deploy them strategically, doing it through joint ventures. Depending on how long they are, we might see other types of monetization of those assets appear.

Allehaut, CapDyn:     Turbines are not the only way. A lot of people went the transformer route. Quite a few people dug holes, built roads, in order to qualify their early development stage assets. So turbines are just a sub-component of securing the PTC. It’s not all 5% safe harbor.

Knapp, CRC: That’s a great point. I think the majority of our financing work has been through physical work versus the 5% test.

PFR:           And on the solar side, we have seen things like the tariffs and the step-down of the ITCs causing spikes in demand for equipment and pushing up the prices of solar modules and other equipment. What’s the latest situation on that front?

Allehaut, CapDyn:     We see a full 10 cent spread between buying a panel now and delaying the purchase by two to two-and-a-half years. So the reality is that it’s fairly nonsensical, if you have the ability to manage your commercial operation date, to secure the ITC [investment tax credit] by buying panels. There are cheaper means, and perfectly fine ones from a tax standpoint, which avoid price gouging attempts in the market. Paying 40 cents, 42 cents per watt for panels doesn’t make any sense.

Portales, NextEra Energy:   We feel very good about the prospects for future solar. Our balance sheet position allows us to take a conservative position as far as qualifying assets, and we’re very pleased with what we expect in the future. I think our view is that it’s a very attractive renewables market.

PFR:           So clearly there’s going to be a lot of renewable energy projects in the next couple of quarters and beyond, into next year, looking for financing. The debt market seems to have easily digested as many projects as the developers have been able to throw at it in recent years, and still have appetite left for more. But do you think that it’s possible that the balance of power could shift a little in favor of the banks, in terms of pricing and other terms?

Erlichman, Bracewell:          I don’t see anything that indicates right now that the market is getting more favorable for the lenders. If anything, the pricing seems to be moving the other way. Even though it has spread a little bit, the term loan B market, although not so much in the renewables space, is causing compression on the term loan A market.

You have new entrants to the market, and you’re seeing bridge financing for wind sub-Libor plus 100 based on trade press reports. So, unfortunately for my lending clients, I don’t see anything improving for them in the near term. But for our sponsor clients and investors, it’s a good market.

Portales, NextEra Energy:   Yes, we see a very attractive market right now in the P.F. space. So much of the business has gone to the tax equity side that there’s a hunger for deals. I’ve been doing project financings for about 10 years and the terms that we are seeing now are the most attractive that I have seen.

PFR:           Are you able to quantify that?

Portales, NextEra Energy:   It’s very attractive pricing.

Allehaut, CapDyn:     On the construction financing side, spreads are below 100 bp. I never thought I’d see it, but it’s now well established. What’s been interesting for us has been, starting from an outlook of rising interest rates, and balancing the bond market—rated, unrated—versus the bank market, I think everything indicates right now that, from a rate perspective, it’s probably quite attractive not to swap, and not to enter into long-term [interest rate hedges]. So the power dynamics between bond and bank has shifted a little bit.

Knapp, CRC: Even on the longer-dated fixed-rate bonds, I think they’re seeing that pressure and having a tough time competing with the bank market. But even that pricing’s coming in. We continue to be surprised as we hit new floors on our financings. I do think we’re probably at the floors right now, and it’s a question of the terms and the amortization profile, sizing, merchant, comfort around basis risk, that also continues to improve. The result being not much of an equity cushion, all things considered. So I don’t think there’s too much room left to move in terms of continued improvement in terms of economics for the sponsors.

Portales, NextEra Energy:   I think that’s a great point. You’re starting to see things that might not have been acceptable to the banks a year ago work their way into deals in an effort to try to decrease the pressure on the rates.

PFR:           Specifically?

Portales, NextEra Energy:   Equity cushion; how much leverage; being willing to take a merchant tail on a solar project.

Allehaut, CapDyn:     A few years ago there were very few lenders that would accept a merchant tail. This is much more widespread. I think we also need to be very careful that not all projects are the same. Not all offtakes are the same. So if you have a very high-quality project, everybody is queuing at the door. We are seeing a lot of projects that are really quasi-merchant, and I think that we’d want to make sure that people are not mistaken in thinking that a very, very high-quality credit rating and long-term tenor is the same as a ten-year hedge in Texas.

Knapp, CRC: You’re starting to see this shift back to major energy strategics and utilities that will own a big portion of the U.S. renewable projects. And a lot of those companies don’t focus as much on the level of leverage that they use, beyond tax equity, and so that’s also a feature that will result in a continued competitive dynamic for lenders.

PFR:           What about tax equity? Is there enough of it to finance this wave of renewables? And if so, on what terms? Because that’s a very different dynamic, isn’t it?

Allehaut, CapDyn:     The tax equity market doesn’t have the same differentiation in pricing that you have in the lenders market. It comes to more complex structuring elements like deficit restoration obligations and the like. I think there’s tremendous appetite for high-quality transactions. Tax equity—somebody said this recently at a conference—tax equity is more senior than senior debt. So they’re much less exposed than lenders. When it comes to the C&I space, where we’ve recently entered, I think it’s more of a subset of the tax equity market than the broad tax equity market at large. But we do think that the tax equity market is also looking at smaller projects and aggregation versus large projects.

PFR:           We were hearing, at the beginning of this year, and toward the end of last year, that all-in returns on tax equity investments had come down a little from where they had previously been.

Allehaut, CapDyn:     Well, I don’t think that’s the case, and I know for sure that quite a few tax equity investors are leveraging. So I already have a grievance around their unlevered return at the project level, but when you see leverage on tax equity based on the cash portion of their investments, it becomes really the best asset class in the space.

But whether you change the flip date or not, they have to have residual interests, so, at least on the solar side, tax equity investors are in the nine-ish percent return bracket. You can’t really escape that.

Knapp, CRC: Over a two-year horizon, there was significant movement in tax equity yields, and the level of spread between tax equity and debt, and its being senior to back leverage lenders, got to a point that it was tough to rationalize how that happened, other than supply/demand. And I think as more investors continue to come in, that was driving the difference, and so it’s starting to come down.

But for us, it hasn’t really moved over the last six to twelve months, where the range we see is, on the after-tax flip rate, 6% to 7%. For a while I think we were in 8% to 9%, 8% to 8.5% range. And it came down to a level that I think makes more sense, but there’s still a fair amount of room from a risk premium standpoint. And it’s just a question of supply/demand as to how far that return will go.

But to Benoit’s point, on the continued equity interest, that’s fundamental to that structure, and you’re not going to be able to move that pricing down.

PFR:           What, at this stage, is limiting the supply of tax equity capital to the point where the supply/demand imbalance is causing that discrepancy?

Allehaut, CapDyn:     That’s Nick’s job, but from a book perspective, tax equity is an acquired taste.

Erlichman, Bracewell:          I think there’s a difference—Benoit, you made this point—there’s a difference between tax equity for your large utility-scale solar and wind and then aggregated C&I or other projects. There still is a spread. The large tax equity investors aren’t interested in deploying $50 million, small amounts of money, when they have an opportunity cost associated with that.

So the challenge is trying to figure out how to find it for small projects, and what we’ve seen is an aggregation process. But that’s where I see the supply limitations. For large projects with quality sponsors and where the metrics make sense, I think the pool of liquidity, from a tax equity perspective, is still there. I don’t know if you disagree.

Portales, NextEra Energy:   The tax equity market’s pretty robust now. There’re a lot of new entrants that we’re seeing that are making some of their initial tax equity investments. On the discussion about small projects, I do think that it is a challenge for tax equity investors. Because the amount of due diligence is the same for a 50 MW or a 200 MW project, and you get more bang for the buck on the larger deals.

Investors like the larger projects because they get the economies of scale and they are able to provide the best terms for those.

Erlichman, Bracewell:          It’s also a transactional cost issue, as much as the tax equity investor doesn’t want the opportunity cost of the transactional side. It gets hard to explain that there’s really no difference between a 50 MW and a 250 MW project for the amount of work that folks like Nick and I have to do.

Knapp, CRC: From a number of tax equity investors’ perspectives, we’re certainly at an all-time high, and it continues to improve. Especially for solar. And I think the biggest dynamic there is just that it’s easier for a new entrant to understand, get comfortable with the risk profile on solar versus wind.

But the issue, in terms of continuing to move and penetrate on pricing, is that there really has to be more competition from a lead kind of bank or insurance company investor, with a full team mobilized, and a real annual budget of a billion or two billion dollars, for them to start to move the needle. Because we’re seeing a lot of entrants that are more participating investors that go alongside other investors.

And the budgets, from an annual perspective, are relatively small in comparison. So it’s tough for them to be the ones to move the needle. So it has to come from a lead bank to really start to move it, from my perspective.

Allehaut, CapDyn:     And I suspect that a lot of new entrants were former syndication partners that are now graduating to participating partners. From a sponsor standpoint, execution matters. And as much as a tax equity team doesn’t want to waste its time with an inexperienced sponsor when it comes to putting the necessary information package together, from a sponsor perspective you don’t want to work with tax equity investors who don’t know how to process due diligence.

So there’s a very big premium on both ends, working with experienced and sophisticated counterparties.

Knapp, CRC: That’s a great point. Because we’ve seen an influx of investors that have historically been real estate tax credit focused. As this market matures and it’s proven out, they’re coming in. But that’s the exact point. On a good project with a good sponsor it’s tough to get to a point of making that decision to go with that first-time investor, from an execution risk standpoint.

And what happens is, they get frustrated over time. We’ve seen this with a couple investors that we spent years getting to the point of approvals to make an investment, but they can’t put the money to work. And then they lose focus on the industry.

PFR:           Okay. So not expecting any huge movement there on pricing for tax equity.

Ron, you mentioned earlier shadow ratings for companies in the offtaker position. All these projects ultimately need to sell their power to somebody, whether it’s under a contract or a hedge or just spot market sales. How has the universe of procurers of renewable energy evolved recently?

Erlichman, Bracewell:          Well, as everyone at this table knows, the traditional PPA, 20-year busbar, is almost non-existent. If you have a PPA, it’s at a hub, and so, best case, you’re dealing just with basis risk. But the market has grown and splintered dramatically. You have hedges as a source of revenue for a project, and the energy hedges may need to have a basis hedge, depending on the project, so you could have a hedge upon a hedge. Everyone knows about the corporate offtake arrangements that are being entered into, and the market continues to grow beyond just companies that have a social program that they’re trying to implement, to companies who need it, in their view, to maintain good consumer relations, and into industries that I didn’t think we’d see so quickly. You're seeing different types of corporate offtakes, where allocations of risk on the project, including operational risk, are being shifted to the project. That wouldn’t have been the structure under a traditional PPA. So it’s becoming more and more complicated. And I think it’s becoming more challenging for the debt markets to understand and accept the risks on those products.

Allehaut, CapDyn:     I wouldn’t be as stark as saying that standard PPAs are now unicorns. I do think that very experienced developers are able to secure more plain vanilla PPAs. I do see a lot of what I call asset flippers that will go for any form of PPA in the hope they can resell. Folks who are long-term owners absolutely care about the inherent quality of the type of offtake.

I do believe that, on the corporate side, there’s more and more realization that some of the VPPAs were not necessarily as good as advertised. They were basically planning on a certain amount of benefit on the arbitrage between what they were signing and the hub. And if prices at the hub kept crashing, they’d be upside down. As a matter of fact, I think most offtakers have been upside down. Most corporate buyers have been upside down in these VPPAs. We are now seeing, in competitive markets, some real interest for physical transactions. So it’s an ebb and flow. It depends on each market. If you’re a long-term owner, like NextEra or Capital Dynamics, you really want to work quite hard on the type of PPA.

And it can be a silly thing such as not taking negative pricing curtailment risk. There’s a lot in these PPAs that you have to be careful about.

PFR:           And with the changing risk profiles of these contracts and the shifting of allocation of risk between the different parties, what are the credit implications of that for project finance?

Erlichman, Bracewell:          Well, I think to Benoit’s point, I agree there have been projects out there that clearly don’t have a long-term view and have entered into PPAs that have some mechanics in them that I would say are challenging. And any time you present something like that to the debt markets, and to the tax equity markets as well, you run the risk of making a project not bankable. I have seen that happen. I’ve seen projects that are in the secondary market because the way they’re structured... No one can get comfortable with it.

Portales, NextEra Energy:   We spend a lot of time upfront looking at the quality of PPAs. Is this going to be a financeable PPA? We’re very disciplined to make sure that that’s the case, and when people show us acquisition projects, one of the first things we look at is the quality of the PPA.

We want to make sure that we have a long-term financeable project. That’s one of the things that’s been a key element of our success, and we’ve very disciplined about our approach. Our track record has given us an opportunity to pick up a lot more of the quality PPAs, where the customers know us and they know we have a track record of delivering on projects. So for us, it’s maybe a little bit of a unique position, our discipline, with regards to execution, and our financial discipline has served us very well.

Allehaut, CapDyn:     We’re seeing more and more, from offtakers, a need to know who the ultimate owner is. And that’s something that we advertise. We own several gigawatts of generation and we’re long-term investors. And it allows you, in negotiations, to probably extract better terms, and terms that are inherent to long-term ownership, as opposed to terms with a view of reselling to somebody. But we pass on projects that are presented to us because, inherently, the terms are either non-financeable, or the risk is mitigated by a consultant report that doesn’t mean much.

Erlichman, Bracewell:          Are you suggesting a change-of-control provision in the PPAs?

Allehaut, CapDyn:     No, it’s simply, when you are sitting down with co-ops and universities and corporate offtakers, they want to know who the long-term owner’s going to be. Twenty-year ownership.

Portales, NextEra Energy:   Yes. They want to know who it is.

Knapp, CRC: When we first started to see the transition, with shorter tenors and basis risk, from the sponsor capital side, debt, tax equity, everyone, people were pretty hesitant to get involved, and really wanted to fixate and focus on finding busbar PPAs. When they realized that the market was shifting, we saw a tremendous move. And I think the markets have opened up. Every project, every PPA is different, but it’s come a long way to allow flexibility for sponsors to decide what can make sense for them.

Erlichman, Bracewell:          It’s like everything else. Nobody wants to be the first. There’s comfort in numbers, and people see projects execute, and with a certain structure, that opens up the market. But then there’s some things that people just won’t pull the trigger on, and that will fall away. So we’ll see what the market will accept.

Allehaut, CapDyn:     We also shouldn’t forget that the product is changing. When I started in renewables, now way too long ago, the only product offered was a unit-contingent PPA. Today, especially with the emergence of batteries, these are more shaped deliveries. So the ability to guarantee, from a technical and operational standpoint, that shaping of delivery is becoming more critical.

So I think that offtakers are looking at who’s going to be on the other side of the equation to really operate these combined power plants, as opposed to simply taking a product as a pay-go.

Knapp, CRC: The demand is certainly there, and to a point we haven’t seen before in the industry. That will continue. We’re not going backwards here. There’s going to be more and more demand for renewable power. And the question we look at is, is that going to be growth in C&I PPAs, or is that going to be a transformation as utilities ramp up as well for a green tariff program, where we start to see more going back to the utility side, to allow for corporates to buy clean energy through a utility?

Allehaut, CapDyn:     The other dynamic which has been interesting is a lot of players have been sitting on the side of market, because they kept seeing the knife falling. So they saw $100/MWh, they saw $80/MWh, they saw $60/MWh, they saw $40/MWh, and they don’t want to buy the peak. They don’t want to lose face by signing an out-of-market PPA. At the same time, we believe that we saw the first increases in prices of wind turbines, and we certainly have the phase out of the PTC. We’ve indicated to potential customers that the ITC has a phase-down. I don’t think there’s a lot of costing out left in the renewable energy market. It’s already a very, very competitive product. But it takes time for some buyers to decide to take the plunge and get into that market without the fear of buying twice more expensive than if they had waited a year.

PFR:           Of course, if you are developing a solar project in Texas, apparently you no longer need an offtaker. You can get a hedge and get the banks to lend on the basis of partly merchant revenues. That was quite an interesting development recently. Do you think those deals make sense and will we see more of them in Texas?

Portales, NextEra Energy:   We’re very disciplined. We focus on contracted projects, and we’ve got a backlog—thousands of megawatts of backlog over the next few years.

Allehaut, CapDyn:    I’ll echo Aldo. We take tremendous pride in being disciplined, and contracted projects, as a long-term owner, absolutely matter.

Erlichman, Bracewell:          It depends on the sponsor, and I think it makes sense for particular sponsors. I think that there are, as Benoit said, there are folks that are looking to flip, and so will do whatever it takes to get a project to a place where they think they can flip it. And then there are some that have experience in the quasi-merchant market and are thinking that there’s upside that they’d like to keep in a project, and that they can commercialize a project in a slightly different way.

So I think there’s two extremes and the middle. Unfortunately there may be some projects that don’t make sense, that will continue to churn in the market.

Knapp, CRC: For Ercot solar, it’s moved so fast, there’s a level of uncertainty on the build-out and what that’s going to mean for basis and congestion. There’s a lot of appetite from C&I in that market as well, but with the current pricing on what we’re seeing, it’s a question of: does it make sense to enter a 10- or 12-year contract at the pricing that we’re seeing today?

Not every project is created equal. Not every hedge is the same. Location matters. And there are projects where the hedge is coming in—we’re starting to see this more—coming from the historical 10-year term to seven or eight years. And in a great location for a good sponsor, we view those as strong projects, and certainly financeable, and we’ll continue to see more of that.

Erlichman, Bracewell:          That’s the key. It’s the location, proximity to load, lack of congestion, and if you can shorten your hedge term, get your pricing down, get tax equity comfortable with that—the shorter buffer—then a project like that might make sense. But again, for the right sponsor.

PFR:           Do you think it’ll work in any other North American markets? I’ve heard some people, this may be quite speculative, but talking about California.

Allehaut, CapDyn:     Well, what’s interesting about California is that the value of the PCC 1 REC is now a significant portion of the total value of a PPA. The environmental attribute is a much greater factor than any electron. And that’s driven, in several markets, by the continued pressure from RPS being increased. And there’s a healthy aspect in signing a long-term PPA with the value of the electron at a discount to the value of the wholesale market. But a lot of folks that are looking at signing these days are doing it with the RPS in mind, as opposed to anything else.

PFR:           Interesting. I did promise that we would come back to the PG&E situation. Now might be a good time. It came up in the context earlier of refinancing activity. How are market participants responding to the situation? What sort of activity is going on behind the scenes, on projects with those contracts?

Allehaut, CapDyn:     I think we were the first to market, and I'm very proud of my team for immediately reacting. We repaid most of our facilities, and have the benefit of a very large balance sheet or equivalent balance sheet with our funds. We learned through this process that the lead mandated arrangers we had selected were quite critical in facilitating this. It can be very, very messy if you work with a very large syndicate of banks, because you’re held by the lowest common denominator.

For us, it’s been a very successful process. This being said, we’re extremely happy with the most recent decisions which really put a timeline on PG&E to exit bankruptcy. I think the bigger concern was contagion happening among other utilities, and in particular SCE and SDG&E, being downgraded to sub-investment grade, which would have had a much broader, unfortunate ripple effect. So hopefully the rating agencies will maintain where they are, and this will unwind.

PFR:           You repaid the debt, so the projects are unlevered. Have you raised that somewhere else to replace that, or are you waiting for the dust to settle?

Allehaut, CapDyn:     We restructured.

PFR:           Okay. And from NextEra’s perspective?

Portales, NextEra Energy:   We are obviously monitoring the situation in California very closely. We are vigorously defending our rights. There’s not a lot I can say with regards to any specifics, but we are optimistic that there’ll be a favorable outcome. It takes a lot of time, a lot of attention, but we’re working on it very diligently.

Allehaut, CapDyn:     It’s fascinating to see. Everybody who’s a big player in the U.S. renewable power market has exposure. And it’s been fascinating to see a technical default ripple through documentation. Not your traditional default of, ‘I can’t pay,’ or ‘I don’t want to pay.’ PG&E is paying its bills. But I have to look on the other side of the mirror, from a lender perspective. Suddenly, internally, these are classified as ‘in default,’ extra credit charge, all of these things.

So it’s really a question of the sponsor working with the consortium and addressing some of the constraints themselves. Nobody that we have seen has tried to take advantage of the situation. And that’s a positive. But it requires a lot of work, and you have to have a pretty agile team to work it out.

PFR:           Ron, you represent lenders. Can you add any insight on what’s going from their point of view?

Erlichman, Bracewell:          We’re currently representing two different lenders with no involvement in the PG&E bankruptcy but who have exposure to projects. Unfortunately, it would be inappropriate for me to comment, other than to say I agree with Benoit’s comment, that it highlights how important it is who you select.  As opposed to, on the front end of financing, saying, ‘Well, I'm going to get an extra 25 bp from this person, so I'm going to go with them.’

These situations highlight why you want to work with the quality lenders on your projects.

PFR:           Presumably it’s also had an impact on deals that may have been about to come to the market, or deal flow in California generally. What has been the impact, and has it also affected deals that perhaps didn’t have PG&E as an offtaker?

Allehaut, CapDyn:     Yes. It froze SCE tax equity. We’ve seen this with very experienced, large banks who asked to wait until the broader trade would happen politically. And we’re hoping that the most recent legislative steps are lifting that constraint. But the cloud of uncertainty and the rating agencies, inverse condemnation, all of these things, really delayed some projects, from a structuring standpoint, because people have choice as to where they place their dollars and they don’t have to do a deal in a particular market if they have an alternative elsewhere.

Knapp, CRC: In terms of some of our mandates, there’s a couple project sales, development project sales, and three to four financings that we’ve completely paused because of it. But everybody was constructive and continued to move along. And I think we have seen positive movement over the last couple of weeks, and I think things will start to open up for the projects we’re working on here.

PFR:           We’ve been talking exclusively about renewables until now. The conversation in PJM is always focused on big quasi-merchant gas-fired projects—they need the most dollars—and financing activity was relatively robust in that area in the first half of the year. We saw several new build deals get done this year, and there are others in the market as we speak. And a bunch of refinancing activity that was just announced in the last few days.

Project sponsors have been using a variety of debt products—term loan As, term loan Bs, of course, for the refinancings, project bonds in some cases, and, something I haven’t seen very much of at all before, a unitranche loan. What can you say about what drives the choice of debt product for the sponsors behind these projects?

Erlichman, Bracewell:          Each project looks at the debt markets and determines which product is going to work for them in terms of how much debt they need as well as the tenor and the flexibility that they may want operationally.

Without commenting on a specific project, you saw one project that appears to have been structured with a toggle, according to trade press, based on whether or not its hedge, or revenue put, or whatever mechanism they’re going to use for revenue assurance on the project, if it wasn’t renewed during the tenor of the debt, there’d be a toggle up to address the pricing risk that the lenders were going to take.

So it’s project and sponsor-specific. Their needs, the project needs, the project quality, project location is driving the different types of pools of debt liquidity that people are tapping into.

PFR:           Yes, we’re definitely seeing differentiation based on the location of the project within PJM or, indeed, New England. And a lot of that seems to be determined by where the capacity clears in those all-important annual auctions.

Erlichman, Bracewell:          There seems to be a focus in PJM on EMAAC and COMED or some of the other zones where there seems to be capacity price separation. Many lenders will say that they’d be concerned about focusing on that price separation, because that can dissipate very quickly through another auction, or a series of auctions. But that certainly has been an area of focus on a lot of the newly announced, and one of the closed transactions.

PFR:           A lot of market participants, certainly the commercial banks and investment banks, have sweepstakes in their offices as to where capacity’s going to clear in PJM . I don’t know if you have one at Bracewell.

Erlichman, Bracewell:          We gave up a while ago, just based on the recent auction results, thinking that it’d be easier to pick a lottery number.

PFR:           In general, would it be fair to say that, if capacity clears higher than it did last year, you are more likely to see more financing of CCGTs?

Erlichman, Bracewell:          I'm smiling, because I’ve chaired a panel discussion at a conference the last two years, and after two years of decline, the topic was, ‘Is it time to abandon PJM?,’ and then there was one year of increase, and it was, ‘Renewed optimism?’ Ultimately, as we were saying in the renewable market, it’s driven by the quality of the project, and the sponsors behind it, and the fact that structures have been put in place in quasi-merchant PJM financing to address capacity market fluctuations with a dynamic amortization balance. So people should stop focusing on the auction, unless there’s dramatic continued decline, and then, maybe, that does suggest that over-building has occurred.

PFR:           I think we may have seen quasi-merchant wind deals in PJM as well. Do the capacity markets in the Northeast have much of an impact on the financing of renewables in those markets?

Allehaut, CapDyn:     The complexity of merchant renewables is tax equity. They generally require a certain amount of contracted cash flows. Projects have been quasi-merchant, but it’s a very small subset of the tax equity market that will accept that, irrespective of fundamentals. Some of the Pennsylvania wind projects were probably 1603 cash grants, really a legacy program. It would be very difficult today.

Knapp, CRC: We worked on a couple last year where the capacity market came into play, and there was significant education with tax equity to get any type of credit for that.

It’s a new factor for everyone to consider, and for some of the tax equity investors. But I think we got to a decent spot on both of the projects, whether there was some level of credit in terms of how they’re thinking about sizing, and their cash allocations.

Erlichman, Bracewell:          And there was no revenue put? Was there anything else as a fundamental revenue stream for those projects?

Knapp, CRC: There was. It was split between a corporate PPA and capacity revenues.

Erlichman, Bracewell:          So it mirrored a CCGT-type transaction?

Knapp, CRC: Yes.

PFR:           Very interesting. We’ve talked about Texas, California, and PJM.  What about the rest of the U.S.?

Allehaut, CapDyn:     We have a development portfolio in Miso, which is a partnership with Tenaska, and it’s a relationship that we absolutely love. Miso’s interesting because it really has, on the supply stack, a very low penetration of both wind and solar. And based on where the cost of solar is coming, it’s really opening new markets, so Miso is ripe for it. There’s a very, very big queue on the interconnection side, but we are working with utilities, and I think they’re generally pretty surprised by where pricing is, and it’s enabling demand. Within Miso, each state and each utility is different.

There is tremendous activity in the Southeast. Georgia is the new North Carolina. So we see quite a few projects coming out of that state.

Portales, NextEra Energy:   We see a lot of prospects throughout the whole country. We have projects in operation or development in 36 states.

PFR:           Is that all?

Portales, NextEra Energy:   We have a very good track record of success throughout the country. Certainly, in the Midwest region. In the Southeast, we’ve been doing some solar projects recently. And in the Southwest, we’ve been active also. We are fortunate in that we have a pretty good success record throughout the country.

PFR:           Looking beyond 2019, project finance bankers tell me that 2020 is going to be crazy, in renewables in particular. Do you agree with that sentiment?

Portales, NextEra Energy:   I do. I think next year will be very active both on the construction front and the financing side. There will be a lot of tax equity and parties will be very busy throughout the year. I was at a conference earlier in the year and people were talking about lining up consultants and attorneys because of the volume of work that’s going to be coming in 2020. It’s going to be a very busy year across the board.

Erlichman, Bracewell:          Never thought anyone would say those words—a lack of attorneys. But we’ve heard that from many of our clients. It’s come up more in the context of specific jurisdictions, local counsel to do the local permitting, title work. That’s a very labor-intensive process.

Also, I'm sure you haven’t experienced this because of your leverage in the market, but there are sponsors that are concerned about access to construction, contractors and concerned about access to sub-contractors, in particular in Texas, with the competition on the west side of Texas in the basins. But to the point about activity, everything suggests it will continue to be robust and increase exponentially, absent other market conditions occurring.

Renewables is gangbusters, but you also have NGL activity, PJM is still producing a deal or two or three a year. Offshore wind. Throughout the entire market, everyone in the project space is incredibly active.

Allehaut, CapDyn:     You need to separate wind and solar. Word on the street is that the U.S. wind market is 10 GW this year, 12 GW next year. Fundamentally, the buyer needs to appropriately pay for power from wind. The PTC has been too much of a skewing factor. Less than $10/MWh for power doesn’t make any sense.

So how the wind market will shape up in a severely ramped-down PTC world is a bit of a question mark. But hopefully some rationality arises. On the solar side, 2020 is going to be bigger than 2019. 2021 is going to be bigger than 2020, and 2022 is going to be crazy. And anybody lining up in 2023 is exposing themselves to the real cliff of December ’23 and the loss of the full ITC.

PFR:           Is anyone wondering what will happen if the tax credits are extended again? At the last minute?

Knapp, CRC: Well, we’ve all lived the last 15 years...

Erlichman, Bracewell:          It’s hard to imagine in the current political climate, and so, as a result, I haven’t heard as much discussion about the possibility. But 2020 will determine it.

Knapp, CRC: There’s definitely a mobilized effort, especially for solar right now, around the extension. But it’s a world we’ve lived in, right? And it’s really got to a traction point. I think the industry always adapts well and works with what we have. The one thing I’d say is I don’t envision a cliff going out to 2023. With climate change and the focus on decarbonization, I just don’t think that we’re going to allow for that to happen. Whether that means an extension of tax policy or we move faster on the rebalancing and normalization of power prices and what buyers have to pay… There’s going to be some period of time when it slows down, but I don’t know that it extends all that long.

Allehaut, CapDyn:     I just think the industry doesn’t need it anymore.

Erlichman, Bracewell:          I feel like that’s a general sentiment among sponsors that people outside the industry looking in are surprised to hear.

Portales, NextEra Energy:   When we look to the future price, wind and solar are going to be the most economically viable generation, the lowest cost. And when storage is included with renewables they become an even more compelling case.

Allehaut, CapDyn:     The interesting thing on the tax side is the potential for standalone storage to get tax credits. Because storage is needed for the real transition. It’s needed for balancing. It’s needed for transmission. Congestion management. So it still, on a standalone basis, needs that kicker.

Erlichman, Bracewell:          As the project finance lawyer, I would be very pleased to see something to help storage development, because right now that’s the biggest challenge. Other than the few deals that have been done, or the one deal that’s been done three times, how do you finance that? That’s part of the issue.

Allehaut, CapDyn:     And the great thing is that tax equity is not disappearing. There’s always been monetization of MACRS. It’s just wind projects with 70% to 80% tax equity as part of the capital structure are projects that are not cash-rich enough.

PFR:           You’re right, tax equity is not going to go away, but it’s going to play a much smaller role. What is going to replace that? Is it going to be more equity, more debt, something else, a combination?

Erlichman, Bracewell:          It’s going to be debt.

Portales, NextEra Energy:   Debt’s the lowest cost of capital, and to the extent you’re able to monetize the tax attributes yourself, it’s the ultimate, to me, form of financing. You do the tax equity deals because you cannot absorb the tax benefits. Otherwise, it’s a more expensive source of financing than debt.

Knapp, CRC: To that point, we have seen a few of the leading lenders work through their approval process on tax equity investments. Hopefully that can be one avenue for a seamless transition, as we get down to 10%, where lenders can still serve that role of monetizing what tax benefits we do have. Obviously, you have to structure it right, but it feels more like debt and will be priced more like debt even though they are still utilizing the tax attributes.

Allehaut, CapDyn:     And don’t forget that because of tax rules, tax equity needs a certain level of cash-on-cash return. So it does take a lot of cash. It’s going to be fascinating with less tax attributes, because you’re going to get to a situation where it becomes structurally very complicated. But they take a lot of cash and that cash can be used by back-leverage.

Erlichman, Bracewell:          That’s the most likely source, either some sort of project debt that prices at a higher level, or a holdco type financing.

Portales, NextEra Energy:   Monetizing just the MACRS gets complicated because of the amount of cash that the tax equity investors will require to make the deals work. It would have to be very attractively priced tax equity because while the MACRS depreciation is a big component of the tax attributes, it’s not the same as it is today where sponsors are also monetizing the PTC and ITC.

Knapp, CRC: And that’s the shift, I think. The leverage will sit with sponsors at that point in time. Or, if they still want to put their money to work, it would have to be more of a prorata-type structure, less of a true tax partnership flip structure. And to make that work they have to price competitively with lenders, and with a good cost of passive financial investors. Otherwise you’ll see sponsors self-monetizing.

Allehaut, CapDyn:     Or the alternative, we just change the tax code.

[Chuckles]

PFR:           Going back to the battery storage component, that’s kind of still quite a new thing, especially on a standalone basis. But it can be commercially integrated into a solar or even wind project. Or even an offshore wind project, potentially. So how big is energy storage going to be, and is that going to develop into its own big stream of financing activity?

Allehaut, CapDyn:     I was talking to one of the leading developers with whom we’ve worked, and the head of development told me that over the last three years in the Southwest they haven’t bid on a single PPA on a standalone solar basis, without storage. Storage is mandatory.

We have line of sight right now on 2,000 MWh of storage. It’s a tidal wave, it’s coming in a very, very big way.

Portales, NextEra Energy:   Approximately 40% of the solar contracts we signed in 2018 included an element of storage. We see it as a game changer. We started with dipping our toe in the water, figuring it out. We’ve made a lot of progress in understanding the technology. We have an advantage because we not only get to see it as a wholesale generator, but we also get to understand it through the utility’s eyes.

For us, it’s going to be huge. It is a complete game changer, and it’s where we see the industry going.   In the not too distant future, there will be near-firm wind and near-firm solar.

Allehaut, CapDyn:     It’s interesting, because China drove panel prices. How much it consumes creates the excess supply or excess demand. With storage it’s the same. There’s been a slight slowdown of the electric vehicle market in China, and they’re very long on cells. And the reduction in battery cost overall has been much greater than what people have forecasted.

So if it’s not part of your toolkit as an owner or as a developer you’re really not going to be in the market for long.

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