Article originally published in Power Finance & Risk.
Reports of the death of the long-term investment grade utility power purchase agreement, settled at the busbar, may have been a tad exaggerated.
Such contracts are still out there, if you know where to look. For it is not universally true that utility companies have comfortably exceeded the requirements of their state renewable portfolio standards. Besides which, in some service territories, wind and solar may anyway be the cheapest option to replace coal-fired plants that are due to retire. Some developers even feel it is still worth the effort to go toe-to-toe with a recalcitrant load-serving entity before the state public utility commission over the pricing of an avoided cost PURPA PPA.
But even if the long-term utility PPA were to disappear completely, there are some people who would not mourn its demise.
Because after working their socks off to get hold of one of these contracts, developers may wonder whether it was worth it. Bidding in requests for proposals is so competitive these days that they may walk away with less than $20/MWh. Developers of renewable energy projects have been telling PFR for years that what they would really like to do is go completely merchant. They believe in their product, and they are bullish on the market for it.
The only catch is that they need financing, especially tax equity, and they are not going to get that, as a rule, without some contracted cash flows. Not in this market.
Contracts for difference, swaps of various flavors, price floors and ceilings, insurance products, parent guarantees and letters of credit have all been introduced, either individually or in concert, in an attempt to bridge the gap between what the developers want – upside – and what tax equity investors and lenders want – certainty. The result is a sometimes bewildering array of financial products, each of which shifts risk from one party to another. When it works, it’s great. Everyone gets what they want. But when it doesn’t work… disaster!
So, in order to deepen our understanding of the benefits and the pitfalls of advanced hedging and offtake strategies, PFR brought together a group of experienced market participants to share their perspectives and insight, as well as the latest trends and innovations, in this lively discussion.
PFR: Traditional utility PPAs have been harder to come by in recent years, which means that sponsors are increasingly going to commodity trading desks to get power hedges. What are the key factors to consider when selecting a hedge product in terms of the risks covered, like basis, weather, counterparty and credit?
Emilie Wangerman, Lightsource BP: We still have a pretty balanced portfolio. Merchant is a great opportunity to increase your revenue and benefit from overall a different customer base. On the other hand, we do still have the unicorn of the 20-, 25-year PPAs with the utilities. That’s important for us to maintain balance in our portfolio.
There is also a lot of growth in merchant types of products. We’re saying merchant, but in reality what you just asked about – hedges, things like that – aren’t truly merchant. There is a difference between truly going merchant and then short-term contracting or hedges or things like that.
For us, the key risks that we see are around the counterparty are their credit quality and the term of the deal. As we get to a shorter tenor, we run into the risk of being able to finance and having limited tax equity available in the market. Are tax equity investors going to take a 12-year hedge or a 10-year hedge? Or are they going to want something that is a 25- year PPA?
Then, as you mentioned, there is the product itself. Any time you move away from the busbar on to a hub-settled PPA or contract, then you’re going to introduce that basis risk, which isn’t necessarily just for these types of products. Even a virtual PPA or a physical PPA would incur that basis risk.
John Bills, Cantor Fitzgerald: I would agree. From our perspective, we focus on the particular parts of the capital structure and what those parts may need. To the extent that it’s tax equity, as Emilie mentioned, those are traditionally the important aspects needed. We’ve also been able to structure deals that rely upon parent guarantees, letters of credit and other forms of protection that ensure that the tax equity does not end up in a situation where they don’t want to be, with respect to challenged ability to produce the tax credits or to receive the investment tax credit.
So we really focus on what’s necessary for a given deal to make that work, and we’re unafraid to structure something which doesn’t have that traditional PPA, or where your corporate PPA has basis risk, or you have a shorter-dated hedge. How do you still find a way to get sufficient capital from tax equity investors to make the deal work? How do you make that meet the risk-reward profile for the equity investors that are part of the capital structure?
Then, to the extent that debt may be involved – not typically done in wind or solar deals, but in battery storage, where it may be standalone and unable to raise tax equity – how do you think about what the lenders may need in that scenario?
So certainly, covering counterparty credit risk in that regard, basis risks, weather risks, etc., are all part of the equation that one has to manage, and also manage it across different investor classes.
Jeff McAulay, Energetic: I definitely agree with the themes highlighted here. At Energetic Insurance, we focus on counterparty credit risk, which shows up in a number of different places. Debt and, particularly, tax equity is driving the bus these days for those requirements of what you need to see in a counterparty.
Certainly, utility credit, in some cases, is not what it used to be. There have been a few scares on the West Coast. It’s unclear if that means, ‘Whew! We got through that, utility credit is completely unassailable,’ and that’s what that proved, or: ‘Wow! We came really close – I’m not sure how that’s going to go from here.’
As well as CCAs [community choice aggregators] – this is kind of a new animal, and there’s a lot of uncertainty about how to treat CCA credit. So even at that traditional utility level, there are some question marks.
Then, obviously, there’s the huge groundswell over the past decade of corporate PPAs. The contracts for differences are with very large, very sophisticated buyers. We’re seeing a lot of those large, 100% renewable energy purchase obligations go through, and now there aren’t as many to be had. How many times can you go 100% renewable?
What we’re seeing now is that those large tech companies, the first movers there, Walmart, Amazon, Facebook, Google, Apple, all those, are pushing those requirements down through their supply chain, which means less creditworthy counterparties. We’re seeing compression in terms of the term of the PPA they’re willing to sign. So all of this comes back to: How do you get financiers comfortable with some of those risks?
Project finance, as we all know, is about allocation of risk. So we’re looking for creative ways to help people fill the gaps and get these deals financed.
Ian Cuillerier, White & Case: By the time the lawyers get involved, often, the front end discussions and structuring may have already transpired, limiting the options. So I’m reacting to what I see come across my desk, and all these discussions have already transpired. What I do see is that often the tension is between what the sponsors retain for themselves as upside in the balance of how much of a given project is going to be merchant, and how much is going to be dedicated already, committed to longer-term contracts. Then the other tension is on the terms of what is going to be demanded by the lenders or the financing parties to insist on this risk needing to be hedged or that risk.
To the extent there are corporate players, their interests and their requirements are going to be much different. What story can they tell their shareholders? How are they going to present it? What level of complexity?
Counterparty risk, as everyone has said, will limit the options available to some players in the market.
Bills, Cantor Fitzgerald: On that last point, and what Jeff mentioned earlier about CCAs in California, as well as utilities and maybe other entities in California that are willing to enter into resource adequacy contracts, we’ve done a series of transactions on the debt side in California that have involved CCAs, in some cases unrated, in some cases with shadow or private ratings, in some cases with public ratings. So we’ve spent a lot of time educating and bringing in lenders that were unfamiliar with them, as well as dealing with risk related to large utilities there that may have had some challenging credit points in the past, and other types of entities.
The lender universe is shifting away, on the thermal side, from the PJM Interconnection deals, and trying to find other deals that are out there. We’re helping package that risk for them and have been successful in doing that in California and now in ERCOT, and have more in both of those markets.
So both in terms of the type of contracts and the counterparties, there are a lot of tools in the toolkit, and we’re trying to make sure we bring those to bear into markets that are outside of PJM on the thermal side.
Wangerman, Lightsource: I am frequently battling the ever-tightening constraints of tax equity relative to the rapid growth in demand from offtakers, who are also requiring more constraining contract terms. Even in situations when the offtaker has strong creditworthiness, the project economics are strong, and the offtake contract terms are adequate, tax equity may choose not to invest because they feel over weighted in that particular market. Because there is limited tax equity, this means we are unlikely to proceed with that project even though it could and should get built.
It’s interesting how much financing is the tail that’s wagging the dog. Obviously, it’s a big part of the renewables growth, but it is an interesting component to it. So what we’re looking to do is work with people like John that are willing to take a little bit more risk or people like Jeff that can actually reduce the risk and help us increase the opportunities. Because there’s just so much interest out there, it’s really a question of whether, at the end of the day, you can finance the projects.
With corporates engaged, you’re absolutely right that there’s different types of interest there. They typically don’t like long-term contracts. They don’t want the operational risk. So you have to get creative with your contracting to address that, and with your financing. Financing has to get more comfortable with more merchant risk, because it is just the future of the market.
Carlos Mendez, Crayhill Capital: I agree with everything the panel is saying. The problems associated with financing these investments are very much structural. The Federal ITC renewable energy subsidy influences everything from how projects are ultimately financed, the amount of leverage available, the timing of those financings and so on. I think the market will be well served by having alternative offtake contracts and financeable power hedges that mitigate reliance on subsidies.
PFR: What are some of the rewards of substituting power hedges for PPAs?
Mendez, Crayhill: Our perspective comes as both a financier of project development capital for and owner of utility-scale solar power generation facilities. In the RTO regions we operate in; PJM, CAISO and to a lesser extent MISO, the cost benefit analysis of power hedges versus PPAs varies greatly.
For instance, in an electricity load environment where renewables are prevalent and a duck shaped power production curve exists such as in California, the liquidity, structure, term, period (five-day or a seven-day), and ultimately, price, are completely different versus markets that do not have an imbalance between peak demand and renewable energy production.
In contrast, in New England, there is only a marginal shortfall of power generation. Demand is characterized by the need to address intermittent gaps driven by such events as scheduled power plant maintenance and one time needs from large power consumers. In the MISO, there exists yet another scenario where there is a foundational need for additional power production capacity, and so there is a smaller distinction being made in economic terms between conventional versus renewable generated electricity.
Our recent conversations with the largest hedge providers in the US bear out how these prevailing regional market conditions affect hedge structures. As an example, in the fourth quarter of 2020, twelve-year term hedges were readily available in the MISO while there was less availability at similar economics for that same contract term in the CAISO. We expect availability and constructs of hedges to change from quarter to quarter as those regional markets continue to rapidly evolve.
Another aspect to keep in mind is that the hedge counterparties are market makers and their ability to set off the risk of any particular contract to yet another party varies greatly from one hedge provider to another. In low volume renewable energy hedge markets, there exists a large variance in available contract terms amongst any group of hedging counterparties depending on their specific access to liquidity. That’s another consideration when you’re dealing with what’s the art of the possible. Ultimately, you cannot rely on any single counterparty.
Specifically, the benefits that our firm is trying to achieve with these hedging products goes back to what Emilie was saying; a financeable solar project that can address the growing industrial demand for three- to fiveyear power contracts. Hedge products may be able to fill in the offtake gaps of a particular solar power plant and negate the need for long-term, inflexible PPAs entirely. That may mean the solar project may be less financeable, resulting in less beneficial, lower levered debt, and less favorable tax equity, but those inefficiencies can be potentially offset by higher net revenues from higher electricity prices associated to shorter term power arrangements. That is the goal.
Obviously, we are not able to implement offtake plans with rolling hedges with every single generation asset, but we are committed to further exploring the approach when possible. We believe that, as hedging products become more flexible and widely available, this power sales approach for solar power plants will become more prevalent and will benefit end consumers.
PFR: And what are some of the more popular hedging strategies?
Wangerman, Lightsource: There’s a difference between a financial hedge versus a physical hedge. There’s a difference between a virtual PPA, which is really a financial transaction, versus a physical PPA.
If we’re really truly talking about just hedges, then for us the biggest focus is how long we can stretch that out. What is the tenor?
On the proxy generation side, they’re introducing things like proxy generation PPAs, and that is getting into insurance products that Jeff can probably talk about.
At the end of the day, what are these different transactions doing? A hedge is allocating almost all of the operational risk to the seller. You have commitments, based on physical or financial delivery, that are based on your actual shape. So it introduces a lot of risk on that side. On the other hand, if you do something like a proxy gen PPA, it’s really limiting that risk.
Yes, it’s still based on proxy generation, and you’re comparing it, and you’re committing to that particular design of this site. That’s probably unique to the developer, that we bear a lot of risk by just committing to the design early on, when we introduce things like hedges and proxy gen PPAs. With a physical PPA, or even a financial PPA, you don’t really have to decide on 90% of the design until far along in the process. But with these types of contracts you’re committing really early on.
So I think it depends on what you’re referring to as a hedge – are we truly talking about traditional hedges, or are we talking about things that hedge risk but are more like a proxy gen PPA, which balances the risk a little bit more? It introduces different counterparties, which is great for us, so it opens the market up, and it balances against a true hedge, which introduces a lot of shape risk.
McAulay, Energetic: Our friends at REsurety with their proxy revenue swap, at least on the wind side, are seeing that as very popular.
A contract for differences fits the bill in many ways, and because it’s a corporate counterparty, if they’re highly rated, that solves your problem. But in many cases, as Carlos was mentioning, you need to bring in hedges with the large banks or oil majors. So there’s this play between those two and we’ve seen a couple of different structures. But even when you’ve got a hedge provider, it’s a swap. They’re turning around, and there’s another counterparty on the other side. We’ve had projects where a developer says, ‘No, I’m fine on counterparty risk. I have this hedge.’ Then the hedge provider calls us and says, ‘Hey I’ve got this downstream offtaker, can you help me out with their credit?’ So it’s just shifting where that goes.
Then the big thing we get into is contract mismatch. Who’s holding which part of the risk? Shape, volume, basis, everything that’s been said.
So where does this wrap up? Ultimately, it’s trying to get the project financed, and there’s this trade-off. What risk protection tools do you need to put in place to get financing? Sometimes that’s binary and sometimes it’s a sliding scale, meaning if I cover this risk a little bit better, I can get access to a lower cost of capital. At which point, you’re trading off between the cost of the risk management product – hedge, insurance or otherwise – and your cost of capital.
The one thing that we see most commonly undervalued is time and complexity. Everybody has a box in the spreadsheet model, a cell for the cost of capital or the cost of a hedge or a floor price or merchant tail. Nobody has a box in their model that says, ‘What happens if this thing blows up in six months because the term that I got in November isn’t true in March?’ Or just complexity. You’ve built this beautiful tower of interlocking contracts, and then you go to get it financed, and the bank says, ‘What the heck is this?’ Or the commercial offtaker says, ‘How do I take this to my board?’
I’m doing the opposite of answering your question, really, which is not talking about the things that are most popular. But we’re getting these complex structures now, and to enable to get them to work it’s about re-simplifying or being able to wrap them together so that you have a clear package to go back for financing.
Bills, Cantor Fitzgerald: To hit on the popular, I think beauty is very much in the eye of the beholder. What we’ve done is, because of the massive increase in scale, the massive increase in quantity of wind, solar and batteries that are coming in, the buyer universe in those needs to be inherently able to accept a bit more risk than they’ve traditionally accepted.
A strategic buyer may be much more willing to enter into a virtual PPA or provide a parent guarantee and build in those commercial, very attractive, high-priced, “popular” hedges, because they’re well-priced, because they’re direct end users that want this renewable product, and we see that.
We have an affiliate that has a consulting business within Amerex Energy Services at Cantor, and they have over a thousand customers in the US. Many of them are in Texas and ERCOT. Demand ranges from 1 MW to maybe 50 MW plus for any given type of transaction, that can range from one-to-two years to three-to-five years. But it’s rare to see five, seven and 10 years.
Parties that can warehouse that and wait for that have a lot of interesting capabilities. That’s part of what’s popular and beneficial. Then there are other parties that are fine to de-risk some of that and leave some of that upside open.
As we think about tax equity, they’re going to come at it from a different perspective. They’re going to want to make sure that tax equity structure stays in place, but if that tax equity provider is someone that also provides hedges, they may be a little more willing to think about the structure differently.
It’s a much simpler story on the thermal side, where you sort of know, with some exceptions, that you’re going to be dealing with these risks. It’s either a commercial bank package, or we package it for private placement investors in the 4(a)(2) market, or we think about it in the gray market or private debt fund market.
We structure according to what we think their metrics will be, and it may just be two to three years of hedges, it may be five to seven years of hedges. We’ll think about that risk profile in the context of the debt that we’re going to put in place, and that debt is going to be customized to raise the capital we need or to refinance what we need or to be the initial stage for an M&A sale. The popular hedge is very much a function of who the right investors will be.
What I’ve seen is, if you enter into a transaction too quickly, where you’re obligated on it, you can find yourself six months later – as Carlos alluded to – in a situation where you almost wish you hadn’t done it. There’s enough change, uncertainty and volatility that what is interesting in one market one day may not be very interesting six months from now. The plans of many of our developers have changed dramatically from what they were planning to do even just a year ago, in terms of asset type and hedge type.
PFR: Is it common to find power hedges being misused if the terms are pushed to extremes, or cookie-cutter structures used inappropriately?
Bills, Cantor Fitzgerald: There have been many lessons learned on how to hedge over the course of at least the 20-plus years that I’ve been in investment banking in the power space. We’ve seen a lot of disasters in terms of how to enter into hedges that can, at the time, seem like a good idea, but it turned out hedging wind with gas wasn’t necessarily a great idea in certain markets.
Hedging a wind project in one region in Texas in another region might not have been a great idea, because you didn’t really understand the curtailment, congestion and basis risk that result therefrom. So, yes, we’ve seen these things go wrong, and I think lenders, tax equity providers have really learned a lot from that.
I’m sure there will still be things that we look back with hindsight and say, ‘Wow! We should’ve seen that coming.’ But I believe parties are very sensitive to this now. While I would say parties may still try to do less hedging rather than more, I think they’re very ‘eyes wide open’ on the risks that we’re talking about. They may end up not truly perceiving the nature of the risk, because there will be changes in the marketplace that are maybe black swan in nature. Five-, six-sigma events that they just didn’t appreciate or just didn’t understand the magnitude of. But people are mindful of what the key risks are in the marketplace, and most are very attuned to that.
Because now, you don’t have a choice. Strategics are used to managing these kinds of risks. Investment, private equity funds, infrastructure funds now need to realize, for the most part, if they want to transact in sufficient quantity, many of them also have to understand that. We’re seeing the direct institutional investors also realizing that that needs to be a part of what they do.
We see that even on the fully-contracted deals, with PPAs. Parties, in order to get the terms they require, oftentimes will have to deal with risk at the very back end of those projects where there may be a number of operational and commercial risks.
Wangerman, Lightsource: There is still that little bit of hesitancy because of being burned in the past, particularly with wind in the Midwest and West Texas. But I’m also seeing that people are getting more comfortable again. That’s great news, because we are moving to a power markets world, and we will not have those unicorns of long-term, high-IRR PPAs. They’re going to be the past.
And frankly, the flexibility of different types of contract structures is a benefit to the market. There really isn’t a reason to have those fixed-rate, long-term PPAs as the only solution. There’s a lot of value in short-term contracting. It introduces a huge amount of new customer base.
On the developer side, it helps that we are backed by BP. We have a big oil major behind us, and that helps us because we don’t just have to have one type of product, because the future is going to need diversity and balance.
Being able to tell our financing parties that we’re not going anywhere has been really helpful. Some of the smaller players can’t really take advantage of that, because they don’t have that creditworthiness in the background.
PFR: What are the key considerations that lenders and investors take into account with a hedged asset that they would not otherwise need to think about?
Wangerman, Lightsource: One particular thing that is different with a hedge is operational risk. Typically, when you have an as-generated resource, you’re contracting based on that as-generated component of it. So whatever you generate is procured and paid for. When you get into shape risk, you have to introduce a different level of risk. You’re accounting for committing to this quantity in this time frame. As you start to prepare for that, you’re introducing complexity, on our side, to planning as well as execution.
You have to make sure that your forecasting is correct, and you have to get more complex with your forecasting. It’s much more specific in terms of that particular quantity on that day, in that season. So it’s really moving more towards a power marketing role.
The last thing is counterparty risk. We’ve mentioned that a lot. Is the counterparty going to try to get out of this contract? But you can introduce risk, if you’re starting to hedge with a counterparty who might say they actually don’t want the contract, and they’re going to break it because they found a better deal. It hits everyone along the line.
You can’t have a junior person that doesn’t understand what they’re committing to in negotiations, and all the way to operations and asset management. They have to keep track of how the project is performing at a different level than they’re accustomed to in solar. It cuts across the board. It introduces complexity and risk, frankly. It also introduces higher revenue, which is good. I don’t want to miss that part of it. There are benefits as well.
Bills, Cantor Fitzgerald: I’d echo what Emilie said, which is that having the full suite of commercial management within the company or the portfolio that you’re looking at is incredibly critical. We start and think through that well before we would package a financing. We make sure we understand what are the hedges that will be in place and how they will be managed from day one, when you enter into the financing, all the way through to when the revenues come in the door. An obligation may arise as a result of an operational challenge. How is that managed? You have a firm obligation to deliver certain types of power. How will that be done commercially?
The lenders or other investors that may come into the deal need to have a true, detailed understanding, to a pretty high degree, of how it’s going to be managed from day one to maturity, in the case of a lender, or to exit in the case of an equity investor. That’s so much more important when you have hedges versus just the busbar PPA, where you sit back and produce.
PFR: The recent high-profile bankruptcy of PG&E may have accelerated the move toward CCAs and corporations. How does the move away from large, investment grade counterparties to smaller counterparties affect offtake contracts?
Cuillerier, White & Case: What we’re dealing with are counterparty credit issues. As you’re moving down the chain from larger institutions with better credit risk, how do you manage that, anticipate for it, and the like? How in this market do we deal with counterparty credit risk? It is important to think of this risk holistically, where entering into the hedge presents new risks that need to be factored into the deal structuring.
Handling those with weaker credits and smaller counterparties is more of a challenge. In dealing with those risks, parties are forced to revisit what was believed to have been already agreed, and this happens more often with lower grade counterparties. The competing interests of the counterparties versus other competing interests of other stakeholders puts the discussion in starker contrast where that counterparty risk is more present, shall we say.
In terms of managing the risk, as you would any other deals, as you move down, it’s perhaps requiring more specific independent collateral for your transactions or more revenue streams, including multiple assets, number one. And number two, that may include things that you wouldn’t necessarily include in other deals. Where is the actual cash flow going? Are you thinking about control over cash flows and the like, when you’re dealing with counterparties that have that counterparty risk that you don’t otherwise see with some of the larger names?
You’re going to deal more with the nitty-gritty of the cash flow. You’re going to get more in the weeds to your counterparties’ operations.
Bills, Cantor Fitzgerald: We’ve closed transactions with multiple CCAs in them on the debt side. We’ve done credit work where needed, we’ve got ratings where needed, and we’ve been able to get commercial lenders and/or private investors comfortable on those transactions.
The marketplace in California is one that absolutely needs resources. They absolutely need resource adequacy. The nature of these assets is critical infrastructure, and these parties now realize that they have to contract at a much longer tenor than they were traditionally doing. We’ve seen very attractive pricing in those contracts on the thermal side for a number of years. You’re certainly able to go out beyond just the two-to-three years that you’ve typically seen, and at levels that are many, many times what they were just a few years ago.
The assets are being run very differently. Combined-cycles are being run effectively like peakers. Mid-merit assets that fill in the gaps around the duck curve are run very differently, yet the revenues they can receive through heat-rate call options plus resource adequacy are substantial and are able to be financed by commercial lenders.
We proved that point in our High Desert transaction with a number of CCA and utility counterparties in the midst of some question and uncertainty around utility counterparties. We’ve also been able to close transactions around other types of uncertainty related to large utilities in California. It’s very California-specific, but it can be extracted, as Ian said, to any number of types of counterparties that you might end up entering into contracts with.
PFR: PFR has received inquiries about the REC market recently. The REC market isn’t as large or as liquid a market as wholesale power. There are also a number of unrated entities who participate, which is challenging from a financing perspective. How much impact can an unbundled REC contract have on the availability of financing for a project? Does it depend on the state that the RECs are generated in?
Wangerman, Lightsource: Definitely. RECs and the value of RECs varies dramatically depending on the region that you’re talking about. If you’re talking about an RA product and tacking on RECs in California, that’s one structure and value. If you’re talking about ERCOT, where there is no forward capacity market, and all of the value is incorporated into the energy rate, then that energy rate is going to be the dominating factor. Plus they don’t really have requirements from a renewable perspective. So the RECs are not going to be the prominent factor there. Really, you’re just selling the RECs as an overall benefit, and most of that value is going to come from the energy.
In PJM, there’s a lot of REC value in Pennsylvania, and we have one of the largest portfolios of solar there. On the other hand, you’re highly dependent on that state being closed off, and the value of those SRECs in particular. If regulation came in and changed that, you can dramatically impact the value of those RECs. It really does depend on which market you’re talking about. If you move into the Midwest, if you’re talking about Ohio, they don’t necessarily have a REC value that something like Pennsylvania or New Jersey or Maryland has.
Either way, there is inherent value in RECs. The question is, how much can you depend on that, and how much will financing parties value it? Is it a long enough contract that you can actually get valuable debt on? Or do you have to just assume that’s another merchant revenue stream and that you can’t necessarily get the full value on the financing side?
Mendez, Crayhill: In the early part of the last decade, we invested heavily in the development of utility-scale solar projects in the UK. The Renewable Energy Certificate, RECs, scheme was very straightforward; a direct subsidy from the government of the United Kingdom to renewable energy project owners. The lack of complexity of the subsidy afforded the market certainty of execution when structuring financing for such projects. There certainly was a lack of funding participants at the time, but at least there wasn’t a scheme as complicated as the ITC and some of the state-level subsidies here in the US.
John, you mentioned warehousing. Ideally, we would be able to construct and connect solar and wind projects to the grid and then optimize both government subsidies and market hedges, not be forced to do so earlier in the development process. That is how we were able to proceed in Britain because there was no need to include a tax-related third party in the ownership of the project prior to construction as called for in the US regulation. We were able to fund, construct and bring operational 32 utility-scale solar projects and then, when we had the portfolio stabilized, we optimized our offtake contracts with the full benefits of subsidies.
From our perspective, we see a lot of potential value in providing warehousing capacity for projects to be able to layer off offtake risk over time and not have to commit to longterm PPAs upfront. The reason that these long-term PPAs are committed to early is because financing parties are generally not comfortable without having these long-term offtakes in place upfront. Hedges of course, as we have been discussing, are an alternative, but the timing issue I mentioned before makes it difficult to lock in a tax equity partner in the face of variable outcomes associated to negotiating and finalizing acceptable hedges.
Bill mentioned structural issues with renewable power hedges in the past. This type of friction is not uncommon in early-stage, high growth structured finance markets. Somewhat analogous are the misstructured variable-to-fixed, interest rate swaps in high yield bond and loan securitizations back in the late 90s. As interest rates changed, the hedges failed to work as anticipated, causing all sorts of problems and financial losses. But, the market fixed those asset-liability issues, and then the CLO market over the next 20 years evolved into approximately a $600 billion market today. I feel we are at a similar juncture, where we can figure out these hedging structures appropriately and enable the renewable market to grow at an unprecedented rate. We certainly will all benefit from straightforward financial contracts that satisfy offtake conditions for readily available senior funders.
Bills, Cantor Fitzgerald: Part of that impatience comes from the fact that many of these are held by small firms that have developed these assets. They’re not the large corporate entities that did it back in the late 90s, early 2000s. These are now very large developers. But you had the range, from a single individual to companies that are maybe 40 to 50 people, and those are our clients. There’s a very finite time under which they have to either sell that project or raise equity capital and tax equity capital and/or debt capital to get the project built. You have to pick or choose something, otherwise the options expire, the permits expire.
In the US, there’s not a lot of corporate patience for the development angle like there used to be in the days of the Calpines, the AESes, the Dynegys, etc. So that dynamic has shifted dramatically, and those are our clients. We feel that sense of urgency and we want to lay out the ability for accessing warehousers like Carlos’s company or strategics that will warehouse the risk. But we also want to show what a longer-term PPA deal looks like.
In some cases, our clients will want to just sell the projects, and in other cases, they’ll want to hold on to it and warehouse it or sell a stake to someone that may want to warehouse some of that risk with them and ride it for a while. So there’s a spectrum. For many of these projects there’s a window, and if you don’t try to close the deal in that window, there may not be a deal to be done. So we’re very mindful of that, and that does feed into why, as Carlos said, there’s a bit of a lack of patience in our particular marketplace.
PFR: On the subject of corporate PPAs, it seems that a few corporations have been burned with some of the contracts they’ve taken on. Any comments on how corporate PPAs have evolved in response?
Wangerman, Lightsource: Yes, corporates are moving beyond just the virtual PPA. They are interested in actual physical delivery. Because they were burned, they’re introducing new products.
McAulay, Energetic: As with any uncertain market and any long-term contracts, there’s going to be winners and losers. And there are some corporate buyers who are happy to justify why they’re losing money, why they’re paying out on certain contracts. But I think that’s generally leading to a higher level of experience and education within the industry, and going forward the buyers are becoming increasingly sophisticated.
In terms of where we’re seeing demand, the reason you have a corporate counterparty is to provide some of that downside risk hedging to get financed. But it’s not as simple as just a corporate counterparty. One of the things we see a lot of the time is that a corporate will sign through an unrated subsidiary. The name might be familiar, but when you actually come down to the contract, it turns out there’s a longer story. Can we see financials on that subsidiary? No. We see that as a gap that needs to be filled.
Additionally, a lot of times they have a buyer’s credit posting that they’re responsible for, which either comes in the form of a sufficiently high rating, cash collateral or letter of credit. We’re finding, especially in the last year, or the last six months even, that that posting of the letter of credit has become more painful, tying up that cash, or tying up their credit capacity.
So we have folks that maybe two or three years ago, when they signed, that was fine, but now they are squirming. Or, even worse, the project changed hands and all of a sudden the seller has the ability to crank up that collateral requirement at the same time that the interest rate, or even that opportunity cost, has gone up.
On the seller side, they can generally get through that with a surety bond in addition to a letter of credit. On the buyer side, it’s a little bit more complicated. So we’re seeing insurance products essentially being able to support or reduce that letter of credit posting. That’s on the corporate side.
Then, even when that corporate has even a hedge standing behind them, there’s contract mismatch to go through, and the shorter-term compression going down the supply chain.
Going back to your question on RECs, in many cases, in the lower-priced market, they don’t really want the power. They just want the RECs. And they want to have additionality. So not just purchasing unbundled RECs, but being able to say, ‘I helped that project exist, and I’m doing my part.’
And then, just show to their board that they’re not losing too much money in purchasing those RECs, that’s why the hedge piece might come into play.
Ultimately, I think the theme of this conversation is increasing sophistication from all sides. Trading renewable energy, as a commodity, used to be like trading a head of cattle, and now we’re selling filet mignon. We’re shaping it, parsing it out, selling different terms, different volumes, different structures to folks as they value it more highly.
Bills, Cantor Fitzgerald: I’d highlight that there are still those great contracts, those great PPAs, those unicorns. There are not just one or two of them, so it’s probably not quite appropriate to say they’re unicorns. But when you have them, the cost of capital is so competitive. And we’ve run very successful processes with respect to those.
Return requirements have had to shift dramatically downward to reflect the extreme competition and demand from sources in North America, Europe and Asia that are competing with very different types of interest rate environments and costs of capital and viewpoints on tenor.
So the amount of operational and other risk that parties like that are willing to put in their book, to take home a return that to some buyers in North America may not seem reasonable, is what’s ultimately going to drive buyers – by necessity, because necessity is the mother of invention – to figure this out. If you don’t, your alternative is competing against those types of buyers that have very strong risk appetites with respect to potentially very low cost of capital.
And those will continue to exist, and that’s the exit strategy. Once you package it, that type of low-cost investor universe, for now, is very much a viable alternative. So the gold pot at the end of the rainbow is clearly there. Just to connect the dots of where we’re headed to.
The other point is that the sheer demand for renewables and the general shift away from thermal has also significantly improved the demand dynamic for renewables. We’ve seen that progress from wind to solar and now batteries. As it has shifted, it has been impressive to watch in terms of its magnitude and geographic scale.
I think these are important points to consider when you think about why are people doing what they’re doing around this merchant risk.
Cuillerier, White & Case: A separate point to consider, one that is overarching, in addressing deal terms for any particular financing transaction, is to think about the individual transaction as one of many. Take a step back from the particulars. As you’re scaling up the size of operations and hence also of the related financing transactions, there is some benefit to consistency and thinking ahead to the next steps. If you’ve done three projects, having consistent hedging strategies that are easy to explain for offtakers or people that are buying sets of projects in given markets, that consistency is an easier story to tell, and can only benefit those that are exiting at some point in the future. So as you’re doing the here and now, think of what might transpire in the future.
Then there’s execution risk. Start as early as you possibly can on your hedging, because it’s more complicated than you think it’s going to be at the end of the day. Always is.
PFR: What is tax equity willing to underwrite and syndicate in terms of merchant streams, hub vs busbar?
Bills, Cantor Fitzgerald: The tax equity market is a very unique market, and it’s a very small market in many ways, in terms of the participants, and it’s a very attractive market for them as a result of that.
But it’s also very large in terms of dollar amounts, and that scale has only increased as we’ve gone from 10 MW, 50 MW projects in wind and solar and maybe even a fraction of that in battery to now 1,000 MW projects in wind, 500 MW-plus projects in solar, 400 MW, 500 MW projects in battery. The tax equity needs are pretty massive.
Meanwhile, the corporate tax rate was cut significantly. That’s significantly reduced the tax capacity for corporates and made the market even more difficult than it was before, for financial institutions, insurance companies and other corporates that participated in it. So there are so many uncertainties around how that will evolve.
It’s important to understand the specifics of a deal. The more middle-of-the-fairway that deal is in terms of contract and certainty, relationship or sponsor, the easier that will be to finance. To the extent it’s innovative, it’s not a well-known sponsor, you better have some reasons why that tax equity participant wants to be a part of it, and you’d better make sure that there’s sufficient ability for them to syndicate the risk that they need to syndicate on the deal.
So the more you shift to a warehousing structure, like Carlos mentioned, the more need there will be to do something that’s either a virtual PPA, LCs, parent guarantee, etc, to allow you to do that. To the extent you do that, oftentimes a hedge that’s done by one of the large tax equity providers can be a good reason for them to do multiple transactions for one deal.
Many things are still very uncertain now with the shifting to the Biden administration and how the legislature will ultimately shape the various incentives. How will battery-related ITCs play into this? Carbon sequestration? There are so many more unknowns than knowns that I think you will have to fall back to a deal that you know will work for a tax equity investor.
Mendez, Crayhill: Yes, we work with tax equity partners to execute on our investment plan, but as we all have experienced, the use of tax equity is extremely nuanced.
As an example, one cannot warehouse tax equity for a project under the current regulations and attract such investment interest post achieving operational status. That forces project owners and developers to lock in tax equity interest early in the deployment process, prior to construction. Furthermore, the rules make it difficult to have multiple institutional tax equity investors co-invested in a single project and results in the need for a single sponsor.
Unfortunately, that translates into significant negotiation leverage by the tax equity sponsor on the whole financing structure of the project. For instance, as tax equity typically requires a certain minimum set of contracted cash flows, reserve accounts are required to be established to protect against potential future basis risk which can be especially difficult to anticipate upfront when employing a mix of hedges for the power offtake plan.
Despite all the much needed benefits the ITC scheme provides today, we look forward to when solar cell efficiency and market demand for green power combine to allow for financing without any subsidies.
Wangerman, Lightsource: If there’s a different way that the federal government decides to invest, that could be a true game changer. With a Biden presidency, I expect there is going to be a renewable investment. The question is, when? How are they going to invest? You’re not going to see renewables going away. The question really is, how are entities going to participate in it?
Carlos said earlier that a lot of companies are getting involved from an ESG viewpoint. I also think they’re getting involved in renewables because it’s cost effective. Not only are they hedging your risk of market volatility, but they’re also a good investment.
This is moving from being a niche market to a market where lots of different products are going to be commoditized and sold. And to Ian’s point earlier, the importance is being able to replicate so that you can introduce consistencies and reduce the complexity, as Jeff mentioned earlier.
On the other hand, complexity and innovation is what’s really going to expand this market. I think the next three to five years are going to be really exciting.
PFR: Finally, what structured products might be available to enhance grid penetration for battery storage? At least one developer has secured a fixed price hedge for ancillary services in ERCOT for a portfolio of battery projects.
Bills, Cantor Fitzgerald: We have financed quick-start generating resources that are carbon efficient but thermal that are heavily dependent upon ancillary services in ERCOT. While there’s no true capacity market in ERCOT, the ancillary services market can be lucrative. In fact, you can find bilateral transactions to provide you with significant benefits if you’re a quick-start or responsive resource. How much you want to actually bilaterally contract on ancillary services versus be fully merchant goes back to Carlos’s warehouse point.
Importantly, that kind of resource provides a valuable, valuable service. You have a market in ERCOT that’s almost 90 GW, and there’s 30 GW or so of wind and solar that’ll be online, probably, by the end of this year. More coming. So a third of your generation is intermittent by nature, and yet you have a tiny amount of quick-start generating resources – less than 2 GW. So how much of a difference in wind forecast and sunshine does it take to be in a very problematic situation? Batteries and quick-start generation are critical resources that ERCOT needs. The market is finding a way bilaterally or on a merchant basis for its counterparties to find ways to finance and develop and construct and operate those assets.
Wangerman, Lightsource: Another key point is that the markets have to embrace storage and they really are starting to do that, to have products that are specific to the value that storage brings. Different types of storage, from long duration to short duration. California is a little bit ahead of the game with creating products, like flexible ramping products, and on the ancillary services side as well as on the capacity side.
Then, as you start to introduce products like that in the centralized capacity markets on the East Coast, like PJM, you’re really going to start to see an uptick, because there is inherent value in being able to address intermittency as well as those steep ramps that come with duck curves. Storage is going to be a vital component balancing the overall market. That’s not just intraday. It’s intraday and intra seasonal.
Mendez, Crayhill: For battery-only projects that we invest in or finance, we are dependent upon hedges to mitigate revenue variability. As Emilie points out in the PJM and John on ERCOT, as penetration of solar and wind generation increases as a percentage of the total power generation capability of a region, large-scale batteries are ideally suited to address the inherent timing mismatches of such power delivery.
However, certainly in the PJM where we are investing now, there lacks long-term offtake contracts with viable counterparties for what batteries do well – frequency modulation. So, battery owners need to also rely on capacity payments and opportunistic energy arbitrage, all of which are predominantly uncontracted, merchant risk.
As battery costs have dropped drastically, PJM RegD hedges that pay a fixed price over a 3- to 7-year term while the operator then pays the difference between the highest and lowest price on any given operating day, are now becoming attractive.
Generally, the economics of stand-alone battery projects remain ‘cuspy’ though their functionality is now such a critical part of operating a power grid that we expect utilities to be strong buyers of such projects in the near-term.