Financing merchant projects after Texas
Many developers are wondering whether the appetite among banks and tax equity investors to finance hedged merchant power and storage projects has changed as a result of the February cold snap in Texas and, if so, how. What lessons did lenders and tax equity investors take away about how to do future projects? Are the effects limited to projects in ERCOT?
Close to 3,000 people registered to hear answers to these questions from four senior financiers who have been significant participants in past financings of Texas merchant projects. The four are Sven Wellock, managing director and co-lead of energy – renewables and power for ING Capital, Dan Miller, a managing director of CIT's power and energy group, James Wright, managing director and head of renewables, clean energy and sustainability in the United States for CIBC Capital Markets, and Rubiao Song, head of energy investments for JPMorgan Capital Corporation. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Sven Wellock, many power projects in Texas sell electricity to the grid at spot prices and enter into hedges to put a floor under the electricity price. In your view, is it still possible to finance new greenfield projects with this profile?
MR. WELLOCK: The short answer is yes. I think the recent polar vortex exposed some loopholes in the financing structure that include unmitigated, asymmetric risks for the lenders and the equity. Some banks are still licking their wounds and may shun these types of financings, but I think other banks are going to continue to look at such financings and will be laser focused on these risks. There are tools to fix some of these loopholes. We can talk about those tools. I think that there is still a future for these types of financings in ERCOT.
MR. MARTIN: Give an example of an asymmetric risk that you consider a loophole.
MR. WELLOCK: An example is where the project is exposed to a settlement under the hedge when it is unable to produce electricity and generate any revenue to offset that settlement payment under the hedge. There is no cap on that risk. The required uncovered payment could be huge, as we saw happen to many projects in ERCOT.
MR. MARTIN: Dan Miller with CIT, is it still possible to finance greenfield projects with hedges?
MR. MILLER: I agree with Sven. I think for the right sponsor, the right credit structure and the right pricing, it is still possible. The sponsor needs to demonstrate that the borrower's credit profile can withstand a similar event and is doing that in a variety of ways. The lenders understand the sponsors' view that this was a highly unusual event, but there still needs to be a well thought-out answer for what is an obvious question.
Some sponsors are putting together back-casts, some are restructuring the hedge entirely with lower volumes and larger tracking accounts, and some are providing further support themselves to stand behind the deal. So there are ways to get these deals done. It just might be a little different than in the past.
MR. MARTIN: The bottom line is the sponsor has to show the project can survive this sort of event were it happen again in the future.
MR. MILLER: Yes.
MR. MARTIN: James Wright, will it still be possible to finance merchant projects with hedges?
MR. WRIGHT: Yes. What comes to my mind is that wonderful line, I think from Jurassic Park, when they said "life finds a way." The financing markets will find a way through this.
The asymmetric risks that Sven mentioned have people thinking more about covariance risk and how we deal with that in renewables. I think we will see far fewer fixed-volume hedges in the future. To deal with some of those risks that Dan and Sven talked about, we need to think more broadly about possible technical solutions in ERCOT to help fix this.
One thing that could help is to combine wind with more storage. Could batteries help mitigate some of that covariance risk? I am always optimistic that life will find a way.
MR. MARTIN: Explain covariance risk.
MR. WRIGHT: It is a renewables phenomenon that is often thought about as being somewhat theoretical, but we saw it in action a couple of weeks ago.
When there is little wind, prices tend to spike in ERCOT, and then prices fall when there is more wind. That means there is a negative relationship: the more you hedge, the more covariance risk you get, and the more renewables you build on the grid, the more the covariance risk as well. We have to be more thoughtful about these hedge structures and some of the possible technical solutions.
(For more detail about covariance risk, see "Covariance Risk: What is it and how to manage it" in the June 2019 NewsWire.)
MR. MARTIN: We will dig into that more deeply. Rubiao Song, JPMorgan accounts for about 25% of the tax equity market in renewables. Will merchant projects with hedges still be able to raise tax equity?
MR. SONG: Yes, but it will be more difficult. It has been increasingly difficult to finance hedged projects in ERCOT precisely because of the covariance risks. And not only that, the hedges also expose projects to large locational basis risk that we can explore in more detail later.
We have to remember that the hedge serves a specific purpose for the wind projects, which is to provide a long-term general power price protection. There are projects with hedges that were entered into five or more years ago that provide a fixed price of $30 or more a megawatt hour. Those hedges are providing real benefits to the projects.
The sponsors need to understand that these hedges are not just a contract: you cannot sign one and put it on the shelf and forget about it. It requires continuous monitoring and risk mitigation at a project level precisely because of the covariance risks.
We saw this in the summer with heat waves. Power prices spike when the wind is not blowing as strongly and electricity output is low. The winter storm exponentially exposed that risk. Now we see that sponsors are actively managing this risk by selectively unwinding the near-term hedges with banks. That gives them long-term power price protection, but without suffering the near-term volatility. The winter storm taught everyone that these covariance risks are real. The market is still thinking about it and also thinking about other risks associated with these types of contracts.
There are always means to manage risk. We need to be actively pursuing these strategies in a programmatic way and not on an ad hoc basis, and not trying to time the market. That is the main takeaway.
MR. MARTIN: Your predecessor as head of energy investments, Yale Henderson, said on a past call that JPMorgan was pulling back from the Texas panhandle because the electricity basis risk had widened to as much as $12 to $14 a megawatt hour. Electricity basis risk is the risk that a project will sell its electricity to the grid at a node for one price and have to pay $12 to $14 more per megawatt hour at a hub to buy back electricity to supply under a fixed-volume hedge.
Were there parts of Texas in which you were not investing tax equity before the cold snap?
MR. SONG: I would not say that there were parts where we would not invest, but we certainly were always very selective about project locations. It was tougher to finance projects in parts of Texas that have local congestion issues and curtailment risk. There are structural features that we can deploy to mitigate that risk. For example, for wind projects, we have been doing almost exclusively pay-go deals where the amount of tax equity invested is tied partly to the output.
MR. MARTIN: Are you working currently on financing any new greenfield merchant projects and, if so, when do you expect the next one to close? What I am really getting at is whether the market will pause for a while before closing another such deal.
MR. SONG: I do not expect a pause, but things will slow down. We know that a lot of sponsors and investors are still actively working through the situation. It will take time to work through how best to mitigate the risks we saw in evidence due to the winter storm. A risk mitigation strategy needs to be put in place.
MR. MARTIN: That says pause to me. Lenders, do you expect a pause on lending to hedged merchant projects and, if so, for how long?
MR. WRIGHT: I expect a pause. I agree with Rubiao. Part of that is a natural visceral reaction to what just happened. It is worth noting that there are a lot of other routes to the market right now for banks and tax equity. If you think about the broader renewables market around the US, the other regional grids are all booming, so it is not like there is a shortage of supply so far as deals.
The current regulatory uncertainty in Texas is also causing folks some indigestion right now. There is a lot in flux with the PUCT and ERCOT plus the governor and Senate weighing in. The state Senate voted earlier this week to adjust some of the power charges retroactively. It is hard to lend into a market with so much political turmoil. I do think there will be a pause or slow down.
MR. MARTIN: One of my colleagues, Sam Porter, pointed out that Texas has finally fully deregulated. The governor fired the sole remaining public utility commissioner yesterday. Dan Miller, Sven Wellock, will there be a pause and, if so, for how long?
MR. WELLOCK: I think it will be a slowdown. I don't know that we can call it a pause. There are some deals in the market right now. ING is in a few of those. They will require more scrutiny to make sure that the asymmetric risk allocation is mitigated and the impact of the events we saw in February will not happen again. How much time it takes to sort this out will probably vary by project.
The case may be easier to make for a solar project that does not have as many moving parts as a wind project, but even wind projects can mitigate the risk by winterizing. We do this all the time in other parts of the US. For example, we have financed wind projects in PJM in harsher climates, and they work fine.
Some banks may take a break, but I think other banks will merely take more time to ensure that they are comfortable with the risk.
MR. MILLER: If there are good answers to the most obvious question what would happen after another extreme weather event, then deals can get done. There are a few ways that sponsors can address these problems. This is not a "one size fits all." Every deal takes on a life of its own, and a sound credit structure will prevail to the extent that one can be agreed to with the sponsor.
MR. MARTIN: But it does seem that people should assume that things will take a little longer. How much longer?
MR. MILLER: Yes. It is like any new interesting risk, whether it was the fire risks in California or the construction-supply risks during the heat of COVID, there will just be a longer diligence process and more questions from banks. To the extent there are good answers just as in any deal, transactions will get done.
MR. MARTIN: The tax equity market has been requiring hedges of 10 to 12 years. Some developers would rather do without hedges because they introduce two risks: electricity basis risk and the price spikes like the ones in February. Rubiao Song, do you think tax equity investors will decide they are better off without hedges?
MR. SONG: I am not sure that I agree with that statement. I do not believe every tax equity investor requires a hedge. We always understood the limited value of hedges and the problems they introduce. Tax equity investors require very little cash to reach their returns. They are mostly concerned with the project generating enough cash flow to cover the operating expenses and to keep production up. For the reasons we were just discussing, hedges are not necessarily the best offtake strategy to ensure such cash flow.
We are open to other arrangements that will ensure a minimum level of cash flow. Looking forward, different types of contracts like contracts for differences, unit-contingency hedges and affiliate PPAs could all be solutions.
MR. MARTIN: But not selling in the spot market without any price protection?
MR. SONG: I think we will expect a certain level of price support. We are not looking to hedge to the P99 level of production. This is going to depend on the project specifics, but we will need certainly a very small level of price support to ensure that operating costs can be covered.
We have seen the corporate offtake market evolving. We have seen some CfDs with price floors and upside sharing with the sponsor; we like that feature. Some CfD contracts would offer the sponsor the ability to pick node or hub settlement. That has been a welcome development.
MR. MARTIN: Sven Wellock, you heard Rubiao say he will need price protection on the down side and there are various forms that could take. How do lenders feel about hedges? Are they required and, if so, at what level?
MR. WELLOCK: I still think hedges will be required to demonstrate resilience in the cash flows. I think that the key question is how much hedging is necessary to get the banks comfortable with some minimum floor of cash flows. The answers will require understanding the availability risk and basis risk in hedges and what the risk mitigants are.
I do not see the hedges going away. I expect to see an increase in the premium for projects that have these risks. I do not see banks going to a full merchant model.
MR. MARTIN: How much of a premium do you think will be required? Most debt in the renewables market is back-levered debt that sits behind the tax equity investor in the capital structure.
MR. WELLOCK: I don't know, but recent events have exposed some loopholes in the financing structure. I don't think back-levered lenders realize they could be completely wiped out if the hedge goes upside down. That was not priced into their margins. How much the premium will be for these types of hedges remains to be seen. I can't answer that question.
MR. MARTIN: Dan Miller, what percentage of the revenue must be hedged if you agree that there will have to be a hedge of some sort? And what happens if the hedge covers only a fraction of the revenue stream? Is the debt sized solely on the basis of the fixed revenue?
MR. MILLER: Taking a step back, we have been working with clients on some fully merchant options. These structures would obviously be much lower leverage and higher priced, but the sponsors are willing to take that tradeoff to gain access to higher electricity prices.
Not every lender will be doing that, but there will be a sub-segment of the debt market that is open to it and thinks that it makes sense to be paid earlier to avoid having merchant risk later in the useful life of the asset on hedged assets with merchant tails.
We have seen a couple broadly syndicated deals get done where 60% to 70% of the revenue is contracted. We are willing to give credit in debt sizing to that 30% to 40% merchant, but clearly at a discount. If it is below that level — say 50% or fully merchant — then you need to start adding a greater discount to the merchant revenue and probably use a higher debt-service coverage ratio as well.
We think that there are some solutions that we can work for the debt to the extent that we can come up with a practical approach that also works for the tax equity.
MR. MARTIN: Let's say the debt-service coverage ratio is 1.25 times P50 for solar and 1.35 times for wind currently for contracted revenue, meaning hedged revenue. What DSCR would have to be used for the merchant part?
MR. MILLER: If the revenue is fully merchant, then the DSCR would be in the two-times range. Maybe the ratio is lower initially. For example, maybe in years one through seven, you hit 1.75 or 1.6 times, stepping up as you get later in the useful life to 2.0 but not going out further than 15 years on an amortization profile. This is not priced anywhere near some of the other bank market products. It is much higher.
MR. MARTIN: What percentage of projects you are seeing in ERCOT with hedges versus standard bus-bar PPAs?
MR. WRIGHT: I think the vast majority have been heavily contracted up until now.
I was going to add to what Dan said. I agree with the way he is approaching this. I think about this in terms of buckets of capital. In a significant portion of contracted revenue deals, those margins start with a one handle, which is where the market has been up until now. They have robust investment-grade constructs. That is one bucket of capital.
Then you have the partially contracted deals that Dan was talking about, which I think of as another bucket of capital, which might have margins of 200 basis points and higher above the base rate, which is matching the risk-weighting of how lenders look at that risk.
And then there is a very small bucket of capital that is going to be doing fully merchant, to Dan's point. There are lenders who will do fully merchant deals, but obviously at a much higher cost of capital.
MR. MARTIN: Rubiao Song, what percentage of projects does JPMorgan see currently in Texas with hedges versus traditional bus-bar PPAs?
MR. SONG: Fixed-rate bank hedges are a small percentage, say less than 20% to 25%. But bus-bar PPAs are also a very small percentage. It is rare these days to have bus-bar PPAs. The most common contracts we see are CfD contracts that require payments on a unit-contingent generated basis. They do not have the price-spike risk about which we have been talking, but they do introduce the locational basis risk, which could be significant in congested areas.
MR. MARTIN: CfDs or contracts for differences are hedges that are financially settled. The project owner swaps floating payments tied to spot electricity prices for fixed payments, correct?
MR. SONG: Right. The difference is whether the settlement quantity is a fixed or pre-agreed amount or it is based on actual output from the project. The latter is better suited to mitigate the risk that happened last month in Texas.
MR. MARTIN: How common are hedged merchant projects in other markets besides ERCOT?
MR. SONG: In any liquid power market, you could use hedges. We have certainly been financing them in California, MISO and PJM. They are not a big percentage.
MR. MARTIN: Hedges take multiple forms. There are fixed-volume swaps that can be physically or financially settled. There are proxy-revenue swaps. There are proxy-generation PPAs. There are contracts for differences that Rubiao Song was just describing. From your perspective, are all hedges the same? JPMorgan's preference is a contract for differences tied to actual generation and not to a notional amount.
MR. WELLOCK: We have a preference for contracts for differences. We have looked at a few proxy-generation hedges, but didn't really get comfortable from a debt perspective with these because they have both basis risk and availability risk.
The more difficult risk to mitigate and get comfortable with is the availability risk. Your hedge might be in the money, but if you are not producing energy, you have no revenue to offset your potential settlement under the hedge.
Electricity basis risk depends on location. If you are in a congested area, the basis risk might be significant. We try to make sure that we are looking at a project that has minimal basis risk.
There are certainly differences in the types of hedges. People need to understand what they are and what risks they are taking with different hedge products. (For more detail, see "Hedges for wind projects: evaluating the options" in the June 2017 NewsWire and "Lending to hedged wind and solar projects" in the February 2020 NewsWire.)
MR. MARTIN: Are there some of type of hedges that you will do and some you will not do?
MR. MILLER: Our preference clearly, after this event, is the hub-settled as-generated contracts for the reasons that were just discussed. The market depth will be much wider for the same reasons, and the pricing would be better on this type of deal.
When we first started doing ERCOT projects, they were mainly fixed-shape hedge deals. We have seen a lot of corporate buyers come in. The projects are being sited closer to the hub to which they are tied. That is alleviating a lot of the basis risk, which is the primary risk in the as-generated hub-settled contracts.
MR. MARTIN: James Wright, are there some forms of hedges that you will do and some you will not do?
MR. WRIGHT: I don't want to generalize. We will look at everything and be thoughtful about what we execute on. The challenge, when you move beyond traditional power purchase agreements with utilities, is the variety of contracts we see nowadays in renewables in the US. Each of the contract types that you just ran through — corporate PPAs, proxy revenue, proxy generation, CfDs — has unique benefits and challenges.
The counterparty credit risk on those can be very different depending on who is on the other side of the contracts. Some of them come with tracking accounts to deal with basis risk. Some will have a lien on the project. When you get into the corporate PPA world, there is a deeper dive on what is the alternative route to market for the project if the corporate defaults on the PPA, particularly with some of those more sub-investment-grade or crossover investment-grade buyers that we are now seeing in the market. All of these contracts require a much more nuanced credit analysis than you would typically see with a utility offtake contract.
MR. MARTIN: How will other terms for hedged merchant financings in ERCOT change, besides what we have just discussed about hedges?
MR. SONG: We have been accustomed to thinking the tax equity is in the first position in the capital stack. Going forward, we are going to be very focused on whether these offtake arrangements have introduced a senior creditor to the project that could cause liquidity or other problems.
Going forward, if you do not have a bus-bar PPA or other well-structured offtake contract, sponsors should expect to have to provide more support for the project through working capital loans or project reserves or entering into affiliate contracts to provide cash-flow protection.
We are already seeing this happening. We are already seeing more deals on a portfolio basis, combining wind and solar, combining projects in different regions and with different offtake strategies. That could be a good way to get the deals done.
MR. MARTIN: So perhaps put one ERCOT project into a portfolio of three projects, with the other two having bus-bar PPAs and being located in other parts of the country. Let me pose the same question to the rest of the bankers: how will other terms for ERCOT merchant financings change?
MR. WRIGHT: The cost of capital will certainly increase, at least in the short term. Lenders will be less bullish on some of those merchant tails that we have been seeing in quasi-contracted deals. There will be a bit of a step change or rethink needed on how tracking accounts work.
MR. MILLER: I think that there will probably be less market depth for some of the fixed-shape hedges. There were probably around 15 lenders who were willing to do the fixed-shape deals before February. That is obviously going to change, and especially if you do not have a good answer to the obvious question how the project survives another extreme weather event.
We are in the market now with several as-generated deals. The merchant plus an as-generated hub-settled hedge is a good combination to marry together, because you could obviously take advantage when there are price spikes and the sun is shining and not get hurt on the downside.
We are seeing a lot of those opportunities come across our desk, and we are seeing a lot of interest from lenders in that profile, at least on projects with top sponsors. I think it all comes down to who is the sponsor, what is the proposed structure, and what is the price relative to the other three or four deals that come across your desk in a given week or two.
MR. MARTIN: Let me mention one more thing, and then we will go to a few audience questions.
Some people have been asking about "default uplift allocations." ERCOT has to break even, and so if it is ordered to return billions of dollars — the ERCOT market monitor said initially that $16 billion was overpaid — all market participants would be required to contribute. There is a cap on how much ERCOT can collect each month.
One question being asked is whether new greenfield projects will end up having to bear a share of these default uplifts. The amounts would be an offset against the future revenue such projects earn from spot sales of electricity. ERCOT is already more than $2 billion in the red before any adjustments for overcharges.
The answer is new projects that were not connected to the grid when the default occurred would not be affected.
CPS Energy — the municipal utility in San Antonio — filed suit on Friday to block the burden from being shared across all market participants.
MR. MARTIN: We are going to audience questions. I will read each question quickly. Just one person answer. Let's see how many we can get in during the short time remaining.
"How do you think about your preference for merchant versus fixed shape if sponsors were conservatively to haircut the fixed shape in lieu of moving to a unit-contingent contract?"
MR. MILLER: We were already there before the winter storm. Lenders were more than willing to trade more merchant risk for less shape risk on the deals that we were getting done. That is one tool that sponsors are using to get through this period.
MR. MARTIN: Next question.
"Will tax equity be available for a contract for differences that is for 80% of the output? How low could you go on contracted output to attract tax equity?"
MR. SONG: A contract for 80% is a pretty high level. The real answer to this question is it depends. In regions where there is a very liquid market, and the electricity basis issue is not a big concern, having a CfD contract that covers at least 50% of the output could make the project viable from a tax equity standpoint.
MR. MARTIN: Next question.
"What percent of debt sizing would you be comfortable linking against purely merchant cash flows?"
MR. WELLOCK: Around 50% or less is an amount of merchant risk that we would be prepared to take.
MR. MARTIN: Next question.
"Is there a greater preference for solar given less availability risk?"
MR. WELLOCK: Yes. I think you can make the case of mitigated risk for a solar project more easily than you can for gas or a wind project.
MR. MARTIN: Another question.
"Is anyone hearing how long it may take market consultants to recalibrate merchant price forecasts in Texas? There were large retirements forecasted in the coming years, and perhaps those units forecasted to retire are the very units operating that saved the ERCOT grid from total collapse. Does anyone have any insight into this?"
MR. MILLER: I have talked to several market consultants about that. Fewer projects may retire in the near term. There were not many retirements expected earlier, maybe two or three gigawatts in the next five. However, other plants may have to weatherize, which could offset the impact. It is a fluid situation. The market consultants are trying to gather as much information as possible for their next quarterly forecasts.
MR. MARTIN: Apologies to those waiting to have questions answered. We are out of time, so this will have to be our last question.
"Unlike wind and gas facilities, batteries in Texas are already winterized. HVAC containers keep them warm when it is cold. They have no problem operating during a cold snap. Do any of the panelists believe that financing batteries on a purely merchant basis in Texas could be less risky than hedged storage?"
MR. MILLER: We will take the same approach that we do on solar. We will work with a market consultant and understand all the assumptions going in, apply a discount to that, and work on some downside sensitivities. If that leads to a five-year repayment profile for a battery deal, then it is something that we can entertain. We are open to merchant, but with less leverage to ensure debt repayment occurs well within the useful life of the asset.