Cost of capital: 2019 Outlook
Around 2,000 people patched into a call in January for a discussion about the outlook for tax equity, bank debt, term loan B debt and project bonds in the US project finance market. The costs of these items are a factor in the price at which developers can commit to supply electricity under long-term power contracts.
The following is an edited transcript. The panelists are Yale Henderson, managing director and head of energy investments for JPMorgan, Jack Cargas, head of originations on the tax equity desk at Bank of America Merrill Lynch, Ralph Cho, co-head of power for North America for specialist bank Investec, Jean-Pierre Boudrias, managing director and head of project finance at Goldman Sachs, and Recep Kendircioglu, senior managing director in the bond and corporate finance group at Manulife Financial/John Hancock. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Yale Henderson, what was the tax equity volume in 2018 in renewable energy, and how did it break down between wind and solar?
MR. HENDERSON: These are still preliminary numbers, but we think it was $12 billion across all market segments. This number includes secondary market transactions, which are sales of existing tax equity investments or part of such investments.
We counted $8 to $9 billion of wind last year and $2 to $3 billion of solar, so the market was still heavily weighted last year toward wind, but we expect solar to pick up over the next three years as solar developers are forced to start construction of remaining projects to qualify for large investment tax credits.
MR. MARTIN: To provide perspective, tax equity in 2017 was $10 billion. Things started off slowly in 2018 -- the first quarter saw little activity as people spent time modeling the effects of tax reforms and waited for solar and steel tariffs to be announced -- but then the market regained ground. Looking farther back, 2016 was an $11 billion market and 2015 was the peak at $13 billion. What do you expect in 2019?
MR. HENDERSON: We expect a robust market. We do not expect as many secondary market transactions. They accounted for about $3 billion in volume last year.
MR. MARTIN: Why less secondary market activity?
MR. HENDERSON: The secondary market players were looking to manage their exposure last year, and they have now done what they wanted to do and are not going to be unloading years of inventory like they were in the recent past.
MR. MARTIN: Just to be clear, the suppliers of tax equity will not be unloading inventory. You do not see any less demand from tax equity investors?
MR. HENDERSON: Correct. We do not.
MR. MARTIN: Jack Cargas, do you agree with these numbers?
MR. CARGAS: Our sense is the market was probably 80% wind and 20% solar. With respect to 2019, we agree with what Yale just said about secondary market trades. Whether the $12 billion in 2018 and the $10 billion in 2017 are apples-to-apples numbers is open to question given the large number of secondary market trades in 2018. The $10 billion in 2017 was almost entirely primary demand.
There were some later-in-life portfolio monetization transactions in 2018 that will not be repeated this year. One or two solar tax equity deals also changed hands during 2018.
That aside, we expect to see growth in 2019 and especially in 2020. There are only two more years left to put wind projects in service to qualify for tax credits at the full rate.
A number of tax equity investors exited the market in the past who may come back this year.
However, there are physical constraints on how large the market can grow. Even if there are more projects seeking tax equity and more investors, everyone must still rely on the same set of experienced third-party experts: lawyers, engineers, insurance brokers, appraisers and environmental consultants. This resource constraint is a cap on how much volume the market can handle.
MR. MARTIN: One large bank was largely out of the market last year due to lack of tax capacity. We have heard from another that it will be out of the market in 2019. Is it possible that dwindling tax capacity may become an issue in 2019?
MR. CARGAS: We do not think it will be an issue. Tax rates have decreased, and that decreases tax liabilities on an individual investor basis, but corporations are reporting large profits in the current economy, which increases tax capacity overall. Some players may exit the market while others take their places.
MR. MARTIN: What percentage of the capital stack of the typical solar project is tax equity as we enter 2019? What is the percentage for wind?
MR. HENDERSON: We see solar in a range of from 37% to 43%. Wind is in the 55% to 70% range, depending on the amount of cash given to the tax equity investor, how much the project cost to build and other factors.
MR. MARTIN: Jack Cargas, do you agree with those numbers?
MR. CARGAS: Yes.
MR. MARTIN: Most listeners are tapping into this call to get a better feel for what the cost of capital will be so that they can make more informed bids to supply electricity. Speaking for my firm, we have been seeing unlevered tax equity yields in the mid-6% range for contracted utility-scale solar to low 7% for hedged merchant solar projects. For wind, we have seen sub-7%. Flip yields for rooftop residential solar have been anywhere from 7.5% to a little over 11%. Again, these are all unlevered after-tax numbers.
The cost of tax equity is a function of demand and supply. In which direction do you sense yields are moving?
MR. HENDERSON: We don’t really comment on pricing because every deal has its own unique features, including sponsor preferences, the offtake arrangement and offtaker credit, the location, the technology being used, and so on. Also, while flip yields are important, not all flip yields are created equal.
Speaking more generally, we expect there to be ample tax equity this year. Assuming little change in underlying interest rates and the broader economy, we would not expect to see the market change much from where it has been the last 12 months.
MR. CARGAS: If listeners to this call are trying to figure out what cost of capital to assume in bids to supply electricity, the best advice is probably to look at where the market has been recently. We are not in a position to make forecasts and, even if we were, we have not been particularly good at predicting where rates will go. The rates you quoted for wind and solar, contracted and hedged projects, are what we have been seeing, as well.
One more point: you are absolutely right that the supply-demand equation has been the primary driver of tax equity pricing to date, but we have been seeing more spread compression in the past year or so, and cost of funds to investors is now more of a factor than it once was. Tax equity yields have not really moved with investor cost of funds over the history of this market. But in a rising rate environment, spreads have decreased, making tax equity investing relatively less attractive compared to alternative uses of capital on the part of investors. Supply-demand is and remains important, but spread compression is also becoming a factor.
MR. MARTIN: Let me ask a series of very short questions with hopefully quick answers, and then I want to get to a broader question about any other noteworthy trends. We have been seeing more tax equity investors take the 100% depreciation bonus on wind projects in order to make the financing more attractive. Do you see that as well?
MR. HENDERSON: Nine times out of 10, where 100% deprecation bonus is claimed in a wind deal, it is a late-in-the-year project and there is some reallocation and, therefore, you end up ultimately back in an economic profile that is equivalent to five-year MACRS depreciation. You do not see bonus much in solar because you cannot get 99% of the investment tax credit to the investor in a solar deal if you reallocate a portion of the first year losses back to the sponsor.
MR. MARTIN: So investors may take the 100% depreciation bonus in the wind market, but because of the way partnership tax accounting works, the economics end up the equivalent of five-year MACRS deal, so there is no pricing benefit.
MR. HENDERSON: Correct. It may be a more efficient way to structure the deal, but ultimately the economics do not really change much.
MR. MARTIN: Next question. DROs -- deficit restoration obligations that allow tax equity investors to absorb more of the depreciation -- seemed to be at 50+% in many deals last year. Do you see that trend continuing into 2019?
MR. CARGAS: A 50% DRO is very high, and I would say it is the exception rather than the rule. There has been upward pressure on DROs. The absolute level is not the only factor. We also focus on the timing of the DRO reversal. Does that happen pre-flip or post-flip and, if post-flip, when is it projected to occur? Yes, we are seeing higher DROs in the current market than we used to see, but 50% is more of an outlier than a standard level.
MR. MARTIN: Yes or no answer. Do you see a return to project-level debt?
MR. CARGAS: The short answer is maybe in one-off or two-off, very specific applications.
MR. HENDERSON: Agreed. Project-level debt does not add a lot of value in a tax equity transaction in our opinion.
MR. MARTIN: What yield premium should one assume if there is front leverage? It used to be 250 basis points, and then it seemed to bump up to 500. Where do you think it is today?
MR. HENDERSON: There is no real market to test. Front leverage is a bespoke product.
MR. MARTIN: What other noteworthy trends do you see as we enter 2019?
MR. HENDERSON: More projects are taking electricity price basis risk when the offtake contracts take the form of corporate PPAs or hedges. We have been fairly good in allocating that risk back to the sponsors, but at some fundamental level, the amount of basis risk that is starting to crop up in certain regions of the country is getting close to the bone in terms of being able to generate enough cash flow to support operating expenses, never mind distributions to the tax equity investor or sponsor.
MR. MARTIN: We heard last year on this call that basis risk is making it hard to raise tax equity for projects in the Texas panhandle. Are there other parts of the country where the basis risk is too high?
MR. HENDERSON: It depends on the tolerance of each tax equity investor for risk. As of right now, I would say the problem is not limited to the panhandle. There are concerns that are cropping up in Oklahoma and possibly even in Iowa. Each transaction has its own profile. The issues are idiosyncratic and turn partly on where you lie on the transmission grid.
MR. MARTIN: Jack Cargas, other noteworthy trends in 2019?
MR. CARGAS: I have some comments on what Yale just said, but I guess I will go to expectations.
We expect market dynamics to become very different in 2019 and 2020 as PTCs wind down. We expect more diversity of product. We expect more demand for repowerings. We expect offshore deals of real size to come to market starting in 2019.
We saw a lot of challenges in recent years: fixed-flip versus yield-flip structures, changes in the way the Public Utility Commission of Texas treats deals, increasing local legal expenses, net metering changes and CFIUS challenges, issues related to real estate title, insurance, title to equipment and gen-ties and many different things. The pace of change is accelerating while resources remain limited and rather precious. The market has to be light on its feet, and it may mean that some investors become more specialized in what they will invest in. Overall, we think the dynamics are becoming more complex and will continue to do so.
MR. MARTIN: So more specialization among investors because the deals are becoming too complicated. Come back to what Yale Henderson said about basis risk. Do you agree with what he said?
MR. CARGAS: Basis risk has turned out to have been significantly greater than what was assumed in base and downside cases, particularly in Texas. A fundamental principle of project finance is the risks must be quantifiable. You need to have a financeable offtake arrangement. To the extent that basis risk is unpredictable, you might not. So there are real concerns there. Do the parties want to move toward affiliate power purchase agreements or other structures that allocate that risk to the sponsor? I am not sure, but basis risk is a challenge.
MR. MARTIN: Developers are wearing more risk as we move to a corporate PPA and hedge market. Let’s move to bank debt. Ralph Cho, what was the volume of North American project finance debt in 2018 compared to 2017?
MR. CHO: The first quarter of 2018 started off a bit slow, but the rest of the year definitely has made up for it. Every banker I speak to has been super busy. The numbers are still coming in, but it looks like North American project finance deal volume was $63 billion in 2018. That is 54% higher than last year, where we saw about $41 billion. It is roughly comparable to the peak in 2015.
MR. MARTIN: Deal volume in 2015 was $60 billion, according to our numbers. How many deals were there last year?
MR. CHO: We counted about 175, which is a little more than the 160 deals that we saw in 2015, which was the last peak year.
MR. MARTIN: How many active banks were there in 2018, and how many do you expect in 2019?
MR. CHO: We saw some new names in 2018. By my estimate, roughly 80 to 100 lenders are chasing projects. They include not just banks, but also grey-market lenders. Of the total number, 30 to 40 are highly active. My expectation is 2019 will remain relatively unchanged.
Volatility in the institutional loan market is going to create some turmoil for the non-bank, grey-market lenders. When you have a divergence in yields between the bank and institutional loan markets, it makes it harder for the grey-market lenders to invest in a bank loan product. The good news for project developers is the bank loan market is not as sensitive to this volatility. The appetite in the bank market is still strong. I think the extra froth that we used to see added by grey-market lenders is going to be a little less frothy.
MR. MARTIN: So we have seen an increase in numbers, but one wonders how long the numbers can keep increasing with so many banks chasing a limited number of deals.
What is the current spread above LIBOR for bank debt?
MR. CHO: It depends on what type of deal we are talking about. Broadly speaking, plain-vanilla loans to finance fully contracted projects have tightened by about an eighth to a quarter percent this year. We see pricing at LIBOR plus 125 to 137.5 basis points. Short-term construction loans have been really competitive. These are pricing below LIBOR plus 100. We have heard of construction debt being offered at spreads as tight as five-eighths or seven-eighths. Quasi-merchant gas deals have been very stable in recent past years at around 325. This year, they have tightened by about 50 to 75 basis points, so let’s say LIBOR plus 250 to 275 basis points for basically operational assets.
The one greenfield quasi-merchant deal that printed this year printed at LIBOR plus 300. So you can see that even in that area, margins are tightening. Plain-vanilla holdco loans are pricing around 300 basis points. We see more commercial banks moving into this risk spectrum, probably because they are having a hard time finding deals where they normally play.
MR. MARTIN: So there is still downward pressure on interest rates.
MR. CHO: There is definitely downward pressure. To put these spreads into context, the three-month LIBOR rate is somewhere around 280 basis points currently. We are probably swapping LIBOR around 300 to 325 basis points. You just add that to your margin to get the coupon.
MR. MARTIN: Do you add the spread to the swap rate or the underlying LIBOR of 280?
MR. CHO: Let’s say you are swapping LIBOR at 300 basis points, just to make the math easy. If a borrower’s margin is 150, it is paying an interest rate of about 4.5%.
MR. MARTIN: Acquisition debt. According to press reports, the acquisition loan for the buyer to acquire a portfolio of wind farms from BP Wind was priced at LIBOR plus 12.5 basis points. Is acquisition debt generally cheaper, particularly for operating assets?
MR. CHO: I think that was a loan to repower several operating wind farms. It was essentially a short-term construction loan. It was not a mini-perm. That should have priced inside of 100, but look, every project has its own nuances, and the lenders are going to bid appropriately for the deal profile.
MR. MARTIN: Is there still an upfront fee equal to the LIBOR spread?
MR. CHO: Not necessarily. The upfront fee we see ranges from 75 to 150 basis points, and that is in the primary markets. Whether the fee is in this range depends on how much a lender commits up front. The higher the commitment, the higher the fee. The demand for projects was intense. Multiple deals ended up oversubscribed with reverse flexing, meaning the final interest rate came in lower than the rate at which the deal went out to market. So upfront fees were probably on the tighter end of the range I just gave.
Appetite in the secondary market has also been super strong because banks cannot get enough paper in the primary market, and so we saw banks trading loan paper somewhere around par or near-par. I call it 99.75%, and that is right after the deal closes.
MR. MARTIN: What are current loan tenors?
MR. CHO: Loan tenors have not changed in the last year. Everything we see is around the five- to seven-year mini-perm. If it is a construction loan, the tenor is like the construction period plus five years. There were some long-tenor deals done for plain-vanilla deals with strong sponsors at 15 or more years. There was no real change there, either.
MR. MARTIN: What are current debt service coverage ratios for wind, solar and gas-fired power projects?
MR. CHO: Wind is still targeting around 1.4 as a DSCR using P50 output projections.
Solar is 1.3 for P50 output. That is driven by the tighter standard deviation, so lenders feel more comfortable about the resource forecast and reliability.
To be competitive in typical contracted gas-fired assets, we see the coverage ratio tightening to 1.3 to 1.35 over the life of the power purchase agreement. This is a function of the pressure as banks try to outdo each other to win that business.
Quasi-merchant gas deals are slightly more complicated. Banks will go as tight as 1.35 for sizing purposes in deals with revenue puts. If you have a heat-rate call option, there is a little bit of basis risk so the banks are sizing it slightly wider, call it a 1.4 DSCR.
MR. MARTIN: Now for a series of quick questions. What are advance rates currently for construction debt?
MR. CHO: The market is hyper competitive right now, so I would say that they can go as high as 90%. Tax equity bridge loans have not changed. We have seen them advancing as much as 95% of the expected tax equity contribution. Quasi-merchant construction deals are typically getting advanced at 50% to 60% depending on the situation.
MR. MARTIN: Is it still the case that lenders are not charging any premium to lend on back-levered basis compared to what they would earn on project-level debt?
MR. CHO: We do not see any meaningful difference. Lenders don’t put a premium on back-levered deals. I am not sure that makes sense, but that is where the market is.
MR. MARTIN: Have you seen any change in appetite among banks for any of the following: for merchant wind, solar and gas deals, for projects with corporate PPAs or PPAs with community choice aggregators, or for community solar? Or is there still strong appetite across the board?
CHO: Strong appetite across the board. Relatively speaking, renewable energy projects seem to be more in demand than conventional thermal deals. The terms always seem a little tighter for renewables deals. We saw two merchant wind deals come out at the end of 2018, and they were pricing at LIBOR plus 225 to 250 basis points. That is tighter than merchant gas, which is getting done at 250 to 275. That said, merchant gas is still pretty strong.
We saw healthy demand for gas deals across all the regions.
Given how many such deals have been done in PJM, deals in other regions seemed to attract extra attention from banks, since they offer banks a chance to diversify their portfolios.
MR. MARTIN: Are there any other noteworthy trends as we enter 2019?
MR. CHO: Notwithstanding all the volatility we are seeing in the institutional loan markets, which I am sure J-P will talk about, I am pretty optimistic. We have hit the ground running in 2019, in contrast to last year when the first quarter was virtually dead.
We expect to see greenfield quasi-merchant gas projects in PJM make a comeback. There are eight to 10 such deals that are already in the market. That is about $8 billion in financing. Each such project requires about $800 million in financing capacity.
Another trend is a large number of quasi-merchant gas projects will reach COD or are already in the first year of operations. Many owners of these projects will be motivated to re-finance the projects in the bank or B loan market in an effort to get better terms than were on offer three years ago when the projects started construction.
LNG will be back in the market. There are four or five LNG deals seeking something like $30 billion in financing.
Jack Cargas mentioned offshore wind. The first of several offshore wind deals should come to market at the end of the first quarter seeking about $500 million of debt. That one looks very promising.
M&A should continue to be a theme. I have been talking about this for three years, but I think clean tech is something that everyone is still anticipating. We have seen a few battery and fuel cell deals, but clean tech has to hit critical mass eventually, right?
Term Loan B Debt
MR. MARTIN: Absolutely. Great summary of where the opportunities are expected to be this year.
Let’s move next to Jean-Pierre Boudrias from Goldman Sachs. We are going to talk about the term loan B market. Let’s start with deal volume for the North American power sector in 2018 and how that compared to 2017?
MR. BOUDRIAS: We saw $8.25 billion last year across 18 transactions. Of that amount, $3.6 billion was repricing of existing debt. The rest was new debt. The overall volume was down by 17% compared to the year before.
MR. MARTIN: In 2017, B loan deal volume was 11 transactions for $10 billion, so there were more transactions in 2018, but overall volume was down.
MR. BOUDRIAS: That is correct.
MR. MARTIN: How many of the 2018 deals were merchant gas-fired power projects?
MR. BOUDRIAS: For the sector-specific questions, we have to isolate to the single assets because a number of portfolio deals were done that skew the data. There were eight single-asset transactions for $2.4 billion. All of them were for gas-fired assets.
MR. MARTIN: So eight of the 18 transactions last year were merchant gas. What about merchant wind or solar? Were any such deals financed last year in the B loan market?
MR. BOUDRIAS: The yields are too tight to get traction in the institutional market. As a result, we will see issuers like sPower come to market with more of a corporate debt offering around a combination of solar and wind assets or Atlantic Power offer a portfolio that includes some hydro assets, but most of the activity in the institutional world is in the gas-powered space.
MR. MARTIN: Where the yields are higher than for renewables?
MR. BOUDRIAS: Correct.
MR. MARTIN: Were all eight of the quasi-merchant gas projects in PJM or ISO New England? What about ERCOT?
MR. BOUDRIAS: We saw one ERCOT deal in 2018. There was also in that single asset group another Texas asset that got financed twice: first for the initial transaction and then an add-on offering in the summer. That project was physically in Texas, but it is really a Mexican asset because that is where it sells its power.
MR. MARTIN: Eight of the 18 transactions were quasi-merchant gas, and there were no solar or wind projects. What were the other 10 transactions?
MR. BOUDRIAS: The rest were portfolio financings, and they were mainly gas assets, as well.
MR. MARTIN: Pricing a year ago for strong BB project debt was around 325 basis points over LIBOR with a 1% floor and 1% OID and for single B projects was 425 basis points over. Where do you see rates today?
MR. BOUDRIAS: It is a very interesting question given what we have seen since Thanksgiving. We are probably 25 to 40 basis points off where we were in November. Our best guess, and it really is just a best guess, is that BB credits are probably in the 350 to 375 range and single B credits are probably somewhere between 450 and 500. But it will depend on specific circumstances. Some deals may actually price wider even at the BB level.
MR. MARTIN: In contrast to what Ralph Cho told us about the bank market, where there still seems to be downward pressure on interest rates, the term loan B market is moving in the opposite direction.
MR. BOUDRIAS: Last year was really a tale of two markets. It was more of the same for the first three quarters and then, in the last quarter, the market retreated significantly. This was obviously led by what we saw in the equity markets. It was a pretty challenging December with no transactions on the high-yield side which we had not seen in the 30 years for which we have data. CLO participants, who are the largest participants in the institutional debt market, remained largely on the sideline for most of December.
MR. MARTIN: There was a 40-day stretch between Thanksgiving and early January when no high-yield corporate bonds were issued. The drought ended yesterday when Targa Resources brought a bond deal to market. What does that say about what is likely to happen this year in the term loan B market?
MR. BOUDRIAS: No one has a crystal ball in terms of what is going to happen. The transaction that was completed yesterday in the high-yield market is good sign in terms of overall risk appetite. Generally speaking, the equity tape has been favorable. Pricing for loans in the secondary market has generally improved from what we saw at the end of 2018. So I think a lot of the signs are actually positive and should point to better conditions as we start 2019.
But we do not have a lot of data points yet, so it will have to be a bit of wait-and-see. There is significantly more uncertainty around policy. This has seeped into the markets. A number of transactions that were planning to go to market in December and were being pre-marketed were put on hold. Borrowers are waiting for market conditions to improve.
MR. MARTIN: You told me last year that the last new-build deal was brought to the term loan B market in 2015. Everything otherwise has been refinancing of operating projects or acquisitions of such projects. Is that still the case? Have we not seen a new-build deal since 2015?
MR. BOUDRIAS: Correct. Developers have chosen to finance in the bank market for new assets.
MR. MARTIN: Advance rates in the term loan B market were in the mid-60% range. Has there been any change in advance rates as we enter 2019?
MR. BOUDRIAS: The math would probably get you to the same place today.
MR. MARTIN: B loans were traditionally for seven years. Any change there?
MR. BOUDRIAS: No. The tenor for most B loans is still seven years.
MR. MARTIN: What other new trends do you see as we move into 2019?
MR. BOUDRIAS: For last several years, we saw waves of repricing. That is unlikely to continue in a market where spreads are moving wider.
It creates an interesting dynamic with the bank market. It could lead to a broadening of the institutional investor base.
When one looks at what happens in our debt subsector, we are talking about a little over $8 billion in an overall market of more than $400 billion. I don’t think we will be the drivers. I think we will be on the receiving end of broader market trends.
MR. MARTIN: Let’s move next to Recep Kendircioglu with Manulife Financial and project bonds.
Project bonds are long, cheap fixed-rate money. The project bond market does not do well when the bank market and term Loan B markets are wide open and looking for product. We heard from Ralph Cho that the bank market is not only wide open, but also more banks are chasing deals than a year ago. The term loan B market is not as healthy. Institutional investors seem to be waiting for yields to go up to come in larger numbers into that market.
But we do have something that tends to push people into project bonds, and that is interest rates in the broader debt market seem headed up. Project bonds have been viewed as a way to lock in the interest rate.
How much volume was there in 2018 compared to 2017?
MR. KENDIRCIOGLU: It is hard to quantify the exact volumes because most transactions are private.
We did not see much action in the bond market for US wind and solar. But the drop in the volumes of those subsectors was made up by more offerings on the international side, particularly in Latin America and some in Europe. We saw some offshore wind in Europe. We have also seen quite a bit of activity in residential solar bonds.
Our sense is that Latin American, European, residential solar and other subsectors made up for the drop in the core project finance portion of the US bond market.
Keith, the interest rate point that you just made is a recent development. There is a time lag before it translates into activity in the project bond market.
MR. MARTIN: By what percentage was core volume down?
MR. KENDIRCIOGLU: I don’t have a number. Our own volume went up overall.
MR. MARTIN: How many deals are in the pipeline today?
MR. KENDIRCIOGLU: We really have mostly direct deals that do not go through a broker. We have three or four of them. It is a little surprising to me that we have nothing in the pipeline from a broker. There may be some projects that are waiting in the wings to see how interest rates settle before coming to market.
MR. MARTIN: So the deal volume as we enter the year is down from a year ago when a half dozen deals were in the pipeline.
Project bonds price off US treasuries rather than LIBOR. What is the current spread above treasuries? It was 175-200 basis points a year ago.
MR. KENDIRCIOGLU: The spreads have not moved in the last year. The spread on B- bonds is 180 to 200 basis points. The 10-year treasury rate is about 2.75%, so the spread translates into an interest rate of around 4.75%.
The bigger moves on interest rates have happened in the LIBOR markets. The big run-up on LIBOR and the increase in the swap rate are making project bonds a bit more competitive compared to where the bond market has been in the past couple years. The base LIBOR rate, even on a swap basis, was below treasuries. Now it is a bit flat. Coupon rates for project bonds are getting pretty competitive, and if you add the lower upfront fees, we should start to see some pick-up in terms of what goes to the project bond market.
MR. MARTIN: Are you worried, given the large US budget deficits, that the treasury rates will continue to rise?
MR. KENDIRCIOGLU: Most of the increase in rates has been at the front end of the curve. Projects that come to the bond market have long PPAs. They are more affected by long-term treasury rates than short-term treasury rate movements. There has not been much movement in the long-term rates.
MR. MARTIN: Let’s move next to a few audience questions, and I apologize in advance as we only have time to get to a small fraction of them. The first question is for Ralph Cho. Put the current debt service coverage ratios for peakers and combined-cycle gas plants into context. Are they moving up or down?
MR. CHO: If anything, there is downward pressure. When we size the debt on these assets, we target where we want to be on a balloon basis. DSCRs are 1.3 to 1.4 currently. We credit some swept cash in the sizing numbers because there could be some variable revenues coming through merchant energy. Banks are under pressure to be competitive by maintaining tighter ratios.
MR. MARTIN: What level of activity have our panelists seen in financing for battery storage?
MR. CHO: Not a lot. The financing terms on offer depend on the revenue model. If you have a fixed-price capacity contract, the spreads are likely to be very tight, on the order of LIBOR plus 125. If the revenues are tied more to the provision of ancillary services and they are merchant, then it is hard to count on those types of revenues, and so the rate is closer to an equity or mezzanine debt yield. But the reality is we just have not seen that many. Macquarie did one at the end of the year.
MR. MARTIN: Tax equity investors, are you seeing storage play a role in any of your projects?
MR. CARGAS: We have seen one or two projects where batteries have been an integral part of the renewable energy project and, therefore, part of the financing. But in terms of standalone opportunities, we have not seen much. We are very interested. We are tracking storage closely.
MR. MARTIN: Ralph Cho, going back to you. If you were to lend to a standalone energy storage project, what coverage ratio would you set?
MR. CHO: I would be willing to go very tight. Call it 1.3 or 1.4, no different than how I would look at any other power plant. Trust me, we would love to do battery storage. We are all over that. It’s just that we do not see many such projects. My guess is a lot of commercial banks would love to do these types of assets.
MR. MARTIN: J-P Boudrias, how are the low gas prices affecting the term loan B market?
MR. BOUDRIAS: Low gas prices have been the main reason why projects financed in our market have underperformed original projections. If gas prices increase, that is a positive for most of the power assets. The fact that they have remained low leads to underperformance compared to expectation.
MR. CHO: I’ll add to that. The sponsor in a merchant deal at which we are looking currently is planning to put on a hedge. Low gas prices mean that such hedges have not been as profitable.
MR. MARTIN: Does anyone on our panel want to speculate about the weighted average cost of capital for a wind project or a solar project? This is taking into account the entire capital stack.
MR. BOUDRIAS: I would guess that solar is around 6%. Depending on the profile of the wind farm -- we see a bit more merchant assumptions around wind farms and maybe a bit more post-contract value compared to solar farms -- I would say 6% to 7%.
MR. MARTIN: A couple of tax equity questions, and then we will have to end there.
The first is whether tax equity is available for merchant wind and solar projects. The answer is yes. They are quasi-merchant projects. The developer must have a hedge in place to put a floor under the electricity price. We have seen a significant number of merchant wind projects come to the tax equity market. The first large-scale merchant solar project was financed in the tax equity market in July and another should close shortly.
Last question: Yale Henderson, is there any appetite among tax equity investors for carbon capture sequestration credits?
MR. HENDERSON: Yes, they are definitely on our radar. We are interested in looking at these types of transactions