Cost of Capital: 2015 Outlook
More than 1,700 people listened in January as a group of project finance industry veterans talked about the current cost of capital in the tax equity, bank debt, term loan B and project bond markets and what they foresee for the year ahead.
The panelists are John Eber, managing director and head of energy investments at JPMorgan Capital Corporation, Jack Cargas, managing director in renewable energy at Bank of America Merrill Lynch, Thomas Emmons, managing director and head of renewable energy finance for the Americas at Dutch bank Rabobank, Jean-Pierre Boudrias, vice president and head of project finance at Goldman Sachs, Steven Greenwald, a senior advisor in project finance at Credit Suisse, and Jerry Hanrahan, vice president and team leader in the power & infrastructure, bond & corporate finance group at John Hancock. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: John Eber, what was the tax equity volume in 2014? How did it break down among wind, utility-scale solar and rooftop solar?
MR. EBER: We were able to get a pretty good handle on the wind tax equity market. It is more challenging with solar, and the solar numbers are still being gathered.
For wind, 29 deals came to market last year. We track on the basis of deals being awarded rather than when they closed. The deals amounted to almost 6,000 megawatts of wind and close to $5.8 billion of tax equity. There were 19 tax equity investors in wind.
That is sizable growth in the market last year compared to 2013 when we saw about $3.5 billion in wind. It is one of the larger years for wind tax equity that we have seen in some time.
The solar market could end up being comparable in size. Last year, solar was slightly larger than wind. It is more difficult to compile the final figures so early after the start of the new year.
MR. MARTIN: Do you have a feel for whether most of the solar activity was in rooftop solar or utility scale?
MR. EBER: I think it is similar to 2013 when we saw a significant amount of activity in rooftop; it accounted for about a third of the tax equity volume in solar. It would not surprise me to see the same breakdown in 2014.
MR. MARTIN: In 2013, there was something like $6.5 billion in total tax equity. You are talking about a very significant increase in volume over 2013.
MR. EBER: Without a doubt, there was a significant increase over 2013, certainly in the wind sector. If you recall, wind started out slowly in early 2013 because the extension of production tax credits came literally on January 1. It took a while for the market to ramp up in the first half of the year.
MR. MARTIN: The trend has been for solar to exceed wind in volume. If that happened last year, then you are talking about an $11.6 billion tax equity market in 2014, which would just be a phenomenal size.
MR. EBER: I am not predicting that that is what happened last year, but there was a sizeable solar market in 2014. Whether it will end up having exceeded wind remains to be seen.
MR. MARTIN: How does 2015 look?
MR. EBER: My sense is 2015 will be a very strong year, especially after Congress extended the deadline to start construction of new wind farms through the end of 2014 to qualify for tax credits. Solar was going to be a strong year regardless because the entire solar market has been working toward a deadline of the end of 2016 to qualify for the investment tax credit. We are as busy as we have ever been right now working on prospective opportunities and expect 2015 to be an extremely active year in both solar and wind tax equity.
MR. MARTIN: When do you think people need to be talking to you about 2015 deals to have any hope of having your attention to close this year?
MR. EBER: There is still plenty of time.
MR. MARTIN: Jack Cargas, the same?
MR. CARGAS: Yes, but we encourage people to alert us to possible 2015 transactions early in the year. The entire tax equity market saw a significant back-end weighting of transactions in 2014 to the fourth quarter. There was tremendous pressure on everyone’s time, and that is not only on the time of the investors, but also sponsors, external counsel and third-party experts. The pressure on human resources last year was extreme.
MR. EBER: I agree with Jack. The bottleneck is with due diligence. There was a notable bottleneck toward the end of last year getting the independent engineering resources to complete diligence.
One reason I think 2015 will be strong is we saw plenty of deals last year that did not really need to close until 2015. We asked folks to be a little patient with us, and we would try to take them up this year versus tying up time last year when we were so busy with other closings.
MR. MARTIN: Moving rapidly through a series of questions, tax equity yields have been fairly stable over the last four or five years, but they seem to be creeping up lately due to the addition of commitment or structuring fees on the front end and use of higher, 20-year yield targets on top of the flip yield at the back end. Do you agree with that statement?
MR. EBER: There is a lot more competition in the market than before because we have more investors now. The 19 investors that we saw last year in wind is an increase over what we saw the year before.
MR. MARTIN: That would normally bring yields down if you have more supply, correct?
MR. EBER: Yes, it should. We are talking about deals that are mainstream deals, meaning deals with leading sponsors, tier-one suppliers of equipment and long-term fixed-price power purchase agreements.
MR. MARTIN: Lance Markowitz said on this call last year that he thought yields for the benchmark wind deals, meaning with the largest sponsors, were 50 basis points above or below 8% unleveraged. That band may be a little wide. What we have seen ourselves is a band of perhaps 20 basis points below to 25 basis points above 8%. How many basis points would you say we are up or down this year compared to last year?
MR. EBER: The market pricing continues to be very stable.
MR. MARTIN: Jack Cargas, agree?
MR. CARGAS: Yes.
MR. MARTIN: How common are structuring or commitment fees at the front end or unused commitment fees at the back end on top of the yield?
MR. CARGAS: We are seeing more of that in our shop, in particular in transactions that include a forward commitment of capital. An example is wind deals that commit capital forward in order to accommodate construction financing. Another example is residential solar funds where there are multiple draws over time. Both kinds of transactions often include up-front structuring fees. Turning to back-end non-utilization fees, those are also common in residential and commercial and industrial solar funds. Once an investor decides that a program is a worthwhile investment, it would like to see its capital deployed.
MR. MARTIN: John Eber, we have seen such fees all over the map. Fees might range from 37.5 basis points to 75 or 100 basis points. There does not seem to be a “market” level of fee.
MR. EBER: They can vary depending on what is happening in the deal. If a lead investor is providing a significant amount of advisory work and services to the other investors and there is a long-term commitment by all of the investors, then you are more likely to see fees at the high end of the range.
If no advisory or support services are required from the lead investor, but there is a long-term commitment, then you might see an up-front fee at the lower end of the range.
MR. MARTIN: What is considered “long term” for a commitment?
MR. EBER: A commitment of 12 months or into the next tax year could be considered long term.
MR. MARTIN: What is the current spread between yields in the benchmark wind deals versus utility-scale and rooftop solar?
MR. EBER: We don’t see much of a difference in our shop on those.
MR. MARTIN: Among all three?
MR. EBER: Between utility-scale solar and wind.
MR. MARTIN: When you get to distributed solar, is the spread 100 basis points higher, 150, 75?
MR. EBER: Those deals are not very homogenous, so they are difficult to talk about in generalities, especially as it pertains to pricing.
MR. CARGAS: There can be a meaningful spread between wind yields and solar yields, but yield is really only one of the metrics by which we and other investors compare these investments. There are different structures potentially and different repayment profiles both from a tax and cash perspective. Obviously wind deals have 10 years of PTCs, and sometimes they have a cash reversion period. Solar deals have an ITC on day one that is a significant part of the yield. Some deals are inverted leases with a constant coupon.
The point is that yield is interesting, but it is not the be all and end all. It is not the only method that we use in evaluating these investments and, frankly, it is not the only thing that sponsors should consider when contemplating structures and pricing.
MR. MARTIN: John Eber has made the same point repeatedly on many calls and panels that we have done together.
How much of a yield premium should one expect currently if one adds leverage, meaning that the tax equity is behind a lender in the capital stock?
MR. EBER: We are seeing few leveraged tax equity deals, certainly very few in the wind space and not much more in the solar market. The tax equity will clearly require a premium because it has a greater risk of not reaching its return. The premiums run a few hundred basis points, but there are so few leveraged deals today that it is impossible to say what is “market.”
MR. MARTIN: What do you consider “market” for lender forbearance where there is leverage? Or is there no market at this point?
MR. EBER: We have not seen much. In solar where there has occasionally been leverage, anybody on the tax equity side would want forbearance at a minimum through the recapture period for the ITC.
MR. MARTIN: Forbearance means the lenders would have normal remedies after a payment default, but could not take the asset for non-payment defaults? All they could do in such a situation is push out the sponsor?
MR. EBER: Right. You would want a minimum of five-year forbearance if you are willing to go into one of those deals in the first place.
MR. CARGAS: I think one of the reasons why we are not seeing that much leverage is because lenders are loathe to agree to those sorts of forbearance provisions. None of the leveraged solar deals was an ITC deal; they were Treasury cash grant deals, and those are mostly out of the picture now.
MR. EBER: If there were a wind deal, then you would want 10-year forbearance because that is the PTC period. That would be an even a bigger lift.
MR. MARTIN: John Eber, you said there were 19 active tax equity investors in the wind sector last year. Do you have a feel for how many there were in the solar sector?
MR. EBER: We counted 25 in solar. We are seeing somewhere around 28 to 30 between both sectors. Many play in both markets. A limited number will only participate in one or the other. In addition to the 28 to 30 active tax equity investors, others are looking at entering the market. This is what one would expect as the economy improves. More companies start paying taxes and look to come back into the market.
MR. MARTIN: Do you see the solar rooftop market moving more in the direction of inverted leases, rather than partnership flips and sale leasebacks, and, if so, what do you think is driving that shift?
MR. CARGAS: We know that some market participants have a preference for inverted leases for solar, but we are not sure we have seen a huge shift. To the extent that there has been some movement in that direction, it may stem partly from new guidelines the IRS issued for transactions involving tax credits for renovating historic buildings in early 2014. Those guidelines suggested the IRS is okay with the inverted lease structure, at least in historic tax credit deals. Some players have concluded that that is de facto guidance for solar.
We maintain a preference in our shop for partnerships and regular leases.
MR. EBER: I generally agree with Jack. Many of the sponsors to whom we are talking have a preference for the partnership flip. That seems the more prevalent structure from our observations, although there are a number of solar investors who will only do inverted leases.
MR. MARTIN: How comfortable is the tax equity market with wind projects that relied on physical work at the project site or a factory to be under construction in time to qualify for tax credits?
MR. EBER: I think most of the market has become comfortable with physical work cases given that we have now had three rounds of guidance from the IRS. We think the accumulated guidance is fairly comprehensive.
MR. MARTIN: Let me drill down a bit briefly. Some developers dug several holes for turbine foundations before year end, and then went back to basic development work on their projects. Some developers ordered a transformer and there was limited physical work at the factory before year end. Are you okay with those cases?
MR. EBER: It will turn on the facts in each case. Let’s just say that I think the sponsors have been very responsible in trying to establish clearly that they began physical work, and there is a range of fact patterns on offer in the market. The more work that was done, the better chance you have of attracting a broad spectrum of tax equity to a transaction. The closer you are to the low end of the requirements, the more challenging it will be to raise tax equity.
MR. MARTIN: How comfortable is the market with projects that were under construction in time because the developer incurred at least 5% of the expected cost, but that will not be completed until after 2016?
MR. CARGAS: That’s a tough question. We are not fully ready to address 2017 because we are still concerned about 2016. We want to see clear guidance from the IRS that the extension of the construction-start deadline to the end of 2014 also had the effect of giving developers through the end of 2016 to complete projects without having to prove that they worked continuously on the projects.
Some participants appear to be assuming that there was already such a back-end extension, but we would like to see it in writing from the IRS and, until that happens, we are not even thinking yet about 2017.
MR. EBER: That is a very good summary. We are anxiously awaiting confirmation from the IRS as is the rest of the market.
MR. MARTIN: Turning from tax equity to bank debt, Tom Emmons, what was the North American project finance bank market in 2014 compared to 2013?
MR. EMMONS: Volumes were up significantly in 2014 compared to 2013: 45% from a $28 billion market in 2013 to $41 billion in 2014. I am drawing on data compiled by Infrastructure Journal. The US was dominant, comprising about 80% of the North American project finance market, Canada about 15%, and Mexico the balance. In terms of sectors, oil and gas was just under half of the market, conventional power was about a quarter and renewables were just under a quarter.
MR. MARTIN: How many active banks were there in 2014, and how many do you expect in 2015?
MR. EMMONS: In 2014, 94 banks played some role in project finance. That is up 20% from 72 in the previous year. Of course, that is the whole universe, including a lot of banks who had low levels of activity. A better measure is the number of major lenders. In 2014, 49 banks committed more than $200 million in aggregate each, and that is up about 20% from 2013. Not only is the market growing in total participants, but the big guys are also putting out more money.
Predictions about the year ahead are always difficult. There will no doubt be new entrants, but we are nearing 100 banks and already have plenty of players. I think what will happen is that the current lenders will step up with additional capacity to meet the demand because those banks still have capacity.
MR. MARTIN: When you say step up to meet the demand, it sounds like you are suggesting that demand for capital to fund new projects in North America is increasing?
MR. EMMONS: There was increasing demand in the last two years, and the banks stepped up. The bank market is adequately liquid, and there are enough players that the bank market can adapt to additional market demand. We remain in a situation where there are plenty of banks and plenty of liquidity. If there is more demand in 2015, the banks will be able to handle it.
MR. MARTIN: It is always a question who has the edge in negotiations. The big story last year was there were so many banks chasing product that there was downward pressure on rates. Is demand increasing faster than supply, or will we remain in an oversupply situation?
MR. EMMONS: We remain in an oversupply situation. There is still downward pressure on rates. As I mentioned, there are more lenders, the market is liquid, the market is competitive, banks have lower funding costs, and there are more short-term facilities. The banks are not being asked to do the heavy lifting of long-term loans.
However, I think most of the rate reduction is behind us. Banks now are often bidding at the minimums in their return models. When you look at this from the perspective of cycles, we are now at margins that are roughly where they were in 2008. It is hard to see how they can fall a lot farther. That said, there is liquidity and there still is downward pressure. The bottom line is it remains a borrower’s market.
MR. GREENWALD: A lot of the increase in the size of the market came from just a handful of mega transactions that took place in the oil and gas space, notably Sasol and the Freeport transactions in the last quarter of last year. We should see some more mega transactions this year.
MR. EMMONS: If you look at subsectors, apart from oil and gas, some interesting trends emerge. US solar doubled to $2.5 billion and lending to wind projects declined by about 40%, dropping from $3 billion to $1.8 billion. Conventional power was about flat.
MR. MARTIN: What is the current spread above LIBOR for interest rates?
MR. EMMONS: There is a wide range, particularly because different projects present different risks, but to summarize, at the low end, for clean, short-term, large, well-sponsored deals, margins can begin as low as 150 basis points above LIBOR, and sometimes even lower in unusual cases. In the middle, for a typical moderately-complex medium-sized term loan, somewhere around 200 basis points, plus or minus. At the upper end, complex and aggressive deals, and back-leveraged debt, can be in the high twos, maybe even approaching three. In very special cases, we are looking at something now, about which probably a lot of people on the call know, that is large, complex and very unusual, and the pricing for it could even go higher if there is a need to bring in a lot of lenders.
MR. MARTIN: Is the up-front fee the same as the LIBOR spread? If the spread is 150 basis points over, the up-front fee is 100 basis points?
MR. EMMONS: Yes. Typically fees are equal to starting margins. There can be exceptions.
MR. MARTIN: Steve Greenwald, is it still the case that there is no LIBOR floor in the bank market?
MR. GREENWALD: That is correct. You still see a LIBOR floor in the term loan B market, but not in the bank market.
MR. MARTIN: How much movement do you expect in interest rates this year? Do you think they will remain where they are for the whole year?
MR. GREENWALD: I expect them to be pretty much where they are currently. I do not see anything that will move them a whole lot lower, and I do not see anything that will give banks the negotiating leverage to push them much higher.
MR. MARTIN: Tom Emmons, what are current loan tenors?
MR. EMMONS: Banks are trying to stay under 10 years for term loans. There are some exceptions where banks are willing to go to 18 years, but most of the market is under 10. A lot of deals today are short-term bridges to tax equity; we just talked about how tax equity volumes are increasing.
MR. MARTIN: What cash sweep should a borrower expect during the term of a bank loan?
MR. EMMONS: In a renewable energy deal, typically none, except there may be some special reason to sweep in a highly-structured deal, perhaps to achieve a particular metric such as a maturity date or some key ratio for a ratings purpose.
MR. GREENWALD: There are sweeps in some of the very largest deals, or perhaps not so much sweeps as dividend restrictions. For example, if you have a $2, $3 or $4 billion bank transaction, the banks will not want to let a lot of money go out the door to the equity while waiting for a deadline to be reached when a huge principal amount has to be refinanced. They will want incentives to encourage the borrower to complete some of the refinancing before any distributions can be made to the equity.
MR. MARTIN: What are current debt service coverage ratios for wind, solar and natural gas projects?
MR. EMMMONS: I can comment on the renewable piece of that. They are quite stable. Solar is 1.35x, and wind is 1.45x plus or minus, depending on the circumstances. Those are P50 coverage ratios.
MR. GREENWALD: On natural gas deals, the coverage ratio tends to be 1.35x at the low end.
MR. MARTIN: What are advance rates on construction debt in the current market: 85%, 80%, higher, lower?
MR. EMMONS: They can be up to 80% to 90% for renewables.
MR. GREENWALD: For other large industrial projects, they can be as low as in the 50% range, depending on the price risk that lenders are being asked to assume, all the way up to the mid- and sometimes high 70% range on the well-structured tolling arrangements where there is little-to-zero price risk being left to the lenders.
MR. MARTIN: Yesterday, the Swiss released the cap on the Swiss franc and let the franc float. It went up 39% in value against the US dollar. You both work for European banks. What effect, if any, will this have on the US project finance market?
MR. GREENWALD: I don’t see it having much effect.
MR. MARTIN: Tom Emmons, agree?
MR. EMMONS: It should make the US business more valuable to European banks because the dollars of income coming back are more valuable. However, most banks that play in this territory are international and they have US dollar funding desks to match assets to liabilities, so I don’t think it has much effect on how the European banks play in this market.
Term Loan B
MR. MARTIN: Let’s move to the term loan B market. JP Boudrias, do you have data on the term loan B volume in the power sector in 2014 and how that volume compared to 2013?
MR. BOUDRIAS: In 2014, we saw about $9 billion of term loan B compared to $11 billion in 2013. The 2014 deals were almost entirely power. There were 16 transactions in 2014 compared to 22 in 2013.
MR. MARTIN: Of those 16 projects in 2014, what percentage were merchant gas-fired powered power plants with power hedges in PJM and ERCOT?
MR. BOUDRIAS: Seven out of 16 are in that category.
MR. MARTIN: And the balance was what?
MR. BOUDRIAS: The balance was a mix of transactions such as Atlantic Power and ExGen Renewables that were holdco rather than opco transactions and renewable deals that tended to have a bit more contracted revenue.
MR. MARTIN: Earlier this week, a panel I moderated in New Orleans expressed the view that merchant power plants will prove financeable in 2015 not only in PJM and ERCOT, but also in the New England ISO. Do you agree?
MR. BOUDRIAS: That makes sense. When you look at the evolution of how the market has gotten comfortable with quasi-merchant transactions, the first deals were done in ERCOT because of good visibility on pricing and then moved to PJM where there is similar visibility and merchant projects can qualify for capacity payments. Obviously, one of the things that has changed in New England in recent years is that capacity prices are in much better shape than they used to be just a few years ago.
MR. MARTIN: For those listening who may not know what a term loan B loan is, it is basically debt papered as bank debt but sold to the institutional market.
MR. BOUDRIAS: From a documentation standpoint, it looks similar to bank debt, but borrowers in the term loan B market tend to have fewer occasions when one needs to come back to the lenders for approvals. It is not quite bond documentation as there are still financial covenants, but a B loan is written so that there will not have to be a lot future interaction between the holders of the term loan and the borrower.
From an execution standpoint, these are truly capital markets transactions. They will be driven by momentum and what is going on in the broader market, including the ability to place the paper in the secondary market.
MR. MARTIN: What do you foresee in the term loan B market in 2015?
MR. BOUDRIAS: It is interesting. When you look at the progression, 2013 saw a lot of refinancing volume. Obviously we entered 2014 with a lot of the refinancing that had to occur already out of the way. When we look at margins over the course of 2013 and 2014, the trend has generally been up. All of this suggests less refinancing activity in 2015. Deal supply will be entirely driven by either new assets that are being brought to market like transactions that had been financing in the bank market, but the sponsors are looking for more leverage or want to take a dividend. New construction and M&A may add to deal volume.
To sum up, in 2015 we expect largely similar volumes to what we saw in 2014. We do not expect significant growth in volume.
MR. MARTIN: Pricing for strong double B credits at this time last year seemed to be about 275 basis points above LIBOR with a 1% LIBOR floor and 1 point of original issue discount. For single B, I think the deals were pricing as much as 500 to 550 basis points over. What is the current pricing as we head into 2015?
MR. BOUDRIAS: It is comparable. Double B is probably around 350 over with the same 1% floor and issued at 99. Not all single Bs are created equal, but they are probably circling around 500 basis points over. This pricing is 75 basis points wide of where we saw levels at the end of 2013.
MR. MARTIN: So it is the opposite of the bank market where there has been consistent downward pressure on rates. What accounts for the increasing spreads?
MR. BOUDRIAS: One trend that we saw throughout 2013, but that was reversed in 2014, was the institutional bank mutual funds saw inflows for most of 2013. They went for 95 weeks in a row with positive inflows. Then in 2014, the trend went the other way. But interestingly, in 2014, we saw record formation of new collateralized loan obligation funds that, by and large, are the largest players in the market, probably accounting for 60% of demand in the institutional debt market.
The difference between the two is that mutual funds have no real cost of funds, since they are not raising funding to invest, whereas CLOs have a cost of funds and will take that into consideration in pricing.
So as the mix of investors moves from largely price-insensitive institutional investors to investors who have a bit of a floor, you would expect that would put upward pressure on margins.
Another thing to keep in mind is this is more capital markets driven. Obviously, there was a good amount of upheaval in late 2014 with falling oil and gas prices. About 20% of the leveraged finance market overall, including the bond market, is exposed to oil and gas borrowers. There has been a lot of selling pressure as the leveraged finance market has felt over exposed to energy; there is pressure to get out of that market and go someplace else.
As a point of reference, energy is about 10% of the S&P 500.
MR. MARTIN: Is a power hedge essential to financing a merchant power project and, if so, how long a term must it have in relation to the loan tenor?
MR. BOUDRIAS: We have not really seen a lot of pure merchant transactions. What we see are transactions where there is some form of price hedge. Probably somewhere around three to four years makes sense. If I tell you any shorter than that, the hedge would not provide any real benefit. It has been important to have a hedge at least in the early years to reduce price risk.
MR. MARTIN: Let’s move to project bonds. Jerry Hanrahan, the project bond market does not do well during periods when the bank and B loan markets are wide open and looking for product. Was that the story in 2014, and what do you see ahead for 2015?
MR. HANRAHAN: I think that’s right. There is lots of liquidity in the bank and other markets, and that has traditionally been where most of the project finance deals have gone. Those markets have dominated. There were no large syndicated deals to the private placement market in 2014, but people like ourselves were able to do a few transactions on a more direct and relationship basis.
That said, the project bond market remains very deep. There are probably more than 25 active players.
MR. MARTIN: Primarily insurance companies?
MR. HANRAHAN: That’s right. The project bond market can handle large transactions on the order of $500 million, maybe even up to $1 billion of capacity for a well-structured deal.
It is hard to say how much volume there will be in project bonds in 2015. We are not hearing a lot of chatter about deals in the pipeline, apart from one fairly significant deal that is in the market today.
MR. MARTIN: You need a spark like a fear that interest rates will rise. Project bonds are fixed-rate long-term debt, unlike floating-rate bank and term loan B loans.
MR. HANRAHAN: That’s right. Many banks are limited in terms of how long they can go, although there are some players that will go fairly long. The project bond market does not have any real constraints on tenor other than the underlying creditworthiness of the borrower and the contract that is the source of cash flows.
MR. MARTIN: Let me run down a list of what seem to be the main differences between bank and term loan B debt, on the one hand, and project bonds on the other. Tell me if any of these items is wrong.
Tenor: you said you do not have a limit on tenor, but the loan tenor can usually run as long as the power contract or perhaps one year short of the PPA term.
MR. HANRAHAN: The tenor generally matches the power contract. It used to be more common to have the loan run just short of the power contract term, but these days, the term of the debt and the PPA term generally match.
MR. MARTIN: There are no up-front fees because the economics are fully baked into the spread. The spread is priced to Treasury bonds rather than LIBOR. Ratings may be required for widely-syndicated deals, but not for the private or direct placement deals that you have been discussing. Another key differences is make-whole payments are required if the bonds are repaid ahead of schedule. Such payments are not required in the bank market. The project bond market takes construction risk, but will charge a commitment fee on undrawn capital.
MR. MARTIN: Are there other differences besides the ones I mentioned?
MR. HANRAHAN: Adding to what you said, ratings are not required, but the project bond market is investment grade-driven. You might see some small high-yield issuances, but the market is overwhelmingly investment grade, and that is a big d