Cost of capital: 2021 outlook
Many developers struggled during 2020 to find tax equity. Interest rates remain at historic lows. The 30-year treasury bond rate was up 24.8% through February 17 compared to year end 2020. It still stood at only 2.06%.
The cost of capital is a key factor in the price at which companies developing new power projects can afford to offer the electricity. Several thousand people registered to listen to a call among a group of veteran financiers in mid-January to learn whether finding tax equity will be any easier and hear views about the likely cost of capital this year. The following is an edited transcript.
The panelists are Jack Cargas, managing director and head of tax equity origination at Bank of America, Yale Henderson, managing director and head of energy investments at JPMorgan, Ralph Cho, co-head of power and infrastructure finance for North America for Investec, Jean-Pierre Boudrias, managing director and head of North American project finance for Goldman Sachs, and John C.S. Anderson, global head of corporate finance and infrastructure for ManuLife. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Yale Henderson, what was the tax equity volume in 2020, and how did it break down between wind and solar?
MR. HENDERSON: It was between $17 and $18 billion, split roughly one third solar and two thirds wind. We expect the ratio between wind and solar to move even more in the direction of solar in 2021.
JPMorgan set a record in the amount of money it put into the renewables market as did, I believe, Bank of America.
MR. MARTIN: That is a remarkable figure, given that we were predicting $15 billion on this call last year. Are those numbers based on commitments made or closed deals during 2020?
MR. HENDERSON: It is a broader number. It is based on commitments as well as funded deals. There were a lot of deals that people hoped to have closed by year end, but that slipped into early 2021 and that people are still working hard to close.
The only commitments included in the number are commitments to close and fund by year end 2020. It includes such commitments where the deal slipped past the funding deadline. It does not include commitments that were originally for 2021 closings.
MR. MARTIN: To put these numbers into perspective, 2019 was a $12 to $13 billion year, correct?
MR. HENDERSON: It may have ended slightly higher than that, but that is close.
MR. MARTIN: Tax equity volume was $12 billion in 2018 and $10 billion in 2017. What volume do you expect this year?
MR. HENDERSON: It definitely could be in the $15-to-$18 billion range again this year, especially considering that large offshore wind projects and carbon sequestration transactions may be coming to market.
You also have to take into consideration that utility-scale solar projects are getting bigger now that they include battery energy storage systems.
MR. MARTIN: Jack Cargas, does $15 to $18 billion sound right for the coming year?
MR. CARGAS: It does. The US Energy Information Administration is predicting close to 40,000 megawatts of new wind, solar and storage capacity additions in 2021. That implies robust demand this year. We expect the main market driver will once again be supply of capital. Our prediction is that we will see similar volumes overall to what we saw in 2020.
MR. MARTIN: Yale Henderson, what percentage of the typical solar project is tax equity as we enter 2021, and what is it for wind?
MR. HENDERSON: For solar, it is 35%, plus or minus 5%. For wind, it is 65%, plus or minus 10%.
MR. MARTIN: Jack Cargas, many developers reported difficulty last year finding tax equity. On our two calls together last January and March, both of you were of the view that it would be business as usual in 2020, at least for your two banks. Yet we held two other calls, with five tax equity investors each, in May and July where some of the investors had dropped out of the market.
How would you describe current market conditions for developers wondering they will be able to find tax equity this year?
MR. CARGAS: It will be a very challenging market. Even if we hit the same volume we hit in 2020, there is so much demand for tax capacity that one wonders whether demand will out-strip supply.
The tax equity supply is difficult to forecast in the face of volatility in earnings and uncertainty around the future direction of the economy in a COVID-19 environment, the eventual scale of loan-loss provisions by banks and possible tax law changes.
MR. MARTIN: Yale Henderson, what do you say to developers who are below the first tier and who had trouble last year finding tax equity? Will they find it any easier this year?
MR. HENDERSON: Will it get easier? No. Are there opportunities for, as you said, non-first-tier but established developers to raise tax equity? Yes.
New investors enter the market to fill the void when opportunities exist. We heard of a few investors at the end of last year and early this year who are stepping up their investments, particularly in solar. Any void for capital is usually filled at some level. It may not be any easier this year, but you should be successful if you keep working hard at it.
MR. MARTIN: Get started early in the year is the best advice.
Many listeners patch into this call to get a better feel for what cost of capital to assume when bidding to supply electricity. I know you are both reluctant to talk about actual yields, so let me do it. At the start of last year, we were seeing flip yields in the range of 6.25% to 6.8% in utility-scale wind and solar tax equity transactions. Some really big developers told us they were being offered sub-6%.
Toward the end of last year, we were seeing pricing more in the 7% to 7.25% range for flip yields.
Yale Henderson, in which direction do you expect the cost of tax equity to move this year?
MR. HENDERSON: Nine times out of 10, if not 99 times out of 100, people are comparing apples to oranges when they talk flip yields across projects. There are too many variables that factor into the economics of partnership flip deals.
That said, barring any substantial change in market conditions, I don’t see any reason why flip yields would change dramatically from where they were last year.
MR. MARTIN: Jack Cargas, let me ask you a different question because I suspect I will get the same answer from you on that one. You suggested before the call that there were newfound challenges in deals during 2020. What are they?
MR. CARGAS: There were at least half a dozen of significance. Let me start with two of them. One was insurance and another was force majeure.
Property and casualty insurance is becoming more challenging to obtain. The problems are lower coverage, more restrictions, higher deductibles and higher pricing. This has made tax equity investors and lenders much more cognizant of where projects are located. They are less likely to want to invest in projects in areas where hail is common or that are prone to hurricanes, earthquakes or flooding.
They want additional structural protections in the tax equity partnership documents, such as assumptions about insurance payouts in the sizing case, different cash sweep or step-up mechanisms or perhaps more reliance on corporate fleet-wide insurance programs to spread the risk and the coverage and costs.
In 2020, many force majeure notices were issued to sponsors by equipment suppliers and construction contractors. Many of the notices appeared to be defensive in nature and blamed COVID. Many of the claims were rejected by sponsors.
It was unclear in most cases what claimants were trying to get out of these notices — delayed delivery dates, decreased liquidated damages? Many claims just became an unnecessary distraction. The question remains what happens with these force majeure notices going forward? Is COVID-19 a pre-existing condition and, therefore, not a subject for force majeure? It is something that we are watching closely.
MR. MARTIN: Yale Henderson, anything to add to that list?
MR. HENDERSON: Yes. We are concerned about the size of the tax basis step-ups that we are seeing sponsors demand in their requests for proposals from tax equity investors.
We also see a continuing underestimation of electricity basis risk by sponsors in the base case models they send us. This has an effect on the ultimate revenue profiles for projects. We encourage them to hire competent consultants to help with a realistic forecast and then to make sure it is properly reflected in the model.
Batteries will obviously be big this year, particularly as developers see opportunities to use them to arbitrage peak pricing and add revenue. Getting credible estimates of what those ancillary revenues will be, how long they will last and at what level will be important.
Finally, commitment periods are getting longer, and that is contributing to some of the issues with tax equity supply. The market is moving toward commitment periods as long as 18 months to two years. However, when tax equity gets committed that far in advance, it puts stress on the ability to handle current market opportunities. It may be harder for sponsors that do not have deep banking relationships to compete for tax equity in such a market.
MR. MARTIN: Jack Cargas, are you looking at carbon capture?
MR. CARGAS: Yes. It is nice to see that the IRS issued the final regulations on section 45Q tax credits in December. Carbon capture projects will be in direct competition for tax equity with offshore wind, onshore wind, utility-scale solar, residential solar and other types of renewable energy projects. We are watching the carbon capture market develop and are beginning to see some real opportunities.
MR. MARTIN: Yale, are you looking at carbon capture as well?
MR. HENDERSON: Yes. We expect to make an investment in such a project in the not-too-distant future.
MR. MARTIN: Jack, have your investment parameters changed as we enter 2021 and, if so, how?
MR. CARGAS: Yes, in at least three ways. We examine the overall bank relationship, both historical and prospective, with our sponsors. We look hard at project quality and geography. And we focus on the sponsor’s ability to execute the trade efficiently. We delivered on every one of our tax equity commitments at Bank of America in 2020, and we expect to do the same in 2021.
MR. MARTIN: These parameters do not seem like a change. Has anything changed?
MR. CARGAS: There is more focus on the overall bank relationship.
MR. MARTIN: Yale, has there been any change in your investment parameters?
MR. HENDERSON: No. We scroll through a list of factors when deciding whether to pursue a particular transaction. The items on that list have not changed in a meaningful way in the last year.
MR. MARTIN: I think you were expecting to end up with about $4.5 billion in total tax equity investments last year. Is that where you in fact ended up?
MR. HENDERSON: We exceeded that number.
MR. MARTIN: Jack Cargas, where did Bank of America end up?
MR. CARGAS: We also exceeded that number.
MR. MARTIN: Are there any other noteworthy developments in the tax equity market?
MR. CARGAS: We completed our first large combined-resource partnerships in 2020. Combining wind and solar makes a lot of sense due to complementary resource characteristics and complementary tax credit characteristics. Sponsors like it for those reasons and because it can make for better upstream financing packages or better sponsor cash equity sale packages.
MR. MARTIN: Does that mean you have a tax equity partnership where the tax equity investor is claiming both investment tax credits and production tax credits?
MR. CARGAS: That’s right.
We have done more than one of those partnerships. We also completed our first large-scale battery partnership in 2020, so that transaction grammar is in place, too.
MR. MARTIN: Yale, other noteworthy developments?
MR. HENDERSON: We did transactions last year with the same profiles.
COVID forced investors to become more efficient at executing transactions. One example is how they do engineering diligence. When our engineers can watch a time-lapse video of a foundation pour, they feel they have a better understanding how things are going, and it increases our comfort level that things are being done appropriately at every site and on every foundation pour and every turbine built. This is just one of many ways we are all having to adapt because of restricted travel and lockdowns, but that are leading to efficiency gains in how investors transact.
MR. MARTIN: So there is an upside.
Let’s move to Ralph Cho on bank debt. Has the bank market settled back into its pre-COVID pattern and, if not, what are the lingering effects?
MR. CHO: Last year was a roller-coaster year. It started off pretty strong during the first quarter. It quickly came to a halt in March and April when everyone started working from home.
I remember having a call just like this with you around that time when everything was falling off a cliff. There was a spike in bank lending costs. Spreads increased by 25 to 50 basis points. The banks at that point were just basically wrapping up deals that were already in process without making new commitments. Any bank that was wider than that level was effectively shut out.
But the bank markets are resilient. By summer, funding costs had fallen back in line with pre-COVID levels and, in some cases, they had even improved.
As for lingering effects, the bank markets are still liquid, but choppy. Not all the capital sources with whom we work are back at the table. For example, we have not seen the South Korean lenders come back at the same level of appetite as pre-COVID. Credit committees in general are still sensitive to COVID-related risks. Construction risk, demand risk and operating risks are all being analyzed carefully.
MR. MARTIN: What was the deal volume in the North American project finance bank debt market last year compared to 2019?
MR. CHO: It was better than expected. The latest preliminary data from Refinitiv — and that will be finalized at the end of the month — suggest that North American bank volumes were up more than 12% from 2019. Total volume was $69.5 billion for 2020 versus $62 billion in 2019. Given that the market was shut down during March and April, this is a remarkable result. The total deal count was around 213.
MR. MARTIN: There were 220 deals in 2019.
MR. CHO: Correct, so down slightly.
MR. MARTIN: How many active banks are there currently in the market?
MR. CHO: We saw roughly 50 to 70 lenders last year, with perhaps 30 to 40 highly active.
We have heard various reasons for this, including that people were uncomfortable about the potential impact of COVID in the US. Some lenders with long underwritten positions have been unable to sell. Some lost money from loans that have defaulted. Another issue has been the difficulty doing site visits and other physical due diligence.
Lenders are more likely to be able to participate in refinancings than in wholly new transactions.
We have also seen a number of tier-2 and tier-3 retail banks go on pause for now because their credit committees are researching their portfolios and are reluctant to add new projects during the pandemic.
This loss of liquidity was counterbalanced by the entry of some newer players in the form of credit and debt funds, albeit coming in at a slightly higher cost of capital. My expectation is we will see some of the sidelined capital creep back into the market this year.
MR. MARTIN: In the last two years, there were 80 to 100 banks and grey-market lenders chasing deals, so there has been at least a 30% drop in number.
What is the current spread above LIBOR for bank debt?
MR. CHO: We saw a lot of deal flow come back like crazy in the second half of last year. Plain-vanilla loans — and I am including back-levered renewables deals — are pricing at LIBOR plus 125 to 137.5 basis points. Short-term construction bridge loans are probably pricing around LIBOR plus 90 basis points. Depending on the size, you could probably go tighter, but 90 basis points is where most of the action is currently. Construction bridge loans that could go up to 24 months are pricing at a slight premium at 100 to 125 basis points over LIBOR. Greenfield quasi-merchant gas projects are probably going out at LIBOR plus 350.
The low cost of funds for banks is keeping their senior pricing tight, as you can see from the numbers. Grey-market lenders do not have the same flexibility. They just try to take a little bit extra risk to get their limited partners the returns they have been promised. Returns for grey-market lenders can vary anywhere from 6% to 12%, depending on the type of debt fund.
Grey-market lenders are buying up stretched senior and holdco paper. If you are a borrower looking for this type of capital, the sweet spot is probably around LIBOR plus 400 to 450 basis points. There are always exceptions where a borrower may end up with spreads a little tighter or a little wider, depending on the project and how much it is trying to borrow.
MR. MARTIN: The 400 to 450 basis points is for debt that is subordinated to other, senior or back-levered debt, correct?
MR. CHO: Yes.
MR. MARTIN: Is there a LIBOR floor currently in the bank market?
MR. CHO: Not really. If there is one, it would probably be 0%. There is a LIBOR floor in most grey-market loans of 1%.
MR. MARTIN: What upfront fee should one expect on a bank loan?
MR. CHO: Such fees generally range anywhere from 100 to 200 basis points in the bank market, based on whether the loan is wholesale or retail. We usually tier the fee based on the size of commitment and whether the loan is being underwritten and syndicated. If the loan will be syndicated, then that tends to push the fee out to 200.
MR. MARTIN: Are there commitment fees on top of that?
MR. CHO: Yes. A commitment fee of 50 to 75 basis points is charged on the undrawn loan commitment or unused letter-of-credit commitment in place of the full LIBOR plus margin on that part of the debt.
MR. MARTIN: What are current debt-service-coverage ratios for wind, solar and gas-fired power projects?
MR. CHO: For wind, they are generally 1.35 times the P50 revenue forecast. Solar is probably tighter at 1.25 times P50. Solar projects have a lower standard deviation on resource forecasts, so the forecast is a little more reliable.
In the past, lenders usually only credited contracted cash flows for purposes of debt sizing. In order to compete today, lenders are crediting up to five years of post-PPA revenue. Thus, even though they are taking some merchant exposure on the back end, commercial banks are still pricing as if these were plain-vanilla loans. That tells you something about the competition for deals.
To be competitive, the debt on contracted gas-fired assets would have to be sized about 1.3 times revenue available for debt service over the life of the power contract. There are not many contracted gas-fired assets coming to market, so any such deals attract a lot of competition. Quasi-merchant gas deals are a little more complicated. We size the capacity and energy payments at around 1.5 times.
We have been using flat-lined capacity forecasts in areas like PJM and New England. We’ve seen increased usage of the cross-commodity netback hedges. We size these cash flows at around 1.5 times, based on a conservative case. Lenders are open to giving credit on conservative merchant energy revenue forecasts at around 2 to 2.5 times. One issue is how much of the debt principal will remain to be repaid at maturity on the bank loan. The answer depends on the location, the age of the project and the technology.
MR. MARTIN: Has there been any change in the typical loan tenor since last year?
MR. CHO: No. Typical loans are structured as five- to seven-year mini-perms, particularly for refinancings and some acquisition debt. That is construction plus five years if there is a construction element to it.
We have seen tenors for some plain-vanilla financings go over 15 years, assuming a long-term power purchase agreement, especially in the renewables sector.
We have heard rumors that some Canadian renewables borrowers can put pressure on their banks to go up to 19 years by threatening to take the debt to the project bond market. However, these offers are more like unicorns; they are hard to come by. They are probably reserved for tier-1 relationship borrowers.
MR. MARTIN: I was going to ask if you have seen any change in appetite among banks for different types of projects — for example, quasi-merchant projects, projects with corporate PPAs or CCA contracts, community solar projects, standalone storage facilities — but I suspect the answer is multiple banks will be interested.
MR. CHO: There is strong interest from banks in supporting all ESG-class assets. Appetite for such assets has increased at every level of the capital stack. ESG investors are willing to take lower returns and higher risk for such assets. They see ESG as the primary driver, and economics are the secondary driver.
There is diminished appetite for merchant gas projects in PJM where the capacity auctions have been delayed a couple times and spark spreads are pretty much crap. However, if borrowers are willing to take a conservative view on capacity forecasts, banks have an appetite to lend.
MR. MARTIN: Are there any other noteworthy trends as we enter 2021?
MR. CHO: Yes.
ESG will remain front and center, especially for lenders across the capital stack and especially when it comes to the energy transition. These financings attract a lot of lenders: commercial banks, credit funds, private equity investors. It clearly shows because you see the returns being beaten down. It will be interesting to see whether more capital is willing to fund before notice has been given to proceed with construction, especially at a friendly cost of capital.
Ted Brandt from Marathon Capital talked on a panel you moderated last week at the Infocast Projects & Money conference about leveraged equity returns coming in at something like 6% on ESG projects. That is remarkable. When we take syndicated deals to market, an ESG asset gets twice the interest.
Digital infrastructure is also going to be hot. My UK counterparts have been active in this market. We polled a lot of bankers about the sectors on which they want to concentrate in 2021. Our polls show 22% want to be in digital infrastructure and 57% say ESG.
PJM activity should hopefully pick up this year after being quiet last year. Two capacity auctions are expected finally this year. Some developers with existing projects are hoping to refinance this year.
Lastly, I think that capital sources will remain frothy. South Korean lenders sat largely on the sidelines last year. I think they will move slowly back into our system. Some of them are sending more bankers from Seoul to New York. They are here now physically and beefing up their local presence. That is a sign they want to be more active here.
Don’t forget about capital that limited partners are investing in blind credit funds. We expect to see more of that this year.
Term Loan B
MR. MARTIN: Let’s move next to Jean-Pierre Boudrias from Goldman Sachs and the term loan B market. Term loan B debt is debt using bank papers, but placed with institutional lenders. It tends to be lighter on covenants. It is often used for riskier projects.
J-P, the term loan B market reacts more quickly than the bank market to changing market conditions. Shortly after the COVID lockdowns started last March, the average B loan debt instrument was trading at only 76¢ per dollar of face amount, which implied a 625-basis-point spread over LIBOR and about an 11% coupon rate. Loans to independent power projects held a little more of their value, maybe 80¢ to 83¢ on the dollar. The market was pretty deeply dislocated. Has it recovered fully?
MR. BOUDRIAS: The B loan market has recovered. The investment-grade bond market was the first to recover. The loan market took a little longer, but the S&P LSTA Index shows the average B loan trading at 97.5% of face amount. That works out to around a little over 400 basis points over LIBOR.
When we had this call last year, about 60% of loans were trading at par or above par. Obviously, that went to zero in the March and April time frame and stayed there for a few months. Now we have slowly recovered and are now at the 40% mark. As a result, you are seeing the first wave of re-pricings coming to market across various sectors.
MR. MARTIN: That is 40% of B loans are still trading below par?
MR. BOUDRIAS: No, 40% are trading at par or above.
MR. MARTIN: Got it. What was the term loan B volume in the North American power sector in 2020, and how did that volume compare to 2019?
MR. BOUDRIAS: In 2020, we saw seven transactions for a total of $5.5 billion. In 2019, volume was about $4.6 billion. It was a small increase, but it was probably transaction-driven in terms of what deals came to market and when.
MR. MARTIN: What types of deals were the seven?
MR. BOUDRIAS: There was only one acquisition financing. Most of the rest were refinancings or amend-and-extend transactions, which means amending the existing debt papers to push the maturity out by a year or two. There were one and a half repricing deals because one of the deals was an amend and extend, but also got repriced. It was launched as a repricing originally.
MR. MARTIN: Were any of these deals renewables?
MR. BOUDRIAS: There was one renewable energy transaction that was a refinancing late last year.
MR. MARTIN: What volume do you expect this year?
MR. BOUDRIAS: We expect about $3 billion to go to market to refinance existing transactions. We expect to see deals that will get repriced, so we will get some volume there. There are also acquisition financings expected to come to market. My suspicion is that we will probably have a $9 to $10 billion year in 2021.
MR. MARTIN: Pricing a year ago for strong BB credits was about 350 to 375 basis points over LIBOR. You were expecting at the start of the year for pricing to fall below 300 basis points, but that obviously did not happen after COVID hit. A single B borrower could expect to pay 400 to 425 points over LIBOR. Where do you see rates today?
MR. BOUDRIAS: We probably ended 2020 where we started, but since the beginning of 2021, we probably gained a bit.
A BB credit is probably pricing around 325 or 350 basis points over LIBOR today with an ability to outperform if trends continue the way they are. With a single B credit, the range is probably wider at 375 to 425.
There has been some differentiation in credit. When I talk about the average bid of 97.5% for the outstanding paper on single-asset power deals, it is important to understand there is a range. Some price above this. A number have not recovered yet and are still in the mid-90% range. The power market where the project operates is an important factor.
MR. MARTIN: When you say “outperform,” from whose perspective are you speaking?
MR. BOUDRIAS: The borrower. I think there is a possibility that spreads will narrow as we move further into 2021.
MR. MARTIN: B loan debt has been sized historically at six to six and a half times projected EBITDA with at least 50% repayment of loan principal required over seven years and a loan-to-value ratio of 75%. Has there been any change in these metrics?
MR. BOUDRIAS: Not really. We tend to see these metrics in acquisition debt. There was only one acquisition financing last year.
MR. MARTIN: What are the metrics for other types of B loans?
MR. BOUDRIAS: It will vary based on ratings aspirations, but we tend to see four to six times leverage for BB and B, respectively.
MR. MARTIN: Loans as small as $225 to $250 million can be placed with B loan lenders, but there is a steep drop off in liquidity once a loan size falls below $500 million. One of the new trends you cited last year was the arrival of direct lenders who are doing deals as small as $125 to $200 million. Are they still in the market? Are there other new trends as we enter 2021?
MR. BOUDRIAS: The direct lender trend is still there. I don’t think we really see any other new trends. Obviously, as volume builds throughout the year, we may see other new developments.
I would like to remind listeners the total B loan volume in our sector is about $17 billion out of $1.2 trillion for the B loan market as a whole, so it is a rather small segment. Often, our sector benefits from trends that start in other market segments and make their way to the power world.
MR. MARTIN: Let’s move to John Anderson and project bonds. Project bonds are long-term fixed-rate loans. The loan tenor can be as long as 30+ years. The rates are fixed for the full duration. The bonds are issued at a spread above current treasury bond rates. Is it 10-year or 30-year treasury bonds?
MR. ANDERSON: The 10-year treasury is the usual benchmark. For a project with a 20-year power purchase agreement, the debt will have an average life of about 12 years, so the 10-year treasury is the best place to focus.
MR. MARTIN: Last January, you said contracted projects were clearing at spreads about 175 to 190 over 10-year treasuries. That translated into a coupon rate of about 3.5% to 3.75%, but by late March after the COVID lockdowns, the spreads had jumped by 200 to 300 basis points. The market has since settled. Where is it today?
MR. ANDERSON: Good news for borrowers in this area. On the spread component, we have really come full circle, back to the 175 to 190 range, and maybe even slightly lower in the US in certain situations. The really nice thing for borrowers is that base rate, the 10-year treasury, has come down from just under 2% a year ago to just over 1% today. Put all of that together into an all-in interest rate, and the widest you would have paid a year ago was a coupon rate of more than 4%. Today, you can get 3% and maybe a touch inside.
MR. MARTIN: Is COVID having any lingering effects?
MR. ANDERSON: Despite the K-shaped recovery and the uneven impact of COVID on the economy, infrastructure, power and clean energy are really motoring ahead. These are essential industries. There is strong demand from investors.
People have talked on this call about some of the remote working techniques to which they have had to adapt. That is true in the project bond market as well.
Insurance companies and financial investors drive the investment-grade bond and private placement markets. ESG and climate change are dominating the conversations today. We see that in the broader bond market, too. If something has a green tag on it, people will definitely look at it with greater interest. We don’t see a premium being paid for green paper, but investors definitely are interested in it.
MR. MARTIN: Let’s talk about volume. The syndicated US dollar denominated project bond market was stable at $100 billion a year in each of 2018 and 2019. What was it in 2020?
MR. ANDERSON: It was at least that or slightly higher. That’s because the clean energy transition continues apace, and we were not disrupted like speculative-grade lending or some other sectors of the economy.
Sometimes we talk about project finance and its share of the broad market. That measure is a bit of a head fake. The project finance share of the broad market went down because the broad market expanded so much. Thus, if you looked at the US dollar investment-grade bond market last year, it went from $1.1 trillion in 2019, which was a pretty good year, to $1.8 trillion last year. The broad market was up by 63% as corporates went after liquidity. We had issuances by such borrowers as hospitals, universities and foundations that do not normally come to market. The denominator was a lot bigger, but infrastructure and projects were still a great place to invest. Maybe they were a smaller share because other issuers were tapping into emergency funding.
MR. MARTIN: What was the numerator for projects and infrastructure?
MR. ANDERSON: We are not a market maker, so I don’t track that, but as an investor it felt like we were up in volume similar to the 12% increase that Ralph Cho said he saw last year in the bank market.
MR. MARTIN: You have said in the past that 19% to 20% of the market is infrastructure and projects, including power. How many syndicated deals are in the pipeline today at the start of the year?
MR. ANDERSON: We see between three and five deals in the market at this point which is a little lighter than we saw at this point last year. We had such a low cost of debt last year that maybe people were front running the market a bit.
MR. MARTIN: You are a direct lender. You don’t place deals in the syndicated market. Project bonds work for direct loans as small as $25 million, while loans in the syndicated market need to be at least $250 million. Has COVID affected either metric?
MR. ANDERSON: That has been pretty stable. You can find a lender to work with you on something bilaterally at $25 to $50 million, but to get a good syndication going, you probably do need to be at least $250 million.
In between, your arranger will help you with a club-type of approach where maybe if you are raising $100 million, the arranger will go out to three or four investors and your direct lender, like Manulife, will act as the anchor. Most of the individual lenders who will do $25 to $50 million as part of a club will also do $100 or $150 million with you bilaterally.
MR. MARTIN: Let’s run down the main differences between project bonds and other types of debt quickly. You deal with insurance companies and other institutional lenders as opposed to the banks. Project bonds generally have the same tenor as the power purchase agreement. There is no up-front fee for a project bond because the economics are baked into the spread. Ratings may be required for widely syndicated deals, but not for private or direct placements. Make-whole payments are required if bonds are repaid ahead of schedule. Such payments are not required in the bank market, but there may be a prepayment penalty. The project bond market takes construction risk and will charge a commitment fee on drawn capital. Is all of this accurate?
MR. ANDERSON: It is. We are the long cheap money so we really shine when you have a long-tenor PPA. People will work on shorter-duration bonds, as well. There is strong investor demand to deploy this year. Infrastructure portfolios held up very well in 2020. We were experiencing significantly lower default rates than other sectors of the economy, so that is a tailwind for us as we move into 2021.
MR. MARTIN: Are there any other noteworthy trends as we enter 2021?
MR. ANDERSON: The tailwind from the government. Investor interest in ESG transactions is also a tailwind. Investors have a lot of capital this year to deploy. Maybe we will see some tightening of spreads along the way.