A record number of banks and grey market lenders are chasing projects at the start of 2022, keeping downward pressure on interest rates despite rising inflation. The tax equity market did a record volume in 2021. However, there are concerns about its ability to handle demand as giant offshore wind farms and carbon capture projects start coming to market. Supply-chain difficulties that are delaying projects helped to mitigate demand in 2021. A direct-pay alternative and an option for solar projects to claim production tax credits will be needed to take pressure off the market longer term.

Developers are facing an unusual number of headwinds at the start of 2022, including broken supply chains, inflation, Customs seizures of solar panels, skyrocketing casualty insurance premiums, tax law uncertainty and rising domestic and international political tensions.

More than 3,300 people registered to hear a panel of veteran financiers talk in mid-January about what to expect in the year ahead. The panelists are Jack Cargas, head of origination on the tax equity desk at Bank of America, Rubiao Song, managing director and head of energy investments for JPMorgan, Ralph Cho, global co-head of power and infrastructure finance for Investec, Max Lipkind, managing director and head of Americas leveraged finance origination for Credit Suisse, 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.

Tax Equity

MR. MARTIN: Rubiao Song, what was the tax equity volume in 2021, and how did it break down between wind and solar?

MR. SONG: The total volume in 2021 was $19 to $20 billion, roughly split 50-50 between wind and solar. If we compare that to 2020, it represents a small decrease in wind and a large increase in solar.

MR. MARTIN: To put these numbers into perspective, renewable energy tax equity volume was $17 to $18 billion in 2020 and $12 to $13 billion in 2019, so the volume continues to grow, but the rate of increase slowed. Jack Cargas, do you agree with those numbers?

MR. CARGAS: Yes. Our estimate for 2021 was $19.5 to $20 billion. We also see the market leaning more heavily toward solar. Our investments at Bank of America were roughly 60-40 wind and solar, but we believe the overall market was roughly 50-50.

We are expecting another $20 billion in 2022, plus or minus 5%.

MR: MARTIN: Rubiao, what is your expectation for 2022?

MR: SONG: I agree with Jack. Demand for tax equity remains exceptionally strong, particularly in the utility-scale solar and solar-plus-storage sectors. However, the volume for the year ahead is harder than usual to predict because of the many challenges, such as tax law uncertainty, COVID, trade tensions and supply-chain issues. It could be the first down year for tax equity in many years.

MR. CARGAS: We don't expect a down year. The market size has roughly doubled over the last five years. It was about $10 billion as recently as 2017. It has been growing steadily.

MR. MARTIN: How much tax equity did Bank of America invest last year?

MR. CARGAS: I can't give a figure, but it is not an exaggeration to say that 45% to 50% of the 2021 tax equity is represented on this panel.

MR. SONG: I think we did about the same volume as in 2020, so that is $5+ billion in new commitments executed in 2021. We would have done more if not for supply-chain delays.

MR. MARTIN: One message from past calls is that most tax capacity is already spoken for by the summer. It is only January, but can you say what percentage of the tax equity you will invest this year has already been committed?

MR. CARGAS: Our message to sponsors last year about 2022 projects was to come to market early. Many sponsors were in a position to comply, and so we have been able to fill out a significant portion of our book for wind, solar and storage. Roughly 80% of our 2022 tax equity is already allocated. That is not necessarily committed through executed term sheets or documents, but circled.

MR. SONG: It is hard to state a percentage. Many deals were delayed into the first quarter of 2022, so that is a significant claim on 2022 capacity. I think 2022 tax capacity is going to be a very scarce commodity given the demand from the solar market.

In general, $10 billion in solar tax equity would require about $10 billion in current year tax capacity, but $10 billion in wind tax equity only requires about $1 billion in current year tax capacity because the tax credits on a wind project are spread over time. That is a huge difference.

How much of the market the scarce 2022 tax capacity will be able to cover will be influenced by the fate of the "Build Back Better" bill in Congress. If solar developers can claim production tax credits and there is a direct-pay alternative to tax credits, it will allow tax capacity to be spread over a larger number of deals.

MR. MARTIN: Last year, you both said that tax equity is roughly 35% of the capital stack for the typical solar project, plus or minus 5%, and it is 65% for the typical wind project, plus or minus 10%. Have those percentages changed since last year?

MR. CARGAS: No. The capital stack percentages could change if some of the "Build Back Better" provisions are enacted.

MR. MARTIN: Let's talk about factors that affect the cost of tax equity. I know you are reluctant to talk about flip yields. Flip yields seemed to us to have fallen in 2020 into the low-to-mid 6% range for the best projects and a few sponsors even saw tax equity yields below 6%. In 2021, they seemed to be moving up and were more likely to be in the high 6% to mid-7% range.

The cost of tax equity is a function of demand and supply. It does not move closely with interest rates.

Do either of you expect supply to be a constraint at your banks? You both have seemed to have unlimited tax capacity. The constraint has been people to do the deals.

MR. SONG: The traditional tax equity base will not be able to absorb the many billions of tax credits on renewable energy projects in 2022 and beyond. A big portion of the tax capacity is already spoken for before the year even begins, and there is competition for the same tax capacity from the low-income housing market.

It is more critical than ever for the industry to attract more untraditional investors, especially if the Build Back Better bill is not enacted. A serious supply-demand imbalance will remain, and there are other headwinds this year like rising interest rates and more stringent regulatory capital requirements for banks.

MR. MARTIN: On the demand side, a potential future issue is the number of giant offshore wind and carbon capture projects that will also need tax equity.

Jack Cargas, do you expect more than one offshore wind tax equity deal to close this year?

MR. CARGAS: We do not. We see numerous offshore transactions on the horizon, but most of those deals are two to five years away. We expect to see one offshore wind tax equity transaction close in 2022.

Supply-chain issues and Customs seizures of solar panels helped to moderate demand in 2021.

MR. MARTIN: Are you aware of any carbon capture tax equity deals that have closed?

MR. CARGAS: We are aware of one or two small carbon-capture-and-storage transactions, but the larger deals look like they are still a couple years away.

MR. SONG: We expect several large carbon capture projects to get done in 2022 that are already trapping CO2 emissions and have existing pipelines and storage sites.

MR. MARTIN: Are you aware of any that have closed?

MR. SONG: No.

MR. MARTIN: Inflation hit 7% in the latest consumer price index report last week. The Fed could start increasing rates as early as March. Is this affecting the tax equity market?

MR. CARGAS: Not a lot. Inflation may have more of an effect on project costs than on financing costs. If inflation leads to higher equipment and construction costs, the already thin developer margins may be that much more squeezed, and developers will need relief on the revenue side or there will be some really nettlesome project economic issues.

As for tax equity, there could be some internal spread compression due to rising costs of funds, but I think tax equity investors will live up to the commitments they have made as priced.

MR. MARTIN: There were a lot of challenges last year. How are you addressing supply-chain delays and Customs seizures of Chinese solar panels in deal papers?

MR. SONG: We have seen both affect construction timelines. Some sponsors are better equipped to deal with these issues than others because of their market presence and their relationships with suppliers. It is more important than ever for developers to be realistic about project timelines. They need to build in an additional cushion, plan for delays and cost increases, and be sensible about when to approach tax equity because a tax equity commitment carries significant cost.

MR. MARTIN: Jack Cargas, are there any special provisions that are put into documents to address these risks?

MR. CARGAS: We are focused on quality assurance and quality control standards for equipment supply and delivery, especially in light of the forced-labor concerns. We want a clear line of sight into the supply and delivery of solar panels and other equipment, including into the country, through Customs and to the project site. We need to have absolute certainty about those things before the first funding.

MR. MARTIN: Another challenge is tax law uncertainty. The Build Back Better bill is stalled currently in Congress. Biden could make another push before his State of the Union address to Congress on March 1. Suppose it passes and projects end up with higher tax credits than were expected when the deal papers were signed. What should happen in such situations? Does the tax equity fund more?

MR. SONG: The devil is in the details. We start to analyze the potential economic impact on deal terms with sponsors before the commitment is signed.

MR. MARTIN: I imagine you are not letting people walk away from the tax equity deal if direct pay suddenly becomes an option after the deal has been fully negotiated?

MR. SONG: That's right. We think tax equity can be efficient even in a scenario where a direct payment is chosen in place of tax credits.

MR. MARTIN: Jack Cargas, if the tax benefits turn out to be larger than expected, of course the extra tax benefits will be taken into account for tracking when the flip yield is reached, but is there also some adjustment in the amount of tax equity invested?

MR. CARGAS: That is how the tax equity market has responded to such changes in the past, and we expect that is how it will respond again. I think the tax equity market has generally dealt very well with change-in-tax-law provisions in the past. This has become a core competency.

The problem with the Build Back Better bill is that it is so complex and nuanced. It is not particularly susceptible to contingency planning. You cannot document comprehensive treatment for the many, many scenarios possibly emanating from the bill. There are too many issues in play, and the outlook for the bill itself is uncertain.

That said, as a general matter, if there is more value in the tax credits, then you would expect to see an increased funding amount.

MR. MARTIN: Last question, and then we will move on to bank debt. Are there any other noteworthy developments as we start the year?

MR. CARGAS: People listening to this call may be struck by the number of challenging headwinds, but there may be another way to look at it.

When Bank of America started its renewable energy tax equity business 15 years ago, there were only a handful of individuals in our shop and across the entire US corporate landscape interested in renewable energy finance. Capital for renewable energy projects was scarce. If you fast forward to today, there are scores of people inside our firm and thousands across the corporate landscape working in the sector, bringing with them massive amounts of technical expertise and hundreds of billions of dollars through many types of capital.

Despite the headwinds — and we haven't even touched on the winter storm in Texas and things like the continuing legislative quagmire in Washington — there is still plenty of room for optimism in this sector.

MR. MARTIN: Well put.

MR. SONG: I certainly echo that. Two other trends to add: one is there are more utilities now owning renewable energy projects and tapping the tax equity market. Another is electricity prices are enjoying a small rebound. More cash flow makes the tax equity financings work better.

Bank Debt

MR. MARTIN: Let's move to the bank market. Ralph Cho, has the bank market settled back into its pre-COVID pattern? If not, what are the lingering effects?

MR. CHO: It definitely looks that way. The bank market last year was super busy.

It just seems like everyone keeps grinding it out in the face of less travel and too many video calls and without an end in sight.

The market is still awash in liquidity. There are more banks chasing deals than there are deals to finance. You really see this as the margins continue to tighten. Even a pandemic has not slowed all of this lending appetite. Omicron shut our offices at the end of the year, but no one really missed a beat. Demand for deal documents is still sky high, even going into this year.

We see investment interest coming in not just from the traditional players, but also from a lot of small regional banks and from credit funds acting as direct lenders. The South Korean investors that have had a big impact in recent years are selectively crawling their way back into the market as well.

MR. MARTIN: How many active banks were there in 2021, and how many do you expect this year?

MR. CHO: Unlike last year when we saw a number of players pause because of the pandemic, it is now a little bit of the reverse. I think I said there were between 50 and 70 lenders last year chasing deals. I put that estimate at closer to 100 this year, if not more.

Smaller commercial retail banks account for a lot of the increase. They are interested in ESG deals. The grey market lenders also continue to expand. A lot of new capital is being raised not just by existing fund managers, but we also see a lot of new fund managers.

Some of the limited partner investors in funds are choosing to become direct lenders themselves. They are looking to hire their own teams to evaluate deals. There was a lot of sideline capital last year. That is also coming back into the market.

MR. MARTIN: You said 80 to 100 banks and grey market lenders in 2018 and 2019, and then the number dipped significantly in 2020. What was the volume of North American project finance transactions in 2021 compared to 2020?

MR. CHO: Definitely down. The numbers are still preliminary, but North American banks came in around $61 billion across 183 deals. We were down in North America about 9% compared to last year. We did not see a lot of super large LNG deals in the bank market. The market remained busy with a lot of renewables deals, but renewables deals tend to be smaller in size.

MR. MARTIN: In 2020, the volume was $69.5 billion and 213 deals. Will all loans this year use SOFR as the benchmark rate?

MR. CHO: Yes and no. New floating-rate issues will have to move to SOFR as the benchmark rate. No bank can issue a new loan that is LIBOR based. Existing LIBOR loans can stay with LIBOR until June 2023, so call it 18 months left. People are expected to adjust their loans before then because LIBOR will be discontinued.

Here's something interesting I can share with you: we have been running new amendments and upsizings for our borrowers, and so we have had to be creative to make everybody happy. One thing we are doing is keeping the existing loan at LIBOR, while basing the upsizing on SOFR. Eventually, everything has to go to SOFR.

MR. MARTIN: What is the current spread above the benchmark for bank debt?

MR. CHO: It varies. The market is still tightening. Every year, I say that spreads cannot go lower, and here we are with plain-vanilla loans pricing as tight as LIBOR plus 112.5 basis points. The low end of the range was 125 basis points at this time last year.

Short-term construction bridge loans are now as tight as LIBOR plus 60 to 70 basis points for one-year paper. These rates are really for tier-one clients. If you are a borrower and you are not getting that rate, I suggest you talk to your banker, because that yield definitely seems to work for a lot of banks.

The range for quasi-merchant gas deals is a little wider. It is LIBOR plus 250 to 500 basis points. It is a wider band because it is harder to move thermal paper or quasi-merchant gas paper. Banks don't want to do it or they at least seem more resistant. We have moved paper that I would say is safer, on the merchant end of the spectrum, to the tighter end of that spread. We have also done more aggressive paper that we have had to move into the grey market on the wider end of the range, and we have a lot of deals that fall in between.

For HoldCo paper, if you are offering LIBOR plus 400 basis points and some upfront fees, you are probably getting momentum with some lenders – not all, but some. Hopefully, it is enough to clear the market. The sweet spot for these types of investors is really around 7% all-in. That is what everybody wants.

There is a potential, if your credit profile is very clean, to find commercial banks willing take HoldCo paper at an even tighter spread, in the area of LIBOR plus 200 basis points. Commercial banks don't need a floor, and they don't need call protection. They are your cheapest source of capital. We have lost hybrid HoldCo deals to aggressive commercial banks this way.

The delta between between OpCo and HoldCo loans is typically around 200 basis points. It is probably around 125 to 200 basis points now because of competition. The reason is the banks are not pricing it to risk. They are pricing it to a spread over their return models. I would take that paper every day if you can get it.

MR. MARTIN: What are current debt-service-coverage ratios? Last year, they were 1.35 times P50 cash flow for contracted wind and 1.25 times P50 cash flow for contracted solar. Has there been any change?

MR. CHO: Not really. I would even now throw in batteries. Batteries are even tighter at 1.2 times P50. However, it is not really solely about contracted cash flows. Borrowers want credit for merchant cash flows after the PPAs end, and they are getting maybe five years of such credit. Such structures are now considered plain vanilla. Lenders cannot get enough of these types of deals, either.

Everything else is still the same. Thermal deals were sizing around 1.3 times contracted revenue. They are now getting merchant credit.

Portfolio debt is still tested on a consolidated basis. We are going down to 1.1 times P50.

Capacity payments and revenue puts are still getting 1.15 times P50. Heat rate call options are still around 1.3 times. We use flat-line capacity payment assumptions for projects in places like PJM and New England. The PJM capacity auctions are really testing the line that we are using with our capacity assumptions. If PJM could get them back on a normal cycle, we could see some good numbers. They even have the potential to reset our assumptions and appetite for new merchant gas financings this year.

MR. MARTIN: Bank loan tenors have generally been five to seven years with mini-perm structures and two-plus-five years if the debt includes a construction loan. Has there been any change in that?

MR. CHO: No change on tenor. Lenders can go up to 15 years, but it costs a little more. The Canadian banks are able to go up to 19 years. I think that is because of local market dynamics.

MR. MARTIN: Have you seen any change in appetite among banks for any of the following: quasi-merchant projects, corporate PPAs, CCA contracts in California, community solar, standalone storage, hydrogen?

MR. CHO: Banks have super-high appetite for anything connected to ESG deals. What really is driving that is the large number of banks that have committed publicly to sustainable finance goals. We have been seeing such banks focus on buying renewable exposure, which continues to add to the liquidity in the market.

Every level of the capital stack that wants ESG exposure has to be willing to accept lower returns and higher risk compared to other asset classes. Some banks are even acknowledging that they are offering lower rates to borrowers for ESG-type exposures.

Exciting areas that lenders are trying to look at now include carbon capture and sequestration, fuel cells and hydrogen. The deal volume in those areas is well short of the available capital.

Thermal assets and quasi-merchant gas assets are harder to place in the market. We have seen banks turn down thermal activity to pursue ESG projects. The dismal capacity prices in the last PJM auction have made banks rethink how much overall merchant gas exposure they should have in their portfolios. They are considering cutting back. Capacity prices have to move up in the next auction before banks will be interested in making new loans.

MR. MARTIN: Last question, brief answer. Are there any other noteworthy trends as we enter 2022?

MR. CHO: Trends. We talked about ESG, liquidity and limited partners in credit funds doing direct lending. I will throw one thing out there that nobody really talks about. That is a banker shortage, Keith. People are becoming more mobile and changing lifestyles. It is hard to find people to fill open positions. We see a large number of people moving from junior levels all the way up to the senior levels at banks. Lots of teams at banks are hurting for staff. The market is going to have to pay up to obtain and retain talent. It is a great time to be a recruiter. Everyone is busier than ever before.

Term Loan B

MR. MARTIN: We are all suffering from exhaustion. The "Great Resignation" is affecting everybody working in this sector.

Thank you for that, Ralph. Let's move to Max Lipkind with Credit Suisse and talk about the term loan B part of the institutional debt market.

To set the stage, the term loan B market is institutional lenders using bank-like loan documents. The institutional debt market responds more quickly to changing market conditions. The term loan B market was pretty severely dislocated after the COVID lockdowns started in 2020. The average B loan debt instrument was trading in the spring 2020 at 76¢ on the dollar compared to the face amount, which implied a spread of 625 basis points over LIBOR and a yield of about 11%.

The market had fully recovered last year. Where is it as we enter 2022?

MR. LIPKIND: The institutional loan market remains in excellent shape. Many of the themes that you heard from Ralph about the bank market are also true of the institutional debt market. The key theme to start the year is the momentum in rates. The 10-year Treasury bond is now trading north of 1.9%. That dynamic obviously hurts the high-yield and investment-grade bond markets, and they have been reeling a little bit to start the year. Conversely, it is a dynamic that is very helpful to the floating-rate instruments like term loan B debt.

The index you mentioned is currently at 98, implying an average spread on loans of 415 basis points over the benchmark rate for a coupon of about 5.46%. That is roughly half of the peak when the market was trading at 76¢ on the dollar a couple years ago.

New term loan B issuances last year were about $611 billion for the overall market. To put that in context, that is more than double the new issuances in either 2019 or 2020. The term loan B market has had a ton of tailwind.

MR. MARTIN: Break it down, though. What was the term loan B volume in the North American power sector in 2021?

MR. LIPKIND: It was fairly subdued. To put that into context, the power sector volume in 2019 was $14 billion across 19 deals. It was about $10 billion in 2020 across seven deals. Last year, there was a total volume of $9.4 billion across 10 deals.

The volume was subdued compared to what we saw in the period from 2016 through 2019.

MR. MARTIN: What volume are you expecting this year?

MR. LIPKIND: Hard to predict. Ralph touched on some of the ESG themes that are also affecting the institutional market. If I had to guess, I would say comparable volume with some upside.

There are some deals from the 2016 and 2017 time frame that need to be refinanced and may not trade all that well. There might be more refinancings this year compared to last year, as some loans are getting closer to maturity and interest rates are rising.

A lot will depend on the volume of leveraged buyout activity. About 30% to 40% of overall volume in 2020 and 2021 was leveraged buyout activity. It is hard to tell how much such activity there will be in 2022.

MR. MARTIN: The 415-basis-point spread is for the market as a whole. Last year on this call, we said pricing for strong BB credits was about 325 to 350 basis points over LIBOR. Single B credits were 375 to 425. Have those numbers changed as we start this year?

MR. LIPKIND: On average, they have not.

To give you a couple data points, the index we keep of power leveraged loans stands at 96.57 as of last night. That reflects an average spread of 468 basis points. The basket of power loans trades a couple points below the overall market. On a spread basis, that is about 50 basis points wide of the overall market, for a coupon of 5.82%.

The reality is there is a ton of bifurcation within that. I think Ralph touched on some of that in his market, as well. Some of the best-in-class BB paper, particularly from some of the independent power producers, is pricing at 200 to 250 over the benchmark. Conversely, some of the fossils and thermal power generation may be a little less in favor. We saw those deals price at 475 to 500 basis points over the course of much of the second half of last year.

While the average index is in the high 90s with a spread in the mid-400s, the reality is not every credit is created equal. The market is bifurcating a lot more than it has in the past five or six years. You can see the divergence. A new issuance will come in with some of the best-in-class pricing, say 200 basis points over the benchmark, while some more levered LBOs are now closer to 500 basis points over, versus the 375 level that you quoted.

MR. MARTIN: B loans tend to be used for acquisition financing and also for refinancing debt on operating projects. Is it still the case that the last new-build issuance in the B loan market was in 2015?

MR. LIPKIND: Truly new build, yes. We did see in 2019 and 2020 a couple of refinancings for single-asset combined-cycle gas turbine projects that were not quite new builds, but that were refinanced not long after COD. For truly greenfield projects, you are right. The last one was a Panda issuance in 2014 or 2015. New builds are being financed in the A loan commercial bank mini-perm market.

MR. MARTIN: Just a few other metrics. Let me know if any of these has changed. Advance rates have tended to be in the mid-60% range, and the tenors have been seven years. B loans have been sized historically at six to six and a half times projected EBITDA, with at least 50% repayment of the loan required over seven years and a loan-to-value ratio of 75%. Are all of those metrics still holding?

MR. LIPKIND: There are a bunch there.

Advance rates and loan-to-value are pretty comparable concepts. Sixty percent debt and 40% equity is probably the right zip code. In some instances, we can stretch leverage closer to the 75% you referenced. In other instances, for older assets or assets with more noise and color to them, it is probably closer to 50-50. That said, 40% is where I would peg the typical equity check.

In terms of sizing, it is six to six and a half times EBITDA. However, the actual figure will be very asset specific. When asset valuations fall back to historically normal levels, I think we will see deals closer to three, three and a half to four times EBITDA, certainly for older thermal assets. Some of the renewables should also be able to pierce through the six and half times EBITDA.

All of this is asset specific. Again, the theme I touched on is there is differentiation in terms of asset quality and asset types. There is strong interest in lending

to ESG projects. I would not say that for traditional power projects, six and a half times is where we see financings.

In terms of repayment, that one depends on the credit quality and asset type, as well. In a couple of recent deals we did at the end of the year, we saw 75+% repayment over the life of the loan. Investors in older thermal assets are looking for closer to full repayment. For traditional power, we see 50+% and really closer to 100% repayment in recent deals.

Project Bonds

MR. MARTIN: Max, thank you for that. Let's move to John Anderson at Manulife and project bonds.

Project bonds are long-term fixed-rate loans. The loan tenor may be as long as 30+ years. The rates are fixed for the full duration. The loans are made at a spread above current 10-year Treasury bond yields. That rate is 1.9% as of this morning.

John Anderson, a year ago you said contracted projects were clearing at spreads of about 175 to 190 basis points over Treasuries. That translated into a coupon rate of around 3%. Where are rates today?

MR. ANDERSON: The change since last year is the increase in the Treasury yield. The spread above that yield has remained unchanged and is still 175 to 190 basis points for long-term, long-tenor, investment-grade financing. That translates into an overall coupon of 3.65% to 3.80%.

MR. MARTIN: We heard figures for bank and term loan B debt in the power sectors, including the transaction volumes last year. Do you have any sense of the size of the project bond market in the US power sector?

MR. ANDERSON: What Ralph Cho described as down by 10% for bank loans sounds right for project bonds. I triangulate in that the broad project bond market had another record year this past year. Our volumes were up over 2020. There is a ton of investor demand. You put on top of that the energy transition is accelerating, so that helps supply.

More investors care about renewable energy because they made public commitments to move their portfolios to net-zero carbon by 2040. Adding zero carbon wind, solar and hydroelectric is a great way to do that.

There is keen interest from across the debt spectrum. Borrowers have good options in the bank market, the leveraged loan market and the bond market. Which way do they want to go? What duration of loan are they looking for? We tend to do our best work when people want to lock in long, cheap money. That is where we end up being the best answer.

MR. MARTIN: I was going to say with inflation looking likely to increase, you would think there would be increased interest among borrowers in long-term, fixed-rate debt. Is there any evidence of that as we head into the new year?

MR. ANDERSON: We are not seeing treasurers say that is the reason. We are talking about civil construction projects that are on the drawing board where local authorities are seeing a 20% increase in total cost based on what has happened with supply chains, labor shortages and everything else.

Getting your cost to capital locked in for a long period of time might be really attractive for a lot of people this year.

MR. MARTIN: Let's talk about how large a loan one needs to make it worthwhile to look at project bonds. You are a direct lender. You don't do syndicated deals in the public market. I think you have said in the past that direct loans can be as small as $25 to $50 million. Syndicated project bonds really need to be at least $250 million to make it worth the effort. I know we have heard in the past that B loans can be as small as $225 to $250 million.

Have any of these metrics changed?

MR. ANDERSON: Those remain good numbers. As you say, we lend from our own book. We don't arrange syndicated financings, although we will participate. We will work on something as small as $50 million. A lot of people will do something like $25 to $50 million if they think it will lead to repeat business.

To get a good syndication, you are going to need to do at least $250 million. You can get together two, three or four direct lenders if you want to do something in that range and don't want to take the time to do a broadly syndicated loan.

You have a lot of options depending on project size. You can see projects easily clear more than $1 billion with a good roster of lenders ready to support them.

MR. MARTIN: Can you give us a sense for the types of deals in the power sector you saw project bonds being used last year?

MR. ANDERSON: It is where people want to go long. We have worked on loans that were as long as 40 years, depending on revenue visibility. An example is hydroelectric projects. Those assets can frequently have 100-year performance lives with proper maintenance.

The 20-year utility PPA is a less common part of the market. There is a lot more competition for them from banks. As Ralph said, lenders are now very constructive about pricing in some merchant cash flows.

The advantage renewable energy projects like solar enjoy is the fuel is free. They are not like merchant gas plants that might prove too inefficient and might not get called to run. A solar plant is going to run, so lenders can give credit for the merchant cash flows.

MR. MARTIN: Last question. There are a lot of tailwinds in this sector. You and I exchanged emails about the two main ones, which are the flood of capital from investors looking for ESG investments and the growing demand from borrowers as the transition to renewable energy gathers steam.

What are the principal headwinds?

MR. ANDERSON: I would highlight two. One is as we start 2022, a lot of investment committees are asking whether the broad markets are getting ahead of themselves. Are asset valuations trading too high? Are we headed for a correction?

Another headwind is this is a tough environment for midstream oil and gas issuers. Investors are being tracked on the carbon profiles of their portfolios. They are worried about stranded-asset risk on natural gas assets, even though those assets are critical in the transition to move the world off coal. There is uncertainty about how long can we lend to them prudently.

There is a dearth of capital going into oil and gas exploration and production. As you heard from the previous speakers — and it is true in the project bond market as well — lenders are more careful about how long do they want to go on natural gas assets, whether it is a power plant or an LNG export facility.

It will be interesting to watch this year whether we see a systematic premium that gas-fired generation, gas liquefaction and pipeline projects have to pay relative to renewable generation, which I think we all expect could more consistently price tighter because of growing investor demand.

Audience Questions

MR. MARTIN: John Anderson, thank you. Let's see if we can get in some audience questions in the few minutes remaining.

The first question is for our tax equity investors. Where would you put the current tax equity yield on section 45Q carbon capture projects?

MR. CARGAS: We think that those projects are still a little far off. Maybe there will be one this year, but they are more likely next year or the year after, so it is too early to predict. The inflation you mentioned earlier, the potential significant demand for tax equity and the cost associated with basically developing a new product would all have to factor into the return.

MR. MARTIN: What about tax equity for natural gas fuel cells, another audience member asks? Is there much interest in fuel cells from the tax equity market?

MR. SONG: We are not active in that market.

Going back to the carbon capture question, most of the CCUS projects at which we have looked are done on a basis of a 50% upfront contribution and 50% contingent contributions over time. They follow the IRS guidelines that were published a couple years ago for carbon capture transactions.

The yield is not the right metric in my opinion. We don't look at those deals from a yield perspective.

MR. MARTIN: How do you look at them?

MR. SONG: The IRR is not a good return metric when you have significant deferred capital contributions since that makes the IRR more volatile. We look at carbon capture investments from a net after-tax cash flow perspective and generally require a higher net after-tax cash flow from such an investment than from the typical wind investment.

MR. MARTIN: Ralph Cho, an audience member asks what debt-service-coverage ratio are you applying to merchant cash flows. Is there a different ratio for merchant revenue or do you use a blended ratio for the entire revenue stream?

MR. CHO: Merchant cash flows are much more volatile. Banks would probably size the debt against the merchant cash flow using a 2.0 times to 2.5 times P50 coverage ratio.

MR. MARTIN: Is that for the merchant tail after the power contract ends? What if a project has a power contract covering 80% of the electricity output and the other 20% of electricity revenue from day one is merchant?

MR. CHO: The merchant tail is different. For merchant cash flows during the power contract term, the debt-service-coverage ratio is 2.0 times to 2.5 times P50 cash flow. For the merchant tail, we generally look at what balloon payment will be required on the loan at the end of the loan term and try to come up with a view, based on the technology, the age, the location and the type of asset how large a balloon payment we are comfortable with heading into a sea of merchant cash flows.

It varies. A brand new combined-cycle gas turbine is going to have a much higher value than a 30- to 40-year-old peaker power plant.

MR. MARTIN: Another audience question: What bank appetite is there for transmission infrastructure and what metrics do you apply to it?

MR. CHO: There is very strong appetite at the level of the operating company and sometimes even at the holding company level. Such projects are usually investment grade. They generate regulated cash flows. Such projects should attract a low cost of capital. Lenders will be all over transmission.

MR. ANDERSON: You should definitely take that to the project bond market. The banks can go long, too.

MR. CHO: Roger that.