Cost Of Capital: 2025 Outlook
The market enters a period of uncertainty as a new administration takes office in Washington.
The US base borrowing rate, SOFR, hovered a little over 5.3% for most of 2024 before falling to 4.8% in September and falling further after the November election to 4.29% by early January. However, long-term rates are moving in the opposite direction. The yield on 10-year Treasury bonds reached 4.71% during the same period, up from 3.62% in September. The rate on 30-year fixed home mortgages has been rising since early November and is now hovering around 7%.
All of this is occurring against a backdrop of a full percentage point of Federal Reserve interest rate cuts since September. Uncertainty around tariffs, mass deportations, tax law changes and rising global tensions is making it harder this year to know what to put in financial models.
A group of market veterans talked about conditions in the tax equity, tax credit sale and debt markets during a call in mid-January. The panelists are Jack Cargas, head of originations on the tax equity desk at Bank of America, Rubiao Song, managing director and head of energy investments for JPMorgan, Ralph Cho, co-CEO of Apterra Infrastructure Capital, and Beth Waters, managing director for Project Finance Americas at MUFG. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
Tax Equity Data
MR. MARTIN: Each year for at least the last dozen years, we have started with the tax equity volume for the year that just ended. It is more complicated this year because so many tax equity partnerships are hybrids where the depreciation stays in the partnership while some or all of the tax credits are sold by the partnership to someone else, so there is the potential for double counting. Rubiao Song, how much in combined capital—that is tax equity investments and tax credit sale proceeds—was raised in 2024?
MR. SONG: For the first time in the history of this call, the total annual tax capital raised for wind, solar and battery projects exceeded $30 billion. We estimated around $33 billion, which is a significant increase from $25 billion in 2023 and $18 billion in 2022.
Precise numbers are hard to obtain. These are estimates based on a number of approaches.
MR. MARTIN: Break it down, Jack Cargas. How much of that was pure tax equity?
MR. CARGAS: We estimate that about a third of the $33 billion—call it $11 billion—is traditional tax equity where investors plan to keep the investment on their own books.
MR. MARTIN: How much did tax equity investors invest in hybrid transactions after netting out the tax credit sale proceeds that were returned to them?
MR. CARGAS: That approximately $11 billion is traditional tax equity without a follow-on tax credit sale. We estimate that hybrid tax equity was about $17 billion, meaning tax equity partnerships with tax credit transfer features that were either optional or obligatory. We estimate approximately 60% of that or $10 billion was tax credit sale proceeds. So the net amount invested by tax equity investors in hybrid tax equity transactions was approximately $7 billion.
These estimates are a consensus view of both tax equity investors on this panel.
That is a lot of numbers. We saw approximately $11 billion of traditional tax equity and approximately $17 billion of hybrid tax equity, for a total of about $28 billion of tax equity capital raised by the traditional wind, solar and storage sector.
MR. MARTIN: That still leaves us $5 billion short of $33 billion. Was the $5 billion direct tax credit sales?
MR. SONG: Yes. We count around $5 billion in sales of tax credits on wind, solar and storage projects in the direct transfer market.
MR. MARTIN: How much was raised from sales of other types of tax credits, like 45X credits for manufacturers of solar, wind and storage equipment, 45Q credits for carbon capture and 45U credits for generating electricity from nuclear power plants?
MR. SONG: We estimate around $6 billion from direct sales of these other three types of tax credits. So combined with the $33 billion in tax equity and tax credit sales proceeds raised to finance wind, solar and battery projects, the total energy tax credit monetization market in 2024 was close to $40 billion.
MR. MARTIN: Now that is a true record. How did the $33 billion in wind, solar and storage break down among those three categories?
MR. SONG: We estimate about $6 billion in wind, slightly down from the 2023 level, $20 billion in solar, which includes utility-scale, C&I and residential rooftop solar, and $7 billion in batteries, which includes co-located batteries and standalone battery projects. There was pronounced growth in the solar and the battery sectors.
Projections
MR. MARTIN: What do you expect the numbers to look like in 2025? It is a year when people will be unsure about where the tax law will settle.
MR. SONG: We expect a relatively flat year in 2025. We see the growth decelerating compared to prior years. There will be more activity in wind repowerings, so there may be a small uptick in wind. The large-scale utility solar projects continue to face permitting and interconnection delays.
Batteries have been a bright spot in the last couple years. The question remains whether the large pipeline of potential projects will convert into actual construction.
We expect an increase in direct transfers of 45X and other tax credits, including some new ones such as 45Z credits for producing sustainable aviation fuel and other clean transportation fuels. Overall the tax credit monetization market in 2025 should exceed $40 billion.
MR. MARTIN: Jack Cargas, do you agree with those numbers?
MR. CARGAS: Yes. There is a lot of interest in managing tax liability on the part of corporate America by buying tax credits, and there is a growing comfort level with the various types of credits. However, there is a lot of political uncertainty, so some buyers may sit on the sidelines until there is greater clarity about what will happen politically.
I want to underline a point Rubiao made. The market statistics that we talk about on this call tend to be referred to a fair amount throughout the year. I want to emphasize these figures are estimates.
There are plenty of capable market observers who believe our estimates on this panel are low. They may have a point. For example, we are aware of a significant pocket of residential solar tax credit transfers and a billion-dollar tax credit trade by a power generator that were not publicly announced.
At the same time, we ourselves at Bank of America have completed a couple billion dollars of tax credit transfers, and we are not sure that transactions like them in the private markets are included by the other statistical recordkeepers. Maybe we should be thinking about this $39 to $40 billion for 2024 as a rough number.
The main point is the total is at least two times the tax monetization volume in the years immediately before the Inflation Reduction Act.
Tax Law Uncertainty
MR. MARTIN: The point is these figures may be the minimum amount raised.
Let's dig into more details. One source of expected turbulence this year is the House of Representatives will try to move a massive tax, border, energy permitting and debt ceiling bill by the end of May. It may also try, as part of the same bill, to tackle any DOGE plans to shut federal agencies and shrink federal spending.
Many developers started construction of projects before year end 2024 in order to preserve the option to claim tax credits under the tax code as it existed in 2024. The production tax credits and investment tax credits for renewables moved to new tax code sections in 2025.
Do you foresee any slowdown in tax equity or tax credit sales for projects that were under construction by the end of 2024?
MR. CARGAS: We do not.
MR. MARTIN: What do you expect to happen with projects that start construction this year? Congress historically has grandfathered projects that have advanced to a point where it is unfair to pull away tax credits that were held out to induce companies to invest before Congress releases the details of any rollback.
MR. CARGAS: Grandfathering is a longstanding practice that we expect to continue. We are cognizant that neither Republicans nor Democrats are going to act in a way that jeopardizes their constituents’ interests or livelihoods. However, we expect a slowdown in financing for projects on which construction starts in 2025 until it is clearer what Congress will do.
There could also be other negatives like a tax rate change or other, new forms of pay fors.
Tax Equity Yields
MR. MARTIN: Rubiao Song, partnership flip yields for the best projects seem to be in the 7.5% to 8.5% range. They have not really moved much in the last two years. Are you feeling any downward or upward pressure on yields?
MR. SONG: I agree with you that flip yields have been pretty stable and moving within a very tight band.
As more deals are done on a hybrid basis, yield is often not the only metric for tax equity pricing. For sponsors, how much credit is transferred at what discount and who takes the transfer price risk are probably just as important.
That being said, we are watching interest rates closely. The volatility in long-term interest rates could affect flip yields.
MR. MARTIN: If you were a CFO modeling a tax equity deal, would you stick with the current yields in your model?
MR. SONG: It is hard to say what to put in the model for a particular deal until we get all the facts.
MR. MARTIN: So best to ask. Some tax equity investors have moved to a MOIC—multiple of invested capita—metric for purposes of pricing and determining the flip date and call option price. Some such investors use both an IRR and a MOIC. How do you view this trend?
MR. SONG: It is not surprising. The investment multiple measure is widely used in other financial sectors such as private equity. The internal rate of return is not really a good measure of profitability of the investment where a tax credit like the ITC is received in year one. At the end of the day, investors want to ensure they earn a certain dollar amount of profits for their risk-taking and for use of scarce tax capacity. The investment multiple measure is a better metric for that.
Tax Credit Sales
MR. MARTIN: Jack Cargas, let's switch to tax credit sales. You said you did about $2 billion of them. What trends are you seeing in that market? What prices and is there differentiation among types of tax credits?
MR. CARGAS: There is a lot to talk about here, and I know you want to keep the answer short.
There is price differentiation by technology and tax credit type. PTCs for wind and solar and advanced manufacturing fetch the highest prices. ITCs for solar and storage are next. Then come ITCs for renewable natural gas or RNG. That is differentiation by technology.
Some market participants are also observing price differentiation by deal size, with larger deals attracting higher tax credit prices. That may be somewhat counterintuitive. It is a reflection partly of the fact that transaction costs tend to be the same regardless of deal size, so tax credit buyers would rather spend the money on larger transactions. There are some investors who are focused on transactions within select geographic areas: for example, their own service territories or areas impacted by floods or other disasters.
All of those things have led to some differentiation on pricing.
MR. MARTIN: What is your advice to a CFO at a renewable energy company who wants to get the highest price for his or her tax credits?
MR. CARGAS: They have already made a decision about technology and geography. Other matters that affect pricing are the quality of the indemnity . . .
MR. MARTIN: Packaging together a larger number of tax credits seems to follow from what you said. Does it make sense to wait until later in the cycle when there may be a shorter supply of a particular vintage year of tax credits?
MR. CARGAS: Perhaps, but we have less than two years of data. I am not sure we can predict yet how the market will behave in any given year, especially in the current politically uncertain environment. Sponsors are looking for the highest tax credit prices, but they are also looking for certainty they can get a deal done. From that perspective, you might advise somebody to sell as soon as possible.
MR. SONG: The transfer price number is not the whole story. One must look at the deal in totality. For example, who pays for the insurance and who pays the legal costs or broker fees? The actual realized economics by the seller can be significantly different from the headline number.
Efficiency and certainty of closure are critical. If you have a closing delay for a few months, that can easily reduce the time value of the tax credits by a few cents per dollar.
MR. MARTIN: Jack Cargas, there are at least a dozen investors proposing to form preferred equity partnerships to buy projects on which investment tax credits will be claimed near the end of construction and then sell the tax credits at a stepped-up basis into the market. Are you now comfortable with these structures?
MR. CARGAS: We understand them. We recognize that what they are trying to do with these structures is to offset the depreciation with the step up. We are always happy to evaluate any structure, but we at Bank of America are wary about structures that step up the tax basis beyond levels that the IRS has previously found to be acceptable.
MR. MARTIN: Are you still capping step-ups at 15% to 20%?
MR. CARGAS: I don’t know if we have a hard cap like that, but that is near the top of the range.
MR. MARTIN: Rubiao Song, same answer?
MR. SONG: Yes, same answer. We have internal guidance. We have been pretty open with sponsors about our limits on step-ups.
Physical Work
MR. MARTIN: Jack Cargas, developers who rushed to start construction of projects last year did so either by incurring at least 5% of the total project cost or by commencing physical work of a significant nature at the project site or at a factory on custom-made equipment for the project.
Do you require at least a minimum amount of physical work to treat a project as under construction and, related to that, does the size of the project matter? Does the amount of physical work you want to see change if the project is $100 million versus $6 billion?
MR. CARGAS: We don't have a bright line. The renewable energy finance bar, of which you yourself are a prominent member, has educated us well. There is no bright line in the law defining exactly what qualifies as physical work of a significant nature, so we are not trying to impose a bright line when there is not one in the law.
We evaluate the meaning of “significant” on a case-by-case basis, Obviously the more work that has been completed, the better. There is a difference in the meaning of significant in the context of a $100 million project versus a $6 billion project.
For example, if you are relying on the construction of roads, X number miles of roads could be significant for a smaller project, but that same X number miles of roads for a larger project could be insignificant. It varies with the size of the project.
MR. MARTIN: What types of equipment besides main power transformers have you accepted as a basis for physical work? Nacelles, for example? Is there anything related to batteries?
MR. CARGAS: Anything that is inventoriable does not qualify, so that rules out nacelles, most battery components and any other assets that can be plug and play.
As I think you have said, qualifying equipment must be customized for the project in which it will be used. We always also focus during diligence on whether the physical work is ultimately used as an integral part of the project. If not, that is a problem for qualification.
We have generally been comfortable with main power transformers, roads and foundations. We have not used nacelles or other inventory-type assets.
MR. MARTIN: Rubiao Song, same answer on nacelles?
MR. SONG: Yes, that is broadly consistent with what we are doing.
MR. MARTIN: Jack Cargas, how much and what type of work do you require for physical work on the project site? For example, how many wind turbine foundations? What depth? How many solar panels or posts? What type and distance of roads?
MR. CARGAS: Sorry, Keith, but it is the same answer. We have been taught not to define this by our counsel.
MR. MARTIN: Next question. As you know, most projects must be completed within four years after the year construction started or the IRS may say that the construction did not start when originally thought. Developers had six years if construction started in 2016 through 2019 and five years if construction started in 2020. A developer can buy more time by proving continuous efforts.
Many people have been asking what happens, for example, if the project uses a main power transformer on which construction started in—pick a date, 2018—and the project is not completed until 2026. How is the tax equity market dealing with such cases?
MR. CARGAS: If the project started construction in 2018 and there is no proof of continuous efforts, then we and other investors would have a hard time financing that project.
That said, the IRS did provide some relief on continuous efforts during the pandemic. Many of us remember pauses at construction sites due to the virus raging through the workforce. To the extent that a particular project might be able to prove continuous efforts, then it is conceivable we could get comfortable with a longer construction period, but it may be a tall order to provide such proof.
MR. SONG: If delay is a concern, we would encourage the sponsors to make a contingency plan, for example, by keeping detailed records of the labor hours and wage information so that in the event of an adverse determination, the sponsor can assess what the financial penalty might be to remediate the deficiency.
MR. MARTIN: Rubiao, here are four data-type questions that hopefully lend themselves to short answers. You said over a year ago that 50% of solar projects JP Morgan has seen purport to qualify for energy community bonus credits. Is that number still 50%?
MR. SONG: For 2024 projects, the percentage was over 60% either based on fossil fuel closure or the unemployment test.
MR. MARTIN: What percentage of utility-scale solar projects are you seeing PTCs versus ITCs claimed on today?
MR. SONG: In our sample, we see about 50% of projects electing PTCs. That may say something about the geographic dispersion of projects. The projects with low build cost and high capacity factors tend to elect PTCs.
My sense is that if you look at the general population, 50% might be an overstatement. There are more investors interested in ITCs than PTCs, and that might influence which tax credit is selected by sponsors.
MR. MARTIN: You are probably seeing the very large projects. Your sample probably does not take into account C&I and residential rooftop solar, where ITCs are almost always claimed.
How common are domestic content bonus credits in the deals you close? How does the answer vary among wind, solar and storage?
MR. SONG: They are pretty common in wind projects, less common in solar and pretty rare in battery projects. We expect more projects to qualify as more wind, solar and battery components are made in the United States.
MR. MARTIN: How comfortable are you with domestic content claims based on cost calculations rather than the simple percentages in a table the IRS published last May?
MR. SONG: We do not rule out use of manufacturers’ costs to determine the amount of domestic content, but it will be a very high bar to clear. We prefer calculations based on the safe harbor table.
MR. MARTIN: Here is the last tax equity question. Jack Cargas, what other new developments are you seeing as we enter 2025?
MR. CARGAS: I don't know if we see anything brand spanking new, but there are a couple developments that are worth mentioning. One is helpful to the industry and one not so much.
The helpful development is the electrification of everything. It is driving up PPA prices and will require an all-of-the-above approach to energy policy. The negative is the political uncertainty. It can have a chilling effect on the market.
MR. MARTIN: To be clear on the uncertainty, your comment earlier was for projects that were under construction in 2024 or earlier, no slowdown is expected, while there is likely to be a slowdown for projects that start construction this year.
Rubiao Song, what other new developments are you seeing?
MR. SONG: What we observed in 2024 is continuing into 2025. Expansion of the tax credit transfer market as well as use of the hybrid tax equity structure will continue to bring more capital into the renewables sector. I agree with what Jack said. It is an unfortunate fact of life that we will have to deal for a good part of the year with an uncertain set of tax laws. We are super focused on executing deals for our clients. The tax equity and tax credit transfer markets will continue to innovate and adapt to reality on the ground to support the growth of renewables as well as other new technologies.
Debt Data
MR. MARTIN: Let’s move to debt. Ralph Cho, what was the volume of North American project finance debt in 2024 compared to 2023?
MR. CHO: It looks like it going to be another record year. Refinitiv has not published its final year end numbers, but looking at the published data through the end of the third quarter, deal volume was up 44% year over 2023. Third quarter volumes in North America were about $108 billion over 218 deals. Assuming this same pace continued through the fourth quarter, that would mean almost $144 billion in total transaction volume for 2024 making it the third year in a row to break the $100 billion mark. The years 2022 and 2023 were anchored by mega-LNG deals, while 2024 was anchored by data centers and not as much LNG.
This year, I think the market will go for broke. We should see not just the typical deals, but a return of LNG, data centers and new gas-fired power financings all come to market simultaneously this year. People are going to have to work around the clock to get the paper out.
MR. MARTIN: Beth Waters, do those numbers sound right to you?
MS. WATERS: Our syndications team was able to get at least the high-level numbers for the year end.
We have $164 billion in North American project finance lending in 2024 compared to $137 billion in 2023. That is a 20% increase.
Ralph said data centers represented significant part of project finance deals, and that is absolutely true. Looking at the same hard data from Refinitiv through the third quarter of 2024, project finance deals totaled about $130 billion. Of that, power was $58 billion, so about 45% of all PF deals during the first nine months of 2024 were power project deals. If you drill down further, $45 billion of that $58 billion was renewables, meaning that 78% of the power deals were renewables. The breakdown within renewables was solar 35%, battery storage 22% and wind 16%. The remaining power deals not falling into solar, storage and wind were 27%.
MR. MARTIN: How many active lenders were there in 2024? How many do you expect in 2025?
MS. WATERS: Every bank might track these numbers a little differently, but we saw about 81 active banks last year. We break it down between active and selectively active.
There were 15 banks that were active in the sense of being open to any kind of financing. Sixty-six of the 81 were selective, meaning they have certain criteria they must meet. The biggest one is an existing relationship with the sponsor. Another is they want to see a certain size deal pipeline. We have seen this change over time. I remember bank numbers in the 90s. Then it went down a bit. Now it is coming back up.
There is some nervousness in the market because of the uncertainty in Washington and the potential for a rollback of parts of the Inflation Reduction Act. Some banks have said they plan to wait on the sidelines. Foreign banks are more likely to fall in this category, because US politics are a little more opaque for them.
MR. CHO: I break the project finance debt market into four categories—the term loan A market, the term loan B market, the private placement market and the private credit market. There are lenders in each one, and it is important to understand all four because it shows how deep the liquidity is.
I see about 100 lenders in the A loan market. Maybe 50 or so are active, meaning they are doing multiple deals. The term loan B market is a lot deeper, maybe 200-plus lenders, with about 150 of them active. The number in the private placement market is maybe 25 to 50. The private credit market is more than 50 with about 20 active. There is a lot of overlap, but the liquidity is very deep.
The private credit market is in hyper-growth mode and is eating into the other three buckets and trying to disrupt it. If private credit lenders are not lending directly, then they are buying deals both in the primary and secondary markets. It is a hot market for syndicators.
MR. MARTIN: Term loan A refers to bank loans. B loans are loans using documentation similar to bank loans, but the paper is placed with institutional lenders.
The Financial Times reported at year end that global corporate debt sales soared to a record $8 trillion in 2024, as companies took advantage of red-hot demand for investors to accelerate borrowing plans.
Here is a quote: “Bankers say cheap funding costs, at least relative to safe government bonds, initially persuaded companies to pull forward their issuances to avoid any market turbulence around the US election. But when spreads tightened further in the wake of Trump's victory, some decided to lock in next year's borrowing needs, too.”
Do you see anything similar happening in the project finance market?
MR. CHO: Good question. The project finance market is financing assets with really long lead times. Lenders come into projects when projects are ready to be built or when projects are ready to be acquired.
It is hard for borrowers in that market to accelerate borrowing. You might see them take advantage of cheaper rates, like in the B loan market. We saw many refinancings and repricings last year. Some loans repriced multiple times as interest rates fell and spreads narrowed. It helps that the term loan B market has been super hot with lenders hungry for assets.
MS. WATERS: To add to what Ralph said, if you are just looking at traditional project finance lenders like MUFG, the market was so crowded with demand from clients and people showing up in mid-October or November—“I need this closed or underwritten by December 31”—that there just was not enough human capital to jump on these deals or a special exception was made in some cases for key clients. We had some very large underwritings that we did by ourselves or with another bank for clients to get them closed quickly and before year end with the plan to syndicate them in the new year.
What happens is a lot of bank funds are not available in the fourth quarter. Project finance banks meet their budgets, and either they are done for the year or they have too many deals on their plates. Thus, it is better to push transactions into the new year when everybody has a new budget. Most of the project finance banks have fiscal years ending in December, so that is what you are seeing now. These banks have a clean slate with an entirely new budget starting in January.
Current Spreads
MR. MARTIN: Let's run down what a CFO should assume in his or her model for various types of debt, starting with tax credit bridge loans. What advance rate, spread above SOFR, tenor and upfront fees should he or she assume?
MS. WATERS: We call them either TEBL for tax equity bridge loan or TRBL for transferable credit bridge loan. The loan could be against a revenue stream that is either contracted or merchant.
If it is contracted, which usually means the tax equity or tax credit buyer is committed, there is a 98% advance rate and low pricing. The spread could be as low as 150 to 162.5 basis points over SOFR.
If the revenue stream is uncontracted and it is an ITC bridge loan, then it is a 75% advance rate assuming the tax credits will be sold for 90¢ per dollar, which translates into an advance of 67.5% against the full face amount of the tax credits.
There have only been one or two tax credit bridge loans against future sales proceeds from PTCs as far as I am aware. The advance on these deals is currently 70% assuming 90¢ per dollar of tax credit. That translates to an advance of 63% against the full face amount of the tax credits.
If you come in later with a signed contract with a tax equity investor or tax credit purchaser, banks will bump up the advance rate to 98% and lower the pricing to a traditional tax equity bridge loan.
MR. MARTIN: Ralph Cho, are you aware of any other PTC tax credit bridge loans?
MR. CHO: No, but we would be interested from Apollo's perspective in providing such loans.
MR. MARTIN: Beth Waters, does willingness to lend against future PTCs change this year with all the uncertainty?
MS. WATERS: Yes. We will be taking everything step by step and doing the due diligence, working closely with our lawyers to look at the deals and make sure that that we are protected as lenders from any risk of a change in tax law.
MR. MARTIN: Ralph Cho, what about construction debt? Advance rates, spreads, tenor and upfront fees?
MR. CHO: Some construction loans are priced a little tight for us, but we try to layer debt on top of them. In general, if you are a plain-vanilla renewables borrower, you could probably model in a range of 150 to 187.5 basis points over SOFR. That is for fully contracted, plain-vanilla deals.
We talked a bit about the tax equity covered and uncovered loans. We are seeing pricing on uncovered loans of around 212.5 to 237.5 basis points over SOFR, so a significant premium over covered loans.
MR. MARTIN: What is the difference between covered and uncovered?
MR. CHO: Covered loans are where you are basically bridging a committed tax equity or tax credit sales proceeds, and uncovered or naked bridge loans are where you do not have a committed revenue stream to lend against.
Here are spreads for some other kinds of assets. For community solar projects, you could probably count on somewhere between 237.5 to 287.5 basis points. For merchant battery assets, you are looking at 275 to 350.
We have talked about pre-NTP development loan facilities over the last couple years. That spread will be wider—anywhere from 350 to 650—because that really depends on who you are as a borrower, your track record and the depth of your relationship with the lender.
The digital infrastructure asset class has been exploding over the last year. There are a lot of greenfield data centers getting financed. We saw over $26 billion in such financings just in 2024, and that number is expected to increase this year. Hyper-scale deals are pricing at 225 to 275 over SOFR, which is a good deal for lenders because a lot of these hyper-scales have investment-grade optics. For the ones with a co-location strategy, you can expect to see somewhere around 300 to 350 basis points. We throw holdco debt over any of these assets.
The pricing premium for holdco debt is 200 to 250 over the spreads on the more senior debt. Any competitive private credit lender will take that all day long.
MS. WATERS: We see the construction loan portion—as opposed to the tax equity or tax credit bridge loan—is usually around 150 basis points over SOFR for fully contracted projects.
It depends on whether the project is solar, wind or storage, a single project or part of a portfolio, contracted and, even if contracted, how much of the projected revenue is merchant. The cleanest, highly contracted deal may price as low as 150 during construction. For our bank, maybe we start at 175. Spreads go up from there.
Batteries seem to command about a 25 basis-point premium on margins during operations over other renewables financings like wind and solar, so you can see pricing up to 300 if there is a significant amount of merchant—say up to 40% uncontracted revenue—versus up to 275 for wind and solar.
MR. MARTIN: Advance rate, 95%? 90%? 85%?
MS. WATERS: It does not work like that. You size it based on standard debt-sizing criteria. However, we want some hurt money equity in there, so the maximum leverage might peak at 85% to 90%. Since the construction debt will carry over at term conversion as back-levered term debt, you are sizing the construction loan for the amount the project will be able to support as term debt.
MR. MARTIN: Ralph Cho, is private credit playing in each of these debt segments?
MR MR. CHO: In general, yes. There are lots of different private credit lenders with many different internal hurdles. For example, there are private credit lenders that are writing direct checks for investment-grade bonds. There are private credit lenders that will try to disrupt the term loan B market. As far as the bank market goes, it is pretty hard to touch the 150 to 187.5 plain-vanilla pricing, but as private credit lenders are able to tap into more efficient baskets of capital, they should be able to play in that mid-200 to mid-300 basis-point pricing.
MR. MARTIN: The pricing will be a little above what you get in the bank market.
MR. CHO: The bank market is always going to be your most competitive market for sure.
MS. WATERS: Sponsors are approaching the traditional project finance banks wanting pre-NTP loans. They know they can go to private credit, but private credit charges more, so they are trying to convince the traditional project finance banks to do the financings for them. We are not saying no, but sponsors do not want to pay the market price for what is essentially holdco debt.
MR. CHO: Every pre NTP facility will have a term loan and LC revolver and no private credit lenders are doing LC revolvers, so we do need the cooperation of the banks.
Coverage Ratios
MR. MARTIN: Beth, what are current debt service coverage ratios for wind, solar and storage assets?
MS. WATERS: I will run through them. This is for debt sizing.
For contracted solar, the projected revenue using P50 numbers has to be at least 1.25 to 1.30 times debt service. Wind P50 is 1.35 to 1.40. The P50 revenue projection for wind could go down to 1.30 for an operating portfolio of wind projects.
Storage coverage is 1.15 to 1.20. P factors are not relevant for storage.
Then you go to merchant solar. Coverage at P50 is 1.75 and at P99 for one year is 1.40. Wind P50 coverage is 1.80 with P99 one-year coverage at 1.40 to 1.50. Merchant storage 2.0 times debt service. Again, there is no P factor for storage.
There is also a cash sweep requirement under P90 one-year on the merchant. For contracted projects that have some merchant cash flows, you have to show you can pay off the debt with a cash sweep during the contract period.
MR. MARTIN: That probably sounded to some listeners like the 6 a.m. commodity report on AM radio in Des Moines, Iowa.
Let me go back to Ralph. The Treasury last week walked back some aspects of the hydrogen tax credit rules that were making it hard to finance green hydrogen projects. For example, hourly matching of renewable electricity with green hydrogen output now will not start until 2030. That is a two-year delay. Hourly matching will not be required for projects in states that have targets to get to 100% renewable energy by no later than 2050. Were the changes enough to make lenders willing to lend to green hydrogen projects?
MR. CHO: We have not yet seen any viable deal flow through our shop for these types of deals as of yet. Project finance lenders still need financeable contracts and proven technology to do stuff like this.
MR. MARTIN: Beth, any view?
MS. WATERS: It is too early to predict whether hydrogen will get traction after the latest changes. We are open to a dialogue with clients. Hydrogen was big, with everybody wanting to do it, and then all of a sudden, it wasn't working.
Debt Projections
MR. MARTIN: Ralph Cho, are you expecting a new wave of gas-fired power plants that need financing?
MR. CHO: That is an absolute capital “YES.” We are entering a new energy paradigm that is being driven by data center growth and new construction. The power has to come from somewhere. The solution is not going to be solely renewables.
MR. MARTIN: Beth, aside from solar, storage, data centers and gas, which Ralph just mentioned, in what other types of projects are you expecting the most growth this year? Batteries, semiconductor fabs, RNG, transmission, offshore wind, carbon capture, LNG, gas pipeline, anything else not on the list?
MS. WATERS: Data centers are insanely busy, as Ralph said. We are seeing a smattering of these other types of projects. LNG projects and anything gas related will make a comeback, but we are not expecting more deals in that sector until the third or fourth quarter.
MR. MARTIN: Ralph, what other noteworthy trends are you seeing as we enter 2025?
MR. CHO: I expect LNG definitely to pick up. There are already a number of expansions that are expected this first quarter but definitely in the first half. I am curious whether it ends up being a positive or negative for our infrastructure business, because I can make arguments both ways. I am not sure how material it will be.
We talked about the new energy paradigm that is being driven by AI. The rapid data center growth will lead to more opportunities to finance gas-fired power plants.
The question is whether small modular reactors will get included in the mix. I expect M&A financing definitely to pick up. The whole elevated market valuation of power assets and increased investor confidence will help drive that.
Finally, I am curious to see how private credit fares. It is hard to compete against the hyper-aggressive bank market, bond players and the institutional lenders in the term loan B market.
MR. MARTIN: Beth Waters, are there any new trends as we enter 2025?
MS. WATERS: Ralph mentioned data centers, and we will need more gas-fired power plants to offset the intermittency of wind and solar. Gas-fired projects will take time to advance. They take three years to build, and that is after an extended development period. I was on one of the last new builds. The financing closed two years ago, and the project is still not in operation.
Renewables have to be part of the electricity mix. It cannot just be gas-fired.
Sponsors have to pay in advance for turbines and transformers. This is draining the liquidity of sponsors. They have to recycle capital. That is why you are seeing so many requests for pre-NTP loan facilities.
We talked about LNG. Offshore wind is a question mark. We have a lot of big offshore wind projects that were just about to come to the bank market for financing. Are they still coming? Those are the things that we are watching.