A group of industry veterans talked in late January about the current cost of capital in the
tax equity, bank debt, term loan B and project bond markets and what they foresee in 2014.
The panelists are John Eber, managing director and head of energy investments at
JPMorgan Capital Corporation, Lance Markowitz, senior vice president and head of leasing
and asset finance for Union Bank, Thomas Emmons, managing director and head of renewable energy finance for the Americas at Dutch bank Rabobank, Raya Prabhu, managing
director and head of power and midstream financing at Goldman Sachs, Richard Randall,
executive director for North American debt investments for IFM Investors, an Australianbased fund with $48 billion under management, and formerly head of power and project
finance for RBS Global Banking, James Finch, managing director and co-head of US loan
capital markets for Credit Suisse, and Ray Wood, managing director and head of US power
and renewables for Bank of America Merrill Lynch. The moderator is Keith Martin with
Chadbourne in Washington.
MR. MARTIN: Tax equity volume in the renewable energy sector hit $6.5 billion in 2013,
which is up about $1 billion over 2012. There was roughly an even split between wind and
solar. John Eber, can you break it down further: how many wind or solar deals were there?
MR. EBER: We saw 21 wind deals come to the market and receive commitments in 2013.
There were 13 different sponsors for 23 projects and about 3,000 / continued page 2
megawatts of capacity. In the large-ticket solar market, we saw
27 deals from 18 different sponsors. Of those deals, 10 each
were in residential and utility, and about seven in the distributed generation market. In total, it was almost 1,800 megawatts of solar.
MR. MARTIN: What volume are you projecting for 2014?
MR. EBER: I am not in the projection business. Let’s just say
we see a sizable pipeline of opportunities in both solar and
wind. If you go to the American Wind Energy Association database and look at all the power purchase agreements, you will
see the potential to double the amount of megawatts that we
saw last year.
MR. MARTIN: Is it your sense that the supply of tax equity is
elastic enough to meet whatever the demand will be this year?
MR. EBER: There will be enough tax equity. The market continues to expand in terms of number of investors. The active
investors continue to increase the amount of tax equity they
are prepared to invest.
MR. MARTIN: Lance Markowitz, yields have remained
remarkably stable over the last three years. Where are they
currently for wind, utility-scale solar and rooftop solar?
MR. MARKOWITZ: The concept of flip yield is misleading, but
you are correct that they have been fairly stable in the wind
market. They range between 50 basis points above or below
8% after tax on unlevered transactions.
We have seen a lot of diversity in utility-scale solar. They
have been the most aggressively bid transactions, so yields in
that market are a little lower than for the benchmark wind
deals. Utility-scale solar has an investment tax credit as
opposed to wind and production tax credits. People bid those
differently. As for rooftop solar, yields tend to be higher than for
wind, but no more than 50 basis points higher. We have seen
really strong rooftop deals whose yields are well above wind.
MR. MARTIN: So rooftop solar is around 9%?
MR. MARKOWITZ: We have not done a ton of rooftop solar,
but we have seen many different pricing files. Pricing depends
on what the parties are trying to accomplish. We have seen
ranges of a couple hundred basis points due solely to the way
the transaction is structured.
MR. MARTIN: John Eber, how many active tax equity investors are there currently? Do you have a breakdown between
wind and solar?
MR. EBER: There are roughly 25 active investors between
the two markets. Of the 25, 13 invested last year in wind.
There were more than 20 investors in the large-ticket end of
the solar market.
MR. MARTIN: How far forward will tax equity commit?
MR. EBER: Most equity investors will make a forward commitment of no more than a year. That seems to work for the
market. Last year, it was a little
different in the wind market
with the rule that wind farms
had to be under construction by
year end to qualify for tax
credits. There were more sponsors looking for longer forward
commitments than we had
seen in a while, so there were a
number of us that provided
commitments longer than a
year, but that is atypical. A year
seems to work for the residential solar space. Many of our residential solar clients are looking to raise tax equity within a
six- to 12-month time frame.
MR. MARTIN: Is the wind market purely a production tax
credit market at this stage due to increasing turbine efficiency?
MR. MARKOWITZ: Yes. I am certain there are a few anomalies, but pretty much everything we see today involves production tax credits.
MR. MARTIN: Pay-go structures appear to have made a
comeback. In a pay-go structure, the tax equity investor puts in
its tax equity over time as the tax credits are earned. Why the
revival? Is tax equity provided through a pay-go structure more
expensive than where the entire tax equity investment is
made at inception?
MR. EBER: Pay-go structures have always been popular. We
have been using the structure since we started investing. They
work well for deals where the financing is already in place, but
the sponsor wants to monetize the remaining production tax
credits. They work well for deals that are more risky than
average; the pay-go feature can help reduce the risk to the tax
equity investor, allowing the investor to commit tax equity to a
deal he might not otherwise do. The IRS partnership flip guidelines allow up to 25% of the tax equity investment to be paid in
over time as a percentage of output or production tax credits.
The tax equity costs the same. The pay-go feature brings the
risk of the investment more in line with a traditional deal. Once
you get it risk adjusted using the pay-go feature, then you
don’t need to seek additional yield.
MR. MARTIN: As solar projects get larger, they are more
likely to need debt as well as tax equity. Yet, tax equity investors doing partnership flip transactions have not been keen on
having lenders at the partnership level. Is this changing?
MR. MARKOWITZ: The preference to avoid partnership-level
debt is not changing, but, that said, some leveraged flip deals
are getting done. Looking at our own portfolio, we were
involved in six deals in the last 18 months that required more
than $400 million in tax equity, and none of them had
MR. MARTIN: Is JPMorgan more willing today to do leveraged flip deals?
MR. EBER: We have done some in the past. Fewer than 10%
of the deals we have done over the last decade had any debt at
the project or partnership level.
MR. MARTIN: Is there anything special about investment
credit deals, which is what the solar market is, that makes it
harder to do a partnership flip transaction or to combine tax
equity with debt?
MR. EBER: No. They are just a very different type of deal, so
they will appeal to different investors. The majority of the tax
benefit comes at inception rather than being spread over 10
years as it is in a deal with production tax credits. ITC deals
have a different income pattern and a much faster payback.
They require a lot more tax capacity immediately for a comparable amount of equipment value from the investor, as compared to being able to spread the tax capacity over 10 years.
We like both types of investments, but there are some
investors who are more comfortable with one or the other
because of their particular tax positions.
MR. MARTIN: One of the difficult issues when you combine
debt with tax equity is that tax equity investors want the
lenders to agree to forebear from taking the assets after a debt
default until the tax equity can reach its yield. The lenders can
step in and replace the sponsor in the meantime. There used to
be a “market” approach to forbearance, but that seems to have
collapsed lately. There are deals that have not gone forward
because of forbearance issues. Is it your sense that whatever
market consensus there was has now disappeared?
MR. MARKOWITZ: Yes, although I don’t know whether there
was ever really a consensus. Over the years, the transactions
that took the longest to close were the ones that bogged down
over debt and equity issues.
MR. EBER: The consensus was that there were one or two
banks that understood the issue and were willing to agree to
forbearance. There was never a broad market consensus
regarding forbearance, which is why the tax equity market
remains dominated by deals that do not have debt at the
project or partnership level.
MR. MARTIN: How much is the current yield premium when
there is project- or partnership-level debt?
MR. MARKOWITZ: The yield will move up to the low teens to
mid-teens, depending on the transaction.
MR. MARTIN: The federal bank regulators came out in late
December with a definition of “covered funds” under the
Volcker rule. National banks cannot invest in covered funds.
Have you been advised by your bank regulatory counsel that
the Volcker rule, as the federal bank regulators have now
implemented it, will affect your ability to continue making tax
MR. MARKOWITZ: I have not. We continue to make such
investments and expect to be able to continue doing so.
MR. MARTIN: Wind, landfill gas, biomass, and geothermal
projects had to be under construction by December 2013 to
qualify for federal tax credits. There are two ways to start construction. One was for the sponsor to “incur” at least 5% of the
project cost by the end of 2013. The other was for the sponsor
to have started physical work of a significant nature on the
project. It does not appear that much physical work was
Cost of Capital
continued from page 3
required in 2013. Are you willing to rely at this point on the
physical work test?
MR. EBER: We expect to be able to do that. That said, we
have not seen many examples of it yet, so we are still feeling
our way about where to draw lines. Hopefully when clients
bring deals to us, the physical work will be well documented
and will be significant enough to fit within the parameters we
think the Treasury and the IRS will use to draw lines.
MR. MARTIN: What do you think is the minimum physical
MR. EBER: That’s a hard question to answer. It will come
down to facts and circumstances. We will make decisions
based on what IRS guidance has been issued to date.
MR. MARTIN: In late December, the IRS released new guidelines on tax equity transactions involving tax credits for rehabilitating buildings. Has this so-called Historic Boardwalk
guidance had an effect on how you are structuring deals in the
renewable energy sector?
MR. MARKOWITZ: No, but I understand that there are a few
general principles behind that guidance that people will at
least pause to think about when doing future deals.
MR. MARTIN: Tom Emmons, was the big story in 2013 that the
banks are back as project finance lenders? The North American
project finance bank market was $40 billion in 2011 and
roughly only $24 to $25 billion in 2012. Do you have a figure yet
MR. EMMONS: That number is hard to pin down, because
there are several databases, they don’t have standard criteria
and some tallies have not been published yet. I think the consensus is that 2013 was up over 2012. Some of the databases
suggest it was up around 20%.
What is more interesting is to look at the sub-sectors within
project finance. Oil and gas and conventional power seem to
be up. Renewable energy seems to be flat or down.
MR. MARTIN: How many active banks were there in 2013?
How many do you expect in 2014?
MR. EMMONS: There were around 40 or 50 in 2012. I expect
the final tallies to show roughly 10 more in 2013. There should
be even a few more in 2014. We are seeing some US regional
banks, smaller Canadian banks and even some northern
European and Nordic banks coming in.
MR. MARTIN: Rich Randall, one would think a large number
of returning banks would mean downward pressure on
margins. Was there? What is the current spread above LIBOR
for interest rates? Where do you see it headed in 2014?
MR. RANDALL: For bank deals, the average is probably
around 200 basis points over LIBOR. I think there is a lot of
downward pressure. We are starting to see some pricing go
below 200 on some new deals. With the additional liquidity
coming into the market, the downward pressure will continue.
MR. EMMONS: There is a large range in pricing. Pricing has
softened over the last year, but I think most of that softening is
with large straightforward deals with strong sponsors. The
pricing on smaller complex deals has not moved as much.
MR. FINCH: The commercial bank market is the one market
where a relationship matters, so unlike all the capital markets, if
there is a strong relationship between the sponsor and bank,
then the loan will be priced at a discount, regardless of the cost.
MR. WOOD: What we are talking about is deals within a
narrow band of risk. There is an implied strong to mid-BB
rating, if not higher. While the high-yield market, the institutional term loan market and the commercial bank market are
much more liquid than they have been in years, they are still
interested only in the low-risk deals.
MR. MARTIN: Current yields are 200 basis points over LIBOR,
with some downward pressure. Is there a LIBOR floor tied to
the cost of funding and, if so, what is it?
MR. RANDALL: Not in the bank deals. The bank market does
not require a floor. However, we are seeing LIBOR floors in the
institutional loan market of around 1%.
MR. FINCH: The reason for the LIBOR floor was that when
rates were falling, institutional investors were trying to preserve some yield, and so they set a minimum rate to which
the spread was added. That is a bit of a legacy that will disappear rapidly in a market where interest rates overall are
expected to rise.
MR. MARTIN: What does 200 basis points over LIBOR translate into as a coupon rate?
MR. EMMONS: The six-month swapped LIBOR is around
3.25%, so you add 2% to that. There are often step ups over
time for longer deals, but the rate is well under 6%.
MR. MARTIN: How much would you expect the rate to step
up ultimately for a 10-year deal?
MR. EMMONS: It goes up typically by an eighth or a quarter
percent every three or four years.
MR. MARTIN: What are current upfront fees?
MR. EMMONS: They vary with tenor and other factors, but
they are often the same as the starting margin, so in the low
MR. MARTIN: We have read a lot recently about manipulation of LIBOR by banks and potential criminal prosecutions. Is
the market moving away from LIBOR as a benchmark or is it
just adjusting how LIBOR is calculated?
MR. FINCH: LIBOR remains the benchmark.
MR. MARTIN: Bank loans seemed to shorten in 2012 to seven
to 10 years with mini-perm features. Where are they today?
MR. RANDALL: Seven to 10 years is still the norm.
Institutions like ours have the ability to go longer, and that is
where we are trying to fit into the market. We see a subset of
banks, particularly the Japanese, that are willing to go as long
as 15 to 18 years.
MR. WOOD: I think the commercial banks have wanted to
keep it shorter for return-on-capital reasons. There has been a
big institutional bid for the longer-dated piece. We have seen
banks come in jointly with pension funds or other institutional
investors so that the sponsor can get the duration it wants by
leaning on banks for the shorter piece and institutional money
for the longer piece.
MR. MARTIN: Tom Emmons, last year on this call you said,
“The shortening of tenors is creating opportunities for institutional lenders and they have been stepping up. I think it is a
permanent shift.” Do you still stand by that view?
MR. EMMONS: Yes. As mentioned, I think banks still want to
keep their legal maturities under 10 years so borrowers are
given the choice of doing a mini-perm with a commercial bank
or going long-term fixed in the institutional market. Many borrowers are electing to go long-term fixed. The numbers in the
institutional debt market were up last year as well.
MR. MARTIN: What are debt service coverage ratios currently for contracted wind and solar projects?
MR. EMMONS: Wind may be mid-1.40x, and solar is
MR. MARTIN: What about new gas-fired power plants?
MR. WOOD: There are not too many of those that come
with the same long-term offtake contracts, so it is difficult to
say. You tend to have amortization over the contract period,
and you are really solving for the merchant loan-to-value. That
is how the rating agencies and institutional investors evaluate
how much debt gas-fired projects can support.
MR. FINCH: Ultimately, you can get coverage ratios for gasfired power plants down to 1.0x through the offtake contract
period, if the market believes that the project is truly contracted with a creditworthy offtaker. However, the devil is in
the details at the maturity of
the loan. Does the merchant
component of the power plant
provide sufficient coverage to
merit the investment? That coverage will be higher than 1.0x.
MR. WOOD: A lot of gas deals
will have a percentage cash
sweep of all available cash flow,
anywhere from 50% to 100%.
There is a coverage ratio for the
mandatory amortization, which
tends to be pretty light, and
then there is a cash sweep.
MR. MARTIN: Every plant has a merchant tail after a power contract runs out. Does the debt need to be shorter than the power
MR. FINCH: No. Merchant is defined regionally. Merchant in
ERCOT is different than merchant in PJM.
MR. MARTIN: What would a coverage ratio be for a merchant plant with a power hedge in ERCOT?
MR. FINCH: It depends on how long the tail is when the loan
matures, but the power hedge usually lasts longer than the
debt is expected to remain outstanding.
MR. PRABHU: One other factor to keep in mind as you get to
the maturity of a term loan B is the loan-to-value. One of the
other metrics investors have been using is the out-year value
that would be assigned by the M&A market and trying to
understand what kind of loan-to-value you have in the base
case and downside scenarios.
MR. WOOD: Lenders are assuming a value well below the
total capital cost of a new build. This is yet another reason why
we are not seeing a lot of new construction. We have seen
some in ERCOT and in other places where people have longterm contracts. There is a firm bid for merchant generation,
but at a sizable discount to new entry capital costs.
MR. MARTIN: What percentage of project costs can be
financed under a construction loan in the bank market?
MR. EMMONS: It depends on the bridgeable capital inflows
coming in at the end of construction, and it also depends on
each lender’s policy for debt ratios, but it could be as high as
80% to 90%.
MR. MARTIN: Are banks back to full underwriting or are the
larger transactions being done as club deals?
MR. EMMONS: In renewable energy, they are mostly club
deals. The deals are pretty straightforward, and the borrowers
do not require underwriting.
MR. RANDALL: On other transactions, we tend to use institutional markets interchangeably with commercial bank
markets. Although it is the same product, there is a different
risk appetite among lenders in the two markets.
For the larger deals that need underwriting, to the extent
that there is sufficient relationship pull through the sponsor,
banks are more than happy to provide significant underwritings to those transactions.
MR. WOOD: The liquidity in these markets lets the relationship banks make an underwriting commitment and have a
high degree of comfort that there will be a decent takeout,
even if the primary form of takeout falls away. There are so
many other secondary forms of takeout with more institutions
willing to step in. We have seen some one-off transactions
where one bank acted as a bridge lender where time was of
the essence and earned an exceptional return for the takeout
risk, but it is not the norm.
MR. MARTIN: We talked a little about merchant projects.
They were another big story in 2013. Gas-fired power plants and
some wind deals were financed on a merchant basis in PJM and
ERCOT. Were all these deals done in the term loan B market? Are
banks getting more comfortable with merchant deals?
MR. RANDALL: It depends on the market. PJM is where most
of the activity occurs. It is the most mature and transparent
market, and the easiest in which to get a deal done. The supply-demand economics work well.
MR. MARTIN: Will banks get comfortable with merchant
MR. EMMONS: I prefer to call deals either contracted or uncontracted. Contracted can mean a power purchase agreement or a hedge with a strong counterparty. Commercial
banks typically lend against contracted cash flow, whether
under a PPA or a hedge with a strong counterparty. There is no
magic minimum number of years for a hedge, but shorter
hedges support less debt, and the balance has to come from
equity or junior debt.
MR. WOOD: All but possibly one “merchant” deal over the
last 12 to 18 months has involved a power hedge. A counterparty agrees to a fixed-price offtake for 10 to 12 years off of a
P90 wind resource scenario. It may even be a lighter production estimate than in the peak summer months, given the volatility in ERCOT.
Most such merchant wind deals have been in ERCOT. The
load-serving entities have little interest in signing long-term
contracts. There are anywhere from 2,000 to 4,000 megawatts
under construction or being planned. Most of the projects
have power hedges, the banks are coming in for construction
debt, and tax equity has been available. A handful of players
are providing the hedges. It will be interesting to see how the
current discussions in Washington among the federal bank
regulatory agencies about the extent to which banks should
be allowed to trade commodities will affect Wall Street’s
ability to continue providing those hedges.
The same type of coverage ratios apply to deals with power
hedges. The banks plan to be taken out with the tax equity or
back leverage at the end of construction.
MR. MARTIN: Raya Prabhu, Goldman Sachs led many of the
most prominent recent financings of merchant gas-fired
power plants in the term loan B market. Do you see merchant
gas as an expanding market?
MR. PRABHU: The bulk of the activity will remain in PJM and
ERCOT. That is largely driven by the fact that these are mature
markets with very strong underlying power fundamentals.
Other drivers have been the low cost of natural gas and the
expected coal retirements over the next few years.
We led most of the projects in the term loan B market this
past year. We found a great reception to them from a wide
range of investors. A lot of that was driven by tightening
yields and spreads for operating assets. People who are
looking for total return are moving to riskier asset classes, like
Term Loan B
MR. MARTIN: Term loan B debt is papered like bank debt, but it
is sold to institutional investors looking for yield. It tends to be
used to finance projects riskier than one might be able to
finance in the regular bank market. Any idea what the term
loan B volume was last year?
MR. FINCH: Rather than being papered like bank debt, I
would say it is bank debt. You are simply selling it to different
investor groups. Whether the buyer is a commercial bank or an
institutional investor, it is still a bank loan. It is particularly
attractive in a rising interest rate environment.
Last year, there were about $455 billion of B loan issuances,
and that was an all-time record. The previous record was in
2007 at $387 billion. Money continues to flow into the term
loan B market to the tune of about $750 million to $1 billion a
week. As you see a lack of new M&A-driven issuances, investors are looking for new places to invest money. Project financing is becoming more and more attractive to them as they
become more familiar with the construct and the risks they are
being asked to take.
MR. MARTIN: Last year, this panel estimated that the combined term loan B and project bond market for North
American project finance in the power sector was about $4 to
$5 billion. Is there a comparable breakdown for 2013?
MR. PRABHU: Focusing strictly on the term loan B market for
greenfield projects, I would venture to say that in 2013,
between the various ERCOT and PJM financings and other
deals, the figure was probably in the $2 to $3 billion range. We
have not seen a lot of greenfield project financings in this subsector of the market. Most deals have been quasi-merchant.
MR. WOOD: One thing that hurts the project bond market is
that banks are so comfortable with solar and wind projects
that benefit from the 12- to 20-year PPAs that the loan-tovalue, spread above LIBOR and the flexibility of being able to
call at par is of greater value to sponsors than going to a noncall, long-duration project bond that has to be rated by both
rating agencies and that locks them into a fixed yield.
Sponsors are more likely to move to project bonds if they are
concerned about rising interest rates. That said, the fact that all
the other markets are so wide open and relatively aggressive on
pricing has made for less volume in the project bond market.
MR. MARTIN: B loans price off LIBOR, just like bank debt.
How do margins compare for B loans to bank debt?
MR. PRABHU: It depends on the credit quality of the underlying asset. We have seen yields in the term loan B market price
for strong BBs and higher as high as 275 basis points above
LIBOR, with a 1% LIBOR floor and one point of original issue
That is at the tight end of what we have seen. On the wide
end as you move further down the credit quality spectrum and
into single B territory, you see deals price as wide as 500 to 550
basis points over.
MR. MARTIN: What about upfront fees, tenors and coverage
ratios? Are they the same as in the bank market?
MR. PRABHU: On tenors, we have seen a pretty stable
market that has gravitated toward seven years as the
In terms of upfront fees, we have seen a compression as the
year has progressed. That is due largely to demand exceeding
supply. We continue to expect that pressure in 2014, but I
would say in 2013 you had anywhere from half a point to a
point of upfront fees.
In terms of coverage ratios, the market is focused on both
debt-to-EBITDA as a metric for initial financings and a debt
service coverage ratio over the life of the asset. We have seen
debt service coverage ratios close to 2.0x at closing of a financing, and then obviously increasing as the debt gets swept over
the life of the loan.
MR. MARTIN: The B loan market does not like construction
risk. It does not allow for delayed draws, so you end up with
negative arbitrage during construction. Are there other differences between the B loan and bank markets?
MR. FINCH: These are all loans, so you consult an institutional or a commercial bank. Commercial banks tend to
operate within a very narrowly defined low-risk area. Based on
that and the relationship that they have with the sponsor, the
first priority is the cost of capital. If it is a club deal, then the
bank is focused on booking the asset on its balance sheet. It
does not account for the loan on a mark-to-market basis, so it
just needs to be earning a basic spread.
The B market tends to price risk across the spectrum from a
high-risk project to a low-risk project. It also factors in where
the pricing is in the secondary market. The secondary market is
on mark-to-market accounting.
The result is that the spread can vary tremendously for any
given quantum of risk based on where
the risk is being priced in the secondary market. Sometimes
the pricing is below the commercial bank cost of that risk,
because the market is so hot and there is a lot of liquidity, and
sometimes it is above the commercial bank pricing for comparable risk.
The B market does not generally do delayed draws. The B
market is a funded market. The investors have raised capital
and are sitting on it.
The commercial bank market is a regulated market where a
regulator says, based on a commitment, you can put some
fraction of your capital against that and, as a result, a commitment is a very efficient way to finance a project and get banks
a return on the commitment, because they are not having to
put dollar-for-dollar capital against the commitment.
The B market developed because of this. Initially the pro rata
market was a revolver term loan A that was sold to commercial
banks to deal with the delayed draw aspect. The B market was
a funded market that had a longer maturity and no hard amortization, which picked up the riskier part of the commitment.
MR. MARTIN: Is there more talk of deals in the project bond
market this year? Last year, there seemed to be a lot of talk, but
not many deals.
MR. WOOD: They are still effectively museum pieces for the
reasons we have already articulated. The debt markets are
wide open. They are looking for product. Project bonds, highyield bonds and investment-grade bonds will be there. The
project bond market remains open, but we are not projecting
as much volume as we are in the term loan B market and commercial bank markets.
MR. MARTIN: Project bonds and tenors can run as long as
the power contract, and there are no upfront fees. The economics tend to be fully baked into the spread. Ratings may be
required for widely syndicated deals. Make-whole payments
will be required if the bonds are repaid ahead of schedule
with the make-whole calculated as the remaining payments
due under the debt instrument discounted at the current
Treasury rate, plus 50 basis points. The project bond market
will take construction risk, but charge a commitment fee on
Do you see other differences besides these between the
bank and B loan market versus project bonds?
MR. WOOD: Project bonds are fixed-rate loans versus floating-rate loans in the bank and B loan markets. Just as with the
B loan market, you need to pay the rating agencies, and there
is a gross spread or an underwriting fee upfront to the extent
the issue is not directly placed.
MR. MARTIN: We heard last year that there were 20 to 25
institutions in 2012 willing to buy project bonds. Do you think
it will be the same number in 2014?
MR. FINCH: It will be significantly greater. You will see a lot
more institutional investors prepared to play in the project
bond market because there are not enough other places to put
MR. MARTIN: Project bonds are priced off Treasury bonds.
What is the current spread above Treasuries? What does this
translate into as a coupon rate?
MR. PRABHU: A lot of these project bonds are being done for
investment-grade projects, so BBB-minus or better, and at that
end of the spectrum, we have seen all-in rates of about 5.5% to
There have been a few deals that have been done subinvestment grade, but even those I would qualify as being
strong BB if not better. They have a premium attached to
them. It is tough to give a spread, as it depends on the interpolated Treasury rate and the weighted average life of the underlying project bonds.
We have not really seen rates creep much below 5.5%.
Depending on the credit quality, the rate could be north