A panel of veteran investment bankers and one commercial banker had a wide-ranging discussion at the Chadbourne global energy and finance conference in June about new trends in the market, with a focus on where 2017 and 2018 deal flow is likely to come from.

The panelists are Andy Redinger, managing director and group head, utilities, power and alternative energy, KeyBanc Capital Markets, Ray Wood, managing director and head of global power investment banking, Bank of America Merrill Lynch, Michael Proskin, managing director, power and utilities investment banking, Credit Suisse, Ted Brandt, CEO of Marathon Capital, and Ralph Cho, co-head of power for North America for Investec. The moderator is Rohit Chaudhry in the Norton Rose Fulbright Washington office.

MR. CHAUDHRY: What new trends do each of you see in the market?

MR. REDINGER: Four come to mind. One is the birth of US offshore wind. Two is the continued erosion of competitive electricity markets in the United States. Three is the market going long on wind turbines. A back-of-the-envelope calculation suggests that it is long by 20,000 megawatts. Four is the changing business model in the residential solar space.

MR. PROSKIN: One trend is the lower market-clearing prices in the recent PJM and NEPOOL competitive generation capacity markets, and specifically how they could potentially change the dynamic for construction of new conventional power plants across the country.

Another trend is the rapid decline in the cost of renewable generation. Utilities — Xcel is an example — are now saying they plan to build thousands of megawatts of wind or solar not just because it is green, but also because it is the best option for their ratepayers. They just want to be in a position to deliver electricity at lowest cost.

I don’t know how much offshore wind we will see built ultimately in the United States, but we will see some, and that sector is starting to get attention.

We are seeing a shift in the LNG market. Offtake contracts will be much smaller going forward rather than a single contract to sell the entire output from a production train to a single buyer. We will see LNG offtake contracts with small counterparties with poorer credits than a Shell or BP.

MR. CHO: We think M&A will be a big theme this year. Acquisition finance is a potential growth area for the banks.

The US market remains awash in liquidity. Many lenders are being super flexible in terms of what they are willing to do for sponsors in order to get some transaction volume going.

At the same time, we see growing weariness among lenders about quasi-merchant gas-fired power plants in PJM, which was a huge chunk of financing activity over the past several years. This is especially true after the recent capacity auctions.

I agree with what Andy Redinger said about residential solar. That financing model is in a transition phase.

MR. BRANDT: Five years ago, we were all talking about projects with 20-year power purchase agreements to sell their output to utilities. The stark new reality is the lack of long-term contracts across not just gas, but also renewables.

Low-cost renewables are something with which the market has not had to deal in the past. We are in the midst of a rotation away from expensive and dirty to clean and inexpensive. Nuclear and coal are at a disadvantage against cheap natural gas and renewables, which are gaining market share.

The other trend is abundant capital. There are massive amounts of capital looking for yield. This will remain true as long as the fixed-income markets and most of the developed economies do not offer much of a real rate of return.

MR. WOOD: There is a real dichotomy in the market. We have a wall of liquidity. Institutional investors looking for places to invest are now willing to invest in projects at the notice-to-proceed stage.

It has not been lost on pension funds, sovereign wealth funds and insurance companies that solar and wind are now mainstream assets. Such investors are sources of patient capital that are looking for the equivalent of contracted annuity streams.

At the same time, we have seen zero equity issuances by renewable generators. This is a market with a broad base of private capital, but it has not been a public equity play. That has also been true of the debt flowing into the sector. It has been primarily a bank market play and not really a bond play, although that might change in the future. Private but not public is one dichotomy.

The other dichotomy is that the wall of money and broad interest in global markets in renewable energy exist at the same time the new US administration is trying to rebalance energy supply toward fossil fuels. The market is weathering the potential disruption caused by Trump administration policies remarkably well: potential solar import tariffs, abandoning the Clean Power Plan, pulling the US out of the Paris climate accord, dismantling existing environmental regulations. As energy storage becomes more relevant and as electric vehicles become more cost competitive, there will be other disruptions.

The potential for change makes this a very exciting market. There is great money flow, but also a fair amount of uncertainty.

Merchant Gas

MR. CHAUDHRY: Michael Proskin and Andy Redinger both mentioned the PJM auction a couple weeks back as an important trend. Ralph Cho, what happened?

MR. CHO: PJM — the part of the US electric grid that serves 13 states starting from a mid-Atlantic core of Pennsylvania, New Jersey and Maryland and then working west all the way to parts of Illinois and Michigan — held an auction for generators who want to supply capacity. The winning bids were so low in some parts of PJM as to call into question whether very much new capacity will be built.

PJM has a lot of sub-regions. The capacity price in probably the largest sub-region was about $76 per megawatt day. That was down from $100 in the last auction. A lot of people were expecting it to be at the same level or slightly higher than before.

Other parts of PJM did okay. For example, the capacity price in the part of the grid owned by Commonwealth Edison was $187 or $188 a megawatt day. We have a financing currently in the market for a portfolio of gas peaking plants in the Con Ed service territory. It benefitted from the auction results.

MR. CHAUDHRY: Every time another new quasi-merchant gas-fired power plant has been financed in PJM in the last couple years, someone says this will probably be the last one to be financed. Yet the financings continue. What is the future for financings in PJM given these capacity prices?

MR. REDINGER: They will be difficult. However, all the recent financings have required the lenders to take a view about the long term. As I have said many times, lending to these projects is more art than science. For any more projects to get done in PJM, you need to be more artistic. You need to have a long view about the future that may be more optimistic than what the present is telling you.

MR. CHAUDHRY: An artistic banker. [Laughter] What does that take? What is the art we are looking for? So there are a few levers on which bankers lending in the PJM market focus. How will those levers change in light of these capacity prices?

MR. REDINGER: The levers on which banks focus are leverage, cash sweeps, pricing and the size of the balloon payment required at maturity. These financings have all been done with around 55% to 60% leverage. There is some level of cash sweep, but definitely not 100%. The banks do not want the balloon payment to exceed $375 a kilowatt of installed capacity.

There have been more than three dozen of these transactions. The majority have been greenfield projects. There are a couple new deals that are set to go to market over the next quarter. One is the Hickory Run project for Tyr and another is the Southfield project for Advanced Power.

The first thing to watch is what the updated forecasts of future capacity prices look like from the consultants. The banks will then plug the forecasts into a sizing formula to determine how much to lend. If the sponsor wants to raise more debt, it will have to lock in higher prices with a revenue put or other form of hedge. That has a cost, but it also produces more leverage.

The last transaction we did closed in February and was for Ares EIF. It had about 45% leverage. That shows the sponsors have a lot of skin in the game.

The latest capacity auction results mean the market will be moving toward lower leverage and a lower balloon payment at maturity, especially if you believe the equity valuations of the projects will fall as a consequence of the auction.

MR PROSKIN: If a couple of years ago, you had a downside case that had $80 a megawatt day for the 2020/2021 year, you would have found it not credible. That would have been viewed at the time as an obnoxiously low number. We saw leverage in the 45% to 60% range in the recent past. The latest prices will affect both leverage and sponsor returns.

MR. CHAUDHRY: The next deal on deck in PJM is Hickory Run. Ray Wood, if I am not mistaken, BAML is one of the leads on this. What interest are you sensing from the market? What is changing?

MR. WOOD: Leverage may be lower as a percentage of project cost. However, it is not lower against projected cash flow. We have a new set of forecasts that must be socialized. The stress point is not the availability of bank capital because we are talking about a loan-to-value ratio in terms of construction cost that is relatively conservative. The real issue is what are the investor’s returns? Maybe Andy Redinger is right that lenders will be looking at terminal value and ancillary service markets and a future 15 years from now to the extent they are using intrinsic value models. There is also an effect on ability to raise institutional capital behind the bank debt.

MR. CHAUDHRY: Michael Proskin, is it harder to raise debt or institutional equity for these projects?

MR. PROSKIN: There is no lack of bank capital. There is no lack of institutional and pension fund money. Neither one just got dramatically harder, but the numbers have changed. So, if a sponsor was expecting a return in the mid-teens on a merchant project, the numbers have come down.

There is less capital for a given project. It is not because of a lack of money chasing projects. It is because the cash flow projections have changed.

MR. CHAUDHRY: Andy Redinger, in light of these challenges — the low capacity prices in PJM — where are the opportunities in other markets? Where are people going to focus attention?

MR. REDINGER: You have to look at reserve margins. The region with the lowest reserve margin is ERCOT. The New England ISO is two or three on that list. Maybe New York is in the top four. PJM has double the reserve margin of these other regions.

M&A

MR. CHAUDHRY: Moving to a different topic, M&A transactions. Ted Brandt, give us a sense of M&A transaction volume so far in 2017 and how it compares to last year.

MR. BRANDT: We focus on renewables. The big one that was announced first quarter was the sale of sPower. That was almost $1.7 billion in enterprise value for a utility-scale solar company. The bidding was robust. My sense is that anything with operating assets and contracted inventory is moving very quickly. The bidders are enthusiastic.

EverPower is in the market now and has almost 500 megawatts of uncontracted, but fully constructed, wind projects without tax equity in it. The projects were all done with section 1603 payments from the US Treasury in place of tax credits. All reports are that the bidding on EverPower has also been robust. My sense is that the wall of money looking for assets is having an effect.

There is some inventory. A couple developers are for sale. There is an awful lot of what the European utilities call asset rotation. We are as busy as we have been in a couple years. I think the 2017 numbers will be way up from 2016. And looking forward, 2018 looks pretty good, as well.

MR. CHAUDHRY: Michael Proskin, do you agree with that? Are we in a deal-constrained market because of a paucity of deals or are there abundant opportunities to buy assets?

MR. PROSKIN: Ted talked about the renewables side. There has been plenty for sale on the conventional side in PJM.

You asked earlier what is next if not PJM. I still contend it is the best house in a bad neighborhood. ERCOT has a lower reserve margin, but good luck. That is a tough place to do business and stay solvent. NEPOOL has had a pretty big reduction in capacity price as well. California is a beautiful state, but I am not sure I want to own a power plant in California.

A lot of the assets put up for sale in PJM in the last year have been sold. Some have not been. There has been a lot of interest among Asian buyers, largely Japanese and Korean. There has been both buying of whole plants and use of subscription processes where buyers are paired in a consortium that either forms itself or is put together with the help of an M&A adviser.

I think we will still see more in PJM. However, the recent capacity prices could eventually lead to a disconnect between what sellers want and what buyers are prepared to pay unless a particular plant has special attributes like a very low heat rate or advantaged gas. It is hard to say where that happens for any given seller.

MR. CHAUDHRY: Ted Brandt, how are buyers valuing renewable energy projects? Do they simply discount cash flow or are valuations becoming more complicated?

MR. BRANDT: The approach to valuing operating assets has not changed. Spreads have probably tightened a bit given the demand for operating assets. The typical metric we see is 30-year discounted cash flow for wind and 35 years for new solar.

Projects that have not been built yet, but that have long-term power purchase agreements, still trade around net present value against some type of typical build cost.

Where the discounted cash flow approach to valuation really falls apart is when bidding for a development company. That tends to be more of a probabilistic scenario where you have to take a view on how much of the uncontracted development pipeline per megawatt will turn into positive net present value. sPower is an example where there was real money paid for a development company.

MR. WOOD: It really is both return of and return on capital. One bidder may be satisfied with a 9% internal rate of return and another needs 10 1/2% or 11%. We are seeing the cost of capital continue to come down which is a reflection of the wall of money and growing comfort with the asset class. People buying a development company with a portfolio may sometimes over allocate money to the operating side and take the position that they are getting the development pipeline for free. This is a psychological thing. When we look at development companies, we look at the kind of returns on capital the company has been getting. Such companies are currently in a great place in the economic cycle.

A preponderance of the value in the renewable energy business has moved downstream. When the cost to build projects declines, it hits the upstream side first. Margins have been tough particularly for the solar panel manufacturers. Developers winning PPAs in places like California wait 18 months to procure the equipment hoping that solar panel prices will have fallen further by the time they have to lock in costs. Developers are effectively short the panel price. They sell part of the project at the start of construction, which is effectively how developers monetize the investment tax credit on the project, and avoid a change of control after construction. This has allowed developers to earn a big gain.

When people see three or four years of big gains and an increase in installed volumes in solar because of the compelling unit economics, there is a rush to get into the development business. Then they have to decide what to pay for a development company that has been making four or five times invested capital per project in the past. They either take a leap and buy the company outright, as happened with sPower with its big fleet of assets, or they use some sort of preferred distribution structure that provides some downside protection but that means once they have hit an agreed multiple return on investment, they are taking less cash flow and the rest goes to the developer. That is called an earn-out model.

We are also seeing M&A volume in the regulated utility sector. It may have slowed somewhat year over year because of regulatory risk. Look at what happened with the Oncor sale in Texas. There is logic to trying to get scale on the wires side of the business.

There is also logic to trying to get scale on deployment of renewable energy projects. We are seeing this not only in Europe, but also in India, Latin America and parts of Asia. There is no lack of strategic dialogue with all the policy changes and changes in cost of equipment and capital. There is active interest among a number of strategic players to get more engaged in the sector in a hurry.

Private Yield Cos

MR. CHAUDHRY: One of the big drivers for M&A in the last two years was the demand from yield cos. That demand pushed up valuations. What replaces yield cos?

MR. BRANDT: The answer is we return to the underlying demand that was there before yield cos. Eight years ago, you would see private equity firms that would price development risk and operating risk the same way. That changed five years ago when private yield cos appeared and pension funds began to take a greater direct interest in the sector by recognizing that the risks should be priced differently.

They would make a commitment, often just before notice to proceed with construction, to buy or invest at the end of construction. This gave the developer a predictable cost of capital. The investor recognized that there was very little risk transfer. There was not an expectation of growth in cash flow over time as developed once the public yield cos appeared on the scene starting three to four years ago.

No one wants to be a public yield co today. Everyone wants to be a private yield co with a patient investor who is getting an 8% leveraged return. The developer retains the upside. There are some structures with preferred distributions, some P50 structures, but that seems to be what has been filling the void.

MR. CHAUDHRY: How do private yield cos work? Does the developer get a commitment from a pension fund like you mentioned for a blind pool of assets or only for specified assets?

MR. BRANDT: The developer usually has a group of projects under development. The private yield co or pension fund writes a check to the developer at notice to proceed for part of the purchase price to buy an interest in each project — 49%, 51%, 80% — and pays the rest of the purchase price at the end of construction. There is almost always some kind of forward commitment for the full portfolio around an agreed underwriting box where the investor commitment stands for the next three years as long as the underwriting hits these six or seven criteria.

The dirty word across the sector is blind pool. This is almost always deal-by-deal underwriting. There is some type of approval process on a deal-by-deal basis as new deals come in, but the basic construct is a forward commitment at an agreed discount rate. The rate is indexed. Virtually the entire commercial and industrial solar rooftop business is being funded that way, and more and more utility-scale developers are working this way.

MR. CHAUDHRY: Andy Redinger, is that what replaces the public yield cos?

MR. REDINGER: I agree with what Ted said. We are seeing the same thing. The difference between a private yield co and a public yield co is the public yield cos promised 12% to 15% returns that were unrealistic. A private yield co is what a public yield co should have been without the growth.

Shiny New Toys

MR. CHAUDHRY: Moving on, Andy Redinger, offshore wind was one of your new trends. How big will that sector be? Is it the next shiny new toy?

MR. REDINGER: It is hard to build new power plants on land near population centers along the US east coast. Capacity prices are increasing along the east coast from Delaware all the way into New England. These are constrained markets, either from a fuel perspective or transmission perspective. The best place to build may be offshore. There is a great wind resource offshore, and it is easier to build a new transmission line to bring the electricity to shore than it is to build a new line to move electricity long distances onshore.

Five states have now put out almost 5,000 megawatts of mandates for offshore wind. We are seeing the beginnings of an offshore wind industry in the northeast. I do not know whether it will head further south than Delaware and Maryland. We will see.

MR. BRANDT: Deepwater just got a PPA in Maryland. I agree with Andy that offshore wind will be the next new thing. My favorite example of this is that DE Shaw got a PPA to supply electricity to the Long Island Power Authority for something like 16¢ or 17¢ a KWh, which you would think is really expensive power, but it is a good price when you compare the 16¢ or 17¢ to zero need for LIPA to upgrade infrastructure to accommodate new capacity on land. When you add the infrastructure cost, the cost of competing power would have been something like 24¢. What these guys are doing is delivering 90 megawatts right at Montauk on the tip of Long Island. There is no other way to inject kilowatts in that area.

We think US offshore wind will be thousands of megawatts. You are clearly starting to see big global money coming into the sector. (For more discussion, see “Is US Offshore Wind About to Get Traction” in the June 2016 NewsWire and “Lessons from the US Offshore Wind Projects to Date” in the September 2015 NewsWire.)

MR. CHAUDHRY: Ray Wood, I want to get your take on what is the next shiny toy. Is it offshore wind or do you put your money somewhere else?

MR. WOOD: I think offshore wind is one answer for all the reasons that have just been mentioned. Technological improvements are making offshore wind competitive notwithstanding the collapse in the price of gas. There is a need for it. I don’t know if it is a shiny toy, but it meets economic and social needs in some key states in the northeast because of the unemployment levels and economic malaise in some of these towns. These are communities that can use the jobs. It is becoming politically expedient for senators and governors to support, and it is making more economic sense.

The truly next big thing is energy storage because it will transform the entire power sector. It is not a this year or next year’s story. We are probably seven to 12 years away from mass adoption. Storage is something to stay focused on, for sure in terms of major capital deployment and economic disruption to the existing business models.

MR. CHAUDHRY: Let me throw in a third possible shiny new toy and get the panel’s take on it: community choice aggregators, or CCAs, in California. At least one large solar project has been financed to date on the basis of a power purchase agreement with a CCA. Do CCAs have legs? Will we see a large number of deals done with CCAs?

MR. CHO: Our bank financed a project with a CCA as the offtaker. Do I think there will be a lot of transaction volume? I don’t know. We look at CCA projects almost like community solar projects where the real credit behind the revenue from electricity sales is a bunch of consumers. The issue for the banks is the CCA does not have a credit rating or financials. It is basically a pass through to the consumers. We end up structuring triggers and cash traps similar to a residential solar deal. The risks are slightly different, but ultimately you are looking to the consumers to pay. We have not seen too much activity around CCAs yet, but we are open to doing more than the one we have already done. (For more discussion about CCAs, see “Financing Projects with Community Choice Aggregators” in the June 2017 NewsWire and “Huge Potential New Demand for Power” in the October 2016 NewsWire.)

MR. CHAUDHRY: Michael Proskin, what are your thoughts on the next shiny toy?

MR. PROSKIN: I’m just concerned about somebody in Washington breaking the toys. [Laughter]

When we talk about the next shiny toy, we always have to be aware of external forces changing the rules of the game.

We have not talked about how the US energy secretary, Rick Perry, has commissioned a report that may find that intermittent sources of electricity, like wind and solar, are a threat to reliability of electricity supply and require government policy to shift in favor of encouraging more baseload power plants.

We have not talked about the threat of import tariffs on solar panels. Such tariffs could be imposed later this year. Solar tariffs could lead to a pretty big shift in the cost curve. One news network trumpeted the potential for such tariffs to save a couple thousand jobs. Another news network focused on the potential for any tariffs that are imposed ultimately to jeopardize a couple hundred thousand jobs. I look to counsel from the esteemed folks at Chadbourne, but I think that the president can pretty well just do what he wants, regardless of the recommendation from the US International Trade Commission. (For more discussion about the threat of solar import tariffs, see “Solar Companies Evaluate Tariff Options” in the June 2017 NewsWire.)