New trends in financing wind farms
Four top executives of prominent wind companies talked at the Global Windpower 2016 convention in late May in New Orleans about new trends in financing wind farms, whether we have reached a tipping point where most future power contracts will be with corporate offtakers rather than utilities and the financing challenges created by heavier reliance on such contracts, new financial products for which there would be demand from wind companies but that no one is offering currently, the current cost of capital, the ratio in which companies are drawing from different types of capital, current discount rates being used to value projects, and a range of other topics.
The four are Tom Festle, chief financial officer of E.On Climate & Renewables North America, the North American arm of the German utility, E.On, Pete Keel, chief financial officer of Longroad Energy Partners, a new company established by the core team that was behind First Wind, Jim Murphy, executive vice president, chief financial officer and president of the operating business group at Invenergy LLC, and Michael Storch, executive vice president and chief corporate development officer of Enel Green Power North America, the North American arm of the Italian utility, Enel. The moderator is Keith Martin with Chadbourne in Washington.
MR. MARTIN: Tom Festle, what new trends are you seeing in financing wind farms?
MR. FESTLE: We see an ever-increasing interest among commercial and industrial users of electricity in wind and solar. That is not a financing trend per se, but it drives what we need to do to get transactions built and financed. Being a German utility, we use our own capital to pay for construction, and we raise tax equity once our projects have been built, and that really has not changed much.
MR. MARTIN: Pete Keel, new trends?
MR. KEEL: Another trend is a focus on minimizing the share of cash that the tax equity is taking so that it can be monetized through back-levered debt or retained by the sponsor. Your cheapest capital is going to be debt. It is much cheaper than tax equity, so trying to maximize the cash that can go to that part of the capital structure is very important.
MR. MARTIN: US Bank pioneered a structure where it takes cash each year equal to 2% of its investment as a preferred cash distribution and not much beyond that. Are you seeing other tax equity investors offering the same structure?
MR. KEEL: The US Bank structure is really more of a product for use in the solar market where projects qualify for investment tax credits. It does not work as well for wind farms on which production tax credits are claimed. Solar sponsors, for the most part, really like the structure. We are not seeing anything exactly like that structure from any other tax equity provider, but most tax equity are trying to be more accommodating on leaving more cash for the sponsor. The days are long gone with the tax equity investor takes 99% of cash before the flip.
MR. MARTIN: Is the most common cash sharing ratio today 60-40, 50-50, 40-60?
MR. KEEL: More like 70% for the sponsor and 30% for the tax equity investor.
MR. MARTIN: When that happens, the sponsor’s capital account, or the measure of what he put in and what he takes out, tends to go negative.
MR. KEEL: That’s right.
MR. MARTIN: Are you seeing tax equity investors require you to promise, as a sponsor, to put cash equal to the capital account deficit back into the partnership for redistribution to the tax equity investor when the partnership liquidates?
MR. KEEL: In some cases. The fact that the capital account goes negative may be a limiting factor in the ability of the sponsor to keep a disproportionate share of the cash. The other limiting factor is the cash-on-cash return that the tax equity investor is looking for. The investor needs at least a minimum cash-on-cash return. Some investors are more aggressive than others. You see a pretty big difference across the market in terms of what people will do.
MR. MARTIN: How do you feel as a sponsor agreeing to put cash back in? You thought you had a deal where you were getting 70% of cash, but there is an asterisk.
MR. KEEL: We are not crazy about it. We never promised to put any money back into the deal at First Wind.
MR. MARTIN: Jim Murphy, what new trends are you seeing in financing?
MR. MURPHY: In addition to greater interest from corporate offtakers, we are seeing more utility interest in owning assets to put in rate base.
Pete Keel talked about tax equity. Maybe I will touch on so-called cash equity, or what some call true equity. There has been a surprising resiliency of capital sources filling in where we had some contraction from the yield cos. We have seen strategics. We have seen funds. We have seen some REITs and other institutional investors coming into the space, and it has been helpful and surprising, and I think it will continue.
MR. MARTIN: I assume the REIT is Hannon Armstrong, and REIT participation in the wind market is lending? Are the other investors pension funds, insurance companies? What types of investors are they?
MR. MURPHY: Pension funds, insurance companies, and as I mentioned, strategics, primarily domestic utilities, looking to take positions. Hannon Armstrong also takes equity positions.
MR. MARTIN: When the utility comes in, does it just want to buy the project in order to put it in rate base, or will utilities sometimes just put in a share of the equity?
MR. MURPHY: We have done both.
MR. MARTIN: Mike Storch, new trends?
MR. STORCH: I feel like they are probably old trends by now it took so long to get to me. [Laughter] One thing that is interesting is the tax equity market has become much more competitive. There is much more willingness to break away from the mold in terms of trying to tailor deals to better meet the sponsor’s needs.
A good example, and Tom Festle can probably appreciate it as well, is sponsors whose parent companies are not domiciled in the US are subject to international financial reporting standards and, under those standards, tax equity is treated as debt. The primary reason for that is there is a target return in the financial arrangements with tax equity and, until the tax equity investor achieves that return, it owns certain entitlements, particularly with respect to cash, and that triggers treatment as debt.
That can have a fairly significant impact. We have done a few billion dollars of tax equity in the past few years alone here in the United States, all of which gets treated as debt. If you eliminate the target yield and have a fixed flip date, then the tax equity is not treated as debt. We are in the middle of such a transaction now. We would like to see it become a trend. With the entry of so many new investors, we finally have a competitive market for tax equity.
Another trend that has financing implications is low PPA pricing. We are seeing power contracts with electricity prices in the teens per megawatt hour of electricity, and it creates a lot of challenges with tax equity since there is not as much cash. The PTC is worth more than the cash you get from power sales in a lot of cases.
MR. MARTIN: Why do you care whether the tax equity deal is treated as debt or equity for purposes of international financial accounting?
MR. STORCH: We are very sensitive to how much debt we have on our corporate balance sheet. We are a public company. We have more than €40 billion in debt, much of it related to the acquisition of Endesa. Every CFO is always focused on his credit rating and maintaining adequate coverages to maintain or get to investment-grade status, because it affects the cost of money.
MR. MARTIN: Tom Festle, in the fourth quarter last year, 75% of PPAs signed by wind developers were corporate PPAs. Have we reached a tipping point where we expect to see more corporate PPAs in the future than utility PPAs?
MR. FESTLE: I hope so. Certainty of offtake is important to all of our investors, whether they are providing debt, tax equity or true equity. Certainty of offtake and creditworthiness of the offtaker are of paramount importance. It is great to have utility customers, but it is even better that there is growing demand from potential commercial and industrial customers.
MR. MARTIN: Does any of the rest of you think we have reached a tipping point? Mike Storch, you told me before the panel that you think we will be at a point soon where half the power contracts are with corporate offtakers.
MR. STORCH: Yes, but I am not as enthusiastic. It is good from a competitive standpoint, but the commercial players are very difficult to contract with.
MR. MARTIN: Harder than utilities?
MR. STORCH: Utilities pass through the cost. It is a different environment. With a corporate customer, you really have to think whether the proposed terms will help the customer be more competitive in terms of the long-term impact on its credit profile. You have to care about that more from a commercial perspective.
Also, the commercial players almost always want the project to take basis risk for the spread between the cost of electricity at the bus bar and at the pricing node, and that type of risk is very difficult to hedge, especially when dealing with a resource like wind. Those spreads can be huge, plus they move around a lot because of the changes in membership in different RTOs that manage the grid. New groups are joining different RTOs, not necessarily in a logical way. Entergy is part of MISO. Why does that make sense?
MR. MARTIN: If the sponsor has to take such a large risk to secure a corporate PPA, then why do you think the market will shift to 50% corporate PPAs?
MR. STORCH: Industrials will continue to want to contract directly for power. The financing folks will eventually develop products to hedge this risk more effectively or we will figure out how to share it with the industrials. We just did an industrial deal where the industrial will take the power at the bus bar. It did not push the basis risk back to us because the risk would otherwise get baked into the electricity price and it can be very, very expensive and very difficult to quantify.
MR. MARTIN: Where is the basis risk in the typical utility deal?
MR. STORCH: Utilities are used to taking electricity at the bus bar. They can pass through the full cost of the electricity as a purchased power expense. It is just a different way of thinking. Utilities, too, are getting more sophisticated. Utility PPAs look different than they did five or 10 years ago in terms of the risk sharing that takes place and the burden that is imposed on the generator.
MR. MARTIN: Jim Murphy, have we reached a tipping point where most PPAs will be with corporate offtakers in the future, and what special financing challenges do corporate PPAs present?
MR. MURPHY: I don’t know whether we have reached a tipping point. We have had cycles before where utilities have backed off PPAs and then come back in force. I think we are seeing a move by utilities toward ownership and not PPAs. We appear to be in the middle of such a trend today.
Will it tip back? I don’t know. There is a limit on the number of corporate PPAs that are possible because you can only do those deals in organized markets. You have to have the right mechanism to be able to do a contract for differences, which is the way most corporate deals are structured.
Clearly it is a trend. The last four deals we have done as a company are with corporate offtakers.
In terms of special financing issues, Tom Festle touched on those. How creditworthy is the offtaker? Is the credit the top entity that has a credit rating or is it a subsidiary that owns a data storage facility, for example? If it is not the credit-rated entity, then how much security is appropriate? Is the security a letter of credit? Is it a bond? All of that is fairly unique to these contracts.
The last thing is to echo in spades what Mike Storch said about basis risk. Most deals we have seen involve allocating basis risk to the sponsor, which is different than the utility model.
MR. MARTIN: Are you comfortable taking basis risk?
MR. MURPHY: Yes. We have to fold it into the electricity price, and we have to think about ways to hedge it as well.
MR. MARTIN: Pete Keel, what special financing challenges do corporate PPAs present?
MR. KEEL: Basis risk, absolutely. The proliferation of corporate PPAs is a great trend. We are happy to have more buyers for our product, but, on balance, corporate PPAs are not as clean as utility PPAs. Other things being equal, they are less valuable because of the basis risk. The tenors are also not as long.
MR. MARTIN: What are the tenors?
MR. KEEL: Ten to 12 years seems to be the sweet spot, so 10 to 12 years with an entity that may or may not be investment-grade and with basis risk versus a 20-year contract with an investment-grade utility whose terms are down the middle of the fairway. Those are very different deals.
New Financial Products
MR. MARTIN: Tom Festle, what new financial products have investment bankers and others been pitching to you recently?
MR. FESTLE: We avoided the yield co out of an abundance of caution. That was the last major product being sold to us in which we declined to participate. For us, it was a tradeoff between the very low cost of borrowing as a German utility versus some passable upsides we might have had on the cost of equity. No one has been pitching us any new ideas recently.
MR. MARTIN: Mike Storch?
MR. STORCH: We are hearing noise that turbine loans might make a comeback. The recent IRS guidance means that people may be looking now at holding turbines for as long as four years. It is a long time to hold equipment, especially for companies that expect significant growth over the next four years.
MR. MARTIN: Turbine loans used to be a product on offer from German banks. Are such banks back pitching such loans?
MR. STORCH: The talk is coming mostly from investment bankers who wonder whether a market will develop.
MR. MARTIN: Pete Keel, are you seeing any other new products?
MR. KEEL: Given what happened to yield cos, I think the exotic stuff is out right now and it is back to basics. Whether it is yield cos, high-yield debt, the term loan B market, none of those products is getting much traction at the moment.
MR. MARTIN: Let’s move to another topic. Renewable energy companies raise capital from six tiers of capital from cheapest to most expensive. The cheapest capital used to be Treasury cash grants. They remain available only for solar. Next cheapest are export credits and government loan guarantees. Then you have straight debt, tax equity, subordinated or mezzanine debt, and true equity in that order.
Tom Festle, in what ratio do you draw on these different sources of capital to finance projects?
MR. FESTLE: We only use two of those in the typical project. The first one is sponsor equity. It comes from our German parent, which has really low borrowing costs, and covers maybe 30% to 40% of our typical project cost. The remainder is tax equity.
Like my colleagues, we try to minimize the amount of cash that we take from the tax equity investors as well as end up paying back to them. We want them to use the tax attributes.
MR. MARTIN: Do you use back leverage to monetize the cash?
MR. FESTLE: We have used it in only one joint venture transaction involving three Treasury cash grant projects. We used portfolio debt. We have not used back leverage otherwise.
MR. MARTIN: So 30% true equity and 70% tax equity. Mike Storch, it is the same ratio for Enel?
MR. STORCH: The tax equity percentage may be creeping up a little because we are seeing these incredible capacity factors. It is not unusual to see capacity factors above 50%.
MR. MARTIN: That means more production tax credits. Therefore, you raise more tax equity. Jim Murphy, what does your capital stack look like?
MR. MURPHY: A little different. We are an independent, privately-held company, and so we are doing 100% project financing. We do not have a corporate parent to lean on.
I agree that the percentage of tax equity has gone up. A few years ago, it was not unusual to have maybe 40% in tax equity. Now we are seeing 60% in some cases. We sometimes put back leverage behind the tax equity. Back leverage can be quite a headache, and we are running into a lot of difficulties working with tax equity investors to accommodate the back leverage and what they want on issues like change of control.
The back leverage tends to work better on projects with long-dated offtake agreements because we can stretch out the tenor and get some volume. Whether or not we use back leverage, we are filling out the stack with a combination of sponsor equity and third-party cash equity. The ratio between the sponsor and third-party equity varies. Sometimes we offer the third-party cash investor common equity and sometimes we offer it preferred equity. When we do the latter, we can increase the percentage held by the third party.
MR. MARTIN: You said there is tension between the tax equity investors and back-levered lenders. You said one source of tension is restrictions on changes of control. I imagine another issue is a cash sweep to pay indemnities. Are there other issues besides those two?
MR. MURPHY: I think those are the main issues.
MR. MARTIN: On change of control, why does the tax equity chafe at the lender coming in and replacing the sponsor?
MR. MURPHY: It cares about who is operating the plant. If the sponsor is no longer there, then it wants to make sure there is another experienced operator with deep pockets.
MR. MARTIN: Pete Keel, does your capital stack look more like Jim Murphy’s than the E.On and Enel capital stacks?
MR. KEEL: Yes, definitely more like Jim’s. The other thing to consider is where are you in the life cycle of the project because that affects the shape of the capital stack. During development, it is all equity. This is the period of greatest risk, and it is hard to raise financing.
To get into construction, we try to borrow construction debt to cover as much as possible of the cost. The construction debt will be sized to what the takeout financing looks like. Usually it comes in at 70% to 80% of the total cost and the remaining 20% to 30% is equity.
The permanent financing once we get to commercial operation is some combination of tax equity, debt, and true equity.
The development equity is high risk, high return, and the permanent equity is lower risk, lower return.
MR. MARTIN: Do any of you rely on export credits from foreign export-import banks? Mike Storch, you are shaking your head no.
MR. KEEL: We do some of it in Latin America, but nothing in North America.
MR. FESTLE: No.
MR. MARTIN: What about government loan guarantees?
MR. FESTLE: We have not used the DOE loan guarantee program.
MR. KEEL: We did at First Wind. One of the lessons for us was you end up with a more complicated structure and a lot of legal fees and questions whether the time and cost are worth the benefit. It sounds good, but we decided we were better off keeping things simple.
MR. MURPHY: We looked at it as well back in 2009 when the first program came out. We had the same experience. We took it well down the road on one project and had to push the eject button because we could not wait that long. The wind turbines were arriving at the site and we had a schedule and the process at DOE was moving too slowly.
MR. STORCH: There is no substitute for dealing with experienced lenders and sponsors, because there are always challenges. When you deal with the right people, they understand that and they can make informed decisions reasonably quickly. The government is usually not in that category.
Cost of Capital
MR. MARTIN: What is your weighted average cost of capital? Tom Festle, you are laughing.
MR. FESTLE: I’m sorry. I think I am prohibited from sharing that number, but I can say the trend line is modestly downward. Our company is very focused on maintaining a strong credit rating in the German public markets. Borrowing costs are very low at this point in time. Renewable energy projects are now considered investment grade, and that helps with the cost of equity, as well.
MR. MARTIN: So the trend line is down due to two factors. One is macroeconomic and the other is the market is getting more comfortable with this type of project. Pete Keel, do you have a weighted average cost of capital?
MR. KEEL: We look at every opportunity as a discrete opportunity and then divide things into development versus permanent financing. Development capital needs to earn a 20+% return, and it is probably more oriented around a multiple on the money invested because it can be pretty short duration. It demands a higher internal rate of return. It is short duration. It has been playing more for multiples.
For permanent financing, the cost of debt is going to be LIBOR plus 175 to maybe 300 basis points, depending on where the debt sits in the capital stack. Tax equity is around 8%. Third-party cash equity is 9% to 12%, maybe even 13%, depending on what the PPA looks like.
MR. MARTIN: Then you take the ratio of each in the capital stack and that gives you the weighted average cost of capital.
MR. KEEL: Correct, but the capital structure changes over time as you amortize tax equity, as you amortize debt, so you really need to layer in the third-party money, tax equity, debt, and then discount the cash flow on that strip of equity. That is the truest way to value an asset.
If you can raise capital at the parent level and put a bond on that is not amortizing, then the equation changes.
MR. MARTIN: Jim Murphy, what is your weighted average cost of capital?
MR. MURPHY: Yes. I guess I will have to take some evasive action . . . . [Laughter]
MR. MARTIN: In which direction is it moving?
MR. MURPHY: I agree with Tom Festle. It is going down.
I am a little frustrated, frankly, that tax equity has not come down more, and I think all of us on this panel share that view and have for a long time. There have been some new entrants, and that is helping a bit, but tax equity has remained stubbornly at 8%. You will hit the flip yield at maybe 7.5%, but the tax equity has a residual interest and there are limitations on what the sponsor can pull out of the project if the tax equity has not reached certain hurdles on the cash side.
The tax equity has a secure enough position that its yield feels overpriced to us. An 8% after-tax yield is equivalent to a 12% pre-tax yield. The fact that the debt is prepared to take the identical risk for a hugely lower cost continues to confound us.
MR. MARTIN: Your company took the lead years ago in pressing for master limited partnerships. The initial thought was that this could be a route to bring in more individual and institutional investors as tax equity. Are you as enamored today with the MLP as a potential source of financing?
MR. MURPHY: Definitely not. An MLP could be a source of cash equity. It really never made sense to view it as a route to additional tax equity investors. We thought that there could be a way to modify the structure, but at the end of the day, it is a cash-oriented product.
MR. MARTIN: Has the fact that people figured out how to do yield cos supplanted the need for MLPs?
MR. MURPHY: Yield cos were developed as a response to the inability of Congress to add wind as an eligible class for MLPs, and I think it has done a fine job filling the gap.
MR. MARTIN: Mike Storch, I can see the pattern here on weighted average cost of capital, so let me take this in a different direction.
MR. STORCH: Thank you. [Laughter]
MR. MARTIN: Development loans used to be on offer for smaller developers. For example, Heller Financial in Chicago offered such a product. You don’t see it much anymore. What financial products are missing today for which there could be a market? We need a product to hedge basis risk. What else?
MR. STORCH: Development capital is certainly an area that requires a lot of attention. A lot of what goes on in a public company is tied to the accounting results. Development costs are expensed for book purposes. Until a project is certain to move forward, you do not capitalize them. This has a pretty big hit on P&L. For a company like Enel, lending money to a smaller developer for the rights to buy a project if the project succeeds can be a very effective way to achieve our goal of building a development portfolio without owning it and having to expense all of the development costs.
Companies like Enel and E.On can make development loans to smaller developers at far less than the 20+% cost to which Pete Keel referred. It makes sense for strategics to offer this product. Commercial banks have much less interest in it.
MR. MARTIN: So turbine loans might make a comeback. There is a clear need for development loans. What other financial products are needed in the current market?
MR. FESTLE: One of my colleagues pointed to inability to hedge basis risk, or the variation in electricity price between the bus bar and the hub node. I would love to see a more effective and more tailored product for the wind industry that can help to address that in an efficient way.
MR. MARTIN: Are there are any other missing products?
MR. KEEL: I am curious whether anyone thinks that turbine loans are really coming back. There was a lot of carnage related to turbine loans seven or eight years ago.
MR. MARTIN: Why was there carnage?
MR. KEEL: The carnage bled right into the financial crisis. A lot of developers had turbine loans. They had gone long on equipment, and this drove up turbine prices. There were a lot of developers sitting on excess turbine inventory. Repayment of the turbine loans was often guaranteed by the parent. You had a lot of secured debt maturing against assets that were illiquid and were overpriced. I wonder if the banks will do that again and I wonder whether it is the best thing for the industry, having seen what happened the last time.
MR. MARTIN: Are any other products needed? Are you using tax credit insurance, for example?
MR. MURPHY: No, we are not. The product that is missing, but for which I am not holding my breath, is a more effective way to monetize tax benefits.
MR. MARTIN: It is called a Treasury cash grant, right?
MR. MURPHY: Refundability, transferability, those features. We are still pushing to see whether we can make some inroads on those sorts of features.
MR. STORCH: I always wanted to see the PTC be something that all of us in this room could buy on line and use on our personal returns and feel like we are supporting the renewable energy industry. There could be an on-line clearing house. People could buy them at face value or maybe there would be a bidding process. A larger share of the subsidy would end up being spent on the project rather than going to middlemen and being spent on transaction costs.
The government would not have to write checks. The credits are getting used, and every American could participate. It would not be that tough to implement.
It is hard to explain to foreign investors why you have to raise financing in order to monetize a government incentive. It is a foreign concept in Europe. In Italy, it is actually illegal to do something like the tax equity deals in this country.
They are not efficient. They are incredibly complicated. They put a lot of expensive people, known as attorneys, to work, but that is what we do. It is our culture. In Europe, they are much more sensible. They use feed-in tariffs and very simple mechanisms that do not require the same level of complexity and transaction cost.
Private Yield Cos
MR. MARTIN: Next topic. Yield cos were the shiniest new object within the last three years. Yield co share prices took a hit after July 22 last year. Some people expect them to make a comeback later in the year once there is a change in shareholders from the hedge funds who were the initial investors to insurance companies, pension funds and other sources of more patient capital.
None of your companies set up a public yield co, although Pete Keel’s company, First Wind, sold its assets to one. Is the basic concept of separating operating assets from the development pipeline a good one, so that you can raise capital more cheaply against the operating assets?
MR. KEEL: I think so. The asset classes are different. A development property is far different than a fully-financed construction or operating property. It makes sense to separate those given their different risk profiles. The market forces a separation. There are lots of infrastructure players who are in the market acquiring assets, and none of them will take development risk.
MR. MARTIN: E.On and Invenergy have not split the two types of assets. Enel did a private yield co. E.On and Invenergy, do think the concept makes sense and, if so, why aren’t you using it?
MR. MURPHY: I think the concept makes sense. There are two reasons we have not done it. One reason is we did not understand the model with the promise of growth. We have no problem separating development from operating assets. They have different risk profiles, but we did not understand the growth component that the market was looking for, and so we were not attracted to it for that reason.
The second reason is we are a private company and we want to stay a private company, and we do not want to add all of the bells and whistles and complexities of being a public company. At the end of the day, we are in the development business. It is a complicated business. It is one where it is difficult to explain why you do what you do because you have to make things happen simultaneously and be very creative in how you execute.
So we do not like the public model. We do not like to have to dedicate management time to reporting, to shareholder calls, and the like. Those are the reasons we avoided it.
MR. MARTIN: Mike Storch, Enel did a private yield co. It put something like 49 operating projects into a separate vehicle and brought in a co-investor. If you had to do that over again, would you?
MR. STORCH: Yes. It made perfect sense. We did not sell it as a growth engine.
I agree with Jim Murphy. The whole yield co model did not make sense. You are selling the idea that you will issue equity in the future to support buying more projects. Interest rates are at an all-time low, so why would you do that? Interest rates are likely to go higher, and yield expectations will go up. It just did not add up.
Separating operating assets from the development portfolio makes sense as long as you are clear that you are selling something close to an annuity. We will consider offering future assets to that vehicle for a fair price based on where the market is at the time under a right of first offer.
MR. MARTIN: Next topic. The IRS issued a notice in early May about starting construction of wind farms. Projects must be under construction by the end of this year to qualify for full tax credits. If the project is then finished within four years after the year in which construction starts, tax credits can be claimed. If the project takes longer, then the developer must prove the work on the project was continuous.
The notice has caused a lot of pain for developers who in 2012, 2013, 2014 did modest amounts of physical work at the project site in order to claim their projects were under construction. This has come back to haunt them. The new four-year clock runs from that earlier date. Tom Festle