Developers on financing issues
A group of top finance officers at wind and solar developers talked about current issues crossing their desks at the 30th annual global energy and finance conference in California in June.
The panelists are Bernardo Goarmon, chief financial officer of EDP Renewables North America, David McIlhenny, managing director for project finance at SunPower Corporation, Esben Pedersen, chief financial officer of Pattern Energy, and Karen Derenthal Schmidt, senior vice president for project finance at Eurus Energy America Corporation. The moderator is Ben Koenigsberg with Norton Rose Fulbright in New York.
MR. KOENIGSBERG. David McIlhenny, putting aside advantages related to the abundant liquidity and low interest rates, what do you view as the most significant advantage your business enjoys and most significant impediment that your business faces over the next year?
MR. MCILHENNY: The advantage is that we are very good at identifying and optimizing energy project value, communicating that to customers and then executing to make it happen. We are good at moving from an idea to a real-life project. It is hard to do all of those things. There are lots of moving parts, and to coordinate and not to make wrong steps is a very difficult task.
There are two challenges. One is regulatory change, including changes in import tariffs, net metering rules, state regulations and government policies that affect what we do. Another challenge is other market participants who do irrational things based on unsustainable assumptions. SunEdison is an example of an irrational participant. It hurt SunEdison; the company went bankrupt. It also hurt the industry, including us, by offering PPA rates and lease rates to customers based on faulty finance assumptions that were unsustainable. We lost business and margin.
MR. GOARMON: I'll start with impediments, so the bad news. EDP Renewables is a low-risk-profile DNA organization. We believe this is important in the long run to be able to attract the most competitive capital. It brings challenges for a company that wants to grow by at least 1,000 megawatts of capacity a year. There is a race to the bottom for PPAs in wind and solar, but probably more in solar. At the same time, the nature of the counterparties is changing and their willingness to provide collateral is changing. The whole utility business model is going through a transformation. Community choice aggregators in California are an example.
The balance between risk and return is changing. Quite frankly, if you look from a global perspective and you have to make capital location decisions, the US is losing attractiveness versus other countries, not so much because of risk, but primarily because of declining returns. This is something new.
Now that I have your attention, here is the more positive news. We think our advantages are scale to leverage procurement and to secure optionality. This allows us to take limited technology risks knowing that there will be optionality to allocate risk within the portfolio. This is one advantage.
I believe the second is in-depth knowledge of the market. We are not here selling megawatt hours; we are serving the customer needs, and the arrangements are getting more and more complex. You have to transport power, you have to understand basis risk fully, you have aggregation of PPAs, you have REC agreements, and so forth. We believe we have strong capabilities in all of these areas.
One more thought about technology: storage and offshore wind projects will become a reality. Storage is already here, and offshore wind is a deep pockets game where project scale is important. We have been working on offshore wind projects for 10 years, in the United Kingdom and France, with 2,000 megawatts developed, so we believe we are well positioned to capture market share in the US.
Picking Niche Plays
MR. PEDERSEN: In some ways this conference is inside baseball. We all know well the competitive dynamics here. However, I talk to investors regularly about the fundamental advantage that our industry has and where we are with renewables. It is telling that we take for granted just how significant an advantage renewables enjoys today in the market, and how much this is still not really clear to the investor universe.
The second thing that contributes to our competitive advantage is that ESG has become a dominant driver for investors. It is something that we were not seeing 18 months ago. As evidence, anyone out raising a private equity fund will likely be told today by investors, "You can have my money, but you can't build a coal plant with it."
Pattern is an integrated developer-owner-operator, and that is really part of our advantage. We do not rely on an M&A market. We build for our own account for the most part. We sell a few projects after deciding what we want to own. Our sustaining advantage, frankly, as a company is our expertise in development. We have been doing this for 15 years as a team, and that means we have seen the cycles and can spot irrational exuberance. We are focused on macro-trends and picking our spots. We are not a volume-oriented business, so we don't just build to build. We pick a couple trends.
I'll give two examples of what we are doing.
For example, off-peak power is valuable today in the west. There is an abundance of solar, which means that there is value in delivering electricity outside of the hours when the sun is shining. That is one macro-trend that we have been following.
Another is we invested significantly in Japan. Renewable adoption there is less than 1%. Japan has only 3,000 megawatts of wind generating capacity, yet it is a 250,000-megawatt market. Japan wants to build 30,000 megawatts of wind over the next decades.
In terms of impediments, the market is challenging for all of us. We are in a shifting market. The erosion in the traditional utility model and the competition among different renewables suppliers on the delivery side will be significant challenges over the next two to three years.
MS. DERENTHAL SCHMIDT: I think our advantage is being part of a global group, so that allows us to pivot to markets where the risk-return makes sense.
That drove our move into South America four or five years ago. Being able to pivot back and forth among wind, storage and solar and among geographical markets is an advantage when returns are irrationally low in relation to risk in a particular market.
I think our challenges are the same as everybody else. We are in the midst of a transition from an infrastructure mindset to a commodity market-driven mindset. We have patient shareholders. Our most limited resource is the human capital to spend on endeavors that are going to end up with a project that gets done.
MR. KOENIGSBERG: David McIlhenny, returning to you. Solar companies must start construction of remaining projects by year end to qualify for a 30% investment tax credit. What is your thinking as a solar developer about the best way to start construction?
MR. MCILHENNY: If there is an easy way to preserve the 30% ITC, it is worth it, but it is not risk free.
If you start construction by stockpiling solar components to be used in future projects, those components will certainly become expensive components because costs will go down in the future. They can also become technologically obsolete. There is also a cost to buy modules or other equipment today to store in a warehouse for use in 2023. It is not a no-brainer to do it.
However, the value of the ITC is very strong and I think overcomes those problems.
MR. KOENIGSBERG: Developers who lack the money to stockpile equipment have been having challenges persuading lenders to make inventory loans for this purpose. The challenges revolve around collateral. If the lender just has the panels and not the underlying project, foreclosing solely on the panels does not allow the lender to sell them to someone else while preserving their grandfathered status for tax credits. How do you convince lenders to get around that risk if you don't want to offer up a full project?
MR. MCILHENNY: Plan A for the lender should be that the developer will use the modules in a manner that satisfies the safe-harbor requirements.
Lending money to a developer that has a long track record of success and a bright future going forward should be a key requirement. The collateral value of the components that you safe harbor will not repay the loan, unless the loan-to-cost ratio is low.
Another way that the lender could structure the transaction is to lend to a special-purpose entity or a joint venture that has more than one developer as an equity partner, so that there are multiple ways to use the safe-harbor modules in future projects.
Lastly, I believe it is very hard to buy modules right now. There is not much supply left, so if you have not started your safe-harbor program, it will be difficult.
MR. KOENIGSBERG: Would you tell someone to go with trackers or other components?
MR. MCILHENNY: If you think trackers or other components are going to be universally useful and not become technologically obsolete, then yes.
MR. KOENIGSBERG: Bernardo Goarmon, prior panels have talked about merchant risk. The market is moving toward power contracts with shorter terms, leaving more merchant exposure. How do you think about such risk, and what lessons have you learned?
MR. GOARMON: We see two big trends in the market. One is scale, about which I already spoke. The second is the need to make bigger bets. The bigger bets are in projects with smaller amounts of contracted revenue, leaving higher merchant exposure.
There are two aspects that we think are important when we have these investment opportunities. First, it is really important that the project be in the right place. Electricity basis risk varies by location.
The second is the percentage of merchant revenue. We reviewed the mix recently in our annual growth plan, and the percentage is still relatively modest, so maybe 20% to 25% at most. If you couple a somewhat longer merchant tail with a contracted revenue stream, you are optimizing risk-return. We are not minimizing return. It is something that we cannot ignore, because frankly it is the first time in years where it makes sense to entertain a little bit more merchant risk.
There are some projects where a flat PPA is worse than being exposed to merchant risk with a hedge or collar.
Lessons learned: people have short memories. It is really about leverage and volatility of power markets. Equity gets its return much faster in real life than it does in Excel spreadsheets. [Laughter]
The project really needs to stand on its feet based on intrinsic cash flow and not on financial engineering. No one pays salaries based on equity; they pay salaries based on cash.
Measures like short-term cash yield, five- and 10-year payback periods, percentage of NPV contracted and things of that nature are important. We sponsors are the residual cash flow.
MS. DERENTHAL SCHMIDT: Adding to Bernardo's list, not every good PPA is a good PPA. Even if you are able to leverage the asset at a lower gearing ratio, not every PPA is a good value proposition for a buy-and-hold investor like us. If there is no upside, the price is low and there is not a lot of risk sharing on other aspects of the revenue proposition, then from our perspective, it is not a good PPA.
MR. KOENIGSBERG: There is an interesting dynamic among the investors, the financiers and the developers. It is a question of whether you can convince the financiers to advance enough capital to get the deal done. It doesn't necessarily mean that you should have a long-term PPA.
MR. PEDERSEN: Can I make a comment on merchant risk? It is easy to say I should be able to move from a 20-year busbar PPA to a 10- or 15-year merchant deal if I can get it financed, but the market for owning such a project gets very fickle very quickly.
It comes back to the issue that you need to be at the right location. If you can't persuade yourself that you have a locational advantage, then you really have no hope of creating value.
There is something irreconcilable about where we are now with the build costs still being significant and the predominant driver of what return you can reach over time and having a variable income stream. It is a real challenge. You have to be very careful about the node where you are delivering power and whether it is an attractive location.
Electricity Basis Risk
MR. KOENIGSBERG: That segues into the next really important question, which is basis risk. This is the risk, when you enter into a bank hedge or a corporate PPA, that the node price at which the electricity is delivered to the grid is different than the hub price at which the hedge or corporate PPA is settled. How do you think about that risk? How do you manage it? What advice can you give people about it?
MR. PEDERSEN: First and foremost, you have to understand the dynamics in the project location. You can do things to retain operating flexibility that are valuable, such as being able to trade in the day-ahead market.
If you believe in your node, you may be better off not having a contract. Hedges exact a rent in order to facilitate a financing. You also need to be careful about covariance risk around your asset. It could go the wrong way, and you are stuck with high costs to deliver under a financial hedge that you put in place to facilitate the financing.
A pure merchant play may be a better proposition. We are financing a couple pure merchant deals. There are ways to do it, but it requires thinking outside the box.
MR. KOENIGSBERG: Karen, the lenders and tax equity investors put electricity basis risk solely on the sponsor. Esben Pedersen says finance on a merchant basis. That may not be an option, so how do you think about basis risk?
MS. DERENTHAL SCHMIDT: Shifting it fully to the sponsor is the, I'm sorry to say, brain-dead response of lenders. The alternatives are cash sweeps, lower gearing, reserve accounts, tracking accounts and similar mechanisms.
I think you need a project with enough money and flexibility to use some of those techniques. We grapple with it. It is a new element of our business. You need to be a power trader, you need to have in-house expertise, you need to manage it, and you need to make a determination whether there are other ways of financing.
We are wary about layering on an additional risk with multiple hedges.
We are moving away from single-asset leveraged financing. You need to make sure the financing fits the asset, and with a power plant, if the contracts don't lend themselves to a single asset, then you need to think about a portfolio. You need to think about a quasi-corporate deal. You need to make sure that you do not have the worst of both worlds, which is the cost of a non-recourse financing and a de facto full-recourse deal. So we look at the full range of options for where to source capital depending on the nature of the revenue stream and what we have in front of us.
MR. KOENIGSBERG: Are we at an inflection point on price where utilities think it makes sense to lock in long-term PPAs, and will we start to see more of those?
MS. DERENTHAL SCHMIDT: We see only our small slice of the market, so there may be others that have a broader view. We don't see a big jump or a big long-term insurance value.
We are looking at niche markets where there is still value for some sort of a premium on a bilateral basis. We are looking for the uncut diamond. I am not waiting for a big upturn in PPA prices over the next 24 to 26 months. I think it will take more time.
MR. PEDERSEN: There are a couple of factors at work, and they don't move in the same direction.
We are nearing an inflection point where we could see build costs start to change. Once the tax incentives expire, that converts quickly into anxiety about what the prices are going to be. Once the prices start to move up, potential offtakers start clamoring for contracts.
I don't see that happening immediately; maybe two or three years from now. Macro-policy on carbon pricing could also drive such a change. These are the types of things that make people consider their options.
The factor that cuts in the other direction is we see utilities increasingly wanting to own the generating assets. BOT contracts may turn into the solution for minimizing basis risk. There will still be a role for developers. Utilities have never been very good at developing.
MR. KOENIGSBERG: Bernardo Goarmon, let's talk briefly about offshore wind. EDP has a joint venture with Engie and another joint venture with Shell to develop offshore wind projects. We saw a record price of $136 million paid the other day to buy an offshore site lease. At the same time, the tax credits for wind projects are winding down. There are lobbying efforts to extend the ITC for offshore wind.
How does a company that is just starting work on an offshore wind project compete with others who already have a tax-credit strategy in place? How do you win a power contract auction against other projects that qualify for tax credits?
MR. GOARMON: Let me try to answer in a different way.
Obviously offshore is important to us as we announced two weeks ago a joint venture with Engie with a target of 5,500 megawatts. This is substantial.
I personally never thought offshore would come so quickly to the United States, primarily due to the absence of a supply chain, but the reality is that it is here.
It is unrealistic to expect an industry to be built without having regulatory certainty. The economics don't work with the current technology. There have been instances of people trying to mitigate a little with cables and so forth, but it is unrealistic to expect companies to deploy hundreds of millions of dollars five or six years in advance of start of construction.
Two competing bills are being introduced in the US Senate to extend the deadlines for offshore wind to qualify for a 30% investment tax credit. One of the bills would give developers until the end of 2026 to start construction or, if later, until the industry reaches 3,000 megawatts. This is what the industry needs. It is an industry that will create a significant number of jobs. It is an industry that has an incredible supply chain with a very high multiplier. You cannot expect such a capital-intensive business to work without having certainty.
MR. KOENIGSBERG: Does US offshore wind make sense economically today?
MR. GOARMON: For certain markets, yes, primarily the east coast, particularly the northeast. In areas like Japan and California, it makes sense to deploy a floating technology. We have had such a technology since 2008. Offshore is becoming a price check to some of the onshore PPAs, so it is here.
MR. KOENIGSBERG: Last question. David McIlhenny, how will storage affect your business? Will all of your solar projects have storage in two years?
MR. MCILHENNY: We look at adding storage to, or having storage on, every new distributed solar system we install. They don't all pencil out. We only put storage where it adds economic value, because the customers don't want to pay for it otherwise. We are also looking at our deployed fleet of projects to see where storage might add value as an add-on. This is just a guess, but perhaps 20% to 25% of the projects we are doing now have storage, and I expect the percentage to increase.