Community solar financing issues
Community solar is a form of independent power project whose output is sold at retail rates. The financing community is just starting to get its arms around the risks. What are the risks? Can this type of project finally get traction with tax equity investors and lenders? A panel of three community solar developers, a lender and a tax equity investor talked about these and other questions at the Chadbourne annual global energy and finance conference in early June. The following is an edited transcript.
The panelists are David Amster-Olszewski, CEO of SunShare, Mark Boyer, chief capital officer of Clean Energy Collective, John Eber, managing director and head of energy investments at J.P.Morgan, Sanjiv Mahan, president of WGL Energy, and Vinod Mukani, head of infrastructure and energy financing for the Americas for Deutsche Bank. The moderator is Marissa Alcala with our Washington office.
MS. ALCALA: There are a number of myths about community solar. The first myth that I want to dispel is that community solar is a new asset class. Mark Boyer, is it a new asset class or is it simply that some potential equity participants, lenders and tax equity investors are taking time to come up the learning curve?
MR. BOYER: We have been doing it since 2010 and have been able to finance all of our projects, which is 100+ projects around the country in multiple states.
It is taking a long time for the financiers to come up the learning curve. It has not been a matter of walking into a bank and saying, “I have a community solar project,” and then having the bank evaluate it the same way it evaluates a commercial and industrial solar project or a project with a long-term power purchase agreement with a utility.
Our early deals had take-or-pay power purchase agreements with electric cooperatives that supplied the electricity, in turn, to the community. We financed our projects based on these PPAs.
Then we layered in community solar where the coops helped us find the subscribers, but always still with a take-or-pay PPA with the coop as a backstop. That is about half our business right now.
The places where it looks like a different asset class are in states like Minnesota, where David Amster-Olszewski is doing a ton of work, or Massachusetts or Colorado, where you have different regulatory regimes for community solar. It is taking the financial community a long time to come up the learning curve.
Community solar is clearly getting traction. We are seeing a lot more people interested in it and trying to get comfortable with the risks around the offtake arrangements, because that is where it all lands at the end of the day.
MS. ALCALA: So community solar is a diverse asset class. David Amster-Olszewski, how long have you been doing community solar projects?
MR. AMSTER-OLSZEWSKI: We have been developing projects for about five years.
MS. ALCALA: So community solar does not seem new to you either.
MR. AMSTER-OLSZEWSKI: I guess to the market perhaps it is a new asset class, but the concept of it is not new at all. In fact, if you look at our executive team and our board, we stacked the team with a lot of telecom experience. Think of community solar as more of a wireless cell phone plan and it does not look like such a new asset class. You have a remote asset from which customers receive a service. There is no equipment bolted to the roofs of their houses. You do not have to roll a truck if a customer defaults. You just switch off a meter.
Our cost of customer acquisition is down to $300 a customer, so if you compare that to the rooftop residential companies’ costs of $2,000 to $6,000 to acquire a customer, it is a massive difference.
MS. ALCALA: Community solar is looking better by the minute.
MR. AMSTER-OLSZEWSKI: There are more useful parallels perhaps between community solar than to the power industry. You could also look at community solar as taking the best from among the three existing types of solar projects. It has multiple customers and, therefore, risk diversification like the rooftop sector, only it is easier to deal with customer defaults by simply switching the service to another customer on a waiting list. You have control over the asset like you would if it were a utility-scale project. You have the benefit of a lower cost to construct due to scale and the ability to put the solar arrays where they will maximize output.
So it depends how you look at it, but I do not think it is that new of a concept. You are just putting together different pieces in a new way.
MS. ALCALA: Another myth about community solar is that the projects cater primarily to individuals as customers. Sanjiv Mahan, Washington Gas is doing community solar projects that are focused mainly on commercial subscribers, right?
MR. MAHAN: That is correct. We are approaching community solar in a very slow and progressive manner. We have watched what others have done over the past few years, tried to learn from their experiences and focused on what seems the best fit for us.
We have been focused on the C&I aspects of the business. We wanted in Minnesota to learn first how the market works, so we started with 40- and 50-kilowatt systems. An organization like ours does not usually play in such small systems, but we wanted to learn the local landscape. We worked with local developers and local communities. From there, we moved to larger projects with Xcel, and now we are moving to build up a subscriber base.
MS. ALCALA: Deutsche Bank has done financings of community solar projects. Vinod Mukani, is it easier to finance projects with a mix of residential and commercial subscribers?
MR. MUKANI: I find this discussion very interesting. David Amster-Olszewski said it right. These projects are the best of both worlds. If you arrange the different types of solar projects along a spectrum, utility-scale solar is well understood. Everybody knows what the issues are and how to finance it.
C&I has a different risk profile. The portfolio and the credits matter. With residential solar, you need to factor in consumer default history.
Community solar picks up the best parts of all and sits right smack in the middle with utility-scale solar and residential solar. The issues related to utility-scale solar are well understood. Now add some residential solar features. You know what FICO mix you need to have. You know what the diversification benefits are. We have a view on how the residential customers behave. We have the default history data from other asset classes. We can underwrite and price that combined risk. Based on that, we can deal with the subscription aspect of community solar. We can put all the pieces together.
Frankly, it is a risk mitigant that the system is not installed on the roof of the customer’s house. It is a benefit that the subscription can move from one customer to another customer. In that sense, it is an improvement on residential rooftop solar from a risk standpoint. The involvement of the municipality and the state also gives you some comfort.
The biggest challenge has been aggregation to get to a meaningful size. Trying to do a 10-megawatt community solar asset is tough because the legal fees are just as high as for a 100-megawatt project. But if you are able to get the size right, then financing becomes a lot more available.
So from a Deutsche Bank standpoint, we took a view that this is not an entirely new asset class. It is an asset class that takes the best parts of the different solar market segments. We were able to offer an aggregation facility for a client to help it fund a portfolio. The portfolio is more than $100 million in size. Now you are able to come up with a financing structure that is efficient. There is a master tax equity facility involved that provides additional capital, but pushes lenders to a back-leveraged position.
As the size becomes relevant, as more states adopt community solar programs, as the portfolios grow in scale, I think financing is there to be had.
MS. ALCALA: We could probably put you on a roadshow for why community solar is great and should be financed by everybody.
MR. AMSTER-OLSZEWSKI: I want to record that. Come with me as we meet with financiers.
MR. MUKANI: I don’t think I am saying anything fantastic. If you look behind the curtain and try to parse the risk, it is sum of parts. If you are in Massachusetts, you need to appreciate how the SRECs work. If you already understand how the SRECS work — they are part of the cash flow stream — then you can underwrite that.
You have to form a view on the consumer risk. Then you can underwrite that. You have a view on the risks associated with getting an asset in the ground, the permitting, the interconnection and all that stuff. You can underwrite that. If you add all of this together, there is nothing extraordinary about the financing.
Tax equity view
MS. ALCALA: John Eber, J.P.Morgan has been a dominant player in the tax equity market. You have not found a community solar project or set of projects in which you are interested in investing. Why?
MR. EBER: Yes. I am beginning to wonder why Keith Martin has put me up here today.
MS. ALCALA: Because we love diverse perspectives.
MR. EBER: That feels like a bit of a set up. [Laughter]
MS. ALCALA: You are going to tell us the problems that we need to overcome, and then we are all going to work together on solutions.
MR. EBER: We are actually in our 10th year of doing solar tax equity investments. We started with CSP or solar thermal projects. We have done C&I deals, residential rooftop deals, and large-scale utility photovoltaic projects. I think only two community solar deals have made it to my desk. There are a bunch of internal filters before I get to see things, so people on my team have probably seen more of them than I have.
The challenge with the ones that we have seen is scale. We are a scale investor, and most of the other tax equity investors with whom we partner are also looking for scale. It feels to me like it is still in the development stages in the sense that there are a lot of smaller deals. I am talking the true community solar deals, the ones that do not look like traditional solar transactions with long-term power purchase agreements.
It is a great concept. It is a fascinating theory. There are all sorts of advantages as just described. We just have not seen opportunities at the scale we need to invest.
MS. ALCALA: One of the scalability issues is the differences among programs across states. We had a discussion at our conference last year about community solar at a time when there were community solar programs in nine or 10 states. Now there are programs in 14 states and Mark Boyer, I believe your company has been doing projects in states without community solar legislation.
Every state has different rules. How should sponsors overcome that as they push for the scale that tax equity investors or lenders require to finance projects?
MR. BOYER: We have actually done community solar in Wisconsin. We have three projects here in Wisconsin, and there is no state legislation. We did them with help from the Dairyland Power Cooperative.
If you are building one-megawatt community solar arrays and trying to aggregate those across 13 states, it is a nightmare from an underwriting perspective. What we have done in that situation is to go to local or regional banks to borrow. We financed almost all of our construction debt and even our long-term debt from regional banks instead of the larger banks, because the bite size works for them. The transaction costs are lower when dealing with smaller banks. They don’t have as many lawyers.
Tax equity can be very difficult to arrange. We have been able to do tax equity. We did it with US Bank, but in a very specific region.
We have been able to raise other tax equity across different states, but with high-net-worth individuals. That is hard to scale. It will not take us to financing large transactions, but it is a good place to start, and we are trying to build on it.
Now what we do is exactly what John Eber said. We will take 20 to 40 projects in Massachusetts, pull them together, do a single financing facility and run all the deals in that state through it.
We are taking one step at a time. The regional banks love this type of project. It has been a good fit. We have even gotten a couple of them to do tax equity, which took some time, but we got them there.
MS. ALCALA: David Amster-Olszewski, what is the largest project volume you have in a single state?
MR. AMSTER-OLSZEWSKI: We are building 100 megawatts of projects in Minnesota over the next two years. In Colorado, the portfolios are smaller, but we are starting to increase the scale of the program there, as well.
I think we are starting to get to the point where we can talk with the larger institutions to attract tax equity. One of the issues we had this year was we were in between: we were too large for the smaller tax equity players, and we were still too small for the mainstream tax equity market. My hope is that we will get to the scale that the larger investors are looking for in 2017.
In the meantime, we have been working for five years on building the software, building the systems, building the sales force, and pushing down the customer acquisition cost. Now we are looking at acquisition opportunities to bring more projects into our portfolio.
Four years ago, there were not any developers of two- to six-megawatt projects that were not connected to a host site that was using the energy. There was no market for community solar. In the last four years, that has changed a lot.
Now you have a bunch of developers that are developing these sites, but have no idea how to subscribe high-revenue customers, how to manage those customers, and how to bring these projects across the finish line. I think that is the other opportunity that we have. It is jumping into acquiring projects and adding them to our portfolio and then bringing them to the large institutions.
MS. ALCALA: That is a little like the C&I market. That market is full of smaller companies that may not know how to get projects across the finish line. It is struggling to reach scale.
MR. AMSTER-OLSZEWSKI: That is exactly right. There is another piece at which you hinted before, and that is the regulatory environment. How these programs work varies from state to state. After working with utilities on community solar as a product for the last five years, we have gotten a very good idea how different utilities view community solar, how to work with them, how to work through their processes, how to make sure you are first in the interconnection queues, how to make sure that you write the programs and systems so that you are able to bill your project and make the subscriber bill credits work with different utilities.
For example, I was just in a meeting two days ago in Minnesota where more than 1,000 megawatts of community solar projects have been proposed. We are working with the utilities on rules for approval of the switch gear in their interconnection process. We have to order switch gear and install the systems, and we would like the utilities to confirm the switch gear will work with their interconnection.
But guess what? Nobody has done that for community solar, so we have to write the process. Those are the things where companies like ours and Clean Energy Collective are leading the way. We can really leverage that knowledge of how to write the rules as this business expands.
MS. ALCALA: Let’s talk more about subscribers. How important is it to have a project fully subscribed in order to finance it. Can the tax equity investors and lenders get comfortable with the idea that a company with a track record will be able to execute on subscription agreements during a construction period? Or must a developer have 85%, 90%, 95% of the subscribers lined up before the projects can draw on a construction loan?
MR. BOYER: John Eber, I think you were set up. [Laughter]
MR. AMSTER-OLSZEWSKI: But I would love to hear your answer.
MR. MAHAN: Let me help John with his answer. We got comfortable with it because when we went into Minnesota, we had a good idea whom we would target as subscribers. We had already had conversations with our larger potential subscribers.
We started putting in the applications with utilities before all the subscribers were identified and in place, but we were comfortable that we had the right partnerships and the ability on the ground to build the subscriber list.
Yes, it was a leap of faith compared to what a large company like ours has done traditionally. With C&I, you have a 20-year PPA. You have the customer agreements in place before you build.
We are a third-party retailer in five states. We sell both natural gas and electricity in five states that are contiguous on the east coast. We can bundle wind energy that we have purchased in the market with brown energy and offer it to customers, and you do not need long-term agreements. We are simply taking that experience and applying it to community solar. It is the same business.
We think we do not need to have all the subscribers identified in advance. We know that we will have success in marketing the power because of our track record of offering other renewable energy solutions like it to our customers.
MR. EBER: Focusing on the underwriting process from an institutional standpoint, the tax equity in a highly optimized structure for a solar deal is only about 40% of the value of the equipment. So essentially you need significantly less than the total output value to pay out the tax equity.
You don’t necessarily need to have 100% of the project contracted for tax equity to be able to view a deal as financeable. The challenge comes when you try to raise the rest of the capital if that capital is behind the tax equity in priority of payment.
Maybe one way is you find another investor who is more comfortable with the risks and who wants to be more of a strategic player than just a financier, and who is willing to bridge some of the risks for a different kind of return, something higher, but delayed. It is all about how you put the capital stack together.
MR. MUKANI: It is important to have a view that the project will be fully subscribed.
We are interested in the track record of the entity that is lining up subscriptions. What is the cost to acquire and replace customers? Does the project have to be fully subscribed at the start of construction? No. Does it need to be close to that? I think the answer is yes, because a loan is essentially a monetization of future cash flow. When we make a loan, we are taking a view that the developer or aggregator is not only able to get the subscriptions done while it is building the portfolio, but also that it will be able to substitute down the line when there are defaults or if a customer wants to get out of a particular contract.
When construction starts, there is a certain level of subscription that one looks for, and the ramp up is what you are judging as a lender. Maybe there is a structure that allows for higher loan to value as more subscriptions come in. The underwriting process is a function of the subscriptions that you have already obtained plus the track record of having been able to do that before.
Going back to the discussion about how you get to scale, I appreciate that it may not be a concern for smaller banks or for Washington Gas, but there may be other ways to get to scale, for example, by mixing in some C&I projects with community solar. Maybe your portfolio is 60% community solar and 40% C&I. That is a way to get to scale that could be interesting to the banks.
Now to the point that each jurisdiction will have its own issues and how do you solve for that. How do you create a template that works across the portfolio? It can be managed. We have seen it done.
MS. ALCALA: Maybe when you mix community solar with C&I and in different states, it helps if the portfolio is limited to two, three or four states, and the customer agreements and site leases use as nearly as possible standard forms.
MR. MUKANI: That is spot on. Striking the right balance so that there is a template that allows you to combine particular states where similar documents can be used becomes an important part of how to assemble a financeable portfolio. Maybe that is how the industry should think about ramping up to get to scale.
Residential v. commercial mix
MS. ALCALA: Let’s hear from the developers on the panel how they view commercial versus residential subscribers.
MR. BOYER: We have about 50-50 across our entire portfolio. However, when you go into a particular state, it depends on the utility, how its program works and what the goals are of that program.
For example, when we do a deal with an electric cooperative, it is extremely important to that coop to see at least 50% residential customers. The coop is member owned. Those are the members. That is who they are interested in doing this for.
If you look at a state like Massachusetts, it is a very different sort of regulated deal. The utility would prefer you never build the project, but you get it done anyway. We are still about 50-50 in residential and commercial customers in Massachusetts. We like that mix because we prefer to keep as many residential customers in the deal as we can.
We think it mitigates our risk. There is a much larger potential base of residential customers and, with the software programs, we can shut someone off in literally 20 seconds if he or she fails to pay, and stick someone else in. You can build a nice backstop for your financiers where you have a waiting list of people who want to subscribe.
If I have a single large commercial subscriber, even if it is an AAA or AA credit, if it drops out, that is a much larger blow to manage. So our goal across all of our projects is to try to keep at least 50% residential customers in the mix.
MS. ALCALA: David Amster-Olszewski, what is your preferred mix of customers?
MR. AMSTER-OLSZEWSKI: I think we are a little more aggressive. We are probably closer to 70% residential customers, but it depends on the state where we are operating and rules and regulations in each state. Clean Energy Collective focuses on electric cooperatives. We focus more on the large regulated utilities. Our base of commercial customers is almost all AA credit with a couple AAA customers.
It is interesting and, Mark, you mentioned this, but a lot of financiers say they prefer the AA-rated customers and would like more of those when we first get into discussions, until you get to the conversation about subscription guarantees in your customer management agreement over the 20- or 25-year life of that contract.
All of a sudden, the rate of residential customers moving out of the service territory is 0.3% a year, and we could still go after them legally to continue paying under binding subscription agreements, but we never do. So the financier asks why we will only guarantee an 80% subscription rate. Well, you wanted commercial in the portfolio and, if one commercial customers drops out, then you will lose 20% of the portfolio.
And, by the way, it does not take me one week to find a new residential customer or just pull from the backlog we always have. So you end up having a bigger chunk of lost revenue in your portfolio if that commercial customer drops out. At the end of the day, residential is really a lot more flexible. There is a lot more demand, and it is a lot faster to get residential customers signed up, and there are more customers behind them in the queue.
The other piece of this is we have never turned on a system that was not fully subscribed. A significant pain point for us has been that we cannot keep up with the demand for our product.
For example, people were on a waiting list for one of our projects in Colorado for a year and half. We want to start accelerating our development, construction and financing schedules so that we can keep up with customer demand.
One of our concerns is what happens over time as the market becomes more saturated. Do you have more competition for those customers and, therefore, do residential customers start dropping out because they are moving to the competition and start breaking their contracts? Legally we can go after them, just like the rooftop solar companies can, but it is not worth the trouble.
Finally, another factor in favor of residential customers is if you are monetizing cash flows at the residential retail rate, you are earning a 35% higher revenue stream. If you add that to a cost basis for the equipment of $2.50 a watt, that is quite a significant profit. That is what is drawing in the competitors.
MS. ALCALA: Sanjiv Mahan, you are focused on commercial customers. After what you heard David say, why?
MR. MAHAN: It is a natural extension of how we have done traditional solar. We have been doing this for the last eight years or so. We have always been focused on C&I. We have a 168-year old gas utility standing behind us. We own assets, including solar and fuel cells, that we use to provide services to commercial and industrial customers across the country. We are now in 19 states and the District of Columbia with that business. It is a natural progression to move to community solar, but focus on commercial customers. We are comfortable with how we have already been doing this business. We think it works.
I agree with David and Mark that we are going to have to make this more a commodity business. When you have 180,000 customers and are in mass markets, you can afford to have some leave in 30 days because they got a better deal from someone else. The only way it works is if you have the mass subscription base.
We think the way to grow community solar is to get away from long-term 20-year PPAs for every single residential customer, because that is a standard offering in an era where customization is what sells. The current customers who sign these contracts are all being very much social minded. They really want to do this for the betterment of the environment, but they also really want this product, which is an absolute truth. They want this product. The best way to grow is to eliminate one of the hurdles, which is the long-term contracts. Turn it into a commodity offering. Then I think you will get mass adoption. The qualifications of an individual are the standard credit qualifications that any third-party retailer would look at.
Then I bring it into my mainstream business. I have to handle all the billing and the other pieces that go with administration and marketing, but we have an engine that already does this, so why not take advantage of it?
MS. ALCALA: Vinod Mukani and John Eber, until we get to the ultimate model that Sanjiv just described, is there a mix of residential and commercial customers that you prefer from a lender or tax equity perspective?
MR. EBER: There are pros and cons to each. We have done a lot of residential solar. We are comfortable with it. I won’t say the risks are easy, but we know how to underwrite them. So to the extent the subscriber base is substantially residential, we are familiar with it. That is the good news.
The bad news is it really takes even more scale to build up to a large enough portfolio to be attractive in our market on the residential side than it does if you are working in the C&I space.
However, the C&I space is more difficult to underwrite because not only are the credit risks varied and challenging, although many of them are customers of our bank so we are familiar with them, but also the customer agreements are all different because it seems to be part and parcel of dealing in the C&I space that the companies want to customize their contracts. The customer agreements are more heavily negotiated. Lack of standardization is a challenge.
That said, we can work with either.