Current issues in community solar projects

Current issues in community solar projects

December 18, 2018 | By Keith Martin in Washington, DC

The community solar business model is still relatively new. The developer of a small utility-scale solar project signs up customers who pay it subscription fees. The electricity goes to the local utility. The customers receive bill credits for the electricity from the utility. Projects are getting financed, but usually in portfolios of multiple projects. Most of the activity to date has been in Colorado, Minnesota and Massachusetts, but the model is expanding to other states.

Three community solar developers and one aggregator of community solar customers talked at the Infocast Community Solar 2.0 conference in New Orleans in November about the how the basic business model is evolving and current issues in the market.

The panelists are Rick Hunter, CEO of Pivot Energy Solutions, Joel Thomas, manager of community solar for independent power developer Community Energy, Inc., Jesse Grossman, CEO of Soltage, and Laura Pagliarulo, senior vice president for community solar and commercial sales at CleanChoice Energy. The moderator is Keith Martin with Norton Rose Fulbright in Washington.

New trends

MR. MARTIN: Rick Hunter, what new trends do you see this year in the community solar market?

MR. HUNTER: More projects are providing electricity to low and moderate income customers.
It is a critical proving time for the industry around customer acquisition. A lot of new developers have gotten into the space. They are all trying to figure out how to nail down the revenue piece and feel confident about it. That has led to a rise of third-party customer acquisition firms. There is a lot of attention being paid to whether those firms can really sign up customers at scale.

MR. MARTIN: Are you able to finance projects with low and moderate income customers without credit support from someone like a green bank?

MR. HUNTER: Yes. There are a bunch of ways to skin the cat. It depends on whose money is being put to work and how they want to see it structured. We have been working with housing authorities as either a backstop or at least a conduit for connecting to the low-income community.

MR. MARTIN: Joel Thomas, what new trends?

MR. THOMAS: New states that are embracing community solar are requiring residential customer participation. The early markets in Colorado and Minnesota involved largely commercial customers. Now states are requiring or placing very big incentives for residential participation.

MR. MARTIN: What percentage residential?

MR. THOMAS: It is usually 60% in the northeastern states.

MR. MARTIN: So each project must be at least 60% residential.

MR. THOMAS: I should say small subscribers as it could be small commercial customers, but it typically goes to residential.

MR. MARTIN: Is that by number of subscribers or capacity?

MR. THOMAS: Percentage capacity of each project.

MR. MARTIN: Next trend?

MR. THOMAS: New states that are adopting community solar are putting in program caps so that the programs are more than pilots, but we are not talking about a whole lot of megawatts. In New Jersey, the cap is 75 megawatts per year as just one example. The programs are a little smaller to start than we would like.

MR. MARTIN: Is the cap a limit on participation by community solar projects in net metering programs? How do the caps work?

MR. THOMAS: Yes. It is a cap on projects that can get bill credits to sell to customers, which is what you need to make a community solar project work.

MR. MARTIN: Jesse Grossman, new trends.

MR. GROSSMAN: A whole ecosystem of companies is emerging that bundle solar residential customers and some commercial customers and provide the full package for folks like us that want to own projects for the long term, but do not necessarily want to administer 100 to 150 residential customers per megawatt of capacity.

Separately, people are moving from other parts of the distributed energy sector to serve this space. Utilities are starting to administer their own community solar programs by offering their customers a green subscriber choice. The utilities are playing offense to prevent customers from defecting to other electricity suppliers.

Another interesting theme is the efforts being made to get capital into this space. From tax equity to debt even to sponsor equity, people are wrestling with how to put this type of project into the standard project finance box. There is no consensus yet on best practices or the right market outcome for this sector.

MR. MARTIN: Laura Pagliarulo, your company focuses on aggregating customers. How are you compensated? By the customers? By the community solar developer?

MS. PAGLIARULO: We are compensated by the asset owner. We have a contract with it for upfront customer acquisition and then longer-term management. It is a nascent market. Even with 100 megawatts under management, we have not reached any kind of real scale. There is a lot of emphasis now not only on how to acquire customers, but also on how to retain them.

MR. MARTIN: Does the asset owner pay a percentage of the subscriptions collected? How does it work?

MS. PAGLIARULO: It depends on when we come into the project. We get projects at different stages. We prefer not to work on projects that have already been subscribed. When we take over asset management, we put a lot of emphasis on the sales process. The better the sale, the more likely the customers are to stay. Often it is a three-way negotiation among the developer, the asset owner and us where the developer gets paid a little less if we are paid more on upfront acquisition.

MR. MARTIN: Jesse Grossman, what percentage do customer aggregators get?

MR. GROSSMAN: It varies. Different customer aggregators charge varying amounts. The charges are usually broken down into two areas. One is an upfront fee or customer acquisition cost that we have seen run anywhere from $10,000 to $25,000 per megawatt, and then there is a long-term asset management fee for managing churn — folks drop out, having a phone line to pick up if customers are curious about what is going on or have issues with their bills — that really ranges all over the place, but is also on a capacity basis.

MR. MARTIN: Laura, are there any new trends you see in the market besides what others have already mentioned?

MS. PAGLIARULO: Three and a half years ago when I started in this space, the typical financier wanted a long-term contract with essentially liquidated damages that would never fly in the residential market. It would raise a lot of consumer protection concerns. Now there is more flexibility in terms of percentage of the project that must be subscribed by the time construction starts.

There is also more flexibility in the contract length. There is more flexibility in termination fees, especially now that the Minnesota attorney general has suggested that a termination fee of $1,000 is too high. Some financiers are getting a little more comfortable with these types of assets.

Basic proposition

MR. MARTIN: Going back to the developers, Rick Hunter, what is your basic business proposition, and has it changed in the last year?

MR. HUNTER: It depends on the market and on whether we are focused on residential or commercial subscribers.
For residential, the typical pitch is the customer will receive an economic benefit while at the same time doing something good for the environment. For commercial, we emphasize the economic benefits and talk though the hedge component in more detail.

MR. MARTIN: So residential subscribers are not as focused as commercial subscribers on the math. What is the typical contract term? Does it differ for residential versus commercial?

MR. HUNTER: It varies market to market. It varies investor to investor. Where we are seeing the most movement today is in terms of how quickly we can get away from credit scores and long-term contracts on the residential side while holding on to a reasonable cost of capital. Everyone is pushing in that direction. We will find out pretty quickly in the next year or two if we can find that right balance.

MR. MARTIN: What is preventing you from moving there immediately?

MR. HUNTER: Getting investors comfortable with a new space that is untested and has no data that can be used to justify assumptions. It will be a process.

MR. MARTIN: What contract term are you using today: 10 years? 20 years? Do you give a 15% discount to the customer from the local retail rate?

MR. HUNTER: We are pushing to a year or less.

MR. MARTIN: Trying to move under a year.

MR. HUNTER: We are pushing there. We are not there yet.

MR. MARTIN: Where are you now?

MR. HUNTER: Five or more. It depends on the market and who the subscriber is. It probably needs to stay at 20 years for municipalities, universities, schools and hospitals, but for residential, I think the market may settle out in the five- to 10-year range. We will see.

MR. MARTIN: Are you selling subscribers a percentage of the output from the solar array or bill credits?

MR. HUNTER: It depends on the market. [Laughter] Usually the subscriber is buying bill credits.

MR. MARTIN: How much of a discount are you giving people to make a sale?

MR. HUNTER: I hate to sound like a broken record, but it depends on the market. We find we need to offer at least 10% savings in year one to move the needle.

MR. MARTIN: Joel Thomas, same questions: what contract term are you using and what discount are subscribers receiving on electricity compared to the price on offer from the local utility?

MR. THOMAS: Our contracts are usually 20 to 25 years, and the discount is 10% or greater, but typically not much more than 10%.

Perhaps this goes in the category of new trends, but a year or two ago, no shops existed to do residential customer acquisition. Developers did it on their own. Third parties are now offering to do it as a service. As a consequence, we are no longer doing our own residential customer acquisition. We find our own commercial customers, but not residential.

In fact, residential is also different in that the offtake can come later in the process. With a utility-scale project, the largest defining moment of value creation is when you land an offtake contract. With community solar, it is more of a marketing process and so there is a little less value creation on getting that offtake. There is the option of selling a project for a potentially meaningful value before the residential customers have been lined up.

MR. MARTIN: What happens if a customer wants to cancel?

MR. THOMAS: He has to pay a termination fee, but states like New York are placing limits on termination fees.

MR. MARTIN: The residential rooftop companies are moving to longer-term contracts. They were at 20 years. Some of them are now moving to 25 years because they can raise more capital against a 25-year contracted revenue stream. Yet you and Rick Hunter say community solar developers are moving in the opposite direction. Why does that make sense?

MR. THOMAS: We do not think our customers want to be locked into 20- and 25-year contracts. The average homeowner moves every seven years. I agree with Rick Hunter that community solar contract terms are probably going to land in the five- to 10-year range since that is the term of the debt on these projects.

MR. MARTIN: Jesse Grossman. Same questions: contract term and business proposition.

MR. GROSSMAN: That is one of the hot topics in this space today.

We come from a traditional project finance mindset, so the longer the contract term, the better. We have been able to maintain longer terms, but we see pressure to go shorter over time. We have a large diversified portfolio, so we can wrap in 20 or 30 megawatts of residential community solar with short tenors as part of a larger portfolio.
We are still in an interesting early stage in the community solar market. There is a wall of capital chasing deals. Some banks and investors may be willing to relax their underwriting standards a bit just to get money into this space. The traditional project finance lenders have more trouble, but some regional banks and specialty debt shops are willing to assume a longer revenue stream than just the contract term for purposes of debt sizing. However, the rates can start to look like equity.

MR. MARTIN: Are you able to finance standalone community solar projects?

MR. GROSSMAN: We have not tried to do a standalone portfolio of community solar projects that are all residential. We have done it with muni and C&I customers, and that has not been a problem, but I am glad we have a larger portfolio of long-term creditworthy assets that we can combine with residential community solar to raise capital.

MR. MARTIN: Rick Hunter, have you been able to finance standalone community solar portfolios?

MR. HUNTER: They have all been portfolios to this point. The time is coming when there will be more standardization and when owners will get a little more comfortable with smaller and smaller portfolios or even one-off projects because they know the partner with whom they are transacting and can do it efficiently.

MR. MARTIN: How many projects do you need in a single portfolio today to have a financing?

MR. HUNTER: Even though we have not done it, I think there are single projects getting done.

MR. MARTIN: Joel Thomas, have you been able to finance community solar projects on a standalone basis?

MR. THOMAS: Yes, but the only cases where that has been true is where we own the projects ourselves and act as the tax equity and backstop the debt with our corporate balance sheet. That is what it takes to finance a standalone project.

MR. MARTIN: So that is not a project financing, but a borrowing on credit.

MR. THOMAS: Correct. It is recourse debt.

MR. MARTIN: The community solar tax equity and debt financings we have seen have been portfolios of 18, 20, 22 projects at a time.

MR. THOMAS: Sounds right.

MR. MARTIN: Laura Pagliarulo, you are a customer aggregator. What contract term and discount do you need to offer to attract customers?

MS. PAGLIARULO: I agree with Jesse. We have sold one-year deals, but we prefer five years and longer. We are selling five-year deals, three-year deals, 25-year deals. You want customers to know that they are locking into something for at least a five-year term. It makes our role easier. It keeps the portfolio more stable.

The first year of any portfolio is always the most tumultuous. The most churn occurs when customers start getting that first bill.

Likewise, I like the idea of reducing standards for FICO. This has to be a fungible product. Community solar is unlike rooftop. An asset owner or tax equity investor about to deploy big dollars to put assets on rooftops needs to see some sort of credit value in the customer base. I don’t think that will go away anytime soon.

I think there are alternative scores that are probably a better indicator of how likely a customer is to pay bills.
Turning to the value proposition, customers are more focused on the fee they must pay to terminate a contract than the contract term. When you are selling to a customer at the door, he or she wants to know how much am I going to save and what do I need to do if I want to get out of it? So the days of $500 and $1,000 termination fees are gone. We probably will not work on a project unless we can sell a termination fee of $150 or $250. We have really good relationships with state attorneys general and that is our sense of what is becoming the acceptable range for termination fees.

Customer attrition

MR. MARTIN: Let me throw out a few statements for the whole panel. Correct them if they are wrong. Developers are assuming customer attrition rates of about 5% a year in financial models, but in fact the attrition rates have been less than 1%. However, there is not much data: perhaps three years at most. True or false?


MS. PAGLIARULO: It depends. We worked on a portfolio in Minnesota where the customers were subscribed and were hanging out for more than a year before the project came on line. We saw 25% attrition. Those are not customers we sold. We inherited that project. It depends, in my view, on how long ago they were sold versus when the project comes on line. We are a society that expects instant gratification.

MR. MARTIN: That is certainly true. How long does it take to replace customers when you have 25% attrition?

MS. PAGLIARULO: We replace customers fairly quickly, but depending on the size of the project, if you have a 40-megawatt portfolio in Minnesota and 25% of the customers drop out, it takes some time to replace that 25%.

MR. MARTIN: Next statement. The customer acquisition cost in this market needs to be about 5% of the project cost for the market to work, but it is currently higher, at least where developers go door-to-door trying to find customers. True or false?


MR. GROSSMAN: Absolutely true. We have seen instances where folks have tried to price their services at higher than the marginal benefit of acquiring a community subscriber.

MR. MARTIN: In the rooftop solar market, the customer acquisition cost is as high as 25%. Rick Hunter, you are picking up the microphone. Where is your cost?

MR. HUNTER: I was going to make a more general comment. One of the key things for community solar as an industry to accomplish is to drive down the customer acquisition cost. We cannot pay $1,000 a customer and make the business model work. The cost should be lower. With a $25,000 rooftop system, you would expect to pay maybe $1,000 to acquire that kind of customer because the customer is making a much bigger commitment. Part of the reason we want these shorter-term contracts is so that people have an easier time saying yes and the acquisition cost goes down. Community solar today is more expensive than it should be. If we want to see sustainable growth, we have to optimize up and down the value chain and, to me, customer acquisition cost should be the major focus now.

Utility hostility?

MR. MARTIN: Are utilities hostile to community solar?

MR. HUNTER: Is this going to be posted? [Laughter]

MR. MARTIN: Depends on what you say. {Laughter]

MR. HUNTER: I don’t know. [Laughter]

MS. PAGLIARULO: I think in markets like Minnesota, the utility has been great to work with. Xcel has established the infrastructure. In states like Massachusetts when you cannot assure when a customer will receive his or her bill credits, the utilities might not be openly hostile, but they are making our ability to do business difficult. Every state is different.

MR. THOMAS: The main way that we engage with utilities is on interconnection. Utilities are not hostile as much as they do not have a very strong incentive to invest in their distributed generation divisions. The lack of incentives to put the best foot forward means things tend to move slowly.

MR. MARTIN: One of the challenges in this market is the mechanics of billing. How would the market change if the utilities did all the billing?

MR. GROSSMAN: It would make the market a lot more efficient. Utilities across the country have different strategies. Some are pro innovation and some are putting their heads in the sand. Dominion and a few other utilities are doing green purchasing programs in an effort not to lose customers to renewable energy suppliers, so they are allowing them to sign up for community solar services and then entering into large PPAs for renewables. This is a fairly efficient structure.

MR. MARTIN: If utilities handle all the billing, will community solar developers complain that they have no contact with the subscribers? The subscribers will contact the utility to drop out. You won’t hear about it.

MS. PAGLIARULO: Our experience with utility consolidated billing with POR — purchase of receivables — is excellent. If we could get that in place, everyone would be happy. If there were utility consolidated billing without POR, the utility gets paid first. If a customer defaults by paying just a little bit, the utility takes that to offset its cost first and we have no ability to go after the customer for payment of any type. So not only do we not have visibility in terms of who is late in a timely manner, we also do not control the payment flow. There is no ACH setup. There is no credit-card information on file. They need to go together — POR plus consolidated billing. Otherwise, there would be a lot of lost revenue.

MR. HUNTER: Utilities need to own a bigger piece of this space. They already have the customers. We would do better to try leveraging its relationships and the trustworthiness of the utility’s brand.

Lots of companies are trying to pitch to consumers who have never heard of them. They are spending tons of money to create brand recognition. There is hostility from utilities, and rightly so, because we are taking their customers and they are not getting any credit for enabling this investment in clean energy. It is some fly-by-night company that just came on the scene and is taking their customers from them.

That model is not sustainable. I think over time you will see a trend, starting with some of the more progressive utilities, of modeling community solar after efficiency programs where the utility hires a third-party implementer who does the work under the utility brand of developing projects in a way that costs less money. Our company is preparing with that future in mind.

MS. PAGLIARULO: What Rick just said makes sense in regulated markets. But the truth is most of the community solar states with prescribed programs today are in deregulated markets where the utility is not allowed to have its own community solar or green product offering. States like Massachusetts, Maryland, New York and New Jersey cannot have utility-driven programs. In other markets that are regulated, it makes sense to do things under the utility brand.

MR. GROSSMAN: This is really a credit question. The challenges that we have been talking about — term of contract, type of entity, low and moderate income customers, FICO scores, etc. — are important because there is really no credit or balance sheet that we can look to in traditional ways. This is an area where innovation is needed for this industry to move from tens of megawatts per year in various markets to hundreds of megawatts.
A large balance-sheet entity like a utility or a utility subsidiary could play a role. They could be important intermediaries. The community solar company would have a contract with one of them and what the utility partner does on its side does not matter. The community solar company can then price the project like a 20-year creditworthy investment and revenue stream.

Alternatively, the insurance companies could play a role here if they priced their product correctly. So could the commodity desks of some of the larger banks. I think that is where the market needs to get. We need to get more data and more analytical ability around this space. We are wrestling with a problem that comes down to the creditworthiness of the revenue stream, and this is the most important issue after permitting and interconnection. How are we getting paid?

Where to probe

MR. MARTIN: Let me ask one more question, and then I will ask the audience whether it has any questions. Suppose you switched sides and you are now working for a bank or tax equity investor thinking of financing a community solar project. Where would you probe first in looking at a project for potential problems?

MR. THOMAS: The first thing I would do is to ask to see a sample customer agreement.

MR. MARTIN: What would you look for once you have the sample contract?

MR. THOMAS: I would look at the rate the customers are being charged in relation to the value that the customers can expect and then develop a view on the likely rate of customer attrition.

MR. MARTIN: So you want a long-term economic advantage to hold the subscriber in place.


MS. PAGLIARULO: I would really enjoy the ability to do this for a few days. I would look at the total solution. Managing mass-market customers is like dealing with a five-headed dragon. It is not just about the platform or the sales process or consumer protection, it is looking at everything as a whole. The truth is you have to be able to do everything well and not just one or two things to have a good project.

MR. MARTIN: So you would park yourself at the community solar company for a day or two to see how it is functioning.


MR. GROSSMAN: I think Joel gave a great answer and would echo that. I would focus on all the traditional risks plus how solid the revenue stream is.

MR. HUNTER: The deals I know that soured went bad because of poor execution. The subscriptions were not filled in a timely manner.

MR. MARTIN: Would any of you focus, number one, on the status of any net metering debate within the state — these projects do not work without net metering — and , number two, on the aggressiveness of the local utility in trying to package its own community solar offering?

MR. GROSSMAN: Yes, absolutely.
The location is very important in terms of assessing the viability not only for upfront subscription, but also for resubscription over time as the market gets more competitive. We have purchased portfolios in areas that have hundreds of thousands if not millions of potential customers. Some folks drop out. Some folks move. The market must be one where it will be easy to replace departing customers.

We have passed on other portfolios in low population areas where, if minimum FICO scores are required, you are reducing your potential population of subscribers even further. We say to ourselves maybe this area can only handle 10 megawatts of community solar projects. If someone tries to build another community solar project and undercuts me by 5%, then I am sunk from a revenue perspective. Maybe it is an area where a utility is thinking of offering its own program and can do so efficiently.

MR. MARTIN: Audience questions?

MS. PETERS: Kacie Peters with Pivot Energy. My question is about the acquisition piece. If you start signing up residential customers too early, people drop out before the project is built. If you start too late, you run out of time. What has your experience been for that perfect secret sauce? When for residential should you be looking to start the process?

MS. PAGLIARULO: We look at the percentage of the total market that must be subscribed. For example, if someone comes to us with a 20-megawatt portfolio that is 100% residential in Central Hudson or Eversource territory, we look first at what percentage of residential customers we will have to persuade to switch to community solar. Say it is 1% of the total available market. Then we work backwards. We have a sense of how many customers we can sign up a month. That tells us how many months it will take to get the project fully subscribed.
Developers have an advantage because they know the true project schedule. Where things get messed up is if the developer insists things are totally on time and the project ends up being delayed. There must be real transparency and communication. We like to sign up the residential customers as late in the process as possible.