Five community solar executives talked about where community solar is getting traction, the different business models, the principal risks in deals and how the market is addressing them during the opening panel at the first annual community solar summit in Denver in late July. The summit was organized by the Coalition for Community Solar Access and Infocast.
The panelists are Zaid Ashai, chairman and CEO of Nexamp, Eric Bank, co-founder and executive vice president of Community Energy, Tom Sweeney, chief of strategic markets for Clean Energy Collective, Ed Scarborough, vice president of network development for Distributed Sun, and Tom Matzzie, founder and CEO of CleanChoice Energy. The moderator is Keith Martin with Norton Rose Fulbright in Washington.
MR. MARTIN: Tom Sweeney, in what states besides Minnesota, Colorado, and Massachusetts is community solar getting traction?
MR. SWEENEY: It has made broad progress across a number of states. Obviously Massachusetts is one that people recognize pretty clearly along with Colorado, but New York is in an implementation phase right now. The same thing is true in Rhode Island and Maryland, as final rulemaking has been put in place. Oregon just passed a legislative enablement, so rulemaking will come next. California has had a community solar program for the last couple years, but it has some disabilities related to the economics and, of course, Hawaii is very close to enabling its rulemaking process as well.
MR. MARTIN: What is the principal disability in California?
MR. SWEENEY: It is primarily the economics. The retail rate that the utility would pay for the power is too low to make typical community solar programs work.
MR. MARTIN: Zaid Ashai, you are based in Boston. How would you characterize the state of community solar in Massachusetts?
MR. ASHAI: We should not take it for granted. A lot of the community solar success to date was an outgrowth of the SREC II program, which was based on virtual net metering. As many of you in this room know, we are going through a new program design called the Smart Program, where there will hopefully be an adder for community solar projects. We are working through that. It seems like all sides are still committed to having a robust community solar program. We find very little disagreement among our legislators, whether they are Republicans or Democrats. It will come down to how the new program is implemented. The new program will have elements of net metering, but it will be a hybrid program.
MR. MARTIN: “Hybrid” in what sense?
MR. ASHAI: We are not going to have SRECs anymore. We will have fixed incentives for 15 years. There is a baseline incentive that you cannot go above. There are adders for different types of projects, community solar being one of them.
MR. MARTIN: Correct me if I am wrong, but in Massachusetts, SREC sales account for a very large share of the revenue, maybe 65% of the revenue from a community solar project.
MR. ASHAI: That’s correct.
MR. MARTIN: Will the economics work if you will no longer have SRECs?
MR. ASHAI: They will. It will be a different style of project. The challenge that we have had in Massachusetts with any solar project is we have had 10 years of SRECs, and we are financing typically with nine- or 10-year loans, after which the capital stack is all equity after year 10.
The new program will provide an incentive for 15 years, which will allow longer-term debt. The goal of the policymakers is to try to make a more efficient program where there is less leakage in the financial markets. With SRECs, there was too much leakage. The program could be made more efficient for ratepayers.
MR. MARTIN: Too much leakage meaning not enough of the benefit goes to the developer?
MR. ASHAI: Not enough goes to the developer or a lot of the costs are passed through to ratepayers.
MR. MARTIN: Are there other states to add to the ones that were mentioned so far?
MR. SCARBOROUGH: Illinois. We expect to see a draft from the Illinois Power Agency in the next 60 days of what the REC program will look like for community solar there. The program is much broader than just community solar, but community solar should benefit from significant REC incentives. We are waiting to see how the economics work. It is an interesting market. You can basically sell electricity to anybody within the utility territory.
MR. BLANK: We also see Illinois as a promising market. In the category of two steps forward and one step back, we are seeing revenue declines in Minnesota similar to what is happening in Massachusetts. There is also a ratcheting back of rates and revenues in New York, and Colorado is now subject to competitive bidding.
All of the markets are viable, but there has been a pullback similar to what was described in Massachusetts.
MR. MARTIN: Is there a lot of new development in Minnesota if the revenues are going down, especially given the cap on project size that Xcel persuaded the regulators to adopt?
MR. BLANK: It is an increasingly challenging business, but we still see it as viable. It is just more competitive than it had been.
MR. MATZZIE: One of the headwinds that we face generally is the deflationary energy market.
MR. MARTIN: Electricity prices are coming down?
MR. MATZZIE: Our primary business is as a retail electricity provider, and the price we can charge for our goods has declined every year we have been in business since 2013. It is not just because natural gas prices are low, it is heat rates on gas plants are falling and the uneconomic units are being squeezed out. Reserve margins are decreasing, so capacity is decreasing. That is a headwind. It makes getting the tariff right and the policy work that the Coalition for Community Solar Access does much more important.
MR. MARTIN: Is this a greater challenge in community solar than independent power generally? Independent power producers lock in a long-term offtake contract and then seek financing for their projects. With community solar, in theory you lock in a revenue stream, but the subscribers can cancel with short notice.
Cash Waterfall Issues
MR. SWEENEY: That’s right. Two points. What Tom Matzzie is pointing out is that as an industry, what we have not successfully done yet is to argue for what the true value of solar is, and because that has not happened, we end up being subject to somewhat arbitrary views as to where to set rates for the purchase of our electricity.
The second point is what you mentioned, which is the administrative cost to have a community solar program with multiple subscribers and net metering credits. This is another place where policy can help us. Without an on-bill debiting enablement where we take advantage of the utility’s billing and collections process, we end up having a much higher soft cost and a much higher administrative cost overall, and it translates into a different risk profile for the financiers. Those two things are worthy of real attention.
MR. MATZZIE: The policy has to be right. Retail electricity has an on-bill advantage. There are a lot of people who would rather see the customers receive a single bill, and then everyone involved in delivering the electricity divides up the cash flow. You have to think about the cash flow waterfall. Who gets paid first: the utility or the community solar company? Unless you have a very clear tariff, it becomes a nightmare. We have lost hundreds of thousands of dollars in the retail markets because there was not a clear cash flow waterfall.
MR. MARTIN: How does that come into play? The subscribers pay the community solar project directly. The electricity usually ends up with the utility. The utility provides the subscribers with bill credits. How does the cash waterfall come into play?
MR. MATZZIE: The billing relationship is entirely managed by the utility. The community solar company transacts with the customer and then enrolls the customer with an on-bill service at the utility. The difficulty is the community solar company is then relying on the utility for all the customer service. The customer can cancel through the utility without ever talking to the community solar company.
MR. SWEENEY: I would describe it this way. The current environment is that we have utilities posting credits to the customers’ utility bills, and those credits have a corresponding debit that must be delivered to the customer. Currently, a project owner must bill that customer independently. That is where the extra cost and risk of collection arise.
If a utility were posting both the credit and the corresponding debit transaction at the same time, then the effect on the customer’s bill is a net decrease in cost. The community solar company still has to have a contract with the customer to participate in the program, but Tom Matzzie is pointing out that when you use the utility to collect receivables, there are other risks that come with it. A correctly structured policy can help. This is a big issue for us in the industry.
MR. MARTIN: Before we leave this topic, let me ask in which state do you think community solar will grow the fastest over the next year or two?
MR. SWEENEY: Minnesota will probably be close to number one this year and next year based on the volume that is being built currently, but Massachusetts still has a pretty large volume going through its development cycle. New York has an opportunity to put some pretty big numbers up, but there are still significant challenges with getting interconnection built and put in place.
MR. MARTIN: Any disagreement about that list? Ed Scarborough.
MR. SCARBOROUGH: No disagreement. I would like to go back to the billing issue for a second, specifically in New York, and about how woefully unprepared the utilities are for this. In their filings on May 1, the utilities basically said it will be a year and a half to two years before they can automate their systems. They will be managing our billing process in the meantime using spreadsheets, which is going to be a lot of fun.
It is not clear when they put the credit on the bill that they will say what the source of that credit is, so there will be this magical credit on the bill that will not say it is from a community solar project or even what month of production it represents, and since credits will vary from month to month, it will be very difficult for subscribers to understand what is on the bill.
As new states make room for community solar, we find in Illinois, for example, that remote net metering is new to the utilities. It is a challenge for them to adapt. That is part of what we need the Coalition for Community Solar Access for: to help identify limitations and have open discussions with the utilities so that we can create an environment in which we can all function.
Evolving Business Models
MR. MARTIN: How many different community solar business models are there? Zaid Ashai, what is your business model?
MR. ASHAI: When we go to town meetings, community solar is an asset. We go into communities that are worried about land and create opportunities where standard solar projects cannot. Our business model is we are typically using virtual net metering in Massachusetts. We bill customers directly. They receive bill credits on their utility bills. We are managing all of that internally.
MR. MARTIN: So you sign up subscribers. Are you selling them net metering credits or a share of the electricity output from a community solar array?
MR. ASHAI: We are selling them net metering credits.
MR. MARTIN: And the electricity actually goes to National Grid or another utility. The utility gives you the net metering credits in exchange for the electricity that you then transfer to the subscribers.
MR. ASHAI: Eversource. Correct.
MR. MARTIN: How long are the subscription agreements?
MR. ASHAI: There are no long-term contracts and no credit scores. We have designed our whole financing stack, our whole asset management stack, to deliver that, and it has led to lower soft costs and higher returns for investors.
MR. MARTIN: Eric Blank, is your business model the same?
MR. BLANK: It is a little different. We started off primarily as a utility-scale developer and found community solar to be a valuable adjunct for creating a more stable revenue stream. We are in Colorado, Minnesota, New York and Massachusetts. We view community solar primarily as a development opportunity. Most of our value add is on the development side. We own and operate a number of community solar projects, but we often find partners in each individual market.
The best partner in Massachusetts is different from the best partner in Minnesota where you have more residential customers, and is different from the best partner in Colorado where the customers are mainly commercial. It is much like utility-scale solar. We see it as primarily a development business with fragmented markets.
MR. MARTIN: Do you also use local partners to find the subscribers? What mix do you have of residential and commercial?
MR. BLANK: We do the customer acquisition internally as part of the development process. In Minnesota, we sometimes have 100% residential customers. In Colorado, we might have 0% residential. It depends on the dynamics of each market and what makes the most sense. In Minnesota, there is a significant premium for residential over commercial. In Colorado, there is virtually no premium.
MR. MARTIN: Zaid Asahi said that Nexamp does not ask customers to sign on for any particular period of time. Do you have a time period?
MR. BLANK: We try to sign term contracts with modest escalation and reasonable termination provisions. However, they are not a critical part of the value creation process because we expect to substitute customers in and out over time.
MR. MARTIN: Tom Sweeney, are there any differences in your business model?
MR. SWEENEY: Maybe the most important distinction is that we are an enabler of community solar programs. We do not build the projects ourselves. We work with utilities to use our software platform to develop community solar programs. The same set of software and services can be available to other participants in the market as well.
MR. MARTIN: Ed Scarborough, are there any differences in the Distributed Sun business model?
MR. SCARBOROUGH: We look for customer agreements with a seven-year term. No escalator. There is always a discount to the credit value. We attend state fairs, farmer’s markets, go into residents’ homes to do direct sales, and we are getting a good response.
MR. MARTIN: What is your mix of commercial and residential subscribers?
MR. SCARBOROUGH: 100% residential.
MR. MARTIN: Zaid Ashai, I did not ask your subscriber mix. What is it?
MR. ASHAI: It depends on the state. In Massachusetts, we typically do 50% commercial with an anchor offtaker and 50% residential. In New York, we will be 100% residential.
MR. MARTIN: Tom Matzzie, are there any differences in your business model?
MR. MATZZIE: We are not a developer. That is the big one. We are a customer aggregator. We have in our retail electric business, which is renewable energy, nearly 100,000 customers already, and we look to apply what we know about acquiring and managing customers to the community solar market. There are other people who are excellent at development. It is a very specific local skill; you have to fight in town meetings sometimes. We do not have to do that. The ultimate financing depends on the customer contract. That is the cash flow, and we take a very specific approach to it.
Possible Inflection Points
MR. MARTIN: Most of the solar industry is focused on the threat of import tariffs on solar panels being imposed perhaps by the end of the year. People are rushing to try to get panels across US Customs before any tariffs are imposed. How does that threat affect your ability to enter into subscription agreements? Who takes the risk that you will be unable to deliver power for the prices currently on offer to subscribers?
MR. SWEENEY: The risk starts at the project level rather than the subscriber level. The reality is that if you are developing a project today and not taking delivery of panels prior to a tariff being implemented, you have that risk as the developer. After that, any tariff will have to be folded into the economics to determine whether a project will pencil out.
From our perspective, that tariff will be an absolute crippler of the industry. It is the worst possible outcome that we could have.
MR. MARTIN: What other potential inflection points do you see in the next couple years that could change the direction of this industry?
MR. MATZZIE: As someone with a retail business, we see opportunities to create what I call synthetic community solar using retail electricity and wholesale markets. The costs are not there yet. It depends on the state. You could do it in New Jersey with a given SREC value. You could do it in Texas given the high insolation there.
MR. MARTIN: What does that mean, synthetic community solar?
MR. MATZZIE: It is not created through a tariff. Community solar today relies on a tariff or some sort of compensation for value of solar. Instead, we would rely on the FERC jurisdictional markets and the various counterparties that exist there. So can you get a revenue put option from a bank against a solar facility in Texas and then upsell for the retail markup?
MR. MARTIN: In other words, you can bypass the state. You do not have to rely on the state to enact a statute.
MR. MATZZIE: That’s right. But not just bypass the state at the retail level, like are you on the customer’s bill or not, but you could have a solar facility in Texas and sell the output and economic value anywhere in the world. You also bypass the state since you operate in a wholesale power market under jurisdiction of the Federal Energy Regulatory Commission or ERCOT or its equivalent.
MR. MARTIN: I am going to throw out a word — blockchain — that people use, but that is hard to explain what it is. Does it have a potential role in community solar?
MR. ASHAI: Yes. We are looking at it given that my previous background is in technology. Our team has looked at the applications within data storage and crypto currencies. I don’t want to go into too much detail because we are still early in the process. There is a lot of hype, unfortunately, and the hype has gone further than the reality, but I think two to three years from now, there will be a role.
We have seen very small activity in emerging markets where people are using solar to mine crypto currencies. They are using their storage facilities essentially to create Ethereum or other types of currencies and using solar energy to do so because solar is cheaper than other forms of energy in those countries. That is one application.
There could be potential other applications in the US. There are some advantages from an accounting standpoint, but it is early and still a lot of whiteboard material right now. It requires more research.
MR. MARTIN: Can you explain in a sentence what blockchain is?
MR. ASHAI: Not in one sentence, no. We would probably have to have another panel to go through it and a whiteboard to write on.
MR. MARTIN: Let’s move to risks. It seems like the principal risk in community solar is the ability of the customers to walk away and the revenue to stop. How is that risk handled?
MR. ASHAI: Through program design. For example, in New York if you have a customer walk away, you have up to a year to sell the net metering credits to another customer. The financing community has not gotten up to speed. Financiers ask you to do long-term contracts with customers. Customers do not like long-term contracts. There are also restrictions in New York about the amount of termination fee a customer can be charged.
As long as the program design allows you to substitute customers within reason, the risk can be mitigated. If that is not a feature of the program design, then it becomes a much larger risk. We usually oversubscribe our projects. We tell people that they are on the wait list and as soon as someone drops out, we bring them in.
Our customer attrition rate is something like .9% a year.
MR. MARTIN: Over how many years?
MR. ASHAI: About two years. Community solar is young. These data sets are small. We had modeled 5%, so it looks a lot better than what we expected.
MR. BLANK: The key thing is to have the customer contracts have attractive terms. If you offer somebody a 10% discount and a relatively modest escalation rate and that customer goes away, then the value proposition is attractive enough that the departing customer is relatively easy to replace with a manageable acquisition cost. If you have a customer contract that is long-term and has 6% annual escalation, that is a very different risk profile.
That said, we primarily view utility credit as standing behind the community solar gardens as much as the individual customers.
MR. MARTIN: How?
MR. BLANK: If you lose a customer in Colorado or Minnesota, Xcel gives you an extended period of time to substitute a new customer. It is really the stability of the utility that is key as long as the customer proposition is fair and in market.
MR. MATZZIE: I think these guys are being modest. It is actually their strength as aggregators that is the other piece of it: the fact that you will replace the customer.
MR. ASHAI: It is also the financial institution’s belief in our platform and the ability to replace those customers.
MR. BLANK: That’s right.
MR. ASHAI: As long as they have faith that you will be around and can replace those customers, that will work. The one caution is we have seen certain players that are trying to play games. They do a customer contract that has a low price for two years and then a higher rate in year three.
I think the last thing we want to do as an industry is make it a game where you are playing tricks with customers and being less than completely transparent. We have seen some companies doing this. The risk is that the regulators step in and take a draconian approach to stop it.
It is important for the industry to regulate itself. Make sure customers understand what they are signing.
MR. MARTIN: Andy Redinger at Keybanc said he argues internally that banks should be able to lend even to sponsors who have not locked in a revenue stream. The bank lends to McDonald’s on the strength that a steady stream of customers will buy hamburgers. Eric Blank, you seem to be of that school. As long as you keep the discount below the retail electricity rate, things should be okay. That has not worked for the rooftop solar companies. Some of them have tried that model and have not been able to raise financing. Why should community solar be different?
MR. BLANK: In Boulder, we are seeing rooftop net metering contracts that escalate at 6% on a rate structure that has escalated at 2% over the last 20 years. If you are trying to monetize the future contract value upfront, that is a significant risk. If you lose that customer, you have really destroyed value.
But if the rate of escalation is more consistent with an historic growth rate, then it is much easier to replace those types of customers. The point is the upfront fairness that allows you to replace customers at reasonable terms is key.
MR. SWEENEY: I would say it a little differently. To have a sustainable base of customers, whether they are residential, commercial or government, you have to deliver an economic advantage for participating in community solar. If you think you are going to charge them a premium to what they are receiving as net metering credits, you will probably fail. So they have to have an economic incentive to participate.
MR. MARTIN: Got it. Next issue: securities. There had been a fear that subscription agreements are securities and, therefore, how you market them is regulated more heavily. Have there been any developments in that area?
MR. SWEENEY: That was a concern early on because of the early type of structure that was being used. You can create programs that look like what has been described, which is like a power purchase agreement where electricity is paid for over time. Those should not be considered securities.
We have seen multiple opinions from counsel at this stage confirming this. There has also been work done by the US Securities and Exchange Commission. There is not a securities issue unless you work really hard to create one.
MR. MARTIN: So the market is getting comfortable. Net metering: there have been disputes between utilities and the rooftop companies over net metering. Those have spread to multiple states. How much does community solar depend on net metering for the business model to work?
MR. ASHAI: It is critical. Back to your question a few minutes ago about what is the biggest threat. It is whether utilities start winning this argument and push back effectively on virtual net metering or they are able to degrade the value of solar within net metering so much that the projects are no longer economic.
MR. MARTIN: Explain why net metering is critical.
MR. ASHAI: Because it allows you to go to customers offsite, and it allows you to swap in customers. It allows us to keep the financing costs low. Those three things are critical.
MR. MARTIN: The cost of acquiring customers in the rooftop market can be as much as 25% of the cost of the installed solar system. What percentage is it in community solar?
MR. SCARBOROUGH: It is not as high as 25%, but we still have to have a certain amount of door-to-door sales in order to get to the numbers we need. So it is still a significant number, probably on the order of 15% to 20%.
MR. MATZZIE: I think you have to look at the cost of acquiring one customer versus the cost of having a customer aggregation-like engine that can guarantee you have customers for the life of the project. The latter has very different unit economics. It makes the customer acquisition cost a small fraction of what it is in rooftop solar.
MR. ASHAI: I don’t think you can survive if your costs are greater than 5% of your project. I really don’t.
MR. MARTIN: How do you bring them down?
MR. ASHAI: It is hard to do with a lot of people going door-to-door. If you look at any great retail businesses, no one is going door-to-door anymore. You have to use effective digital tools. There are great platforms that can target customers with the exact preferences for which you are looking and the right geographies. The energy industry has been slow to adopt them.
MR. BLANK: If you have a structure that provides economic benefits to the customer, it reduces the acquisition costs.
MR. MARTIN: Build it and they will come.
MR. BLANK: Not quite, but I agree with what Zaid said. It has to be more like 5% of the project cost.
MR. MARTIN: Many community solar companies rely on local contractors to find subscribers. Any consumer-facing business always has to worry about sales practices. How do you protect yourselves from problems later?
MR. SCARBOROUGH: You have to enforce that through your contract with the local contractor and through oversight. If the local contractor is representing you as an agent, then you will be liable for anything it does in that sales process, so you have to be sure to control how any agent does its job.
Coming back to “they will come to us,” we are building too much just to wait for subscribers. Once we see a surge in subscriptions, we can back off. We find that we become intimate with the community while working to develop a project. We have to go into people’s homes. We have to visit not just with the town council, but also with individual residents to get the permits approved, and that builds a base for subscriptions. But for us at least, it remains a one-to-one conversation. As soon as we see the surge of subscriptions from the internet, we will back off.
MR. MATZZIE: If you don’t have to worry about FICO scores and you don’t have to have 20-year contracts, then you will have very low customer acquisition costs. There are plenty of people who pay their bills every month who do not have 700 FICO credit scores. FICO is only good for six months anyway.
The key is to design the product so that it is customer friendly. The retail electricity industry has gotten away from this basic law of business, and it is a source of problems. Community solar is much more dependent on regulatory involvement and the value-of-solar tariff. We cannot have anything but very friendly customer contracts. The term needs to be what the customer wants. We should not have a credit qualification. The fact that we can replace the customer should be enough.
MR. MARTIN: I spend a lot of time with financiers, and you guys have said three things that would be anathema to any financier. First, you do not want to lock in the revenue stream because the customers should be able to come and go. Second, you do not want to have to find customers that meet minimum credit standards. Third, the price customers pay should float with retail electricity prices, which may go up or down.
Any one of these would probably be fatal to the ability of a solar rooftop company to secure tax equity or debt. What success have you had selling this to the financial community?
MR. ASHAI: We have been very successful in selling this.
MR. MARTIN: Do the financiers raise these as potential issues?
MR. ASHAI: They do. Of course these are issues. We spent probably three years in the capital markets on how we design our debt and tax equity stacks to accommodate those risks. As long as they have faith in the platform that you can deliver those risk mitigation techniques, they get comfortable.
One thing to add on the FICO scores is there is no evidence that someone with a lower FICO score is going to pay his or her energy bills less frequently than a wealthy person. In fact, we have observed the inverse where a wealthy household is more likely to forget about the bill because it is so nonconsequential. With lower income households, the bill is so consequential that they stay on top of that. Some banks do get it, but some banks will not.
MR. MATZZIE: In Greece when people were not paying their taxes, the government started adding taxes to electric bills because people always pay their electric bills.
MR. MARTIN: Are there any audience questions?
MR. KANZER: Bill Kanzer with Relay Power in Massachusetts. We do customer acquisition. I wanted to follow up on the question about different flavors of community solar. What percentage by kilowatt — not by number of customers — for each of you are residential customers as opposed to commercial customers?
MR. SWEENEY: I will posit this guess. Our customer base stretches across all of the states that have enabled community solar so far and some that have not. In terms of total offtake, our commercial and residential split is probably 65% to 70% commercial and the balance is residential, but there are particular markets or projects that are all residential.
MR. REED: Andrew Reed with Borrego Solar. What other third-party services are surfacing to service the community solar market, like software platforms or billing or reconciling the utility credits and things like that. Can you comment on a couple of boutique industries that are growing out of this?
MR. MATZZIE: We offer that as a service to people for whom we do customer aggregation.
MR. SELIGMAN: Jake Seligman from NRG. I want to drill down on one point about which Keith asked. Have any of you convinced lenders to size against the residential contracts that do not have terms or FICO scores? I could see having success where such contracts are part of a mix in a project with, say, an anchor customer, but have you gotten sizing against those contracts?
MR. ASHAI: Yes, we have.
MR. BLANK: We have been forced to establish FICO scores by the investors with whom we work.
MR. MATZZIE: We have had to chase down certain FICO scores on projects that were 100% residential.
MR. MARTIN: What needs to be done to make community solar better?
MR. SWEENEY: Collectively as an industry we have to be advocates for good policy. Good policy is not just enabling community solar, it is also doing so in the right way. On-bill debiting is an example. We need to make sure we have a right to interconnect and have access to the utilities, customer information systems and data. That is probably the most important thing we can do as an industry.
MR. BLANK: We need to honor the spirit of what animates community solar. In a setting like Minnesota where there were gaps in the rules, people were trying to co-locate 40 megawatts of community solar on one site. In New York, many interconnection queue positions have been filed without land control. There needs to be some collective responsibility to stick with what the underlying spirit of community solar is and not try to take advantage, which I think harms all of us. It forces the regulators to ratchet back the rates, change the rules, and sometimes overreact and pull back too far.
MR. MARTIN: Last question. The investment bankers say there is a wall of money looking for projects. Are you having more money thrown at you than you are able to use effectively?
MR. ASHAI: Yes. I think our problem at Nexamp was probably three years ago. We had more projects and not enough capital, and now it is the reverse.
MR. MARTIN: Of the various types of capital — true equity, tax equity, development capital, debt — is any of these in scarce supply?
MR. ASHAI: No. Tax equity is there, but the terms are still challenging.
MR. MARTIN: Any competing views?
MR. SWEENEY: Capital is plentiful. The challenge is we have a job to do to educate the various sources of the capital so they become familiar with how community solar works and the intricacies of these subscriber agreements and the transferability capabilities. That is something we could do collectively that would be helpful.
MR. BLANK: There is too much capital chasing too few well-developed projects. If you have projects, you can create a lot of value, but it is creating enormous competition on the project side. We are seeing prices being bid way down in competitive utility processes, and on the land and interconnect side, the competition is enormous even for community solar gardens.