Community solar is gaining ground with the 49% to 80% of utility customers who are not candidates for rooftop solar. How does it work, why has it taken root to date only in eight states and what is its potential?

A panel answered these and other questions at the Chadbourne global energy & finance conference in June. The panelists are David Amster-Olszewski, founder and CEO of SunShare, Mark Boyer, chief capital officer of Clean Energy Collective, David Feldman, senior financial analyst with the National Renewable Energy Laboratory and author of a paper on community solar business models, Steven Miriani, general counsel of SoCore Energy, and Erik Stuebe, co-founder and president of Ecoplexus. The moderator is John Marciano with Chadbourne in Washington.

MR. MARCIANO: What is community solar? The term means different things to different people.

MR. BOYER: At Clean Energy Collective, we define community solar as building utility-scale solar arrays that are interconnected to the grid. The electricity from the project is sold to the local utility. Customers of the local utility can purchase as little as a single panel worth of the project all the way up to a large industrial customer who may want to participate in half the project. The customers receive bill credits for the electricity sold to the utility from the project. The credits can be used to offset what they owe the local utility for the electricity they buy from the local utility.

MR. MARCIANO: You might have many people with ownership shares in the project or you might have just one or two.

MR. BOYER: We average about 300 per facility.

MR. MARCIANO: Some people describe such projects as a form of virtual remote net metering.

MR. BOYER: That’s correct.

MR. MARCIANO: David Amster-Olszewski, what form of participation do your customers have in such projects? Do they own individual panels?

MR. AMSTER-OLSZEWSKI: Mark gave a great summary. Our customers are everything from individuals — I am a participant, our employees are participants — all the way up to the city of Denver and the University of Colorado. They are everything from large AA and AAA credit quality customers to residential customers with a 700+ FICO score. The business model is similar to SolarCity’s business model. The only difference is we take the panels off the roof, put them in a field, reduce the system cost, dramatically reduce the customer acquisition cost, and increase the market potential by five times because there is no appliance on the roof and there is no shading issue.

Community solar really is something that brings solar to the masses with large projects. Rather than have a thousand households with a thousands systems, you can have a thousand households and large customers all in one project where you control the assets.

MR. MARCIANO: I believe community solar works currently in eight states. What makes a state a good state for community solar?

MR. FELDMAN: There are actually nine or 10 states that have passed some sort of legislation to facilitate community solar. The authorizing legislation usually takes one of three forms. There could be some form of virtual net metering regulation that allows customers to get credits on their bills for generation from something that is not connected to their meters. There are also incentives that provide money or some other form of inducement to share ownership of a community solar project. Then there is a third type of legislation that is more comprehensive in trying to advance community solar rather than just allowing things to develop on their own.

There are other states that do not have legislation, but where utilities may be interested in promoting these types of projects as an alternative to net metering. All you need in those states is to work out some of bill credit mechanism. It may not require legislation.

Utility Response

MR. MARCIANO: Why would a utility be interested in promoting such projects?

MR. FELDMAN: They have a lot more control over the assets. They potentially have a lot more control over the rates. The utility does not lose its customers. It can still charge the full retail rates. The bill credit is for the wholesale rate. The project can be put in a more ideal location than on the customers’ roofs. A larger project has the potential to generate electricity more cheaply.

MR. STUEBE: Truth be told, utilities are generally resistant to community solar just as they have been resistant to net metering. It is inherently in conflict with their business model which involves earning a regulated return on invested capital. The fact that the project is owned by a third party means it is not in the utility’s rate base. We have seen resistance across the board in California, Minnesota and other states, and by developers and utilities will ultimately have to compromise over the allocation of costs to ratepayers and other stakeholders.

MR. BOYER: We try to function in a number of states, and about 60% of our business is with electric coops and municipal utilities. If you think about their missions and community solar, the two are well aligned. So I think the coops and munis are receptive. We have been successful in signing power purchase agreements with them directly; no state mandate or state legislation is required. You have to help them figure out how to provide the bill crediting, which can be difficult, but that is one area where we are able to help.

MR. AMSTER-OLSZEWSKI: Granted I agree with you; the utilities can take a long time to recognize that something good is coming to them and then a longer time to adopt it. But we are starting to see the shift, especially from four years ago when nobody knew what community solar was.

I think utilities are starting to see community solar as a vehicle to maintain control over their customer relationships. For example, with a community solar farm, we are using the grid that exists. We need the grid. There will not be a battery backup system, a storage package in the customer’s basement, that is tied into a rooftop solar array. The utility is not losing the customer and, in many states, we can start negotiating with utilities about rate recovery to solve some of their concerns as well and even operating community solar farms for the utility.

The problem in the community solar space has been in cracking this nut of how to make solar work for the utility.

Xcel signed well over 100 megawatts of power purchase agreements last year and, in the Denver Post, there was a paragraph about two inches long.

There is no comparison between that and the amount of positive attention that a community solar project brings for the utility. It is a full-page article starting on the front page of the Post. It is a completely different level of consumer interaction that utilities are able to garner through community solar programs. I think you are going to start seeing the number of such projects increase dramatically over the next five years.

MR. MIRIANI: There is great demand in both the residential and the commercial and industrial spaces for community solar, but things need to be worked out with the utility. Minnesota is an example of a state where the legislation is in place, but there are still issues on which developers have spent a lot of time and money. There is plenty of demand for the subscriptions in Minnesota. The issues are with Xcel and various implementation aspects of the program. People are still working through the issues.

MR. MARCIANO: Yet it is in the utilities’ interests to work through these issues rather than have customers disappear to rooftop solar companies?

MR. AMSTER-OLSZEWSKI: Yes. The question for utilities is whether they move fast enough to seize the opportunity in front of them. The people at utilities recognize the rooftop alternative could lead eventually to a death spiral. The question is whether they can turn those large ships fast enough to take advantage of the opportunity.

MR. BOYER: We have been doing this for five-plus years. When we first went in to see utilities, it was always, “You want to do what?” Now there is a conversation about how the utility can participate in it. They see the benefit. I agree with David that they move very slowly through any process.

MR. MARCIANO: If you have 300 participants in an average project, what does that make the average project size.

MR. BOYER: Our average is just north of one megawatt, or 1.2 megawatts DC.

Risks

MR. MARCIANO: How do your investors or lenders get comfortable with the risk that a customer might stop paying?

MR. BOYER: The utility has a take-or-pay arrangement, so it will pay. That is the standard financing structure, and it makes it easy to arrange financing.

In some cases, like with Xcel, the utility will only pay the avoided cost of any power that comes to it without a subscriber. One way to address this is to have a prepaid program from the customer so that you are moving through the financing much faster, and the debt is paid off much more quickly.

The beauty of community solar is the easy transferability. If a customer stops paying, you are not stuck with a system on its roof. You simply replace the customer. In some cases, you can do it right away and move their bill credits to another customer. If a customer moves but stays within the same utility service territory, it is a simple telephone call. The customer still gets its bill credits. If the customer moves farther away, we tell the customer we will resell the customer’s interest in the project. We sort of view ourselves as the Coldwell Banker of community solar for our deals. Come back, and we will resell your interest.

MR. MARCIANO: One of the challenges for rooftop solar companies is what happens if a customer stops paying. You cannot really remove the system easily from the roof and redeploy, at least not economically, so the customer has you over a barrel. You are saying you are in a better position than the rooftop companies.

MR. BOYER: Yes. I think the way to look at it from a financial perspective is this is the first solar product where you have a recoverable asset. I control the field that the panels are in. I control the panels. It takes my team about 20 seconds to unsubscribe a customer from the online system. If the customer does not pay, I unsubscribe him and my lost cost is not the $15,000 dollars of remaining payments in the contract, although the customers under our contracts are still responsible for that. In reality, the lost cost to us is the number of months it takes to find a new subscriber and the cost of customer acquisition for that new subscriber.

It is like a cell phone business model that you can start moving to as you start having more creative financing options that are available for community solar. We are not there yet, but that is the direction in which it is moving. You do not have a cell phone contract that is meant to pay off the cost of a cell phone tower. You know that your customer acquisition cost is $200 dollars and you subscribe a new customer every five minutes. That is the way that financiers are starting to look at community solar.

MR. STUEBE: Those are great points, and I completely agree. I would add that it is important to vet the creditworthiness of subscribers carefully. Our approach is to go in with either municipalities, school districts or Fortune 1000 offtakers. Then you have the added benefit, in the event one of them defaults, of the ability to swap them out.

Reaction Among Financiers

MR. MARCIANO: Are lenders and tax equity investors interested in participating in these projects?

MR. STUEBE: Yes. We have worked with several tax equity investors. From a financing perspective, community solar projects are similar to net metered projects with creditworthy offtakers, with added downside protection from the ability to swap out a subscriber in the event of a default. The community solar construct is also flexible enough that it can accommodate customers who need to move or expand their facilities.

MR. MARCIANO: Steve Miriani, you do more than community solar. How do the financing costs differ between community solar and other forms of solar?

MR. MIRIANI: I do not think they differ. It comes down to credit quality of the offtaker. In many ways, community solar is easier to finance than other forms of distributed solar. You are not on somebody’s roof. You have the ability to remarket the power if you have a credit quality issue. You have a diverse enough portfolio that the banks can get past that.

MR. STUEBE: There is the potential to finance solar customers who would not otherwise qualify. For example, in some states there is an opportunity to have low-income participants be involved. Ecoplexus has developed more than 10 projects in which low-income renters are subscribers.

MR. BOYER: There is definitely an education process with investors. We financed 4 1/2 megawatts of community solar in Colorado last year, and there were definitely groups of investors that did not want to do the heavy work to come up to speed on the program and the subscriber agreements. Eventually we got it done.

MR. AMSTER-OLSZEWSKI: We have seen change over time. When we did our first two megawatts using Treasury cash grant panels four years ago, no one knew what community solar was. Multiple customers in a portfolio? That gives me a brain hemorrhage.

Meanwhile, they are financing 10,000 residential rooftop systems with 10,000 different customers each with a different rooftop configuration and system size. There is a little irony there.

Now we have 12 megawatts in the ground working with GE Energy Financial Services as the tax equity. We have another 200 megawatts under development this year and the first part of next year in Minnesota and Colorado.

The industry is moving quickly toward scale. In Minnesota, 750 megawatts AC are in the queue; add another 20% to get to DC. The Minnesota program opened for business in December. That is an explosive growth rate in just six months. It is $2 billion worth of projects in a state like Minnesota, where the installed capacity today is less than 15 megawatts.

MR. MARCIANO: What has been the key to the success in Minnesota?

MR. AMSTER-OLSZEWSKI: We have been working with Xcel for years now in Colorado. It supported a community solar bill in the Minnesota legislature. I do not think they wanted it to be unlimited, but that was thrown in at the last minute, so you have an unlimited community solar market in Minnesota that was confirmed by the public utilities commission even though the utility wanted to put caps on it.

What the program creates for customers is free choice. You have a regulated market with a regulated monopoly, but then you also have a free-choice customer option where any customer can choose to use renewable energy and any developer that has the foresight to find a piece of land and connect to the grid can pull together customers and the financing to build projects.

MR. MARCIANO: With that kind of growth, are you having to pay for expensive network upgrades to the grid to accommodate the additional electricity?

MR. AMSTER-OLSZEWSKI: It is too early to tell because the system impact studies are still being done. Many of these projects are connected to distribution lines rather than transmission lines.

MR. BOYER: Interconnection costs are still unknown and are difficult to control. Interconnection with Xcel in Colorado has been relatively inexpensive. When you get to Massachusetts and have to deal with National Grid and NSTAR, it is a different ballgame. We are still waiting for numbers.

MR. MARCIANO: National Grid seems to have a pretty expensive view of what it takes in Massachusetts.

MR. BOYER: It does, but there is opportunity in that as well. We did a project with a coop in southern Colorado, and the coop told us where it wanted the project. It said it has a problem on a particular transmission and could use more generation on another line. It asked us to put the project somewhere between a particular substation and the load. Things worked out perfectly. The project is literally in the middle of nowhere. We built a megawatt there. The interconnection costs were almost negligible because of that. This is another opportunity for community solar that might not be available to larger projects.

MR. MARCIANO: Can you earn extra revenue for placing the project in the right place and providing a sort of ancillary service?

MR. BOYER: We were able to use the location to get a slightly higher electricity price in the PPA.

MR. AMSTER-OLSZEWSKI: There is actually a tariff in Minnesota that provide additional compensation for locating systems in the right areas, so, as Mark was saying, a lot of the game and expertise in this is getting to the market early. Having a good interconnection engineer who can find the right location is essential. It is not like you go on the internet to find the best spot on the grid to connect the system. One of the competitive advantages is having an engineer who worked for either the public utilities commission or utility and who knows where the good spots are so that you can be first in the queue for those spots. That leads to the lowest interconnection cost. That is one of the areas where I think we have differentiated ourselves: being first to market and first in the queue with the lowest interconnection costs.

Audience Questions

MR. MARCIANO: Let me stop there. Any questions from the audience?

MR. HERMAN: Steve Herman with Energy Capital Partners. Let me raise a policy issue. Is there not a social or economic justice issue with community solar? Put aside where there is a mandate for low income, which I think is the exception. I heard someone suggest you have to have a 700+ credit score to participate in this.

MR. AMSTER-OLSZEWSKI: That is a great question. That is the reason I got into community solar, right at the heart of the passion. Right now solar requires a good rooftop, owning your own home generally, and a 700 or higher similar credit score. What we are moving toward with community solar will eventually be a product that can be sold to anyone. Community solar is the great equalizer in solar energy. That is one of the things that is driving it so fast — from nobody knowing about it and no state laws five years ago to now 10 states having laws and another 22 states that have policies in the process of either being approved by regulatory commissions or legislation.

It is moving so fast because of that popular appeal of the ability to bring it to everyone. The last challenge now to crack is flexible financing terms so that we can truly provide it to anyone.

MR. FELDMAN: I agree. The issues are not dissimilar across distributed solar in general. The economic inequality issue is an unfair burden to pin on these companies. Electricity rates are not inherently fair in general. Certain people pay more than others. No individual customer is paying the actual cost of energy. There are a lot of places, particularly in California, where higher income households are paying more on average for their energy because they consume more. There is a recent study that showed that, even with distributed solar on their roofs, the higher-income communities are still paying a higher average rate than other customers.

The argument is unfair, but even if you have a problem with distributed solar, community solar has the potential to make it more fair.

MR. EBER: John Eber with JP Morgan Capital Corporation.

This is the first time I have heard a panel talk about distributed solar and not really mention net metering. Does net metering not exist in the world of community solar? If so, won’t community solar eventually replace rooftop solar?

MR. AMSTER-OLSZEWSKI: In short, I would say that is the opportunity.

MR. STUEBE: We view the Minnesota structure as a form of remote net metering. The only difference between remote net metering and more conventional net metering is that the solar facility is not co-located with the load.

MR. EBER: What I meant by net metering was the ability to offset more than the power that you are using in your home. With a typical rooftop solar system, the homeowner is getting some benefit beyond the amount of power that he needs in his home. Is the same thing happening with community solar?

MR. AMSTER-OLSZEWSKI: There is usually a cap. For example, in Colorado, community solar can be used only up to 120% of a subscriber’s existing load. From our experience, very few people participate at a level above 100% of their load. The average is probably around 50% to 60% of load for the average residential subscriber.

MR. STUEBE: Our company has done about 45 net metering projects in California, and never once has the available roof space been able to offset more than 80% of the load. Often it is 30% or 40%, so the advantage with community solar is you can offset up to 100% without being restricted by the size of the roof.

Another important advantage is, in California, 44% of residences are multi-tenant facilities. The landlord of a multi-tenant facility has little incentive to try to help renters save on their utility bills or, if the landlord wants to help, it requires complex accounting. Community solar can address that problem by allowing renters to contract with a community solar company directly.

MR. AMSTER-OLSZEWSKI: You are touching on an important policy point.

Colorado has net metering for rooftop systems, so let’s say the retail electricity rate is 11¢ per kilowatt hour. Someone with a rooftop solar system generates a kilowatt hour and sends it to the grid. His meter rolls backwards by 11¢.

For community solar what we negotiated with the utility there, via the public utilities commission process and a legislative process years ago, was a different type of rate. It is not the full retail rate. It is the retail rate minus transmission and distribution cost. That is the customer credit. The customer might be paying 11 cents per kilowatt hour for electricity from the utility, but the community solar bill credit may be 8¢ per kilowatt hour, so the utility is still getting compensated by that customer for the cost of its transmission and distribution system.

That’s the type of compromise that has the potential to get utilities on board with community solar. You allow utilities to recover some of their fixed costs, specifically for the transmission and distribution systems, with community solar in a way that they are not able to do with rooftop solar and net metering.

There are PPA deals being done in Colorado for between 5¢ and 6¢ per kilowatt hour. If I sell to a customer for 8¢, that is not a bad spread. I do not need the 11¢.

MR. SALANT: Marshal Salant from Citibank. I like where you are going on the size of the credit, but have a follow up to John Eber’s question about net metering. We at Citi would love to start financing community solar, but we have spoken to law firms and our counsels are saying very clearly, stop, this is going to be challenged by utilities. This is going to end up in the courts. This could end up at the Supreme Court. It could end up needing legislation from Congress because it has not been adjudicated yet.

What do you say in response to that? You are making it sound like there is no controversy. I am just trying to figure this out.

MR. AMSTER-OLSZEWSKI: That’s a good question. We have not seen any controversy in the community solar space until recently in Minnesota, when you went from zero to 750 megawatts in the queue in six months and you can probably figure out why there is some controversy there.

The utility is thinking, “Whoa, we just let the cat out of the bag. How do we reel it back in?”

All of our projects in Minnesota are 10 megawatts because community solar is supposed to be distributed generation and the tariffs say that distributed generation is 10 megawatts and under. Some companies that have gone out and proposed 30-, 40- and 50-megawatt projects.

If you stay under the 10 megawatts, you will be safe. Just like anything else, if you follow the rules of the program and if you have the right policy supporting you and you have the right people on your team in the community that are well engaged with the utility and with the policymakers, you can set up strategies ahead of time that allow you to move past the risks.

Some folks moving into Minnesota thought they saw a good opportunity to combine multiple 10-megawatt projects on the same site because the utility commission allowed for a decreasing marginal cost of interconnection. There is no tariff for interconnecting anything over 10 megawatts.

Of course you are going to have a problem if you co-locate projects like this.

MR. BOYER: Xcel has raised the co-location issue in Minnesota. We think that will be resolved fairly quickly to the satisfaction of the financial community. We cannot be certain what the resolution will be, but we think the eventual resolution with Xcel on board will give the certainty the banks need to move forward.

MR. MIRIANI: In terms of the timeline, these settlement discussions are about the caps on individual project size. The authorizing legislation is clear that there is no cap on the program as a whole. The public utilities commission is expected to issue a ruling by around June 30. The market expects this to be resolved quickly.

MR. SMUTNY-JONES: Jan Smutny-Jones with the Independent Energy Producers Association representing wholesale private power producers here in California. It sounds like to me like these arrangements are sales of electricity for resale, which would bring federal jurisdiction into play. How has that been addressed?

Related question: you are exempted explicitly from being a utility or is the public utilities commission actually regulating you as a utility?

MR. BOYER: This is a new field. We have had to spend a lot of time and legal dollars to make sure that we are vetting these issues relative to the federal Public Utility Regulatory Policies Act and the Federal Energy Regulatory Commission. The fact that the utility is collecting the T&D charge as part of the rate it charges the customer helps with the potential regulatory issues at the federal level, including the sale-and-resale stuff. We have been through this a number of times and I know that SunShare has as well.

MR. AMSTER-OLSZEWSKI: I would also point out that virtual net metering community solar is not new. It is new at the scale we are seeing in Minnesota, but our company has had about 10 virtual net metering projects in California operating for about four years. Some of them have up to 260 subscribers, so this model has been vetted and what is in question in Minnesota is not the essence or the structure of the program itself or whether it passes muster under federal and state law. What is at issue is only the size of the individual solar project. We are not seeing challenges to the legality of community solar.