Cutting down the soft costs: an interview with Standard Solar


pv magazine: Can you talk about what you see as the state of the C&I market in the United States right now?

Scott Wiater: I think it is an underserved market, with an almost unlimited potential. I still think it has its challenges from credit underwriting and transaction cost that make it problematic. Since the deals are typically not that large, you have to have enough scale to make the deal worth the transaction cost that go with those kinds of deals.

Tony Clifford: What that means for us is we co-develop and finance projects from 50 kW up to tens of megawatts. It’s distributed generation (DG) stuff and that includes community solar, but we can’t do a 250 kW site by itself, we have to do it as part of a portfolio.

I think one of the things that Scott mentioned about the financing challenges is that we faced them. When we got started in distributed generation, we were a developer and an engineering, procurement and construction contractor. We didn’t have any more access to finance more than anyone else did. So we would have to get a deal developed and try to go out and finance it.

And it was really hard in those days to do DG. The financial market has gotten somewhat better. It has gotten much better for us, as since we go acquired by Énergir, we now have a multi-billion dollar finance sheet that we can look to, we can finance large projects. We just announced 42 MW in New York, and that was all DG


pv magazine: At pv magazine one of the things that we are starting to see is large institutional players come into solar project finance – things like insurance companies. And certainly with the utility-scale stuff we are seeing large asset managers buy up whole portfolios. Are you seeing this move by institutional capital to embrace solar in the C&I sector, and is this having an impact?

Wiater: We are seeing more at the portfolio level. There have been DG portfolios, operating and some later-stage development that are being sold. And we are seeing institutional players come in, which is interesting to me. The operational aspect I understand a little bit, but typcailly those institutional players don’t like the construction risk.

It is a supply and demand issue, and there is lots of money chasing few deals. Those institutional players are going farther upstream than they typically would, if there wasn’t a shortage of assets for them to purchase.

The other thing that we are seeing is some of the merchant assumptions that they are willing to take on. Many of the financiers would view those as very risky assumptions. So the uncontracted revenue… typically those institutional players want a pretty sure deal, and they are taking a lot more risk than we’ve seen in the past.

Where the more strategic players like us, where we are owned by a utility, we take a more utility view of merchant risks. Uncontracted revenue, out-years of incentives and those kinds of things.

Clifford: By out-years of incentives, it’s assumptions about what the value of SRECs is going to be. We see this stuff on a policy level, and SREC programs change. There are some people making some very big merchant risk assumptions on what the out-years are going to look like, both from the value of the electricity and the value of those various incentives.

Wiater: We bid on a lot of those operating assets, and we have low cost of capital, and in some cases we are beaten pretty handedly by people who are making merchant assumptions that are on the very aggressive side. I think that is short-lived trend, and I don’t think that will be the long-term trend. And I think as financial markets change you will see more rational behavior with the money.

Clifford: I hope solar projects last for 45 years, but I would not take some of the bets that people are taking that they will be able to last for 45 years. It could be some new technology that makes it cheaper to flip the system than to wait for 45 years. But people are taking this sort of risk.

Wiater: And the curves is 45 years are gong to be great. It is going to be 4% per year compounding for 45 years.


pv magazine: In your first comment, you mentioned that you have to have enough scale to make it worth the cost. And I get the sense that what you are alluding to here is transaction costs. And what I am hearing from developers is that these C&I deals are still largely snowflakes. That there isn’t the standardization of the process, and I’ve been hearing about efforts to do this for four or five years. So what’s the big barrier to making the process and the contracts more standardized?

Wiater: There are a couple of factors. The first is the underwriting process for the C&I space. There isn’t a standard underwriting process that the bankers have bought into and said: Hey there Moody’s of whoever is out there, go rate this project and give me a rating. That doesn’t exist.

So the underwriting process is a one-off, snowflake process. And a lot of these are un-rated entities that you would have to spend a lot of resources to go do a shadow rating, which folks don’t like to do. Why would you spend those resources on a 500 kW project, when you could spend the same amount of resources to do a 5 MW project.

That’s something folks don’t like to do.

Now the PPA standardization has always been a goal of the industry, I believe. In some cases a lot of it has been standardized. But in almost all C&I cases there are attorneys representing both parties. And every attorney I’ve ever met likes to bleed red ink on the document and will almost never take it like it is.

So we see very few if any come across without changes, no matter how fair the contract. So I think that is really the two major transactional expenses. And then most folks require an Independent Engineer evaluation if they are going to 3rd-part money, they require a 3rd-party appraisal. All of those transaction costs, unless it is a very lucrative market, it makes those deals much tougher to do.

And the spread between a 500 Kw and a 5 MW, in terms of spreading those fixed costs – the cost is basically the same. So if you can spread those costs across 5 MW, it could be a couple of cents on the overall project costs. But if it is on a 500 kW it could be pretty meaningful and a large percentage of overall costs.

Clifford: The only thing that I would add, is that you run into all sort of unsophisticated people doing DG stuff. We’ve running into projects where the project looked good, but the original developer now has two brokers in the deal. You can’t make projects work when you have that much stuff going on in the deal.

I don’t think that is going to change much. People are gong to get more sophisticated but I think it will remain a challenge.


pv magazine: What’s the path forward for C&I solar? How are we going to solve some of these problems?

Wiater: We’re fortunate. We are in a unique situation where we have out own capital stack from tax equity all the way down. So those projects that typically wouldn’t be feasible because third party financiers with tax equity or debt, that would stack on transactions costs. We’ve looked to use some of our internal tax equity to reserve it for the more challenged projects. I think we are in a unique situation there.

But again it is cutting down on the soft costs. We are seeing permitting and interconnection costs going up instead of going down, and becoming more difficult to obtain instead of easier to obtain.

SunShot was the DOE program to lower those soft costs – it seems to be going the wrong way, especially in the Northeast. And as we get more saturation in the market, I expect that will continue. Storage of course i the cure-all for everything, and once storage is more mainstream, I think that these projects combined with storage will change that.

Clifford: There are four different sessions in this conference on soft costs. And half of the DG meeting is about soft costs. And then there is a permitting meeting that follows directly past the DG meeting. People are working on this issue, but you have so many different states, so many different municipal governments, so many different utility districts… as solar becomes more more economic, you are running into the fact that you are going into places where we haven’t seen solar before.

And so that slows stuff down. It is their first solar permitting of something other than a residence. And that’s just going to take time.

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