For one week following each TAP Webinar, you are invited to ask questions of the presenters, enter comments about the topic of the presentation, and share comments with others.
How to use power purchase agreements to finance public sector PV projects?
The TAP Webinar archive posts the presentations from the May 27 TAP Webinar and links to background information and reports dealing with financing public sector PV projects.
These questions are from the May 27 TAP Webinar that were unable to be addressed due to time restrictions.
How are solar Renewable Energy Certificates (RECs) handled in a Power Purchase Agreement (PPA)?
Normally, the RECs stay with the system owner, which in this case is not the public entity but rather the private-sector counterparty to the PPA. You can negotiate to purchase both the electricity and the RECs as part of the PPA. But of course, this will increase the price on a per kilowatt-hour (kWh) basis. Most cities I work with decide against purchasing the RECs in order to keep the cost of electricity as low as possible. If you do it that way, however, you cannot say you are "solar powered" because only the owner of the RECs can make that claim. Instead you can say you "host" solar panels on your facility.
Can you please comment on what REC arrangements you have seen in the PPAs? Are they typically retained by the public sector client? How have you seen them assign financial "value" to the RECs?
Building off of the last response, I have seen PPAs where the city has requested that the PPA counterparty offer a price that includes the RECs and one that does not, so the city knows how much it would actually be paying for the RECs. In markets where the renewable portfolio standard has a solar carve-out, in Colorado for example, the PPA provider bids for a REC price to the utility. If the utility accepts the bid, the utility will buy the RECs from the PPA provider as they are produced. In Colorado, the solar RECs can be worth as much as $0.15 per kWh. Although prices a few year ago were much higher, they have come down over time. In California where there is not a solar carve-out per se, most people give RECs a value of a penny or so per kWh. I have heard of structures where a public entity wishes to share the RECs with the PPA provider (say 50:50), but I have not seen this in any of the contracts I have worked on.
Can you please talk about the RECs and the ability of the City to claim that it is a clean energy producer?
If you don’t own the RECs, you are restricted as to what you can say about the system. In my opinion, you are not a clean energy producer unless you own the RECs associated with the power.
One alternative is to purchase replacement RECs to substitute for the solar RECs that you do not own. For example, if the cost to purchase the solar RECs was too high, you could go into the voluntary REC market and buy an equivalent amount of RECs, say from a wind project. These wind RECs will likely be cheaper. So in this case, you’ve "greened up" your project and can make clean energy claims although not "solar-powered" per se since you’ve purchased wind RECs.
You referred to a fixed rate for PV power in PPA. Have you ever heard of a rate that is indexed in some way to market electric rates?
The most common pricing scheme that I see is a price for electricity in year one with an annual escalator. It is also common to have a fixed priced per kWh for the life of the contract. It may also be possible to structure a transaction where the price escalates for a fixed number of years but then remains constant after that.
As far as trying to tie the rate to market electricity rates, conceivably, you can negotiate a "utility rate minus x%" tariff in the PPA. In this scenario, you’ll always be cheaper than the market rate, but you don’t know what the actual rate will be, which may complicate your budget process. Under the fixed rate scenario or the price plus an escalator scenario, you will know your cost per kWh for a given year. In the case where we explored this "utility-minus" idea, it becomes very complicated to figure out how to create the billing mechanism for it. Or imagine that electricity rates increase by 15% in one year; the fact that you’ve received a 10% discount (or 1.5%) off of a 15% increase is not necessarily a positive outcome. In this instance, the agency decided against the "utility-minus" model. If for approval sake, you need to guarantee that you will always be lower than the utility rate, you could structure a "utility-minus" option, but in general terms, I don’t think it is a good idea. It overly complicates one of the primary advantages of the PPA: price predictability.
Could you also discuss the PPA model in a fully regulated state where a government entity cannot directly purchase electricity from a third party?
I know that there are some states that limit the ability for third parties to sell electricity within a utility’s franchise area. In some cases, there are work-arounds. In others, there might not be any recourse until the state public utility commission makes a definitive ruling on the legality of the third party PPA model for solar. To use an example from Denver, Xcel Energy and the PPA counterparty signed an agreement in which Xcel grants permission for the third party to sell electricity within Xcel’s territory, but in no way does it waive the utility’s franchise rights. (Read the agreement letter from the Xcel Energy Web site. PDF 26.3 KB). Download Adobe Reader.
For public schools that are subject to state public bidding laws, do you have suggestions to make a PPA work?
A number of school districts have signed PPAs, particularly in California, so I don’t see why public biding laws would be an issue. One suggestion is you bundle systems on many schools to get the total installed capacity of the project to a high enough level to make sense for a PPA transaction. A 20-kW system on one school would not be one in which you’d go the PPA route.
Some PV installers are encouraging us to use some of our funds to offset the installation costs to get lower rates. In you experience, does this tend to overcomplicate the process?
This is what Boulder County did, as you’ll remember from the presentation. I do think there is value in considering prepaying some of the installation costs. If you assume that the cost of capital for a public agency will be less than the cost of capital that the PPA provider will need to raise, you can strip out 20–25 years of some financing costs from the transaction. If there is cash available — possibly stimulus funding — then you should at least run the numbers. By buying down the cost of the system, you may be able to get a very attractive rate for electricity in the PPA. Also, with the difficulties in the financial markets, this upfront payment to the developer may be the difference between getting a project off the ground versus having it stalled.
What are the risks to be considered in the allocation of risk between system owner and lessee?
Some risks might be as follows:
- Down time of the system due to roof maintenance – both the lost revenues, as well as who pays for the roof maintenance
- Risk that the building occupant might leave
- Risks of shading
- Environmental risks if a ground mounted system
- Security costs and property insurance – who pays and who might be in a position to mitigate these risks more cheaply
- Damages due to negligence of the PPA provider
- Damages due to negligence of public agency
- What happens if funds aren’t appropriated to pay for the electricity?
What is Boulder County’s typical $/kWh they pay, or specifically what was the rate for the PPA versus the rate from the utility?
I believe Ann said they normally pay $0.09/kWh, but given that they paid for some of the installation costs, they got a rate of $0.07/kWh.