U.S. Department of Energy - Energy Efficiency and Renewable Energy

Office of EERE

Community Renewable Energy Success Stories Webinar: Developing PV Projects with RFPs and PPAs (text version)

Below is the text version of the webinar titled "Developing PV Projects with RFPS and PPAS," originally presented on January 15, 2013.

Operator:
The broadcast is now starting. All attendees are in listen-only mode.

Sarah Busche:
Good afternoon, everyone, and welcome to today's webinar sponsored by the U.S. Department of Energy (DOE). I'm Sarah Busche and here with me is Devin Egan. We're broadcasting live from the National Renewable Energy Laboratory (NREL) just outside of Denver, Colorado, in Golden, and we're going to give everyone a few more minutes to call in and log on, but during that time Devin is going to go over some of the logistics to make sure that you can hear us and see the slides. Devin?

Devin Egan:
Thanks, Sarah. Good afternoon. First of all, you have two options for how you can hear today's webinar. In the upper right corner of your screen there's a box that says, "Audio mode." That will allow you to choose whether or not you want to listen to the webinar through your computer speakers or over the telephone.

As a rule, if you can listen to music on your computer, you should be able to hear the webinar. If you have questions during the webinar, please use the questions pane in the right hand box on your screen. There, you can type any question you may have during the question and answer segments at the end of today's presentation and after today's webinar, you'll be prompted to complete a short survey. Please take a few minutes to submit your answers when the webinar has ended.

Today's webinar will be posted online on the Community Renewable Energy Deployment Website. Once the presentations are posted, you'll receive a link to them via email when it's available along with the video and the transcript of today's presentation. This process can take anywhere from 7 to 14 days. With that, I'll turn it back over to Sarah to talk about today's webinar.

Sarah Busche:
Great! Thanks, Devin. I hope everyone can hear us just fine. This is the sixth in a series of U.S. Department of Energy Community Renewable Energy success stories and we call Community Renewable Energy 'CommRE.' Each of the webinars features communities that are successfully implementing renewable energy technologies all around the country. The CommRE project is a more than $20 million dollar effort funded through the American Recovery and Reinvestment Act (ARRA) of 2009 to promote investment in clean energy solutions at the community level and also to provide real life examples for other local governments, campuses, and utilities to replicate.

There were five community-based renewable energy projects that received funding under this program. Those were in Vermont, Wisconsin, Colorado, and California. The webinar series not only highlights what they're doing, but also highlights what other communities that are leading the way across the country are doing, so during today's webinar, we're lucky to have representatives from Tucson, Arizona, and Minneapolis, Minnesota, and they're going to discuss their city's experiences with developing solar projects using RFPs (Request for Proposals) and PPAs (Power Purchase Agreements). I'd like to remind you that we'll do a Q&A session after each presentation, so please don't be shy.

Go ahead and type in your questions and we'll get to as many as we can immediately following each presentation, and then we'll also do a general Q&A at the end. Without further ado, I'd like to introduce our first speaker, Bruce Plenk. Mr. Plenk is the solar coordinator for the city of Tucson, a post he's held for the past five years, and he's been involved with solar installations and policy for many more years. Bruce, if you're ready, we'll turn it over to you now.

Bruce Plenk:
Great! Thank you very much, Sarah, and thank you for the invitation to participate in today's webinar and welcome to all of our listeners.

[Next Slide]
The program today is going to be a discussion about five different RFPs and RFQs (Request for Qualifications) that we've used in Tucson to develop our solar stockpile, if you want to call it that, or solar repertoire, so let's jump right in and go to the next slide, please.

[Next Slide]
So Tucson was one of the first cities to start investing in solar. We put up our first solar project on a councilperson's office in 1999 and had some creative staff people working for the city that were able to utilize city general funds to do these relatively small investments over the next nine years or so. We were able to put up about 220 kilowatts (kW) of total PV on eight different city sites that range from community recreation centers to a reservoir deck and a number of other places, and we used the money from the general fund, as well as leveraging money from solar grants and utility rebates. We were also able to do about 300 bus shelters with solar that were fully funded through the advertising at the bus shelters. These systems were all relatively small and the smallest was about 3 kW. The largest, about 64 kW, and in addition, we did some solar hot water systems. Let's go to the next slide, please.

[Next Slide]
So one of the things that always comes up in making decisions before you do solar is what do you have to think about before you do an RFP, or an RFQ, or some other kind of solicitation and basically on this slide I've outlined a couple of different routes that people have used. The first one in Plan A, you could have the property owners select the sites and have the vendor determine the details and the size of the system, or you could have the property owner do some preliminary work. In Plan B, which has been popular with a number of cities and counties around the country, the vendor selects the sites from a list of possible properties based on the various characteristics that I've listed on the slide and the property owner, whether it's the city, or the county, or whomever, may predetermine the total size of the PV system or completely leave it open. In that case, the vendor's doing all the studies and doing everything to get from an address to a possible PV system. Next slide, please.

[Next Slide]
So when you start talking about the different locations and different sites, there are a number of important things to consider from the get-go. The two that are critical are the electric load of that building, particularly if you do not have what's called the aggregated net metering. That means that if you don't have aggregated net metering, it means that the solar system will need to be matched to the electrical load of the building where you're putting up the PV because that's where the solar system will be integrated to the grid, and the output from the solar system must be matched to the load of the building.

If you are lucky enough to be in a jurisdiction that has aggregated net metering, then that's not an issue, so you can avoid what we've called here the small load, big roof problem. That's where you have plenty of room for a giant solar system. You just don't have the load, so you can't really utilize the roof. The second really key point is doing a structural analysis of the building, which normally would require a structural engineer to determine what amount of weight can be supported by that roof.

[Next Slide]
And the third thing that's obviously really important – let's go back to that previous slide, please.

[Previous Slide]
The third thing that's really important is the interconnection requirements. I've listed a number of other items on this slide that can be important when you're picking a site for solar that are less significant, but may be important as well. Sometimes zoning or some of these other things can be problematic, but the first three are really the critical issues. Now let's go to the next slide, please.

[Next Slide]
So once you've started determining which sites you might want to use, then you have to decide probably the most critical question, which is do you as a city or a county or business want to own this solar system, or do you want to use a power purchase agreement or lease some kind of a third party system? On this slide, I've tried to illustrate some of the difference between the two. The biggest difference, of course, is that if you own the system, you have to come up with the capital to buy it in the first place and you next have to be able to have the money and the skill set within your staff to deal with any kind of maintenance issues.

The other piece, of course, is that because cities and states and counties don't pay taxes, there's no way to directly take advantage of the tax credits that are available, or depreciation, which can be utilized by a developer if they're going to be offering solar through a PPA, and this would also apply to a lease. This is probably the biggest distinction between the two, and this is probably the most significant fork in the road. Let's go to the next slide.

[Next Slide]
Despite the fact that it's a fork in the road, the city of Tucson in 2007 tried to do a combination PPA and CREBs bond construction. CREBs are Clean Renewable Energy Bonds. We were able to obtain some CREBs authorizations by applying to the IRS and I'm sorry to report there's no current CREBs authorization available at the moment. They may be authorized again, but there have been several rounds in the past where CREBs allocations were available for a short time (background conversations) and different governmental entities could apply for and get the CREBs allocations and the city of Tucson was lucky and was able to do that. In 2007, we had a consultant help us determine the sites that we were going to use for our PV projects, submitted those to the IRS, and were approved.

Sarah Busche:
Hey, Bruce?

Bruce Plenk:
Yeah.

Sarah Busche:
Bruce? Can you hold on for a second?

Bruce Plenk:
Sure.

Sarah Busche:
Brian? Can you mute yours?

Brian Millberg:
Okay. Let me see if this works. Am I muted?

Sarah Busche:
No.

Devin Egan:
No.

Bruce Plenk:
No.

Brian Millberg:
Doesn't work.

Sarah Busche:
So we're going to come back around ___ _____, Brian.

Bruce Plenk:
Okay. Are we good?

Sarah Busche:
I think so. Thanks, Bruce. Thanks, Brian.

Bruce Plenk:
Okay, sure. Anyway, so we were trying to combine two things that involved a PPA for 20 years, and then taking over the system and having the provider pay, an issuant pay for the CREBs response.

[Next Slide]
And basically nobody went for that, so that was a fizzle. It basically just didn't work and we learned our lesson. On this slide, there's a date error and I apologize for that. The date on that should be 2008, not 2010, but basically we did learn the lesson from the first go-around, that you can't really mix PPAs and CREBs together.

[Next Slide, Previous Slide, Next Slide]
So in 2008, we reissued an RFQ, Request for Qualifications, for a design and build project and made it clear that we had decided to finance the PV project with a bond sale and that we would own the project. We should not try to integrate a PPA with it at all. So, we also issued a separate RFP to locate a company to help us place the bond. We had the seven sites still from the earlier CREBs allocation and we signed a contract through the RFQ with a company called SPG Solar. And with them and in that contract, they agreed to a ten-year O&M (operation and maintenance) agreement as well as the solar production guarantee and we signed their contract, then placed the bonds and went from there. Next slide, please.

[Next Slide]
To make this all happen required a lot of different people, who we've tried to illustrate on this slide. We had to get the IRS to approve the CREBs bond. We had to get assistance from our finance department in helping us locate the bond placement and place the bond, which was eventually placed with Bank of America. We had to have a procurement department involved. We had a list of vendors who applied and we had to choose the correct vendor, and we had to work with the city government branches that were in the different buildings that – where the solar was going to be placed. Next slide, please.

[Next Slide]
This timeline kind of shows basically the two-year process that it took from the time that we initially selected sites and heard about CREBs and applied for CREBs through the process of watching the bond market, getting approval, choosing a contractor, and then building the actual solar project. I should say, and this is probably a really important point, that one of the differences between the first time that we issued the fatal CREBs PPA mixed bonds that didn't work and the time that we issued the second – our second attempt to get CREBs issued, Tucson became a Solar America City through the U.S. Department and Energy (DOE) and we got some very useful help from NREL and New Mexico State and other technical support through DOE as part of our Solar American Cities grant and the folks at NREL were particularly helpful, particularly Jason Coughlin in helping us understand CREBs.

[Next Slide]
So the next piece we had to deal with was making sure that we could pay for the bond, so what we did was basically worked it out so that the customers in the buildings that had the solar put on would continue paying for the electricity that they use. They just would now pay part to the utility company and part to us for the amount that was generated by solar and then we were able to sell the RECs, the Renewable Energy Credits to our local utility company, Tucson Electric Power (TEP), at their PBI, which stands for Production Based Incentive option, so every quarter we get a check from TEP and the money that we get we use to pay the bond. The critical issues that I listed were basically some of the questions we had to deal with in deciding about how the bond would be paid for and convincing the political leaders that this was really a feasible project. Let's go to the next one, please.

[Next Slide]
So this shows you the kind of projects we did and where they were. They were sort of spread out around town from neighborhood centers, to a warehouse, to some recreation centers. Let's go to the next slide.

[Next Slide]
So, because we were going to own the system, we needed to be more involved in some of the technology decisions, so one of the first ones for a roof-based system is are you going to use a ballasted system, which uses much – a lot more weight. In the picture, you can see that we've used paver blocks, sometimes using sand. This is a nice way to do solar on a rooftop if you've got the roof that can support it, because you don't penetrate the roof. The lower picture shows a more traditional racking approach, where we penetrated the roof, and of course there you have to deal with leaks, roof warranties, and other issues, city roofers that freak out and so forth. It also gives you the opportunity, and it's worth thinking about –

[Next Slide, Previous Slide]
– whether you want to ground mount and that's another alternative on the next slide.

[Next Slide]
Same with ground mounts. See, our older systems, we used fixed systems. In our newer systems, we use single-axis trackers, which cost more, but produce more electricity.

[Next Slide]
We went with single-axis trackers on most of our CREBs projects. We had some buildings that had very weak roofs, so we had to use a product that would be useful on weak roofs and we chose Solyndra, which probably everybody has now heard of, and I put the P.S. in there to note that it actually works fine. Next slide.

[Next Slide]
One thing that's really important that cannot be overemphasized is the importance in tracking the performance of the system. There are now a variety of different companies that produce very useful and usable 24/7 web-based monitoring. That screenshot that you see below is the system that we chose for our early project from a company calledFat Spaniel, which basically sends us alerts as well as to the solar installer any time there's a deviation from an expected range of production or the system goes down or anything else. Hugely important, because we're depending on the systems to produce a certain number of kilowatt-hours (kWh) to enable us to get the payments that we use to pay the bonds. Next slide.

[Next Slide]
So, roughly at the same time that we were doing that CREBs project, we also decided we wanted to explore the other branch of the fork, which was doing a PPA. The city of Tucson depends on bringing water from a long distance away from the Colorado River, and so we have a number of very large water pumping stations that bring water uphill to get it to the city, so we decided we would put in a one-megawatt system at a water pumping station that actually has about a seven-megawatt load. So in 2008, we issued an RFP that asked people to submit bids for one to five megawatts, and I will say that range caused some confusion because we were not as clear as we might have been about what we're looking for, and the bids ranged quite a bit from people that bid in at one megawatt versus five megawatt, so that caused a bit of confusion.

We also had to make a decision about what to do with the RECs and we decided to retain the RECs initially in connection with the PPA. We had some discussions about the kind of equipment that was being used, but because this project was being owned by a third party, we had much less say in choosing the equipment. We basically got an opportunity to say what we wanted, but in the end, it was SunPower, the winning vendor, who was able to make the final selections for trackers and panels, and finally we had some discussion about when in the course of this project we might be able to purchase the system from the third party vendor.

[Next Slide]
The same questions came up that we talked about earlier between PPA or ownership and focusing on the PPA. These are the items that I think are important challenges to pay attention to. Some of these may seem obvious, but just to be sure, number one, it's really important to negotiate your power costs so they are no more than current power costs and less than anticipated future power costs. Sometimes PPAs can be costly to draft and execute, meaning expense that's rolled into the cost is some lawyer fees usually not well suited for smaller projects because of these transactional costs and definitely requires some legal oversight and close review to assure that there are no hidden costs, and again, as a Solar America City, we had some very helpful work from various DOE folks to make sure that we were doing things right. And the final thing that's critical and that there's some states where PPA are simply not legal and obviously it's important to determine if a PPA is legal in your state to prevent the argument that the PPA provider is really a public utility company that needs to be regulated. Next slide.

[Next Slide]
So what did we learn? Basically, we learned that the next time we do this, we're going to start with our own PPA instead of a PPA from the vendor. Now, since the time has passed in the past five years since we did this, there are now a number of model PPAs available online. One that I've referred to in the slide here was developed by a number of cities in Arizona, including Tucson, to make what we call the solar-friendly PPA. I would certainly encourage you to take a look at that if you want.

The second thing that I think is critical is if at all possible, you should avoid escalators in the PPA because that's essentially a guess as to what the increased utility costs would be and there's really no real reason to have escalators in most cases, so I would encourage you to avoid escalators. The third one, which has been the curse of a number of PPA projects, including some in Arizona, is the demand charge. If you're not familiar with this, you need to learn enough about utility tariffs to understand that many commercial and governmental locations are on a utility tariff that has a demand charge, which means you pay a certain amount of money based on your highest usage in the month. If you have several cloudy days and you're using a lot of power from the utility company, the demand charge that that can result in may eat up and even exceed the savings from PV. So I think these are the most critical things. Let's go onto the next slide.

[Next Slide]
So, we took a look around that time in deciding whether the next project after that would be another PPA or another round of CREBs because we saw that there was another round of CREBs available and the determination we came up to in looking at the long-term savings at that time, and this is definitely a snapshot, comparing two projects at a certain time, but as you can see from this, we decided the savings from doing another CREBs project compared to another PPA were substantial, so we went ahead with the next slide.

[Next Slide]
And we were successful in bidding for some additional CREBs money, this time in 2010. We were able to get an allocation that would allow us to do two megawatts. Again, we did an RFQ with the design-build focus. Sites were preselected as per the CREBs requirements. We did some structural analysis, and again, that was a very helpful use of consultants from DOE through our Solar American Cities program and just for everyone's potential use, I put in here what we used as the evaluation criteria on this RFQ. We felt the technical concept in terms of what kind of equipment was proposed and so forth was really important, but almost as important was the experience in managing systems. We didn't want to get somebody that could put up a good system, but had no expertise in managing it and keeping it going, so that's why those two things were equally weighted, and then you'll see the other items there. So let's go to the next slide.

[Next Slide]
And we can look at some of the issues that came up. We bid all these projects as one, which made it difficult for smaller, local installers to bid and caused some criticism that came out at some meetings. Some of the local installers did join with general contractors to bid. The bonding issue was the biggest impediment for the smaller companies because they needed to be able to have the capacity to get a $10 or $12-million dollar bond for this. We also encourage the vendor to use local equipment where possible, and we use mostly Schletter racks, a German company, U.S. headquarters in Tucson.

Excellent racks. We've used them now in a number of projects that have worked out very well. We also in the end moved toward doing a number of PV carports at our police station locations because we were able to do three things at once. We were able to generate electricity from the solar. We were able to protect the electronic equipment in the cars, which the police folks were stressing quite a bit. And finally we were able to deal with urban heat island issues, which were a substantial problem in the southwest, and that's definitely a big problem for Tucson. Let's go to the next slide, please.

[Next Slide]
So, we also had to make some adjustments in where we were going to do the installations. We ended up dropping some of the smaller sites and moving ahead with expanding some of the larger sites to deal with some cost issues. We realized that it's extremely important to be very careful about the vendors and the suppliers that are being chosen because we have a ten-year O&M contract, but we have a 25-year warranty on the solar panels, which clearly wouldn't be useful if the vendor, the manufacturer of the panels, was not around at that time, so that's a huge issue in choosing vendor and equipment, and finally, we looked at and learned that there is insurance available for potential future "orphan" projects, namely projects where either the installer or the manufacturer has gone out of business, so that's a useful thing to remember. Next slide, please.

[Next Slide]
So, these are some pictures of some of the larger projects we did. This is a very large city building that housed the city shops and so forth. We covered a pretty large percentage of the roof on that. Next slide.

[Next Slide]
We also covered the roof of our convention center. You can see there that pretty much the entire roof of that one area of the building has been covered. Next slide.

[Next Slide]
This shows an area where we have a library and a police substation together. We were going to initially put the panels on the roof, but were convinced that for the reasons I mentioned before, that it would be a better use of our money at that location to do PV carports, so we did PV carports for police cars instead of panels on the roof. Next slide.

[Next Slide]
This slide shows another combination building, part police station, part other stuff, where we did both. We put PV panels on the roof and we also did PV carports to help shade the police cars in the background, so we've tried to be open minded about roof versus ground mount versus carports, but the police were the most interested in the PV carports, and I think that's really an excellent use of the technology. Next slide, please.

[Next Slide]
Well, this one I've entitled, "Now for something completely different," because this involves an RFP and it involves solar, but it doesn't have anything to do with our regular procurement process and didn't have anything to do with solar on city buildings. In 2012, the city of Tucson, in conjunction with a number of other large employers in town and with some assistance from ICLEI (Local Governments for Sustainability) and using a California company called Group Energy, put on a program called Solar Benefits Tucson, which was a discount program to provide for solar installations at the homes of employees, so in this case, we had an RFP, but it was much simpler and had many fewer pages and a lot less complication because it was not a city public procurement process. The RFP was put together by Group Energy, the administrator of this discount program. They were employee representatives that were doing the choosing for the solar vendor and that employee committee decided that hiring a local installer rather than a national installer was extremely important for them, and so they chose a local vendor to do the installation and ended up with about 92 installs. The biggest difference in the RFP there was that it was not part of the public RFP process and therefore was much simpler. Next slide, please.

[Next Slide]
Sarah Busche:
Hey, Bruce? You've got about four more minutes.

Bruce Plenk:
Okay. We're just coming to the end here, Sarah, so I think we're in good shape.

Sarah Busche:
Oh, perfect. That's great.

Bruce Plenk:
So, the conclusions from all this is much as I'm always reminded whenever I start to paint something, it's really the prep that is, if anything, more important than the actual painting, and I think that's true for these solar RFPs as well. Spending the amount of time and getting the right advice in terms of preparing yourself and the folks that are going to have to make the decisions on the RFP is hugely important, and that, as I mentioned before, can be doing the electric load analysis, the structural analysis, and also the financial analysis to decide which way you go on that fork in the road, but that's all the prep time. And it is important to recognize that you're comparing options at that moment. It's really a snapshot. It may be that a PPA or a lease is the way to go now and in a year, it may be that that's not the way to go and purchasing and owning this system makes more sense.

I think keeping the RFP as simple as possible is really important. There have been a number of sample RFPs out on the web, and I think that it's useful to take a look at those from other entities similar to city to city and so forth. I think it's important to remember that other and perhaps bigger priorities, like supporting local businesses, integrating solar with long-term climate change plans and so forth and finally, the most important thing is that I'm a solar advocate and I think there's no question that solar really is a winning, long-term investment and the trick is to figure out how to make it pencil out in the short run as well as the long run to convince the powers that be that your city, or your county, or your business, or whatever is ready to go solar because in the end, it's the right thing. It's just the question of how to make it work and how to make it look good on paper so that you can get those solar panels up there and generating electricity, and with that, the next slide.

[Next Slide]
That's what it usually looks like in Tucson, except that we're having super cold weather, so even the cactuses are drooping a little bit right now, but I'm happy to deal with any questions either now or afterwards.

[Next Slide, Previous Slide]
And thank you very much for the opportunity to present today, Sarah.

Sarah Busche:
Well, thank you so much, Bruce. That's excellent to hear about Tucson's experiences. We have a number of great questions that have come in. We're going to have time to get to about three of them right now and then we'll get to a few more after, so the first one comes from Russ. He asks if you can talk a little bit more about the demand charge and how Tucson ends up handling it.

Bruce Plenk:
Well, okay. That's a great question, because that really is the curse of many a project. The way that demand charges work, as I said, is that many times most of the utilities in their industrial and commercial tariffs, which is their official, approved regulations that are approved by the regulatory body, have a demand charge that's normally based on the highest usage on any given interval, and that interval is different in different tariffs, but let's say it's on a given day, so that means if on one day you – and I'm going to make up numbers. Let's say on one day you use 100 kWh, even if your normal usage is only 30 kWh, and these are small numbers, but just for an example. If you hit that 100 kWh usage, you hit 100 kW, I should say, not kilowatt-hours.

If you hit a high usage, you're going to be paying that charge on top of the number of kilowatt-hours of electricity that you use, so in Tucson, we were successful in getting a number of our buildings – in fact, all of our buildings that have solar on them shifted to a different tariff that did not have a demand charge in it. We were able to work with the utility company so that we did not have a demand charge on any of the buildings where we put up solar. If you are unable to do that, and obviously if you can do that ahead of time, you're better off. If you can't do that, it's very important to pay close attention to the usage and try to avoid any big usage days, because that will really undercut the savings that you're getting on the energy side by saving kilowatt-hours. If you're hitting a high kilowatt usage, even with low kilowatt-hour usage, you might be subject to the curse.

Sarah Busche:
Hey, great! Thank you. Wendy is wondering if you could provide an overview of the legal challenges and characterize how Tucson works through these issues with the city attorney's office.

Bruce Plenk:
Well, the biggest issue initially was when we were looking at doing the first PPA was there had never been a decision by the – in Arizona, it's called the corporation commission. It's the utility regulatory body. There had never been a ruling from them about whether PPAs were legal or not, and when I say that, I mean whether a PPA provider who frankly is selling us electricity, what makes them different from a utility company. While we were pondering that and trying to figure it out, a school district conveniently – who is working with Solar City, one of the big, national solar companies, filed a case with our state regulatory body to determine that question.

We participated in that case and in the end, the regulatory body decided that for non-taxpaying entities, the PPA providers were not to be regulated as public utilities, so that involved about a year of litigation that we were only peripherally involved in, but that's what it took to clear up the question that some of the financial people had raised about whether it was legal in Arizona to go ahead with that kind of arrangement. With regard to the RFPs, that was pretty much a city attorney reviewing the contracts in the same way that other contracts were reviewed, but what we learned from a variety of sources is that there's a likelihood of increased charges being rolled into the PPA if looking at a nonstandard PPA, and now this has changed a bit over time because there have been more and more PPAs, but in the past every PPA was done as a one-off proposition, which meant a lawyer had to be paid for writing it and revising it and doing it, and that would get rolled into the cost of the electricity. We tried to avoid that by developing the PPA that I mentioned that's on that website, but we've had good luck with that and we're hoping we can utilize that the next time we do a PPA to minimize, among other things, the cost of any airtime involved of any legal review.

Sarah Busche:
Thanks for discussing that for both the projects. That's really helpful. So we are going to do one more question and then we'll switch it over to Brian and get back to more questions for you, Bruce, at the end. Kelly asks if you can talk more about how your office is able to get political support for these types of projects.

Bruce Plenk:
Well, that's, of course, a great question from Kelly. The main thing with showing that the city was not gonna be dipping into general funds to pay for these on the PPA side, basically we were able to show that the cost of electricity would be the same or less using our projections, going out 20 years, so that we would be saving money by having reduced – I mean it was speculation, of course. I believe it'll pan out, but showing that we would be paying less for electricity over time because the PPA contract comes up with a set amount of electricity. In our case, there was an escalator, which again, I would discourage, but we knew what the cost of the electricity would be over the next 20 years and projected savings over what we would be paying had we not done the PPA.

On the city owned projects, basically the way that we structured it with our successful bids for the REC, the utility incentives, plus the payments from the building occupants was sufficient to cover the full cost of the bonds, so basically we were able to go to the city council and say, "We can have this installed. We can own the project. After the bond's paid off, we'll be saving the money on the electricity and in the end, there will be several million dollars in savings." We projected a couple million dollars of savings over the life of the project, even with the need to potentially replace some inverters, which usually will go out before the panels do. The short answer is it didn't hit the general fund and so it was both green and financially doable.

Sarah Busche:
Great. Thank you so much, Bruce. Brian, we're going to go ahead and turn it on over to you, so I'm just going to do a quick introduction to save some time.

[Next Slide]
And I would like to introduce everyone to Brian Millberg. Mr. Millberg is a registered professional engineer in chemical engineering. He has 35 plus years in engineering and is currently the energy manager for the city of Minneapolis, Minnesota. Brian, are you there? Uh oh. He said he was having some phone issues. Well, let's go ahead and do this. Bruce, we've got a lot of questions for you. We'll give Brian a second to get that worked out and we'll ask a few more questions.

Bruce Plenk:
Sure. That sounds great, Sarah.

Sarah Busche:
Thanks. So we have one from Andrew. He was wondering if you have any suggestions or advice for people who work in states like Iowa, where PPAs aren't legal.

Bruce Plenk:
Well, that's a tough one. The first question, I guess, and I don't know Iowa well, so I'm just throwing out ideas off the top of my head, Andrew, but I think the first question is whether there – if the issue has not yet been litigated, there's always the possibility of litigation to clarify that. The vast majority of states that have considered whether PPA providers should be regulated like utility companies have come down on the side of no. That they're not public utilities and they don't need to be regulated. So, one route would be to consider litigation to clarify that issue. The second route that's been used in some states is to go the legislative route and see if there's a possibility of legislation that would clarify the state's definition of public utility companies, public service companies, whatever the state terminology is, and see if there's a possibility of clearing things up, definitionally speaking.

If that issue's been litigated and the answer is no, too bad, you can't have PPAs, then there's the possibility for some customers. My understanding is not cities or counties, but some other customers may be able to do leases and the leases differ from PPAs usually in that there's a monthly payment rather than a per kilowatt-hour payment, but in some cases, even where PPAs are not available, people have been able to structure leases that pass legal muster and I guess the final piece is if the issue's been litigated and that's a dead end and you can't do a lease for whatever reason, then I think the question is going to be to try to figure out how to creatively arrange financing so that you can have solar and make it work out so it's financially doable. Now, one recent development that many people have been reading about in the past few weeks has been crowd funding solar projects and Mosaic is the outfit that is sort of leading the pack on this, although there are some others, and Mosaic has been funding – has recently funded a number of solar projects in certain states and that's an idea that we've just started looking into to see if it'd be possible to have out of state investors funding a project.

It's not something that has gotten very far, and it's just been a few projects, but the basic idea of Mosaic is to have many people putting in small amounts of money to cover solar projects and getting a return from those solar projects. So that's another possible way for raising money for a project if the entity isn't able to come up with the money for itself. So those are a couple of ideas and there probably are others, and I think that there's gotta be some other good ideas out there, but that's what I can think of right quick.

Sarah Busche:
Bruce, thanks for punting on that one because I know that is not the experience that you have in Arizona, but I appreciate you giving some of your advice on how others might be able to handle that in states that don't allow PPAs. It sounds like we've got Brian on the phone, so Brian, if you're ready, all right.

Brian Millberg:
Yes, I am.

Sarah Busche:
Perfect. Okay.

Brian Millberg:
Thank you very much for this opportunity. I just want to let people know that unfortunately, due to some technical difficulties, I'm not in a private room, so we'll try to keep this as quiet as possible. I wanted to talk a little bit about power purchase agreements versus owning your own system, so let's go to the first slide.

[Next Slide]
There are advantages to direct ownership, but obviously the biggest drawback is the cost and the payback. We're seeing prices now below three and a half dollars per kilowatt installed and even at that rate in the upper Midwest, we have a fairly low electricity cost of ten cents per kilowatt-hour and even factoring in automatic inflation, which we've seen to get like clockwork every year with 3% it still is an 18-year payback, which obviously is very politically hard to justify spending public money. In some areas, obviously, the payback is better due to higher electricity costs and if the renewable energy credits do begin to have some value, that would make direct ownership more palatable, but for most of us public entities, we don't really have the money up front to do this type of project, and it is a political price to pay, so we typically go to the next slide, which is the power purchase agreement. We can look at some of the benefits of that. Next slide, please.

[Next Slide]
Obviously, with a PPA, there can be low to no front end costs and the cities can in effect take advantage of the investment tax credits. They obviously can't claim it themselves, but through these separate entities that actually own the array, they can pass through that savings and lower electricity costs. As Bruce said, you can lock into a flat rate or you can do an escalator. They both have advantages and disadvantages, but it does give you a very good comfort level of what your costs are going to be for up to 20 or 30 years into the future.

The other advantage with a PPA is that you hopefully get someone who knows how to do this project, and you don't have to hire a design firm to actually do the design as well as what can be a fairly extensive amount of permitting work and rebate applications with your local utility, and then during the maintenance and the operation of the array in the system, once it's up and running, is just a simple phone call. I'm looking at my monitoring system. It's not doing what it's supposed to do. Go out and check it and your own maintenance staff doesn't have to be involved. Next slide.

[Next Slide]
So just for those who haven't really investigated how this works, let's say we're going to do a one-megawatt system and the private entity can claim the 30% federal income tax credit, the ITC, the investment tax, and there's a special 5%-year accelerated depreciation, which up until the end of 2012, they could take 100% of the installation costs as depreciation in the first year. That has now been changed. They can only take 50% , but then they have four more years to claim their remainder, so in the first year, they can claim, in this particular setup, a 30% tax credit. It would be $900,000.00, so the developer is actually only spending $2.1 million and out of that, they can claim a little over a million in depreciation the first year, which at a 42% tax bracket saves them $441,000.00 in taxes, and if we go to the next slide.

[Next Slide]
You can see how this works throughout time. Basically, on the left-hand side of this chart, you see what the price would be for the PPA or the owner of the array selling to you the electricity to the end user and at a flat rate, for example, of 10% or 0% flat rate, no inflator at ten cents, it would take 17 years to pay back. And obviously, as the price goes up, the developer makes more money, and as you can see, especially with escalators, they can make more money. On the far right side of this chart, you see a ten-year internal rate of return with a 20% buyback in year ten.

What's very typical with large PPA projects is you could sign a 20-year contract for electricity at X dollars per kilowatt-hour, but after seven to ten years, the PPA owner typically wants to sell the unit back to you at a very reduced price. It's typically between 15% and 20% of the initial installation costs and if you do this, the array owner, the initial developer, gets their money out of the project sooner and can get a better rate of return. For the end user, the advantage is they're purchasing a solar array that may only have used up a third of its lifetime for a very small fraction of the initial installation costs. Next slide.

[Next Slide]
So, this is a little busy, but typically in a municipal or a public arena you – just as Bruce said, you get this question. Should we float a bond and install something on our own? Should we do a PPA with an escalator? Should we do a fixed PPA? How to do all of these things, and so the column that's labeled 20-year bond shows a 3% municipal bond.

There's an initial upfront cost of about $60,000.00 for floating of the bond, plus your interest every year and over 20 years, you get a net present value of just over your $3 million dollars. If I went with the utility costs at 20 cents, which some people actually are at with their current utility and at a 3% escalator rate, you can see that over those 20 years you would save almost $2 million dollars in electricity costs if you owned your own array, but you still have to float the bonds and so people typically go with a PPA, so in this third column or fourth column over, I show one with a buyback after year ten. That's why you see such a large number of $939,000.00 in year ten, but after that, your electricity is free, and even though there was an initial escalator, you're still paying slightly less than the bonded project and you don't have all of the initial headaches of the outlay of the money. At the far right, we show an example of the PPA at a fixed cost. It's somewhere in the middle between those scenarios. Next slide.

[Next Slide]
So our project was not that large; a 601-kWarray on our convention center. I want to stress something Bruce said. It's very important to get the correct developer through your RFP. We started our project in 2007 and spent two years with a developer that could not perform. And it caused a lot of headaches, obviously, not just with the delay of the project, but with political issues and our utility, Xcel Energy, was heavily involved in the project with a $2 million dollar grant, so we had a third-party grant entity that made things very complicated. So we basically, after two years, had to start all over again. Next slide.

[Next Slide]
In fall of 2009, we floated a second RFP with hopefully many lessons learned. We did have seven people submit proposals. In an RFP, we asked for a 600-kW system and we did not specify too much around the system other than the 600 kW because that was what our grant from the Xcel Energy Renewable Development Fund allowed. The system that we ended up getting was with silicon panels, over 2,600 of them, the Unirac ISYS mounting system, six individual inverters, and I'll explain why six. It's got 567 kW of AC, about 750 kWh a year, which is 8% to 10% of our daytime electricity and it's owned by a separate LLC that was formed to do the project, MCC Solar. Next slide.

[Next Slide]
Now, this again, project, was started at the end of 2009. Prices were somewhat higher, about $5.00 a kilowatt. The total cost, $3.1 million. $2 million dollars of that was directly funded by this renewable development fund, and we opted to sign a 20-year fixed price contract at the price stated there. It does have a buyout position in year seven, which actually falls each year if we decide to delay buying it back. In this project, we do not own the RECs. We had to sign those over to Xcel Energy due to receiving the grant. Next slide.

[Next Slide]
I wanted to stress a little bit in just the actual construction of your team that's going to develop the RFP, the actual paperwork that's going to go out for your proposals. Obviously, these can be large projects, so it's very important to have someone who can handle overall construction management. I really want to stress the contract lawyer. We opted not to use our internal city attorney. We actually have a contract with an outside firm that specializes in utility law and there were advantages and disadvantages to that, but I do want to say this was our first PPA in the state of Minnesota and it was somewhat complicated and I estimate that the costs between our cost and the final developer's cost was somewhere between $50,000.00 and $100,000.00 in legal fees.

I think the second time through is going to be much, much less, but the first time can be expensive. We had a risk manager on our team checking on liability. This is a very high visibility site. Roof leakage is an issue. We have tornadoes here.

We've had things come off the roof of that building already, so we had some risk issues and then we specifically went out and hired, on an hourly basis, a financial consultant to help us determine if these developers who were sending in proposals actually had the financial backing that they said they had. We realize we did not do anywhere near enough due diligence the first time through, and we wanted to make sure that when we selected somebody, we knew they could do the job. Other people that we had come in from time to time, a purchasing manager, because of all the various grant rules and purchasing requirements, and then if this is your first solar project at all, I think it is helpful to find someone who can help you understand the lingo and to help evaluate the proposals from a technical background. Next slide.

[Next Slide]
When we did our RFP, we had these five basic areas that you see here, and I'll just walk through quickly each of these areas. Next slide.

[Next Slide]
In the RFP, the project description was actually fairly sparse. We said we want a certain size. We want so much kilowatt-hours per year output. We said that we wanted the system to be a non-penetrating system. We had monitoring requirements.

We want to match this against the utility 15-minute time period for the demand charge that Bruce talked about, and I'll talk about that a little bit later and we wanted to make sure that we were alerted of issues through email notification from a monitoring system because we were looking to reduce energy costs through this solar array and we didn't want it sitting idle, so that was part of the description. And then we felt we were doing something useful here by putting a sample PPA right into the RFP and asking the respondents to comment on any sections that they would like changed. This was a great idea. We found that they'd all basically said it's fine, but then when we got into negotiations, the legal fees mounted, so I still think it was helpful, but I don't think it saved us too much money in this case. Next slide.

[Next Slide]
We have some unusual regulatory requirements. This was partially funded through Solar American Cities. We had some ARRA funding money for engineering costs and through the Xcel RFD fund. We had to have products made in the United States. Obviously, you always have your construction code inspection, general construction requirements.

We had an unusual situation where no one had done an array this large in Minnesota, and so there was a question. We have to do a prevailing wage type of contract and you have to know what the labor classification – so we had to actually go to the state labor board and get a decision. Does the person doing the racking have to be a certified electrician or under the supervision of a master journey-level electrician? So we had that taken care of. We also have our minority and small business goals and the other thing in the intangibles, one of the things we put in our RFP was we wanted training on site, because this was the first large solar array in Minnesota for local electricians, local inspection people, and other code officials to learn how this project went and so the provider had to create a small training program of two days of training during the project at various stages. Next slide.

[Next Slide]
In the RFP, we showed aerial photos of the site. We gave a very concise legal description. I think it's very important to always have your architectural reviews and I'll show you in this next slide. We not only talked about where we want things placed on the building, but since this is a convention site, there are trucks going out in and out every day, where they can stage, how much loading they can put on various parts of the roof. There's security issues. All these things were called out in the RFP. Next slide.

[Next Slide]
So here's an aerial view of our convention center. In the manila colored circles are huge copper domes. They're semicircular domes, so we obviously weren't going to put any panels there. The plan was to put the panels on the red sections, which are all mechanical areas so that if there was a roof leak, it would not actually leak down onto the convention floor.

The green area was our second choice and the blue area was our last choice. Even though it was a perfectly flat roof, the blue area roof was ten years old, whereas all the other area was a brand new membrane roof, which I think is very important when you start a project. How old is your roof? You want to try and get your roof replaced at the same time if you're going to put it on a building. Next slide.

[Next Slide]
Obviously, things don't always turn out the way they should. Here's an aerial view of the actual installation and you see that we abandoned many of the smaller little areas and did go to our second selection at the bottom of the picture there for quite a bit of the array, and this also shows why we have six inverters. Because the arrays are so far spread apart geographically, we would've had much too great a line loss if we'd gone with a central inverter, so we have six different inverters spread out throughout the system. Next slide.

[Next Slide]
In the RFP, we had some grant requirements. We also had a weather horizon. We had a completion date, but obviously here in Minnesota, with our severe winters, we always have standard weather clauses in there for damages if they don't complete by a certain date and an issue here in Minnesota, it appears, is there has always been a problem with the final connection of a solar array to the utility. We get everything done. The utility agrees to all of our one-line drawings, and then things sometimes come to a halt, and so we actually agreed that substantial completion for this project would be proof of power generation in a one-hour test, and not necessarily the final hookup because we could not get an exact, set date for that final interconnection. Next page.

[Next Slide]
In our evaluation of the RFPs, it was very similar to what Bruce had. I did want to highlight the total kilowatt-hours per year guarantee. This was fairly contentious, but we felt that since we are buying electricity and we want it to offset our fossil-generated fuel, and we want to advertise as a benefit for having your convention at our convention center, you're using a green facility. We want that amount of kilowatt-hours guaranteed, and so there were many discussions with the RFP respondents about using PV Watts and that they had to guarantee a certain amount of electricity per year along with the price for kilowatt-hour and I know people say that PV Watts does not work very well, but after the first 12 months, our PV Watts number came within 0.1% of the actual generation from the site. So, I think it works pretty well. Next page.

[Next Slide]
Again, we have people come in and say, "We can generate 20% more than what PV Watts can do," and so while we didn't within this contract, in some of our smaller systems we actually require the developer to reimburse us after a year and in some of our contracts even up to ten years if the production falls below this guaranteed kilowatt-hour. Next slide.

[Next Slide]
So, when we got around to assessing the RFPs, like I said, we had seven respondents. They ranged in price anywhere from the final agreed price of just over 10 cents to up to 38 cents a kilowatt-hour, quite a large spread. It's very important, again, to assess their financial strength, and we actually required a signed letter of credit with a bank that we agreed, they had to be a bank of a certain size, that they have the funds available to finish this project, and our financial consultant worked all of those things out. The second thing is some of these projects are large and we felt that some of the smaller solar installers who were interested really did not have the overall construction management experience to finish a project this size. And what seemed to work out best for us of the top three proposals that we had to select among the seven, they all had very large construction firms in town with also very well regarded electrical contractors as the main subcontractor. We felt very confident picking amongst those three. Next slide.

[Next Slide]
Then it's time to write the power purchase agreement. I'm not going to go through all of these general topics, but I did want to talk a little bit on the two in red, the financing and construction, and talk a little bit about what we provided there as well as some of the insurance requirements. Next slide.

[Next Slide]
On the financing, again, this letter of credit and then because we had a grant entity, there were milestones that had to be met, so that all had to be part of the contract. This is a general construction contract. There was the system design and installation. Since we were doing an RFP with very general specifications, we had to review all of their shop drawings with our electricians and our code people to make sure that it met our needs. We also had to review their structural engineering support-work to make sure it would work on our roof, and then we of course had to do the utility approvals and interconnection agreement, which in our case is sometimes quite lengthy.

There was a long discussion about what happens if the array goes offline? How do they reimburse us? What's their requirement? The ownership of the RECs, and again, this remuneration for the loss of solar production.

I just want to warn people that, again, this was our first PPA. It was somewhat complicated by this grant. This contract was over 60 pages long. Next page.

[Next Slide]
This again, the hot button issues we found were this interconnection agreement. It's incredibly important to have your utility there before you ever go out and submit an RFP to the general public to make sure that they're on board with the concept and in Minneapolis, we have what's known as a networked grid in our downtown area. It's an interconnected network of transformers that are all parallelly operating and our utility, Xcel Energy, refuses to let us connect to that grid, so you need to find out if you have one of these grids. They do exist in most large municipalities and it could be very complicated and it can put the end to a project way up front. And again, all of the engineering costs and interconnection costs needed to be paid for by the developer, and so it sometimes can be hard to understand at the beginning of the process what all of these charges are going to be, so again, it's very important to involve the utility, and then again, as I said, what happens if there's no solar production? Next slide.

[Next Slide]
Bruce talked a little bit about the demand reduction. There are two basic types of demand pitfalls. Here, as you see, is a daily demand curve for our convention center. It happens to be for last month, and the blue line is the actual kilowatts of power that our utility was sending into us every 15 minutes, and you see in the red circle, it turns out to be at 7:30 in the morning, we hit our highest demand for the entire month of December. It was 3,020 kilowatts, but as you look at the bottom, the red line is our actual solar production.

We actually had a pretty nice day. It hit almost 500 kilowatts of power at solar noon, but the solar power's not on at 7:30 in the morning, and so my demand charge for that month was all the way up at 3,020 instead of in this trough between 9:00 and 2:00 in the afternoon that you see where the solar has reduced the demand. So, while we did save those kilowatt-hours of charges, we did not save any money in the month of December on our demand charge. There's also a totally separate issue in some states with what's known as a standby charge and for large arrays, many utilities require you to participate in a standby agreement, and in such an agreement you commonly pay this 15- minute demand charge on your entire building load, not what you're getting from the utility, but the actual load, which is your utility power and your PV generation power, and that's the case here in Minnesota. And so we have not saved any money on demand charges at the convention center. Next slide.

[Next Slide]
If you do decide you want to do direct ownership, and we've done seven smaller projects that we own directly, what we found works best is not to do a design build on a small project. In other words, don't say to a contractor, a solar installer, "Here's a building. Tell me what you can put on here." We actually hire someone to design a system and we bid that exact, fully designed system that we know will work.

The bidders who reply can enter into alternate, mechanical equipment, or other designs, but those have to be approved by our designer. We find that that solves a lot of problems. We also have, again, gone back to this kilowatt-hour per year guarantee, and we actually hold back 5% of the entire project cost for the first 6 to 12 months to ensure that the system produces the amount of power, and again, picking these competent contractors is incredibly important. Next slide.

[Next Slide]
I do want to reiterate again what Bruce said. There are some excellent resources out there from NREL and EPA on doing these agreements. They can be hard to work through. We spend a lot of time with lawyers, but in the end, we've got a fantastic system. It's a great public relations thing for our convention center. It's doing everything that it's supposed to be doing, technically, and it's been a great asset to our city.

Sarah Busche:
Well, thank you so much, Brian, for detailing the process that Minneapolis went through. We've got a number of questions and we'll get to as many as we can, so the first one comes from Scott. Can you talk about how you overcome issues with snow resulting in decreased production?

Brian Millberg:
Yes. Actually about two weeks after the installation was completed at the end of December in 2010, we had 14 inches of snow. Our array was set at a 30 degree angle. Now, this caused some problems with the project. Obviously, you have a large wind load at that high of an angle. Where we are, the absolute ideal angle would actually be around 40 to 45, but that was too much of a stress for the roof. We ended up having to penetrate the roof, even though the original design was not to do so, but that's worked out quite well, because it was a brand new roof and there have been no leaks, but at the 30 degree angle, on that 12-inch day of snow, a crew did go up and remove the snow. Subsequent to that, we had several snows of three to five inches, and within 24 hours, all the snow had melted off, so we didn't find a big issue with a typical snowfall, and to date now in three years, we've only done that one brushoff of the system.

Sarah Busche:
Okay. Thank you. Danielle wants to know what happens if the PPA provider does not meet the ________ a month.

Brian Millberg:
Well, our contract is not guaranteed per month. It's on an annual basis and actually if you go into the PV Watts program for calculating your generation values, that's actually a random number generator and so in any individual month of values, you could be wildly off. For example, one month my convention center produced 15% more than what PV Watts said it should and the next month it was 7% below the number. Well, that's because PD watts is a random number generator and over the 12 months, as I said, it came out right on the nose and with our other smaller installations, we've been – people had been very honest with us and we'd been getting – in all but one. We have now eight installations. There's only one small ten-kilowatt installation that's not meeting the production numbers.

Sarah Busche:
Great. I'm sure that people in other cold climates are interested in that answer. So, Bruce, this is a question for you and it comes from Lisa, Ron, and actually a few others. They were wondering if you could talk about the value of RECs to the Tucson project.

Bruce Plenk:
Sure, that's of course an important question. We ended up doing, on the PPA agreement in the end, doing a three-way agreement where we did – we kept the RECs at the time of the PPA, but we ended up essentially doing an agreement so that they're going back to – sort of getting turned around, I should say is the easiest way to say it, so we kind of used it as a way that we ended up turning them back to the utility company in exchange for an additional payment that just came much later. In our owned projects, the CREBs funded projects. In Arizona, there's been a little bit of a change over the years, but basically there's either an auction that occurs at different times when people bid for the available REC money from the utilities. In Arizona, it's a utility-by-utility program, not – so it's different than the California CSI program, so in those situations, we bid for and the utility agreed to pay X amount to the RECs. At the time that we did the CREBs projects, we were able to get 16 cents per kilowatt-hour on the REC. Now, in Arizona, the maximum you can get is roughly seven cents, so you can see how much the market has changed in the past few years, but in both cases we ended up selling the RECs to the local utility company for varying amounts depending on the timeframe when we were doing the bidding, basically.

Sarah Busche:
Thanks, Bruce. Brian, this next one's for you. Have there been communications or messaging difficulties since the city doesn't own the RECs and can't claim reduced emissions and that's from Anthony.

Brian Millberg:
Well, the utility owns the RECs in this particular project, and they actually installed six production-grade revenue meters on each inverter, even though the inverters already generate an electricity generation value, and the utility goes in and reads these meters every month and this shows up on my bill as a check and we cross check our numbers and they've always been within 1% or 2%. And so they know on a monthly basis how many kilowatt-hours have been generated and they're claiming those RECs. In the system operator we have, MISO, the RECs are pretty much worthless at this point. There doesn't seem to be much of a market in our area for the RECs. I don't know if Xcel Energy is able to sell these or I do know that they are using them to meet their renewable portfolio standards. They do have a certain percentage of electricity that, through regulation, must come from renewable resources and they are using these kilowatt-hours towards that goal.

Sarah Busche:
Great. Well, thank you very much, Brian and Bruce. We are at the end of the webinar. We want to thank everyone for joining us and like Devin mentioned earlier, we will be posting the slides along with a recording of today's webinar and a transcript online. It takes about 7 to 14 days to get all of that up there, but as soon as it's up, we'll send an email out to everyone so you have the direct link and I encourage you to fill out the survey that will pop up when you log out because it really does help us determine what to include on future webinars, and I also encourage you to join us for the next CommRE webinar, which is on February 19th, and we'll focus on how municipal utilities are designing and implementing renewable energy rebate programs around the country, and we're going to focus on a very small municipal utility in Massachusetts and then a much larger one in Texas, so thank you again everyone, and have a wonderful afternoon.

[End of Audio]