Navigating the legal, tax and finance issues associated...

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Navigating the legal, tax and finance issues associated with the installation of Municipal PV Systems

Please join Patrick Boylston of Stoel Rives LLP and the National Renewable Energy Laboratory (NREL) for a conference call addressing a variety of legal, tax and finance issues related to the installation of municipal PV systems.

Date: Friday, June 13, 2008 Time: 1:00 – 3:00pm (Eastern Standard Time) Dial-in Information:

1-210-339-7129 1-866-702-7095 (toll free) Passcode: 9665317

Agenda: The following agenda was developed based on Pat Boylston's experience assisting municipalities with their PV projects and the requests for information that the Solar America City technical team leads have received from many of the 25 Solar America Cities since the April 2008 meeting in Tucson. 1. Critical Potential Deal Constraints Embedded in Municipal Law. A. Debt Limitations in City Codes, State Statutes and Constitutions B. Restrictions on Contracting Power in City Codes and State Statutes C. Budgeting, Public Purpose and Lending of Credit Issues D. Difficulties in Granting Indemnifications E. Authority to Grant Site Interests and Purchase Electricity 2. Crafting a City-Friendly PPA that is Financeable A. Identify your critical "Must Haves" before issuing the RFP

B. Understand what the developers and investors "Must Haves" are likely to be (in order): Shared Risk Allocation; Certainty; Exit-Mitigation Options; Financial Return

C. Identify where no compromise is possible between your "Must Haves" and the developer and investors "Must Haves".

In other words, "What Are You Willing to Give Up" to make a deal D. Electricity Price Calculations and Purchase Option Pricing Formulas



3. Potential for Combining Incentives and Structuring Options to Increase Overall Attractiveness A. General Ability to Combine Different Types of Tax Incentives New Market Tax Credits and Solar Deals; Other Potential Combinations B. "Tax Exempt Use Property" Issues With True Leases and Lease- Purchases C. "Tax Exempt Use Property" Issues With LLC and Partnership Flip Structures/ Solutions 4. Most Common Reasons Municipal Transactions Fail - Working Around the Problems Presenter: Mr. Boylston is a business lawyer, concentrating on issues relating to renewable energy development, interaction with municipal entities and the financing of solar photovoltaic installations, corporate debt and public infrastructure. Having spent twenty years working extensively in public finance as bond counsel to a variety of state and local government entities, Patrick's varied experience is particularly useful in assisting renewable energy projects which will involve some level of public participation, either through power purchases, public financing or siting on public facilities. Working with public and private power purchasers, developers, site hosts and financing sources, Patrick has been involved in solar photovoltaic projects in service or under development in California, Colorado, Oregon, Washington, and Hawaii. In addition to public finance, Patrick has a graduate degree in tax and has become more deeply involved in a variety of tax related and motivated financing transactions. Patrick's experience with working with local governments has been invaluable to energy sector clients entering into power purchase and development contracts with local governments and municipal utilities. Email address: [email protected] Stoel Rives has recently released its Lex Helius: The Law of Solar Energy guide as part of its "Law of ..." Series. The guide can be found at Stoel Rives' website at the following address. (http://www.stoel.com/showarticle.aspx?Show=2886)



Disclaimers

Stoel Rives LLP. The transcript attached is a verbatim recording of a telephone conference call sponsored by NREL on behalf of the Solar Cities Program. Nothing stated in the call is intended to be relied upon as a formal or informal legal opinion of the speaker, Patrick G. Boylston, or the law firm of Stoel Rives LLP. The statements made reflect only the personal perspectives and thoughts of the speaker, and do not represent formal positions of the law firm of Stoel Rives LLP. A copy of the transcript edited to account for the oral and unscripted nature of the original will be made available at a future time.

National Renewable Energy Laboratory (NREL) This report was prepared as an account of work sponsored by an agency of the United States government. Neither the United States government nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States government or any agency thereof.



Jason Coughlin: And real quickly, the genesis of this call – after our meeting in Tucson, I began to get a number of questions, legal-related questions that I am not necessarily in the best position to answer. And so Stoel Rives gratefully agreed to work with us on putting an agenda together based on past experience plus some of the questions that I got from different cities as it relates to a whole host of things – PPAs, new market tax credits, et cetera. So we tried to capture as much as we could, and we will hopefully cover all these topics to the best of our ability in the two hours that we have. So again, thank you all for participating, and thank you to Stoel Rives and Pat Boylston, who will be our primary presenter. So with that, let me introduce first the law firm. Stoel Rives is a hundred-year-old law firm with more than 365 lawyers across seven states. Stoel Rives’ renewable energy team is a leading provider of legal services to a wide variety of clients, including developers, investors and large consumers of electricity. Stoel Rives publishes its “Law of...” series that includes legal guides on solar, wind, biofuel, building green, ocean energy and geothermal energy. I’ve personally found these guides to be very useful, and you can find them on the company’s website. I think I put the web address on the agenda where you can get the “Law of Solar” series, which I find very, very useful. And turning now to our presenter, Mr. Patrick Boylston is a business lawyer concentrating on issues relating to renewable energy development, interaction with municipal entities and the financing of solar PV installations, corporate debt and public infrastructure. He’s had 20 years of experience working in the area of public finance as bond counsel to a variety of state and local government entities, working with public and private power purchasers, developers, site hosts and financing sources, has been involved in solar PV projects in service or under development in California, Colorado, Oregon, Washington and Hawaii. In addition to public finance, Patrick has a graduate degree in tax, and as we all know, this intersection of tax, legal issues and finance really is the crux of the context here when we talk about municipal PV. So a full bio is in the agenda, so I will stop there, but let me turn things over to Pat at Stoel Rives, and again, thank you all for participating.

Pat Boylston: Thank you, Jason. As I was thinking about this call, I was getting increasingly intimidated because if any of you have gone to



seminars on effective communication, you usually hear there that 50 percent of the message is based on visual and non-verbal cues. So we start off with 50 percent of the message sort of cut out of the loop. Of course, the upside of that is, unlike when I make presentations at formal seminars, I don’t have to worry about the person in the second row who’s always just staring at me like I kicked their dog and wondering what’s going on. In order to kind of keep some formality to this, I will sort of look for questions after the end of each subtopic when we entertain questions here. I have not prepared a two-hour lecture format because I’m seeking not to bore everyone to death on this as well. And I appreciate you all taking the time to be here. As Jason said from the bio introduction, I have a somewhat unusual introduction for what is now an energy renewables lawyer. I did work for many years in public finance representing local government entities, both in bonds and in business transactions. And then my career sort of morphed into working with our private sector energy generator clients who were entering into power purchase agreements with municipalities, and acting more or less as an interpreter for the private side to explain to them what the unique issues were that existed for the municipals, how to deal with them and how we could come up with work-around compromised solutions that were acceptable to both sides because I have discovered many times over the years that on both the public and the private side, there are different views of what these particular issues really mean. And there are two sort of fundamental realities on the municipal side that the private side truly does not understand and is largely unfamiliar with. The first one is something that’s called Dillon’s Rule. It’s recognized in, I believe, all 50 states. People think it’s a statutory or legislative rule, but it isn’t. It was promulgated by a Judge Dillon back in the middle-1800s but is now accepted as sort of the fundamental statement of what are municipal powers. You usually see it expressed in one of two variations. The first one says that a municipality only has the authority that it is expressly granted, and that would mean granted by the state constitution or the legislature or by the city charter. In the case of counties, the constitution, maybe charters. Brings up the point that there are a lot of variations on these in each state. The principal generally holds true. The details of how it plays out can be very different depending on where you are. So first element, express authority. The second element is municipality has the powers that are



necessarily implied from express authority. That seems reasonably narrow statement. In the broader reading, they say, “Or municipality has the powers that are reasonably implied by either of the above. This fundamental statement of a limitation on powers plays out in a business transaction in a way that is very worrisome ________ ________ participant, and that’s because generally accepted rule across the United States is that if a municipality or a governmental entity is doing something or in entering into a contract is exercising some power which doesn’t fall within that box defined by Dillon’s Rule, the transaction is not voidable, which would mean the parties could choose whether or not to remain in the transaction. The legal principle is that the contract is void. This is a risk that the private side really is not prepared for, and frequently when they discover this, they look at the transaction in a very different light, which is one of the justifications, really, for this seminar, is to talk to the governmental side and let them know what the effect of these two doctrines can be in the private side, how to anticipate the problem, how to potentially recognize when the private side doesn’t have a clue what they’re walking into and to manage the issues from the beginning. So we go and do specific applications of where things come up. One thing I frequently see discussed from the government side and in a very inarticulate form from the private side are questions such as, “Well, is there a debt limitation applicable to this transaction?” In government acquisitions, government financing areas, you have questions like, “Are we entering into a long-term obligation which extends over more than one fiscal year?” The general rule is that if you are, it’s a debt, and then you have to see whether or not it violates any of these limitations. For instance, in Colorado, as the people from Denver will know, your constitutional limitation basically says any financial obligation that’s being entered into is subject to a vote of the people. Colorado previously had a debt limitation that said, “If you enter into a debt, it’s limited,” and there was case law that said if it had a contingent liability, you didn’t know if it was going to be triggered or not, it wasn’t a debt for constitutional purposes. But in these solar deals, you’re being asked to enter into a power purchase agreement, usually for a period of from 15 to 20 years, and the question is is that a debt. As it plays out, I think the general position is in most states that if you’re exercising your



purchasing power, which means your buying electricity, and you’re only paying for what you get, I don’t believe there are any cases that necessarily say it’s a debt. It’s not all that clear. But it’s different from the situation where, for instance, you’re buying a building or you’re buying buses or you’re buying equipment. People often refer to lease/purchase transactions. It goes under a number of different names, and those transactions, even though they’re intended to be long term, they are intended to end up with the governmental entity owning something. The obligation is year-to-year. The governmental entity can cease making payments at any time, and the seller/lessor’s only recourse is to take back the property. That risk is a serious problem for private side solar developers. They are, well, investing a significant amount of money in hardware. It’s installed. From their point of view, it’s a tax advantage transaction. All they want to really know is that they have a certain stream of revenue for a period of time coming off that project. That they could be told that at any time, “You have to take it off the roof, and by the way, we don’t owe you anything” will generally be viewed as an unacceptable risk. In some places with somewhat looser debt limitations or if it’s not triggered or if everyone is comfortable that a contract to purchase a commodity, electricity, where you’re only paying for what you get is not a debt for state constitutional purposes, then you can enter into what is considered a binding to term contract. For instance, in Oregon, for school districts and things where they’re buying under lease/purchase, our statute specifically allows binding to term contracts. Many other states do the same thing. So there are answers to the questions of, “Are we violating a debt limitation?” – but it does take some thought and some review of local precedent and authorities. Another place this often comes up is the question of solar contracts who also have a purchase option, and you see this really particularly in non-profits and municipal transactions, the desire to own the facility earlier. The private side tend to be what’s called a straight PPA structure, which is you’re looking for really a 20-year PPA fixed revenue stream, and the developer will grant a purchase option after year 15 or at the end of the 20-year term. I have had the question raised whether a purchase option violates debt limitations, and my consistent answer has been no because phrased properly, as they usually are, that’s exercisable at the discretion of the governmental entity. You don’t have to exercise it. In my



mind, that’s the sort of contingent item that does not constitute a debt. Okay, are there any questions on that point? Moving along –

Question: How do you see most of these contracts being written for what happens to the system at the end of even a 20-year term?

Pat Boylston: Universally, there is an obligation on the part of the developer to remove the system at the expiration of the PPA and return the – if it’s a rooftop – the rooftop area to prior condition, normal wear and tear, accepted and with a serviceability standard because nobody wants to say, “We have to return it to being a brand new roof, the way it was 15 years prior or 20 years prior.” It’s just, “We’ve gotta fill the holes.” Honestly, at that point, there is usually a purchase option, but there is a practical reality point too. At 15 years or 20 years, does the developer really want to incur the cost of removing the facility? At this point, there really isn’t a developed secondary market for used solar installations. I don’t know if there ever will be one. It’s a little bit up in the air right now because nobody really knows where the technology’s going to go over the next 10 to 15 years. As a practical aside, as you all probably know, solar PV, on a per watt basis is presently the most expensive form of renewable energy. A large part of that has to do with the current efficiency/output level of the panels versus the cost per watt of the panels. If the equation moves strongly in either of two directions, solar PV becomes much more affordable, which means either the output per square foot of panel goes up significantly or the cost per square foot of panel goes down. If the technology moves that way, the value of current technology solar PV panels probably goes way down. I know a lot of people who speculate in 15 to 20 years, the value, fair market value, of a solar installation using today’s technology could well be zero. That puts the developer in the position where they have to be out of pocket to remove it. My guess is they would be very amenable to working out an arrangement that might be less than any purchase price that’s supplied in the contact at the time. From a user’s point of view, the only question is are those panels still functional. Everybody thinks they will be based on history.



And is the sizing of the output from those panels still sufficient and at a level that it’s useful for you to think about keeping them in place, particularly if you can get a very good price for them, or even get them free. But to swing back to the question again and to repeat it, universally across the board, I see that the developer has an obligation to remove the facility upon the termination of the PPA and the site lease. Okay, restrictions on contracting powers. These are the tiny facts that are buried in usually city codes or statutes that people often forget are there. For instance, I’ve had a number of instances when I was negotiating PPAs for wind projects to public purchasers, we would go into the city codes and discover that there was a restriction on a contracts to 10 or 15 years where a client had been negotiating to do a 20-year PPA. There are little things like that out there that are potential traps. Again, swinging back to this question of void not voidable, you ask questions such as, “Okay, if I enter into the 20-year PPA, but the city is only authorized to enter into a 15-year PPA, does that invalidate only the last five years? Or does that invalidate the entire contract?” And theoretically, could the private side supplier be liable for paying back to the municipal purchaser all the money they received from the contract, even if you find out that it was void only in year ten. There are a number of California cases on this kind of issue, nothing really directly on point where you saw the court quoting the void/non-voidable standard and then leaning over backwards very hard to try to come up with an equitable solution. Now, in municipal law, those equitable solutions are not supposed to apply. It seems reasonable that a court would try to do that, but the private side can’t rely on the court in any particular case doing that kind of compromise and looking for a middle ground. So again, it presents a risk issue for them, which they have a very hard time quantifying and dealing with, so if they know what’s going on, they will be trying very hard to pin down some of these facts, and again, it may be a situation where once they learn what has been contemplated, been presented as a 20-year transaction might have to be a 15-year transaction, that doesn’t mean that it’s not doable. It just means that that’s the economic benchmark, so they’re going to have to be renegotiated, usually at a point in the process that is very irritating for both sides, very frustrating. So it’s good for the governmental side to sort of have a handle on



these details going in so that the transaction that’s getting structured is one that’s not going to unexpectedly run into this kind of a problem down the road. Other things that come up that people usually don’t anticipate comes back to this, “What is your authority?” Many statutes, many city charters authorize the purchase of electricity. Obviously, given the time they were drafted, they don’t say anything about authorizing the purchase RECs, Renewable Energy Credits, Green Tags or any of the other six or seven names that that goes by. I have seen transactions where the private side sale of RECs actually was well counseled and asks this question, and I believe the transaction failed at that point, which, since it was a multi-year contract to sell RECs, was more palatable to the seller than taking the chance that the contract would be unwound because clearly the private side has issues with market and supply. On an issue like RECs currently, once RPS standards kicked in, the voluntary market is having a hard time getting enough RECs to fulfill all of its contracts. That raises their costs. A lot of their contracts were executed at a time when people anticipated that the market value of RECs would stay lower, and they entered into economically beneficial contracts for the seller, and now they aren’t anymore, and the market is having to deal with that. If there’s an issue about whether the governmental side had the authority to enter into the contract, that adds to the question of whether there’s even a workout possible, where the market variations can be dealt with in a way that there’s a compromise acceptable to both parties. Another question you often see come up on this is questions of delegation, which is really is the right person signing the contract. Has the person who’s signing it, or the person negotiating it, or the person agreeing to the terms actually delegated the appropriate authority to do that? There are also situations where – I’ve seen it come up primarily in public utility districts and many other situations where you’re told by statute that certain decisions are really supposed to go to the board, but the decisions are being made by the executive director and signed off on by the executive director with no clear board approval for authority. Again, something which, if anticipated, can be dealt with, but if it hasn’t been anticipated, and it doesn’t go to the board, it creates a problem for successfully completing the



project. Another one that comes up is are these solar projects subject to public bidding laws. That can be a tough one. We’ll get later in the discussion into the RFP process. Most state public bidding laws allow ________ exemptions upon certain findings. As a public body, you will be asked to represent and warrant, usually, in these contracts that it’s not subject to public bidding laws, but again, if the private side really knows what’s going on, they realize that general rule on the court cases are that any party contracting with a governmental entity is charged with knowing all of the applicable law. In other words, they don’t have an “I was dumb” defense. That means that they may ask for a more definitive showing of exemption from public bidding. Presumably you would be willing to do that and would be a good thing to anticipate that you might get asked so that you can prepare for it in advance. Any questions on that subcategory? Okay, moving into budgeting, public purpose and lending of credit issues. Most of these – or several points come up, and on questions of budgeting, in the discussions I’ve been in – and I’m not an accountant – questions have come up from time to time about how do you appropriately deal with contingent obligations that might come up under the contract. My bailout suggestion is talk to your accounting people. It’s something that they may be interested in. Another thing you’ll often see, though, in these contracts, which is sort of more interesting for this category, is grants. If the governmental body’s going to be making some grants to a project because, as I’ll get to in the intro of the next section, the economics of solar are ________ ________ very tight, projects often need some additional financial bridging to be viable, the governmental body will be asked to make a grant. Many are very willing to, and generally this shouldn’t be an issue, but you get the question of a governmental body potentially making a grant to a for-profit investment LLC that owns the PV system. In most states, there is authority, and often it actually exists only in things like opinions of the attorney general, that governmental bodies can make grants to entities that are potentially fulfilling a governmental purpose. Often that’s interpreted to be either 501(c)(3)-type entities or other governmental bodies. There is a legitimate question at least about making grants to a for-profit entity. That’s why some situations where those are necessary,



because of the flexibility in structuring the revenue pricing under a contract. Take, for instance, the ________ to see if those can be fit into a box of a prepayment for electricity or if the governmental body, presumably the ________ of power, can get a better pricing formula for the electricity they’re buying. A lot of these transactions – I should say that of the 20-some we have been involved in over the last year, I think the majority of them involve a municipal site host and power purchaser, a 501(c)(3) site host or power purchaser, and a lot of these questions came up with the governmental particularly, “Is this a lending of credit?” Traditionally those lending of credit cases look at a different situation, but again, it can vary from state to state, so it’s something that is worth at least touching base on to establish where your states come out of it. In Oregon, for instance, I don’t believe it is because the question that was always tied to the lending of credit was, “Were you taking a risk on behalf of the private entity?” – not, “Were you subsidizing through, presumably, a 501(c)(3) or another governmental participant in the transaction. But it’s a difficult line to determine exactly where it is. One place where it very clearly can come up, and you should be very sensitive about, but also, fortunately, I have not seen in any transactions, is if as the governmental power purchase you are requested to provide guarantees of your performance, ________ ________ ________ ________. That is a very common feature in private side power purchase agreements. They often run it off a rating test. If the purchaser is betting on the rating going down, they’re required to post security, often in the form of a letter of credit. If their credit rating isn’t considered good enough from day one, they might be asked to supply security in the form of a letter of credit or a guarantee from a credit worthy parent. So far we have avoided those in solar transactions, potentially for a reason I’ll get to in a minute, which has to do with the real role of power revenues in the transaction. But if you are asked, I think that is a situation where potentially lending of credit issues could very easily be raised. Any other questions on that subcategory? Okay, difficulty in granting indemnification. The typical power purchase agreement and/or site lease will ask for indemnifications.



I’ll deviate here for a second and make a comment about the document structure under these transactions. One thing that’s true with solar development is that the number of variables in the mix can multiply so quickly that it is difficult to come up with one set of documents that handles everything. Frequently, you’ll see a situation where the site host and the power purchaser are the same body. For instance, you’re putting solar panels on a city or county building, and the city or county owner of that building is going to be buying the power. In the commercial world, you’ll often have a situation where there are entities called REITs, real estate investment trusts, own hundreds, thousands of warehouses and shopping centers around the country. They’ll want a solar facility on the roof that perhaps just to serve the tenant of the warehouse or a part of the shopping mall. And because of state regulatory rules and differences on how they define what constitutes a public utility, having more than one purchaser typically can create serious difficulties. For instance, in California, if you have more than two purchasers, you have to register as a public utility. That is a very expensive process solar developers absolutely do not want to become subject to because it changes the economic transaction so radically. That’s what investor-owned utilities are. It also makes them subject to regulation by the Public Utility Commission. So a year ago, there were a lot of proposals to put solar facilities on, for instance, multi-family apartment buildings and then a meter in each apartment, and each apartment could buy solar power. And we pointed out to a number of developers who were considering that model that that would make them a public utility. Consequently, those proposals have now shifted into doing a solar facility sized to serve the common areas, with the building owner being the sole purchaser. If you have a situation where you have a facility in a governmental building that, for instance, is served by city – occupied by both city, county and perhaps another governmental entity offices, the private side developer will generally look and see how many meters are in the building, and if there’s only one meter, they will want to enter into a PPA with the entity that is listed as the customer on that meter. Because these onsite facilities are generally located behind the meter, theoretically you could split that power between all the different entities in the building, and that may seem reasonable, but the solar developer will definitely



not want to do it if it raises the risk of becoming a public utility. In Oregon, we have had since 1985 a state statute exempting from all regulation electricity generated by renewable resources. Like many places in the late ‘90s, when open access was a large issue, the state passed legislation governing when open access would be available to an electric system supplier. I don’t have that right. It’s ESF. Then, within the last year or two, regulations and rules were drafted to implement net metering. Within the last couple weeks, our Public Utility Commission has been requested to deliver a declaratory ruling on what the implications of net metering are for the otherwise serving public utilities. It will be interesting to see whether our Public Utility Commission wishes to keep this broad exemption we’ve had or decides to regulate the industry more. Okay, going back to where I started here, granting indemnification, it’s hard to find cases on this, but generally when you do, the courts sort of view them in two different flavors. There’s the indemnification you’re asked to grant which is indemnifying the developer for actions of any third party. That looks a lot like insurance. Courts will generally say as a matter of public policy governmental bodies shouldn’t be doing it because it places at risk the public funds –

Jason Coughlin: Excuse me, Pat. It sounds like somebody’s on a cell phone in traffic. If you could just mute that cell phone, that’d be great.

Pat Boylston: Okay. As a matter of public policy, giving that kind of insurance-type indemnification can be held unenforceable, and the private side will understand that. With something like insurance, they generally are willing to go try to get their own insurance to cover for it. The other kind of indemnification is against your own bad acts. In a way, that’s – you can call it a confession of judgment. You can call it just simply a recognition of damages. I have not found cases invalidating that kind of indemnity. But as a practical matter, I’ve often encountered governmental bodies of all different sizes that take the position, “We don’t give indemnities; we get indemnities.” That may or may not present you with a difficult negotiating position with the private-side developer. I have dealt with several large financing sources that sort of as a matter of principal say, “We don’t do one-sided indemnities. Whatever we’re negotiating as the indemnity we’re



giving you, we should get the same back from you for the same damages caused by your own actions.” That’s something to be aware of. It is very likely to come up unless you’re dealing with a developer that just wants to do the project so badly that for whatever reason they’re willing to push ahead, but the word of warning is there are many financing sources who are not willing to put their capital contribution into the project. That’s sort of the lay of the land they’re looking at. Any questions on indemnifications? Onto the authority to grant a site interest and purchase electricity. Often you will see the site lease for a governmental transaction framed in terms of an easement where the broad belief out there that governmental entities can grant easements, but if they’re granting a lease, they might run into a problem with disposal and interest in public property that might require a public bidding process or a public offering of the site. So far, I have not seen anybody raise significant questions about whether the easement approach works. In all particulars other than the name, the terms of them will typically look a lot like a lease, but obviously there would be no ability for the developer to transfer it except in accordance with the terms of the agreement, which would usually involve a purchase of the project-owning entity. Even then I’ve seen it restricted. It might come up – somebody might make an issue of this at some point, but as I said, so far I haven’t really seen it come up. There are some theoretical arguments that could be made as to whether granting the easement would otherwise make the property unavailable for the intended public purpose, but I think reasonably if the governmental entity is the power purchaser, that’s unlikely to be a big issue. Another question – and I want to touch on this for a second – goes back to the question of what is the authority. You can purchase electricity, but can you purchase RECs? Because a number of cities I know have entered into contracts or attempted to enter into contracts to purchase RECs to show their greenness. The state of Washington had a case within the last year that’s generally known as the Oakes case. I believe it’s O A K E S. Municipal utilities in Washington were making cash contributions



to renewable projects in other parts of the United States and were seeking to recoup the cost from their ratepayers. The Washington Supreme Court in essence said, “You can do this if you want, but if the projects are outside the state of Washington, there is insufficient local benefit, and so you may not recover the cost from the rate payers.” That was after Washington had passed a statute directing utilities, in essence, to acquire RECs. So even when you have the express authority to do what you are attempting to do, you also have to access yourself, “Are we providing the necessary public benefit for our residents, for our citizens, for a group closely identifiable enough with the city, state or county that the court would feel like the expenditure of funds was reasonable. Okay, at that point I’m breaking at Point 2. Are there any questions under anything under Category 1 of this presentation?

Jamie Cox: I do have a question. This is Jamie Cox, City of Sacramento, and you had discussed a little bit of the legal issues having to do with the third party with multiple purchasers and having to identify their self as a utility. What if the purchaser actually is a utility, public utility? Is that fine? Or does that bring up a whole different range of issues?

Pat Boylston: Generally, if the project is going to a public utility, there will only be one purchaser. The issue in California spins off of the number of retail purchasers, and in that case, it’s probably one wholesale sale to one purchaser, so that’s not likely to trigger the issue.

Jamie Cox: Okay, great. Thank you.

Matt Sancorni: I have a quick question as well. This is Matt Sancorni. I guess you’d have to check the State Utility Commission in each state to determine if that was the case or not. Is that true? I mean, whether or not –

Pat Boylston: Yes, it is. We had a summer associate, summer clerk last summer, starting a review – basically starting from the Pacific and working East to do exactly this, and I think he got over to Montana and Wyoming. I’ve got a clerk working on it this summer to keep expanding it. That’s the kind of resource that we hope to have in house relatively quickly because it’s usually pretty clear by statute. There usually is not a lot of question about whether or not you constitute a public utility, although the Colorado Public Utility Commission only got around to it last year when the question was



raised to them. They issued a ruling last August that the third party solar model for the project LLC selling to a non-utility power purchaser did not constitute a public utility, and they looked to the intent of the statute as to whether there was an obligation to serve the public on the part of the third-part developer and found that there wasn’t, and that was sufficient to find that these third-party deals are not public utilities. But in some cases, it may not be quite as clear on the face of the statute as you would like.

Matt Sancorni: So in those cases you have to go before the Public Service Commission and the ________ commission, and they make ________ ________ there.

Pat Boylston: Theoretically, if there’s a serious question in your state, you may, which lends to something that I’ve seen in a number of projects, that there’s actually a lot more lead time than you anticipate going through the site-ing, Public Utility Commission approval, et cetera, versus the time it takes to actually construct the facility because this is evolving in a lot of states.

Matt Sancorni: Okay, thanks.

Male 2: Patrick, regarding the multi-tenant buildings, that’s part of San Francisco’s Solar America Cities Program, and they just celebrated their first installation, which is an eight-tenant unit, and the way the unit was with nine separate solar systems, one serving each one of the tenants and a ninth one serving the common areas. Does that sound okay to you? I understand the issues that you raised with multi-tenant buildings, but what’s your recommended solution there?

Pat Boylston: Well, what would be interesting to me is who owned each of the nine units because there’s always an argument that if you have nine different owners, nine different limited liability companies, each owning one of the units, or each only selling to one purchaser, what comes out and what is not necessarily clear – and I don’t think it’s clear in California yet either – is whether a concept of aggregation might apply, which is say you have one master fund, like a parent entity, and it sets up nine separate special purpose entity LLCs, each one to own one of those ________ units. Does the fact that all nine of those LLCs are controlled by a common parent – in effect the common parent is making nine sales? I just – I don’t think – at least I’m not aware, and I can ask some of the people in our California offices, particularly Sacramento or San



Diego, whether the CPUC has actually ruled on that question yet. We have certainly debated it internally. We didn’t see any problem with taking that approach, but on the other hand, there was nothing that clearly said it was fine and if the CPUC ever considered the question, they’d think it was fine too.

Male 3: Patrick, going back to the Oakes question of a state buying RECs outside of the state and the argument that it didn’t benefit the state’s ratepayers enough, could you elaborate a little bit on the reasoning underlying that and that taking CO2 out from Oregon presumably isn’t any different than taking it out of Washington?

Pat Boylston: Well, it’s an interesting argument, and I will note that the Washington Supreme Court has tended to cast a jaundiced eye on the activities of public utilities in Washington from time to time. They weren’t just purchasing RECs, though. They were actually making cash contributions to the construction cost of facilities in other states. So it wasn’t as simple a fact pattern as simply buying RECs. But on your point, deeply embedded in the concept of municipal law is this concept of boundaries, and municipal entities, authority and powers exist within its boundaries unless it is expressly granted the authority to act outside its boundaries, as you’ll often see with sewer and water statues, will authorize a city to supply the residents and this in the immediate surrounding area or basically anybody they can connect up to a pipe in an area they think is reasonable. I don’t know – the court didn’t say anything that told me they were applying that kind of a legal doctrine to it. It may simply have been, as simple as it is, that if it’s Washington ratepayers paying the cost, it oughta be Washington ratepayers who are getting the benefit of the environmental enhancement.

Male 3: Thanks.

Pat Boylston: For what it’s worth. Okay, so next, crafting a city-friendly PPA. I want to take just a second to sort of go over the basic economics of solar PV projects and then to explain where the investor’s looking to in terms of realizing their return, really their “value” on the transaction, recognizing that these numbers will deviate by a few percentage points, but in terms of scale are probably reasonably accurate. Most developers think that about half of the value of a solar PV facility comes from the combination of the federal investment tax



credit and the accelerated depreciation. They will also say that only something between eight to ten percent of the value of the installation actually comes from electric revenues. There are reasons for that that I’ll explain in a second. That means roughly 40 percent of the investor’s return has to come from some combination of state incentives, REC sales, local incentives, other things like that. That is a heavy, heavy need for subsidy and for subsidies beyond the federal tax code. And when you look at – well, and why are rates at ten percent or eight to ten percent? Because generally developers understand that power off-takers are going to be sensitive to the cost of electricity from the facility in comparison to market rate offered by their utility. A year ago, there seemed to be a real belief that you had to start selling electricity at a rate below the market rate, and the standard pricing formula was three or four percent annual increase based on the justification that it could – looking at a trend map over the last 30 years, that was reasonable believe the annual increase in market rates. Now, I have seen from some developers a trend to move more towards starting at market rate and increasing five percent a year, or I have seen some pricing formulas where you start above market, but it’s a fixed rate, and based on both sides’ estimates of where market rates are going, it crosses the line and becomes below market rate in about year seven or eight. There are lots of variations on the pricing of the electricity, but that falls within this context. Roughly in order of magnitude, the ________ and investor or developer can get value out of a product – number one is the general ITC. Number two is accelerated federal depreciation. Then, depending on what state you’re in, it’s either state incentives, RECs. The number five spot is power revenues, and number six is local incentives. Or, if you’re in a state like Colorado – or currently New Jersey with their market – you would flip the state incentives and the RECs and say the RECs are in third place. The state incentives are in fourth. States where RECs are a higher percentage of the value of the project are those which have a solar carve out in their RPS. The scope of these RPS require a specified percentage of their generation sources from solar. That makes it much more valuable. Oregon, for instance, has an RPS similar to a number of states,



where it’s basically – it has – it’s a fixed percentage from renewables, but within renewables, it does not set specific percentages, and that means solar is competing with wind and all other renewables, and because of the scaling and size generation capacity of a wind farm, wind’s going to be cheaper than solar. It’s just a fact of life in the world at the time. Other states that have very high REC values – for instance, again going to Colorado – that passed a program that allowed local utilities to purchase the output of solar renewable resources and buy the RECs at a very large price. It was $0.395 per REC compared to a local power price of roughly $0.06, more or less. So under that contract – and that arrangement is what ________ ________ the Colorado Public Utility Commission was looking at and then authorizing the third-party model where they said, “You’re still okay if you’re selling the electricity to somebody other than the utility that’s buying the RECs. Going to the revenue point – okay, so you look at this list, and you say, “What can be moved to increase the value of the project to the investors?” And this is, again, a market-driven item that is interesting. I have seen a number of projects with large financing sources that were targeting roughly seven-and-a-quarter IRR off of the transaction. Now I’m seeing some transactions that are smaller, with sort of what I would call secondary market or rich individuals who can qualify to use passive losses, looking for an 11 or 12 percent IRR. And a project that is producing enough to get 7.25 is going to have trouble getting to 11 or 12 in what I would call a standard model. So off of this list of six things – yeah, local incentives are not going to change quickly. Federal tax code isn’t going to change quickly or in a way that would benefit a specific project. That sort of leaves you with state incentives, RECs or revenues, and since the state incentive structure can substantially affect the value of the REC, as a practical purpose, if you’re looking at needing more money out of a project to make it work, the only two places to look are RECs and revenues. That sort of explains why the developers are looking more at putting in price structures which are likely to produce higher revenues over time. Not all of them are doing it. It’s just something I’ve seen. And when we are talking about crafting RFPs, it’s an issue that will come up again and be worth talking about. So as we move in to identify your critical must-haves before



issuing the RFP, clearly I’ve looked at a lot of governmental RFPs over the years. I’m sure all of you have drafted many of them. I’ll take an example – Snohomish PUDs RFP for renewable resources that was – I think it was about six months ago. They issued an RFP for a hundred megawatts of renewable resources. They received proposals for a thousand megawatts – all kinds, all sizes, all sorts of stuff. In a situation where I suppose you’re relatively indifferent to what comes over the transom, and you wish to spend or don’t mind spending the staff time to assess all those proposals and figure out which is more inline with where you want to go, that’s okay. If you’re dealing with a smaller solar installation, as we usually are in the governmental/nonprofit world, that process would really be self-defeating, which sort of in a way comes back to the necessity of determining whether you’re subject to public bidding. Because I know certainly developers would prefer – and I think in many situations, the governmental entity would prefer dealing with a single entity where they have the ability to negotiate the parameters of the transaction on a one-on-one basis without going through the full RFP process. As I said, many of these things can be somewhat unique. If that is an option, it is something to thing about, but when you talk about the list of must-haves, while clearly it’s up to each of you to decide what those are, the typical issues are things that I would say from your point of view is – at least in my discussions it’s come up first is sort of like, “What’s the price of electricity? And do we have a purchase option?” Well, there are actually a number of other issues which can come up, such as, “Are we going to be required to provide security? Are we going to be required to provide indemnities? What size do we want? Do we want to size it for future growth demands? Or do we want to size it for current demands? Do we want to leave open the possibility of newer technologies? If the panels are going it be replaced, is that an option you would want to talk to the developer about?” I will say I haven’t seen that yet in a contract. I’m not certain that if newer technologies start getting more press releases that we won't start seeing that. Moving on to the next point, though, which is really – and this is solely my personal opinion – what the developers and investors seem to do as their must-haves – and sort of in this order of priority. It is a business transaction. Inherently there are risks of



all kinds involved. In a rooftop installation, for instance, you have the question of, “Is the roof structurally sound for the weight of this installation? Is this installation engineered to handle the hundred-plus year event in the area? What is the risk that the building might be abandoned or vacated? What is the risk that the tenant might change?” so that you’re selling power to a different party than you had intended. It goes to the second point, which is really from the investor’s point of view, this is a tax advantage investment where what they want is to know what the benefits and values coming off the project are and that those are certain in the time periods in their pro forma necessary to hit the investors internal rate of return. This came up on a side note in IRS Revenue Procedure 2007 – I think it was 62. Might have been 65. It came out in the fall – dealing with wind projects. There’s lots of discussion in the legal community and accounting community about what this means and what its implications are for solar, but one of the points the IRS made was that they want the investors to really bear some risk. Now, I’d note that these are Safe Harbors, which by their nature are more conservative and more favorable to the IRS’s position than perhaps necessarily dictated by the existing state of the law, but they put it out there. And investors’ desire, if they had their perfect world, they would not take any risks in the transaction of any nature, and there are many – as I said, there are many different types, some of which you might not normally assume would be going into a calculation or estimate of “risk.” I know from my years of dealing with governmental entities that there is a strong desire not to take risk on that side. If that is the two sides’ bargaining position, you do not have a deal. That is one of those elements where if it’s the desire to have it ________ ________, there needs to be work around to find neutrally satisfactory middle ground, which can go a lot of different ways. An investor also cares about the exit strategy and mitigating the risks. They will – in a typical transaction, if you’re dealing with a serious party, they realize that there are certain risks that they fairly take – fairly meaning the ability to control or avoid the event is really theirs, that the other side has no ability to influence the occurrence of the event. The other side can very reasonably step up and say, “We’re not taking that risk because we can’t prevent it. We can’t mitigate it. We can’t do anything about it. You’re the



only party that can do that.” This particularly comes up in issues on the site lease. Whether the facility – ________ casualty at the facility can cause damage to the building. The project entity/developer typically understands that they’ve got to take that risk. It’s up to them to make sure that the facility is properly maintained, that they have a good O&M provider who is competent to inspect the wiring connections and make sure that nothing has come loose, competent to fix them if there seems to be a problem, competent to identity a situation that might pose a fire risk, competent to identify whether there are problems with the roof mount that means a panel or panels might come off in a high wind. On the other hand, the project entity developer will want the site host to take the risk that there is something structural about the building that means it’s just not really suitable for the size installation or the type installation that’s being proposed, and that putting the panels up there is going to cause damage to the building. They will want the site host to take responsibility for having maintained, inspected, reviewed the electrical system of the building and that it’s going to be capable of taking the output of the facility without harm or fire risk or posing a danger. Other places it typically comes up, which is really interesting, is roof maintenance. The developer will generally – and this is pretty universal – ask the site host to take the risk that the site host wants to fix the roof. The contract will provide for this by saying, “for your convenience if we need to shut down production, move the facility on the roof or remove the facility from the roof so that you can do repairs or maintenance on the roof, the developer will want compensation.” – from the site host – and this is a very interesting issue if the site host is not the power purchaser. But the developer will look to the power purchaser to say, “If this is being done for your convenience, we want to be paid what we were not able to receive due to this act.” Usually it means if we’ve got to take the facility down for two or three weeks while you re-roof, we want to be paid for the power revenues that couldn’t be generated during that period. Often it comes up, depending on the situations, they will want to be paid for the RECs that were not generated during that period because it’s lost revenue done for the convenience of the site host. As far as exit strategies, almost everybody these days, as I mentioned, will offer a purchase option. From the developer’s



point of view, and it grows directly from the fact that this is viewed as a tax-advantaged investment – in the tax old days of the ugly tax shelter world, there was a point at which those tax shelters, instead of generating losses, started generating positive taxable income, sometimes not associated with a similar amount of cash. So all the sudden people who had gotten into these things to get losses, depreciation, avoid other taxes, were suddenly ending up with taxable income. That was referred to in the trade of that particular investment having turned into an alligator. From some of these investors point of view, the solar PV facilities, by the time you get out to year 15 or so, potentially turn into alligators. It depends a little bit on the nature of who your owner is in your project entity. For instance, let’s take an example – SunEdison or MMA. Very much geared towards a long-term 20-year power purchase agreement. They are really looking at their overall return on the investment for a long period of time and viewing it as a revenue source, ultimately. Once all the tax benefits have burned off, what they’re interested in is the revenue stream. If you had a pure tax equity investor, they would tend to view it that once you got past year five, when the recapture period for the federal ITC runs out, and once you get past the substantial recapture period for the accelerated depreciation, which theoretically isn’t triggered unless the project is sold, but might be year seven or ten – at that point they don’t care that much whether the project is sold or not. They weren’t in it for the revenue potential. What they wanted has been used, which is one reason you see such variation on the dates of when the purchase option is available. I’ve done some where actually the power purchaser wanted it at any time, any time after day one, even within the first five-year recapture period. And the answer was the developer said, “Well, we’ve gotta do it to make this deal,” but what they established as a termination fee – or really think of it as a purchase price – was a huge amount that included the financial consequences of all the recapture. So from the power purchasers point of view, he had the option from the middle ground economic reality point of view. He’d be foolish to exercise it, but he had it. Lots of projects will allow a purchase option to the power purchaser after year six or seven, and the benefits have been used up, if it’s a tax motivate transaction.



If it is a PPA revenue-motivated transaction, you will often see that the purchase option doesn’t top in until year 15 or a 20-year PPA or exercisable at year 20 at the termination of the PPA. Well, depending on what kind of an investor you’re dealing with, you can have that variation. How you might structure your request and your RFP is likely to make a difference on what kind of a proposal you would get back on those. And the final point, as I said, on the must-haves for the investor is their overall financial return. So far in the market, this has been based on simple internal rate of return. In recent discussions and at recent conferences, I’m starting to see a trend – I don’t know whether it will grow or not – for the investors to be looking at, instead of just their accounting internal rate of return, looking at what’s call their cash on cash internal rate of return is even creating cash benefits as a cash equivalent. If the – and this dovetails again back to the point I said earlier of how do you get more cash out of this kind of transaction, it’s either you raise the power of revenues or you raise the amount you can get on RECs. Viewing these on a cash-on-cash basis puts severe pressure on this two items. An investor looking for a return on that basis simply has to get more – to get an IRR competitive with what people are accepting as – call it an accounting based IRR. They’ve simply got to get more out of the project. I think those are the projects where you tend to see pricing formulas that are trying to push the power costs up for a longer period of time. Simply, I don’t think you would ever specify in an RFP that you only wanted them to make their proposal on a regular IRR basis, but it is something to be aware of in evaluating the proposal. Then this is simply the negotiating point of view. Identifying when no compromise is possible between your must-haves and the developer/investor’s must-haves. I would say one clear place this almost always comes up and you can anticipate it coming up is if there is any kind of an environmental question about the site. I negotiated a lease for a site that was being located on an old landfill. Although there were all kinds of representations and assurances that there was nothing toxic at this landfill, the investor was absolutely unwilling to take any environmental risk. On the other hand, we were dealing with a landowner in that transaction who very strongly took the position that as a matter of law, they were not allowed to give indemnifications.



In a way, that looked like a no compromise position. We ultimately worked it out, though, by simply agreeing that the landowner was responsible for any environmental condition discovered at the site unless we caused it, and that included many what we called “the barrel of green goo” discussions. If it turned out there was a barrel of green goo in the site and something bad happened and it migrated to surrounding areas and there was absolutely no evidence that we had ever touched it or gotten close to it, we are not responsible. They aren’t indemnifying us, but we aren’t responsible. On the other hand, if in putting – it was a ground mount system. If in putting our mounting pads down we happened to break the unknown barrel of green goo, then we’re on the hook. The investor could accept that because he felt he could mitigate it, both from the design of the facility, from warranties, from the installer. He had ways to do it. And ultimately, you know, he wasn’t going to be held responsible for something that wasn’t, “his people’s” fault. And that was a position he could deal with. On the other hand, he wasn’t also being asked to take responsibility for something that he had never had any control over, didn’t know anything about. This landfill had been there for 50 years. Okay, moving on to the next point – almost done – electricity price calculations. I’ve mentioned a bit about this before, and the key point being that many developers understand that there’s an expectation of a power purchaser that they may pay a little bit more for renewable energy, but they’re not willing to pay a whole lot more. Often, from the power purchaser’s point of view, they want all of the ease and certainty that their local utility offers, which is when you flip the switch, the electricity will come on, and the price will be, if not below, at least not grossly out of line with what they would have paid for the local utility. Now, there are a couple of factors into this that complicate it somewhat. As I’m sure you’re all aware of, solar is what’s called an intermittent resource. It only produces energy when the sun is shining. In Oregon, current estimates are that on our typical extremely cloudy day, the output of the solar panels goes down by about two-thirds. One particular solar installation currently under construction that has been sized to provide all of the electricity needs of a light manufacturing facility today is going to need to take off-the-grid



for about two-thirds of its power on a very cloudy day. Now, the reality there is they would have put up more output, but they were constrained by the footprint of the building and the efficiency of the panels they could get. They simply could not be assured delivery of enough – it’s about 4,200 panels – enough of the highest efficiency panels produced by their chosen manufacturer to be certain that the facility would be in place by December 31, 2008, which is the current expiration of the federal investment tax credit. Consequently, they downsized to a design of about 875 kilowatts and realistically were prepared to compromise and come down slightly more if there was a problem getting enough of the proper panels to hit that output level. Well, when they look at their price of electricity, then they’ve got to take into account that they are still going to be drawing a substantial amount of power off the grid simply because Western Oregon, Western Washington, Coastal California are not great solar resource areas. So where they are in relation to market price makes a difference. In that case, how we handled it was they have a reasonably good purchase option – in fact, a very good purchase option – any year after year seven, which I expect they’ll exercise. When you go into other ways of looking at purchase options, a year ago, because of IRS requirements to say that the purchase option must be at no less than fair market value, a number of the provisions were written to say, “It will be sold at fair market value.” Then the discussions got going, as I said earlier, about what is likely to really be the fair market value in 15 years, and people started saying, “Well, that’s not a good thing. We don’t want to just give it away.” They started coming up with a concept of the termination fee, which caused the calculation to be phrased as “purchase option is the greater of fair market value or the termination fee” or early termination fee or what have you. And the early termination fee was actually the discounted cash flow for the remaining term of the PPA. So in selling the project, at least the investor/developer could have some assurance that the return they expected through year 20 based on their PPA was going to be realized, at least on a discounted basis. The newest variation I see on that formula, which I think is really interesting, from the developer’s point of view at least, is to say



purchase is at the greater of fair market value or, A, the yearly termination fee and, B, a buyout price. Now, naturally, the closer you get to the termination of the PPA, the smaller the early termination fee gets. It’s on a discounted basis because it’s approaching zero. So the buyout price is a fixed amount, fixed on day one. In the better ones I’ve seen, it basically approximates 20 percent of the installed cost of the facility. And so what the investor really can do is look at their power revenues and know that if at the end of the period they’re going to get that 20 percent payment purchase option, it allows them to look at the power revenue numbers a little differently and perhaps reduce the electricity rate. The other thing it does is helps with a federal tax issue, which comes to this point of why do you see so many of these agreements being called energy service agreements. It’s because nobody wants them to be classified or characterized as disguised installment sales. In a disguised installment sale, the project entity and developer would not be the owner for tax purposes. Under the true lease rules, you can hear different variations. Sometimes it’s called the 320s. Sometimes it’s called the 380s. To be classified as a true lease, the term of the lease is only supposed to be equal to no more than 80 percent of the useful life of the property. The lessor is supposed to have an equity investment in the property at all times equal to at least 20 percent of the value, and there was supposed to be a reasonable expectation – really probably beyond that – that the property will have at least 20 percent of its initial value remaining at the end of the lease term. Well, if you set a buyout price of roughly 20 percent, it certainly solves the issue about what the residual value expectation is as to property. I think from your point of view, the question is out in your 10, 15 or 20, would you be willing to pay 20 percent of the original price as your purchase option price? I will note here as well, as I said earlier, there’s also a reality check here that since we aren’t far enough through the term of these contracts, we don’t know how it’s really gonna play out. But the question is at year 20 or year 15, if a developer is legally entitled to a payment equal to 20 percent of the value but the developer realizes if you don’t exercise that purchase option, he’s got the economic cost of taking the installation off the roof at the end of the PPA, and if there is no active secondary market for used



installation equipment, or that developer doesn’t think he’s got some place to move it to relatively quickly where it can start generating revenue again, the question is what is that installation really worth to the developer. What is he really going to agree to as a purchase price? No one knows. It’s an interesting speculative question. Okay, potential for combining incentives and structuring options. First, are there any questions on that section of the outline?

Jason Coughlin: Pat, this is Jason. I have a quick question. We’re beginning to see some responses to RFPs that are trying to pass the insurance cost of the system on to the city. Are you seeing that as a common way – I guess at the end of the day, if you make the PPA provider absorb insurance costs, you’ll pay that in the electricity price, but is it still fair to say that insurance should be born by the owner of the system? Or do you see some movement in that?

Pat Boylston: Well, it comes back to the point I said earlier, Jason, that people are – developers are realizing that these are not the most lucrative deals in the world, and a trend that has been somewhat discussed in the market over the last year was that developers didn’t really understand the economics very well, and they were under-pricing the electricity since it’s one of the few things they can influence directly. And they were in situations where they were going to have a very hard time meeting the expectations of investors or getting investors because they had negotiated agreements that just weren’t gonna make it. So you started seeing a trend towards developers, integrators saying, “We’re serious. We’re in this for the long run. This is a business. We understand the terms we have to get for this to be viable.” You also saw a countertrend of what I would call local developers seeing that there were people coming into their area doing these projects. They wanted a piece of the market. They figured – they’ve said to themselves, “We know how to do this. We’ll just price it so low that we get it.” So they’re repeating the learning curves of the earlier developers and again pricing things so low that the project is likely to be in trouble from the investor’s point of view or likely not to realize the required return to the investor, which is gonna be a really interesting battle between the investor and the developer. It shouldn’t be an issue for the power opt-taker. Now, as part of that, a sort of trend, I’ve seen things like you



mentioned, trying to offload costs onto the power purchaser. It’s not typical. It’s a way to try to increase the returns. What I have seen, which seems to me to be reasonable middle ground, is that people are realizing that it’s actually cheaper for the site host to carry the installation on their insurance even though they don’t have an ownership interest in it, and it appears that the insurance companies are agreeing to insure for that. And then I’m seeing the developer reimburse the site host for the cost of that insurance. So in essence – and be named an additional insured. So in essence it’s being provided by the developer, but they’re doing it as the lowest overall cost to the project.

Jason Coughlin: Could someone please mute their phone who’s talking in the background? Appreciate it.

Pat Boylston: Any other questions there?

All right, combining incentives. Something to keep in mind is that there are no inherent double-dipping rules, for lack of a better term, which says if you qualify for two different kinds of tax credits, you can’t claim them both, so long as there is not an express provision in one or the other that says you have to reduce it or can’t claim it if you’re claiming some other credit. One that I’ve seen come up or at least be proposed recently which I think has maybe some interesting potential is combining new market tax credits with solar tax credits. The new market tax credits really don't involve governmental bodies necessarily, but it is a redevelopment. And certainly if you’re in a situation where you know that there is a developer who is looking to do a project in your area that might qualify for new market tax credits, you can certainly discuss with them the fact that there’s nothing which says you can’t do the new market deal, and if you put a solar installation on the roof, you can also claim the solar ITCs as a way of encouraging solar development in your area, which would not be any money at all out of the pocket of the governmental entity, depending on what your local incentive structure is. There may be other opportunities to take advantage of this. I frankly have not seen any come through us in the 20-plus deals we’ve done yet, but again, it in part, I think, comes from the fact that right now the solar industry is basically retrofitting existing buildings or putting in ground mount units to serve existing buildings. I think as the green building, the sustainable building programs evolve and expand, there are going to be more opportunities to put solar or think about putting solar on what are



either new buildings or substantially renovated buildings that have environmental credits of their own. So these opportunities for combining credits to enhance the affordability of what are privately owned buildings should be increasing, and that would be a way for governmental bodies to encourage these kinds of activities in their areas by simply acting as information conduits and assisting interested parties in identifying and learning about what subsidies other than those they’re thinking of or focused on. Because if you’re a building developer, you will tend to focus on those things which directly affect your development of the building. You may not think about solar, may not think about other things. So I think it could be some interesting possibilities in the future. Now, B and C really speak to a couple of the structures of these deals your seeing in the market. As I said, what is called the PPA model really contemplates a project-owning entity, maybe one owner, long-term PPA, a long-term site lease. Tax credits flow through, and it’s really a long-term revenue generating transaction. The second type of structure that gets a lot of discussion in the market is what’s called the flip transaction. It contemplates the project-owning entity having two owners, typically it’s an LLC, so two owners – could be a partnership – one of whom starts out with a one percent ownership interest, ________ equity investor starts out with a 99 percent ownership interest. Then when the project realizes an internal rate of return that matches the target that was specified by the equity investor, the interests flip. So what was the one percent owner now becomes the 99 – excuse me, 95 percent owner is the allowed IRS guideline number. What was the 95 – what was the 99 percent owner now becomes the 5 percent owner. All allocations follow the percentages. There are a couple things going on here. Number one is that is a method of allowing the equity investor to take advantage of all of the tax credits available from the facility, and even though it gets 99 percent of the revenue from power sales in the first period until the flip, those are typically not real big numbers, which means that after the flip, what was typically the developer entity of the sponsor that was the one percent owner is now going to get ninety-nine percent of the cash as the revenue price on the PPA starts rationing up in response to the annual escalator. The investor will still be getting five percent, but that will to some extent be offset by O&M costs, so it’s not getting a lot of revenue, but it still has reached that point I described earlier as an alligator.



So there are expectations at that point, although not requirements, that the sponsor partner will buy out the other partners five percent interest at that point and let them go on. However, the flip structure also is combined with a purchase option in the power purchaser, so another alternative is that the members in this entity may be expecting that the power purchaser will exercise their option, and then the 95 percent partner will get 95 percent of the cash, and the 5 percent partner will get 5 percent of the cash, which is fine. You don’t necessarily see these with any particular purchase option, structure, as I described before. I think people just haven’t worked it through enough to decide where there’s a material advantage. I think, also, in reality, people are looking at it and saying, “That’s an issue that’s 10 or 15 years down the road. We’re in this for the equity investment. We’ve pretty much gotten what we really want out of this deal, so we’re not gonna sweat it too much at that point.” Now, one reason that the flip structure is very interesting or much desired by non-profits, 501(c)(3)s, are the one percent owner, who ultimately owns 95 percent, they can own the facility for essentially five percent of whatever its fair market value is after the flip point. The fly in that ointment is what’s called tax exempt use property under the internal revenue code, which says that if a non-taxable entity, such as a governmental entity or a 501(c)(3), is an owner in a project entity owner – project entity type structure – the available tax credits and depreciation are disallowed in accordance with the highest percentage that that tax exempt entity would ever own in that project entity. So if you look at the flip structure where they intend to ultimately own 95 percent, from day one, 95 percent of the tax benefits and depreciation would be disallowed. That would not be in the interest of the transaction. So in the case of 501(c)(3)s, what we do is set up a taxable – usually what’s called a C-corp, which think of that as a regular corporation, subsidiary of the 501(c)(3). The internal revenue code has rules and regulations laying out very clearly how you can do that legitimately and in accordance with the code which all grew out of, really, hospitals setting up these subsidiaries throughout the



‘80s and the IRS stepping in to regulate them. And the non-profit participates in the project ownership through this taxable entity and, ultimately, after all the flips, the taxable entity buys out the five percent partner, and the non-profit effectively owns it own power. There are – as there usually are under the internal revenue code – some toll charges to pay to get to that result, but the view of these non-profits is that within a reasonable amount of time – and again, they sort of project it out to be about year seven – the flip will have occurred. They will own 95 percent, and they will be able to buy, effectively, the facility for 5 percent of its fair market value. Then they’re in the position of their energy cost – it’s not free. There’s no such thing as free energy, but their cost is amortizing whatever that five percent purchase price was plus whatever they had to contribute at the front end to make the deal feasible over the remaining useful life of the property. The problem in using this with a governmental entity is the state positions usually recognize ________ of the difficulty of governmental entities setting up a taxable entity, generally, questioned whether setting up a taxable entity is really within the public purpose powers of a government. I would say that generally – and I’ve been hanging around the public finance area for really about 25 of my years out of my 30-year career – there were not many if any situations where trying to set up a taxable subsidiary and really seeing it at work was worth it because there was usually some other alternative available. Much more reasonable. People much more familiar with the structure and the idea, and it was just like, “Eh, it’s an interesting idea, but it would be a waste of time and effort to explore it.” In this particular area where you have the tax exempt use property problem on the governmental entity being an actual owner of the solar project ownership entity, it may be worth taking a look at. It may be worth it. However, even here there is what is probably a better alternative, which is the simple purchase option in the power off taker or site host. It may not – depending on what your purchase price is structures as, it may not be as cheap as five percent of fair market value, but it’s still unlikely to be much, and it is very clean because the tax exempt use property rules do not apply if the tax exempt entity’s only involvement is as a power off-taker and a site host. It is triggered by an ownership interest in the project entity.



All right. All right, here we go. Real quickly. The most common reasons municipal transactions fail. Number one, the governmental entity feels that it can only use tax exempt financing or tax exempt proceeds or tax exempt money, so no matter how you do it, to provide for the facility. Internal revenue code, 95 percent of a tax exempt financing has to be used on capital items, capital ________ and equipment. To be tax exempt for federal purposes, that means it has to be owned. If a governmental entity is going to own the facility, you have just, as I mentioned, under the tax exempt use rules you just removed the economic incentives for doing a third-party transaction. It becomes a basic straight purchase of the equipment. Since arguably the overall costs of the project are significantly lower if you take advantage of the tax benefits, it’s a high-cost way of acquiring solar. Other things that I have seen kill municipal transactions – I mentioned one of them – digging your heels into the ground and saying, “We’re a governmental entity. We do not give indemnities. We only get them.” I have seen transactions fall apart on that sort of no-compromise, no-middle ground negotiating posture. I have seen situations where one side – and frankly, it’s usually the governmental side – has an attorney negotiating for them who takes what I refer to as sort of the litigator’s position, which is, “My client takes no risks. You take all risks.” And usually a developer will be represented by somebody who takes what you call the business layer position, which is there are issues that we need to settle. We need to find a common ground. We need to find a compromise.” It comes somewhat back to – in a way to what Jason mentioned just a little while ago about the developer asking the power purchaser to get all the insurance and take all those costs. A lot of transactions sort of fail on this point of going in with someone in the transaction – it doesn’t have to be the lawyer, but it usually is, particularly if they come out of a state attorney general’s office – that, “This is it. We’re not going to take any risk.” The developers can live with taking risks. It’s what they do. It’s a base part of a business transaction. They know the parameters in which they’re willing to take those. Generally they’re willing to compromise, but it becomes very difficult to put a deal together if there is not a sense of compromise on what are perceived as key risk points, key points that the put the private side’s ability to



reasonably determine their return on the transaction or potential return on the transaction or position in the transaction, at risk, which they cannot mitigate, they cannot insure over, they cannot pass costs they feel are unfair, they shouldn’t be covering over as a means of compromise. It’s simply a problem. One other provision which – in a formal agreement which I have seen cause problems in municipal transactions is the one that if the building is abandoned or vacated during the time of the PPA, the developer will want to be made whole for his full economic loss at that point. This sort of goes back to the lease purchase concept I mentioned at the start of the call, where under a lease/purchase, the governmental lessee can walk away with no consequences to the transaction at the end of any year when they don’t appropriate. Investors will not accept this. If the governmental entity, if anybody – I see this in private agreements – if the site host or power purchase – basically the power purchaser, particularly if it’s different than the site host, is going to walk away, and there is no one to sell power to any more, the investor cannot and does not want to take that risk. It’s not one they can insure for. It’s not one they can control. It’s not one they can really mitigate for. So what they will want is their full economic damages at that point. What does that usually mean? Lost power revenues. And again, _______ – I mentioned this – to an extent, that depends on when in the life of the PPA the event occurs. But lost power revenues. Lost REC sales between the long-term REC contract. If it happens early, maybe recapture. Probably not as long as you still have the facility in point. There’s no production requirement tied to the federal credits. There may be a production requirement tied to state incentives. There may, in effect, be an unamortized value of the solar installation, which the developer investor can’t find a market to sell. Those are the kinds of things they’re talking about. If you feel like you’re in a situation – and this applies to any potential site host power purchaser – where you’re not willing to commit not to occupy the building for the term of the PPA, maybe you should be negotiating a shorter-term PPA or maybe you should be looking at a different site location. In a sense it comes back to what I mentioned earlier about roof repair and the project wanting to be compensated for lost revenues.



If you want to put a solar facility on a building for a 15-year term that you know you can’t re-roof and maintain around easily, A, maybe you don’t want to be putting the site on that building. B, maybe you want to accelerate maintenance and re-roofing and get it done. C, if you’re like up here where having a 15 year, 20 year life for a building is very unusual, maybe you want to make sure the way the project is installed, the design facilitates movement and relocation on the rooftop so that re-roofing is possible without having to move it off the rooftop. Things that, frankly, the site host typically does not get that involved in discussing with the developer/installer, whoever’s designing the system. It’s a place where more communication would be useful and probably avoid problems down the road. And I note that by my watch I am dead on 3:00 p.m. Eastern time, so I’m done.

Jason Coughlin: And thank you, Pat. This is Jason here. Certainly a whole host of information on a lot of different topics. So I’m not sure if there’s any questions out there. Maybe we can take one before we lose the time block here for the call. If there are no questions, what we will do from our end at NREL is create the transcript. We’ll do some editing both here and at Stoel Rives and then make that available to folks that were on the call as a backup document and for those folks that were unable to dial in. But I just want to thank Patrick again for two hours of generous time, and I know the cities appreciate that time as well. So thank you from our end, Pat, and thank you to your team there, David and Ashley and the rest. We do appreciate it.

Pat Boylston: Thank you for the opportunity, and we certainly would be glad to respond to questions that are emailed. Or if anybody wants to explore any of these things further, please do feel free. We have offices all over the place and lots of people who know a lot more than I do about things in the renewable area.

Jason Coughlin: All right. Thank you. And that’s a good point. I’ll distribute your e-mail address when we distribute the transcript, just so folks have that. All right, well, thank you, everybody. Bye now.

[End of Audio]

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