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[Rep. Kathleen James (Chair)]: Okay. Welcome back everybody to House Energy and Digital Infrastructure. It's Friday, January 9, and we are here for testimony on the definition of single plant statute. That was an issue we worked on quite a bit last year and took a lot of testimony and asked the QC to do some work and report back. So we're gonna start out with, ledge counsel who's just gonna remind us of what we accomplished last year. I'm representative Kathleen James. I'm from Manchester.
[Rep. R. Scott Campbell (Vice Chair)]: Scott Campbell from Saint John Ferry.
[Rep. Richard Bailey]: Richard Bailey, Lamoille Two. Chris Morrow, Windham, Windsor, Bennington. Christopher
[Rep. Christopher Howland]: Howland, Rutland and Ford.
[Rep. Kathleen James (Chair)]: Dara Torre, Washington two.
[Rep. Bram Kleppner]: Graham Sutton or this is thirteenth, Burlington.
[Rep. Kathleen James (Chair)]: Laura Sibilia, Windham. Great. And online.
[Rep. Michael "Mike" Southworth]: Michael Southworth, Caledonia two.
[Rep. Kathleen James (Chair)]: Great. Thanks, representative Southworth. Here in the room, we have
[Rep. R. Scott Campbell (Vice Chair)]: Peter Sterling, Renewal by Andrew Martin. So excited to be back.
[Steph Hoffman (General Counsel, Public Utility Commission)]: Good. Great. Steph Hoffman, general counsel for the Public Utility Commission. Super.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: And Wes Goodmore, staff attorney with the Public Utility Commission. Great.
[Rep. Bram Kleppner]: Tennessee Lam with the New Cross.
[Ellen Chittenden-Kowski (Legislative Counsel)]: Super. Alright. We're gonna turn it over first to our legislative council. Helen Chittendenkowski, office of legislative council. So last year, you passed out of the committee s 38. Yes? S 30? S s 50 which became act 38. And that bill had to do with the, you know, 25 is the new 15, changing the threshold related to net metering. But at the end of the session, you started looking at this issue regarding the definition of plant. That's right. It's not the definition of single plant, but the issues arise when there are more than one plant and the distinction between what is a single plant and what are multiple plants. And the reason that that is an issue is that it's a defined term in Title 30, Chapter 89, which is the Renewable Energy Program Chapter. And it is used more than 200 times in that chapter. And it is the definition that is used, it's sort of the basic unit of an energy system, is what is a plant. So it's used frequently, but it is also part of how the PUC distinguishes or makes decisions about what things qualify for certain programs. So you will hear about that more from them in a moment, but I'm gonna read you what you put into act 38. So the issue came up, you had some time for testimony at the end of session, but it was May. And the things that you that are at issue with this definition are fairly technical. So you asked the the Public Utility Commission to work with stakeholders and look at the issues regarding this definition. So in act 38, you added this language in section five. It's posted under my name today. I can't remember if I already told you that, but here it is. On report 11/01/2025 and with input from stakeholders, the Public Utility Commission shall admit a recommended amended definition of plant in 30 BSA eight thousand and two eighteen. 8,002 is the definition section for chapter 89, and an overview of their process and explanation of the recommendation to the House Committee on Energy and Digital Infrastructure and the Senate Committee on Natural Resources and Energy. In making its recommendation, the commission shall consider the land use benefits of colocation of energy generation facilities, the ability to ensure comprehensive review of colocated facilities, and the potential impacts to ratepayers associated with co located facilities.
[Rep. Kathleen James (Chair)]: Great. Thank you for that reminder. I just wanna bring us back to basics. So that is what we passed. That is what we asked the PUC to do. Thank you. You're welcome. And I think we can now bring on our next witnesses to
[Rep. R. Scott Campbell (Vice Chair)]: Oh, sorry. Oh, no.
[Steph Hoffman (General Counsel, Public Utility Commission)]: I'm gonna stay. I'll be here. Good afternoon. Thank you, Chair James and committee members for allowing us the opportunity to testify today. My name is Steph Hoffman. I'm General Counsel at the Public Utility Commission. With me today is my colleague, Wes Sibmore. We're here to walk you through two different filings we made related to one another. One directly in response to the Act that Ellen just went through with you, Act 38 of 2025, and the other companion memorandum that we submitted, a letter explaining a decommissioning proposal that we think goes hand in hand because the same interested parties and participants who come before us to seek certificates of public are affected directly by both of these projects that we grouped together and are proceeding to invite them to talk about these issues during the last year. Before you is a copy of this presentation, and I'm going to be going through the first half of that. That deals directly with what Act 38 of 2025 asked of us. And then my colleague, Wes, is going to talk to you about the decommissioning proposal that we brought together with that proceeding. So as Ellen already discussed, we needed to provide a recommended amended definition of plants from 8002. That definition does affect principally siting of generation projects, the vast majority of which are solar projects. The three sorry. I'm sorry. Did you wanna share your screen
[Rep. Kathleen James (Chair)]: or no? Should we just all go through the
[Steph Hoffman (General Counsel, Public Utility Commission)]: name of that? I I didn't bring a computer. Can't my Sorry about that. Talking with people. Sometimes I have it on a flash drive if you prefer to have it up on the screen.
[Rep. Kathleen James (Chair)]: Nope. We have it. I didn't mean to interrupt. Go ahead.
[Steph Hoffman (General Counsel, Public Utility Commission)]: No. Absolutely. Please. I want everyone to have access to the information, so stop me at any time. This definition principally functions for three different types of renewable energy programs that the commission has to look at when citing facilities. Those are the net metering program, the standard offer program, and compliance with the renewable energy standard. It functions much differently in those three categories. The first two being financial incentive programs, meaning you're gonna get paid as a developer of a net metering facility or a standard offer facility a certain amount of money to generate that power, and those programs have capacity caps. The standard offer program is capped at 2.2 megawatts. The net metering program capacity cap is 500 kW kilowatts generated by the facility. Those caps are tied to the fact that there's a ratepayer impact for those costs of producing power. In the renewable energy standard category for renewable energy programs, that's to determine whether compliance for utility purposes, whether the utility is going to be able to use that project for tier two and tier three, etc, if they're eligible or not for that program. We engaged with a number of participants in our process and considered the three statutory directives that you saw in front of you here, which were land use benefits, comprehensive review of these facilities when they come before the commission and break hearing. For a moment, I'm going to explain why in this context we linked these two subjects, both the definition of plant and decommissioning, so you understand why Wes is going to talk about decommissioning in a few minutes. We opened a proceeding right before this legislation became effective on 06/30/2025 in order to invite the relevant participants to come to the Commission and provide us with information, share information, and engage in a dialogue about the definition of plant and decommissioning. We sought any and all definitions, proposed definitions of the word plant and statute as part of that initial order opening the proceeding. So basically seeking the gamut of what people are looking looking at and thinking about. And we also put out affirmatively the statutory language we shared with you on decommissioning and what our proposal was for decommissioning. We wanted to start that conversation from a very stable starting point because it was something we were generating, we were initiating with this group of interested people. We ended up receiving and soliciting two rounds of written comments. We held two workshops, one on the definition of plant and one on the decommissioning proposal. At the end of that process, this sort of bilateral process of receiving feedback and giving out information, we put out a proposed definition of plans and ask for one more round of feedback on that definition before concluding and writing the report that we submitted to your committee. The Commission has been thinking about the issue of decommissioning, just to give a little bit more background on why that got linked here. How we do decommissioning, how we ensure decommissioning happens of these facilities at the end of their useful life, we've been thinking about that question for years. In 2017, we actually promulgated a rule in response to the language in Section two forty eight(five) requires the Commission ensure that decommissioning occurs when facilities are built on sites. Meaning, if that facility goes out of use, how is it gonna be taken down? How is the site going to be restored? We're charged. The commission is charged with ensuring that decommissioning occurs. We sorry. Go ahead.
[Rep. R. Scott Campbell (Vice Chair)]: Just a
[Rep. Richard Bailey]: quick question. Are we just talking about solar projects or any kind of energy generation facility?
[Steph Hoffman (General Counsel, Public Utility Commission)]: That provision in statute applies to any type of facility. Wind, solar,
[Rep. R. Scott Campbell (Vice Chair)]: hydroelectric. Nuclear.
[Steph Hoffman (General Counsel, Public Utility Commission)]: Nuclear has its own set of specific provisions regarding decommissioning that are separately set out in statute. So that A5 provision is not important. What we've done historically before our rulemaking in 2017 and after it is we've established a set of conditions in any certificate of public good that require a decommissioning financial instrument to be filed with us. When a facility is proposed, it receives a CPG, they go to mostly banks, sometimes insurance companies. They receive traditionally a letter of credit, and they file that original instrument with the commission securing the decommissioning that letter of credit is held in the amount of a decommissioning fund estimate for when that facility is going to be decommissioned. And we're talking about decades in the future. Right? Solar facilities' useful life may be anywhere between twenty and forty years, just as an example, assuming it's gonna come down at the end of that time rather than, let's say, repurposed or repaneled. That process has many complexities because they have to continually refile these financial instruments with us over the course of the life of project. And the cadence that they're required to file those under our current rule is every three years. Some facilities have an obligation to annually file with us. So on an annual or at most triannual basis, facilities have to seek out new instruments, the CPG holders seek out new instruments, they file them with us. We determined that this process after we received feedback from several CPG holders and we had recently gone through a comprehensive audit of everyone who has compliance obligations with the commission and to see how many of those facilities are in compliance and what they needed to do to come into compliance, we determined that there must be something going on with decommissioning that's causing some impediments to that compliance, and also we'd heard some feedback that these products are difficult to obtain. So we ended up saying to ourselves, okay, what are some other alternative methods of looking at this problem and Start conversations around that. Because all the same folks were going to be in the room, we paired that with the definition of plan and asked these questions because we had representatives of developers and CPG holders in that proceeding, folks who represent interest groups about renewable energy and other types of folks that appear before us, plus the state agencies that are charged with reviewing these facilities, all participating. So we brought both of these topics together and that's why we presented them to you at the same time. In our report on the recommended definition of plant, we have proposed after much engagement with these participants a definition that does several things. First, it sets a new general standard. That standard is essentially that a plant is a single plant, it's one plant, if it's on the same or contiguous parcels of land and if it uses the same generation technology, solar, wind, hydroelectric, etcetera. So that's the standard. So if you are on the same parcel and you are a solar facility, you are one plant. But there are exceptions to that. The exceptions are each policy driven exceptions that are also looking at the three factors the legislature asks us to consider. The first exception is what is A in the definition, individual residential net metering. Nothing about this definition should prohibit one homeowner who lives next to another homeowner from each having a roof mounted solar facility at their house, let's say. If we use the definition of same or contiguous parcels, we'd end up prohibiting neighbors who come second to that from building a solar a small residential solar at their house. So that's what a is attempting to exclude from the definition. We don't want to prohibit neighbors from developing solar. B is multi owner individual residential net metering. Essentially, if you have a housing development duplex, triplex, quadplex, or even some scenarios with buildings of homeowners who each have their own billing meter for electricity, we don't want to prevent them also from taking advantage of residential solar. We see development where you might have a duplex where the developer wants to put solar as part of the package, meaning this is a renewable home, etcetera. You don't want to prohibit it such that only one solar installation can be on that parcel of land at that duplex because you end up then with a situation where only one homeowner, only one billing account could be associated. So you're basically cutting out one of those duplex eventual owners from having solar at their house. I'm sorry,
[Rep. R. Scott Campbell (Vice Chair)]: just to clarify, you probably said this, but it went fine. So this is the threshold then is the meter. Is that right? So a separate meter can have each meter can have its can be associated with a with a renewal.
[Steph Hoffman (General Counsel, Public Utility Commission)]: Yes, the billing meter is used as the separation. Yes. And then the third exception here is more than one renewable energy program facility, so long as there are different points of interconnection and what that definition is, and it's not part of the net metering or standard offer program. What that portion of the exceptions is meant to deal with is we want for res compliance there to be the opportunity for multiple facilities to be on the same parcel or contiguous parcels so long as they're interconnected separately. Because the res compliance portion of the definition of the program for res is not meant to use plant to say, Oh, we need to make sure that these are not receiving a financial incentive. That's not what RES is doing. Whereas net metering and standard offer program are providing a financial benefit to someone who's developing and there are capacity caps associated with that development to try to limit what incentive is available. That there's ratepayer impacts for that, and there's and therefore also concerns that they basically would be able to violate those program caps if they are allowed to develop more than one facility in a co located way. Whereas the res, it's not targeted toward that type of a purpose. So that's what that definition exception is meant to do. Then the final portion of the definition is a set of definitions meant to clarify terms that we use in our proposal. Any questions or concerns about the actual wording of the proposal?
[Rep. R. Scott Campbell (Vice Chair)]: I'm sure there are. You went very fast and very, you know, great. Yeah. It's just that. I do we have the proposal? Yeah. Yeah. So, ma'am? Yes. Oh, yeah. Would it be
[Rep. Christopher Howland]: fair to say that the term single plant then is a subset definition of plant?
[Steph Hoffman (General Counsel, Public Utility Commission)]: We just use the the term as a full term of our single plant when we're referring to a determination that it is in fact one facility, one plant. It is the word plant is itself a single plant. And if you meet this definition, you are one plant. If you are more than one plant, then you would be outside of the the definition. So, basically, you are one plant. You are a single plant. If you use the same generation technology and you're on a single parcel, then you're contiguous parcels of land. Otherwise, you are multiple plans.
[Rep. Christopher Howland]: So if a standard offer plan exceeded the 2.2, it would become two plans on a single parcel?
[Steph Hoffman (General Counsel, Public Utility Commission)]: If you're putting, let's say, a solar facility on the same parcel of land, no matter how big it is, it cannot be in the standard offer program if it's about 2.2 megawatts. That's what we're looking at when
[Rep. Christopher Howland]: we determine eligibility for the standard offer program. And so I thought the single plant limitations was one connection to the electric grid not to exceed 2.2. Well,
[Steph Hoffman (General Counsel, Public Utility Commission)]: the current definition of plant actually uses a number of factors to determine whether or not a facility is a plant. The way the statute is currently written, it asks us to ask whether it's the same project defined by three terms, contiguity and time of construction, same owners, and proximity. And then does it share infrastructure or equipment? And so, a point of interconnection would be a form of infrastructure or equipment you could share, but the Supreme Court has looked at a number of things like sharing distribution lines or distribution line upgrades or sharing transformers. There's all sorts of infrastructure and equipment that could be shared. So right now, the definition asks us to do this very onerous and extensive look at each facility, how it's constructed, the entire history of the facility's planning to determine whether or not it is one facility. And our attempt here is to make that process a lot simpler and a lot more efficient. We look at these two factors that are very yes or no type factors. If you need them, you are a single facility or a single plant. And if you don't, then you're separate and you can be treated as two standard offer, two net metering, etcetera.
[Rep. Kathleen James (Chair)]: Do have question and a comment? Yep. For the record? I'll take
[Rep. Laura Sibilia (Ranking Member)]: as the absolute legislative counsel. Can you talk more about the third exception? I'm slightly confused about how it
[Ellen Chittenden-Kowski (Legislative Counsel)]: is used because you referred to a standard offer and net metering
[Rep. Kathleen James (Chair)]: and tier two.
[Rep. Laura Sibilia (Ranking Member)]: And so I am trying to pick can you talk just a little bit more about how that works?
[Steph Hoffman (General Counsel, Public Utility Commission)]: I'm a little confused on that one. Yeah. Absolutely. You can't have more than 500 kW in a net metering program on the same parcel or contiguous parcels or 2.2 megawatts of solar for the standard offer program on the same parcel or contiguous parcels under definition. Otherwise, you violate those programs and therefore you're not in that exception. If you're not participating in the net metering program or the standard offer program, but your solar is being used for a PPA contract with the utility to satisfy the res, all we look at is points of interconnection.
[Rep. R. Scott Campbell (Vice Chair)]: Okay.
[Steph Hoffman (General Counsel, Public Utility Commission)]: That's what that's what C is doing. Okay. And
[Rep. Bram Kleppner]: if I'm Mike, just to clarify, I think that same point. So if someone had a 500 kilowatt off-site community net metering facility and there happened to be adjacent to it an excellent spot for another couple of megs that they just wanted to do as a PPA, they had a separate interconnection, that wouldn't screw up the original 500 kilowatts that
[Steph Hoffman (General Counsel, Public Utility Commission)]: It would not under this definition. Under the status quo, it would have a you would aggregate all of it to look at.
[Rep. Bram Kleppner]: Right. But under the new definition, it would not screw
[Steph Hoffman (General Counsel, Public Utility Commission)]: it. You can just you can max out up to the program participation, but beyond that, as long as it's outside of the programs, we're not concerned with anything but point of interconnections.
[Rep. Bram Kleppner]: Got it. Thank you. That makes me happy. Not that that's the goal of legislation necessarily.
[Steph Hoffman (General Counsel, Public Utility Commission)]: Okay. Alright. I'm going to turn it over to West. Thanks Thank so you.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: Thanks, Steph. Thanks, Chair James and the committee. Steph did a great job of sort of introducing my half of this testimony, which is on the decommissioning topic. And just to sort of hone in on what we're talking about, we're talking about the financial obligation that a non utility generating facility has to restore a site at the end of its useful life, which encompasses removal of the generating technology apparatus and restoring the site to its original condition. That is a obligation that the PUC is tasked with ensuring under section two forty eight a of title 30. And currently, our process for ensuring that is by requiring, you know, developers to take a series of steps when they apply for a CPG with us. Those steps include obtaining a decommissioning cost estimate, providing the same with us, providing a draft financial instrument, usually from a bank that articulates that cost estimate and contains an obligation that the bank or financial institution will make good on that estimate at the end of the useful life of the facility if the developer is not able to decommission on their own. So what we're really aiming at is restoring sites to their original condition after the generating resource is no more is no longer useful. So currently, the financial institutions have to be A rated. Those instruments have to be filed with the commission and updated somewhat frequently, typically every three years to adjust for inflation. And then at the end of the useful life of a facility, the developer does have an obligation to decommission. And in the event that the developer did not meet that obligation, the commission would call on that financial instrument, often a letter of credit as Steph noted, for the full amount of the decommissioning obligation, and that's sort of where things grind to a halt from our standpoint right now, and I'll explain what I mean by that. But just first to define a couple terms. So decommissioning is the process by which a CPG holder or other responsible entity removes a generation or storage facility at the end of its useful life. Financial assurance is the umbrella term that I'm going to use to describe various assurances provided by CPG holders to ensure that the money needed to decommission is there when it needs to be called on. Financial surety instrument, like Steph noted, could refer to a letter of credit. It could be a surety bond or it could be an escrow agreement between a developer and a third party financial institution like a bank or insurance company. And typically we see letters of credit or surety bonds. And those are the legal documents that actually guarantee that financial obligation. So currently commission staff are required to triannually engage in tasks, really compliance related tasks related to these decommissioning obligations. And developers are as well. Inflation adjustments, updated financial instruments, these are all things that are filed into cases with the PUC as part of developers maintaining their compliance obligations that were part of their CPG. The problem I mentioned earlier, I've broken it in on the slide, I've sort of broken it as three separate problems, but I think there also is a fundamental problem, which is we're tasked with ensuring decommissioning at the end of the useful life of facilities, but we do not other otherwise regulate the people performing that work or the tasks related to successfully decommissioning a facility. So we do not regulate merchant generators, so independent developer of an energy resource, in the same way we do utility companies. Essentially, and Steph, you can correct me if I'm wrong about this, but our interaction with developers is largely limited to the CPG process. So once a CPG is obtained for a facility, our interaction with those developers is limited to those ongoing compliance filings for the most part, unless of course they were to try to construct another generation facility. And the last point here is that the commission does not currently have statutory authorization to meet our decommissioning obligation, which in statute is to ensure decommissioning, in the event that a developer, was non compliant at the end of the useful life of a facility. So we have financial instruments. These are paper copies that we have in our offices that are theoretically our ability to make good on a developer's decommissioning obligation, but we don't have any statutory authorization from that point onward. So if we needed to actually use that document and go to a bank and ask for the, let's say, 200,000 of inflation adjusted funds, we don't have an account to place that money into, and there's no clearly articulated process for us to fall. And it hasn't come up yet largely because a lot of these facilities are relatively new in the last ten or fifteen years, but it's something that could be on the horizon in the next decade or two. So if we were to try to call on a financial assurance, so a letter of credit or surety bond right now, We have nowhere to deposit them, as I noted. We have no statutory authority to place these funds into any particular account to make use of them. Obviously, maybe this goes without saying, we and the folks in our office are not skilled at the actual work of deconstructing a generation site. So we have little to no guidance about what would go into that and retaining contractors and what that process would look like. And the other important thing to note is enforcement of one of these financial instruments could be quite complex, because we're not going to a developer twenty years from now to seek enforcement, we're going to a bank. Oftentimes, we typically require an A rated bank. Those are often very large banks. And so actually calling on that instrument to ensure that we meet our obligation to ensure that the site is decommissioned could be legally and administratively very complex. On top of this, and Steph noted this earlier, the current system related to decommissioning relies on regular developer compliance with various filing tasks that are placed on them. This is typically the inflation adjustment. That's primarily what I'm referring to every three years, most decommissioning instruments have to be adjusted for inflation, but there are other related filings that do have to be made on a three year basis. The commission recently engaged in a general compliance audit, and we found that between 6065% of facilities that were required to maintain financial instruments for decommissioning were out of compliance. We think this demonstrates constraints on the part of regulated entities, merchant generators. And it's it's difficult for us to manage that system because it, you know, inevitably inevitably involves us chasing new paper documents from developers that already have their their CPGs. The last point is there's a lot of uncertainty and liability, both for our agency and for the state related to the status quo. The crux of this point is really that financial assurances are meant to be used when a CPG holder has defaulted on their obligations at the end of the useful life of a facility. Typically that could mean that a CPG holder is unable to be located, has become insolvent, or you could imagine things of that nature. And that makes it very difficult for us to engage with them in a regulatory capacity from that point. So there's inherent risk with requiring this consistent engagement between developer and regulator. And if an instrument is not maintained throughout the life of a facility, there really is no financial assurance in place to allow us to ensure decommissioning. And then a last point is just we're also depending on solvency of the financial institutions. So what we're proposing is a fund model. And I have this slide where I detail some of the attributes that we're suggesting that model would hold, and those are, it's an upfront contribution idea paid into a fund. The fund would be managed by, we think the best approach would be a combination of the commission and the treasurer's office. We think the fund could grow over time following some sort of market mechanism. The federal bond rate, for example, would be one option. That fund would be available and would be held regardless of delinquency on the part of developers. So if a developer is insolvent thirty years down the line, the fund is still there and is still controlled by the state. The fund would, we think, be best suited to cover commission costs for administration and to account for overruns. And we coupled the single plant definition recommendation with this recommendation about a decommissioning fund being created primarily because of overlap between the parties, as Steph noted. So the process for this was pretty much followed the single plant process. We opened an investigation on June 25. In July, we received a first round of comments on the decommissioning proposal. We issued a draft conceptual plan for the decommissioning fund proposal in September, and then we held a workshop in September seeking feedback from participants and interested parties. We received multiple rounds of comments, answered various questions and concerns on the proposal, and most of the feedback, if not all the feedback, was centered around how to calculate amounts that would be contributed to the fund, is a natural question a developer would have. And the important point here is the statutory language we proposed in the letter we sent to the committee would authorize the creation of a fund, and that would be followed by a thorough procedural series of steps at the commission level to arrive at those kind of answers, to receive input from interested parties and professionals and experts on what that fund would look like, what the contribution percentages might look like, what numbers would be reasonable or unreasonable. So And our proposal currently is really limited to getting the fund created, and all the details would be arrived at through rulemaking and other commission procedures after the fact because we need the input of experts.
[Rep. Kathleen James (Chair)]: I think we have a question for Sibilia.
[Rep. Laura Sibilia (Ranking Member)]: I'm just wondering, still reading through the comments here. Thank you for including those. If this decommissioning funds I'm familiar with sort of decommissioning funds for. And those funds are available to and belong to the company that's that owns the site. Who would own these funds and the interest and did the did the commission contemplate that?
[Steph Hoffman (General Counsel, Public Utility Commission)]: So there's two ways to construct, I think, this fund. The two cleanest ways are you're either forfeiting the funds to the state as a contribution upfront that is held by the state, you know, in trust for this purpose. And the the model we have proposed gives us also the flexibility to return the funds at the end of a project's life if it's if the decommissioning is performed by the CPG holder and is the site is reclaimed as it should have been according to the CPG. Both of those models follow models that ANR uses for holding a site cleanup fund. There are models there where you're making an upfront contribution should there be an issue on a site as sort of a participant in that field. And then there are round field type models where there's a return on investment when the contribution is made at the beginning
[Rep. Laura Sibilia (Ranking Member)]: of a project. Is probably a little bit more in the weeds than where you're prepared to go, but what about the interest that's held in that? Would that be utilized by the commission, or would that also be given did you contemplate that?
[Steph Hoffman (General Counsel, Public Utility Commission)]: We have so, again, a lot of this is preliminary. The functions in the statutory language that are proposed allow some flexibility so that this can be built out with experts. We've done some preliminary consulting with other states and with experts who study this issue because we are far enough away, but not far enough away that a lot of other jurisdictions are thinking about this problem now. But we have contemplated that the interest would benefit both the state and the developer. Should the developer do what they're supposed to do, they would receive their funds back with interest having accumulated. But some portion of interest is used as a buffer for cost overruns and for other embedded costs in administering this process because all of it is an estimate. Even if we're doing that estimate and updating it on a regular basis, it still presumes certain levels of risk, certain inputs. Solar decommissioning, should that be the way that solar facilities go? Because I do wanna acknowledge that might not be the only path for solar sites is that at the end of thirty years, they all come down. Maybe you have renewable energy obligations that presumably will live past the first solar facilities that were built. Maybe they should be reconditioned or repaneled or they're good sites for further development in renewable space in the future. But if the sites are coming down, they don't pose the same risks as, let's say, I mean, obviously a nuclear facility, but also a facility that has toxic chemicals or toxic wastes. Batteries are in this world too. Storage facilities would fall under a five's requirement to ensure decommissioning. They have certain safeguards and protections on batteries, but you could have some cleanup. That's all gonna go to ANR if you're talking about chemical contamination and be covered by their program. So we're really talking about infrastructure and site re remediation only to restore mostly soil restoration or removal of small areas that have become impervious surface, like a pad where a transformer has been placed or something like that that was concrete. It's really removal of those much more stable sort of elements and then return of the condition as much as as possible, which tends to be soil replacement and movement of soil on the site to replace things that were stockpiled. How many sites have been decommissioned
[Rep. Laura Sibilia (Ranking Member)]: in the last, I don't know, ten years? Zero.
[Steph Hoffman (General Counsel, Public Utility Commission)]: New England doesn't have much evidence of this at all. The most decommissioning happening in the country is in the Southwest and in California. Their solar program is further along than ours is. The issues in New England are different than they are in the Southwest as well. Like I mentioned, many different jurisdictions are looking at whether decommissioning is the only way of thinking about the end of useful life because useful life is really an economic concept. It is when a project ceases to be economically cost beneficial to the owner of the CPG, it's at that point that you have to decide whether it's due to panel degradation. When the panels start to degrade, you're not generating as much power, therefore you're not able to be compensated for the generation of power in whatever arrangement you have. So when you hit that point where the project is no longer financially viable, what are you going to do then? There are lots of different options in the marketplace, not just taking all the panels down, taking all the racking down, removing the cemented areas, restoring soil horizons, and leaving the site back to the way it was, let's say, thirty years or thirty five years in the past.
[Rep. Kathleen James (Chair)]: I have a really basic question about the money. And I realized there that this would be a program that would be designed through rulemaking, but you were talking about return of funds. So just super high level. So I am a developer. I am building a solar array for utility to meet its obligations. I put $200,000 into my decommissioning into our new decommissioning fund. And thirty years from now, the the site we decide the site's gonna come down. And at that point, my 200,000 is worth 250,000. And the cost of taking it down is less than that. I I I'm not understanding how the money works.
[Steph Hoffman (General Counsel, Public Utility Commission)]: So we did a back of the envelope for the folks participating when Wes had talked about it on your slide when it says September 11 commission issues draft conceptual plan. The idea with that was, and we are not the expert folks, but this is what we showed. Let's say the decommissioning obligation in today's dollars is a 100,000. It's gonna cost 100,000 to decommission this facility. What is that gonna be in '20 what year are we in? 2056. You adjust for inflation, recognizing that's an estimate, right? Because inflation adjustments still aren't static. You extrapolate forward, and let's say that 100,000 becomes a 140,000 in 2056 terms. Mhmm. Then you extrapolate back how much you need to invest today based on a rate of return to meet that then. And we're trying to right size those numbers so we don't end up with two, three, four times that's needed even if decommissioning had to be done for all of these facilities. Because rational folks looking at this problem probably wouldn't say every facility is going to be in this position. I would tend to think it's less than a good a small chunk of them would ever be in this position. And so, how do we make sure this account stays right sized at the beginning, gets adjusted along the way to be right sized when we get there, and you can return these funds to the folks that are following through on their obligations. That are doing the work. Okay. And right now, it's very hard to estimate what decommissioning, if that's the route we go, will cost because there's many cost components to that. There are other financial also incentives for folks to do that work that exist that are outside of our regulatory control.
[Rep. R. Scott Campbell (Vice Chair)]: Yeah.
[Rep. Christopher Morrow]: It's just a parent I'm not sure where you're getting the same sheets you're giving your testimony off. This doesn't seem to match what you're you were reading there. And then my first, the other question is the Shaftesbury Solar had a in there a billion dollar decommissioning cost. 20 mega megawatt. Well, whatever whatever they approved that they estimated.
[Rep. Christopher Howland]: Just recently approved the other It
[Rep. Christopher Morrow]: was a very huge amount to decommission and take it take it down or whatever they gotta do. So how much money would they have
[Steph Hoffman (General Counsel, Public Utility Commission)]: to put into that fund?
[Rep. Christopher Morrow]: Yeah. I'm trying to figure out how we're not gonna have taxpayers pick up stuff to decommission these things to
[Steph Hoffman (General Counsel, Public Utility Commission)]: Yes. I absolutely agree that I think our goals are to minimize risk to Vermont tenants and to the state of Vermont in leaving us with an obligation where actually the status quo might not have a dollar available under the construct where we use a financial instrument for the reasons Wes was talking about. So, we are looking at something that is more financially stable for Vermont taxpayers, for Vermonters to ensure these obligations are carried forward. I can't speak on the exact decommissioning obligation in a case because we're not able to talk about those cases. I think no matter what the amount you're talking about is, we would have an expert come in and tell us how to look at how that estimate is calculated, which, by the way, now is done on a private basis. Like, each developer is providing us with their decommissioning cost estimates. We would be finding a methodology through this process that establishes the cost estimate through a centralized formula so that that is standard and it's done through our methodology. Then that amount is met by what is contributed today based on inflation estimates and then the state's essentially investment methodology when you have a special fund is to invest that and it's, tagged to the bond rate. So it wouldn't be something like we have to invest in risky stocks or something like that to
[Rep. Christopher Morrow]: to achieve it. I understand that. I'm just I mean, one of these operators go bankrupt and do have to pick up that tab.
[Steph Hoffman (General Counsel, Public Utility Commission)]: When the useful life I see.
[Rep. Richard Bailey]: That's what they're trying to do. It's just
[Rep. Christopher Morrow]: Well, yeah. I know, but I'm we're but we we've already got many of them already there, and none of them have contributed or they've given you a piece of paper that says the bank may give you a certain amount of dollars, but it's not in hand.
[Rep. Kathleen James (Chair)]: I'm seeing in the PUC filing from Shaftsbury Solar an estimated cost of decommissioning of 1,680,000.00.
[Steph Hoffman (General Counsel, Public Utility Commission)]: I wasn't sure if you I thought you said a billion.
[Rep. Bram Kleppner]: You're right. He rounded up. And
[Rep. Kathleen James (Chair)]: I I'm not saying
[Rep. Bram Kleppner]: at all.
[Rep. Kathleen James (Chair)]: Okay. I'm not saying that's not nothing. I just wanna make sure. Yeah.
[Rep. Richard Bailey]: So with this fund, with each new facility pay into it to the point where they would the the projected money in the future would cover their, decommissioning? Or are you trying to create a global fund that would have enough money to decommission whatever the projected 30% of these things that need to be decommissioned? Some Some of them are gonna be in existence for a hundred years, right, theoretically. New new panels, whatever they so they won't be decommissioned within, you know, so given length of time. So I'm wondering whether you, you know, you mentioned that you mentioned that. So are we creating a global fund to cover Vermonters on decommissioning a subset of those, or in the hypothetical that all 100% need to be decommissioned in x amount of time. Did I explain that question correctly? I understand. Okay. Yeah.
[Steph Hoffman (General Counsel, Public Utility Commission)]: The goal of the fund is that each project has the funding available should it default. The benefit of a fund is that if we got it wrong, like we got an estimate wrong on a particular project, that there are funds to cover that cost overrun. That's sort of the benefit of a fund that an individual instrument wouldn't account for. I wouldn't want to create a scare that we think there's a risk that something like 30% of these are not going to be properly attended to. I think the numbers are far, far lower than that, if any. Some of these projects, like I mentioned, have multiple reasons why the CTG holder will hold on even if the project is not financially penciling out anymore. There's other reasons financially that they want to either remove the project or reuse the site or do something else in the future. Also, is the question of how do we deal with the folks. There's about 90 to 93 current projects that hold decommissioning obligations. Our goal in this process, should we have this authority, is to create a system that has an incentive for those who are already participating in financial instruments to join the fund. That would be the goal, and there's probably a breaking point where we do this correctly, and based on how long those projects have been in existence, there would be an incentive to join because comparing with the status quo, every three years you have to secure a bank letter of credit and that you're paying a one to 5% fee on obtaining that letter of credit and you're doing that every three years for thirty years means 10 times minimum you're securing that instrument at 3% of your total decommissioning cost adjusted for inflation each time plus the lawyer's fee to file or your management costs. If you pencil that out, you can imagine that those numbers and we've looked at them somewhat, maybe we've compared these, that if we get the number right, you're eliminating this uncertainty or eliminating this constant need to interact with the regulator on this one obligation. That upfront investment is certain. It helps with financing a project. It helps with knowing what the full financial obligation investment cost is going to be, including decommissioning. Right now, they don't have that.
[Rep. Kathleen James (Chair)]: Yeah.
[Rep. Christopher Howland]: 93 sites have decommissioning obligations. How many do not have decommissioning obligations? There's
[Steph Hoffman (General Counsel, Public Utility Commission)]: a break point for when the obligation kicks in, which is if you're at or under 500 k w, you have the obligation to remove the facility at the end of its useful life, but
[Rep. Christopher Howland]: you do not have a financial instrument obligation. Below 500, no financial, above 500 financial. And do these obligations, quantities vary on properties that have a lease agreement on leased land rather than owned and fee?
[Steph Hoffman (General Counsel, Public Utility Commission)]: The obligation from the commission standpoint is the same. It doesn't matter what your ownership or leasehold relationship with the landowner is. Our understanding is that localities and landowners do rely on the fact that folks are paying, who are holding some sort of decommissioning fund in order to obtain those agreements if they are leasing. They want these types of assurances as well that the facility will be removed.
[Rep. Christopher Howland]: And to the extent that decommissioning, you mentioned concrete, so removing the roof and restoring soil, but, obviously, you can't restore trees. You can replant, so we can't Some
[Steph Hoffman (General Counsel, Public Utility Commission)]: facilities do have aesthetic mitigation planting plans that were required at the time the CPG was obtained, so they may have been already required to put in, at times, hundreds of trees for purposes of aesthetic screening and other functions. There are certainly sites where trees are cleared and there are sites where some have been planted and thirty years in the future, hopefully, some of the ones that are planted would have grown to maturity. But, yes, they can't replace the ones they took down directly.
[Rep. R. Scott Campbell (Vice Chair)]: I have another just quick question here about coffee overruns. It would seem that just playing out your scenario about suppose the decommissioning cost of a of a site exceeded what the estimate was and all the financial factors are hard to predict, come into play, that you still have to collect enough from each CPG holder, each CPG developer, enough enough to actually exceed the projected cost so that you weren't in a situation where you had called to the point, because you're returning the full full amount of the fund to the holders who do decommission their their their projects properly. Right? So, I mean, just conceptually, theoretically, if everybody who does the decommissioning properly gets the full amount of their contribution to the fund back, and you only have one project that you have to pay for the decommissioning, then that project costs more to decommission than than anticipated, then you're still not fully. So it's or the data is still not fully. Right? The taxpayers aren't. So you'd you'd have to am I am I am I saying this yeah. Does this make sense to you? You'd have to collect collect enough, to account for potential cost overruns, other words, like contingency fund or something like that. Isn't that so? Or is that am I missing something here?
[Steph Hoffman (General Counsel, Public Utility Commission)]: Not missing anything. Our hope is that the way we're looking at this problem would allow for the collection of funds that grow over time such that the interest is shared somewhat. The growth on these funds over time would be returned mostly to the person, a six gs holder entity that is doing the decommissioning correctly, but that some small portion was retained for the purposes of cost overruns and administering the program. That's the map that we want a consultant. It's a complicated formula methodology that's used to make sure that all of the goals of this system are accounted for financially.
[Rep. R. Scott Campbell (Vice Chair)]: You've explained it now. Maybe you did that before and I missed it. Thank you.
[Rep. Kathleen James (Chair)]: Reptory, sorry. Go in the wrong order.
[Rep. Bram Kleppner]: Is there data out there about how good or bad we are in general at estimating decommissioning costs in terms of money we collected and then thirty years later found out whether it was enough or not?
[Steph Hoffman (General Counsel, Public Utility Commission)]: Us specifically
[Rep. Bram Kleppner]: I mean, nationally for energy projects.
[Steph Hoffman (General Counsel, Public Utility Commission)]: So we're we one of the organizations we consulted with is NREL. They're the ones doing the most national work on collecting data on decommissioning. They just recently completed a 50 state analysis, both in terms of what decommissioning estimates look like and also what mechanisms they have in place for insuring it financially. In New England, don't know yet because we don't know. We're not at the place where we can know what happened at thirty years and look back and say these were the factors that influenced stuff were down. But the folks that are studying what influences play into how much a decommissioning estimate should be in today's dollars versus what might happen in thirty years are looking and constantly tweaking those formulas. The way we collect decommissioning estimates now is, like I said, dispersed to all the different developers who make their filings with us, some of whom do it internally, some of whom use engineers and consultants. Creating uniformity there is one good place to start where at least all the inputs are the same and we're looking at all the inputs in the same way as opposed to getting You will see within New England the same size two megawatt, five megawatt project having a decommissioning cost estimate in Connecticut that is different than Maine by two, three times. And why that's happening, we're just not there yet. We don't know all of the information, but knowing it and pointing it out and looking at it and thinking about it, I think, is the purpose of this. This is to create uniformity, have those numbers be stable, clear, all the inputs laid out, and so we can then judge against that what's necessary for the current the current future, if that makes sense, rather than the ten years from now future or the third twenty five years from now future.
[Rep. Bram Kleppner]: Seems as though Sorry. Seems as though in Vermont, we've recently decommissioned a decent number of dams. Like, we're decommissioning one a year, two a year, whatever it is. So presumably, we know how much that costs. And so this applies to hydro as well. I've got hydro
[Rep. Christopher Howland]: data,
[Rep. Bram Kleppner]: but not solar data. Then we haven't decommissioned any solar panels yet. Yes. Got it. Thank you.
[Rep. Laura Sibilia (Ranking Member)]: I was curious about other states. The fund approach popular or are there other states that have gotten a little further along?
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: There are no other states that have a decommissioning fund.
[Rep. Laura Sibilia (Ranking Member)]: No other.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: But in doing research into the topic, we have several states that are in our inboxes wanting updates on how ours is going. It's
[Rep. R. Scott Campbell (Vice Chair)]: going. Good.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: So it's something other states are interested in. And I think it's fair to say that a number of other states are looking for creative solutions to this. I wouldn't call it a problem, but this situation.
[Rep. Laura Sibilia (Ranking Member)]: Yeah. I could see, like, agencies and natural resources leading on it instead of PUCs.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: Right. A lot of other states handle siting very differently.
[Rep. Laura Sibilia (Ranking Member)]: Yeah.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: So I think in our research, we saw that in New Hampshire, the their PUC may not get involved unless a solar array is above 40 megawatts, and it would be handled at a sort of a local zoning or permitting level. I don't mean to overspeak on topics I'm not aware of, but that that sort of concept is common in other states. So we're a bit unique in the sense that we we being the PUC oversee siting of relatively smaller solar facilities, and we have obligations to ensure that they're decommissioned. The only state
[Steph Hoffman (General Counsel, Public Utility Commission)]: that provides DPGs to solar facilities of these sizes. When you look at other jurisdictions, of the decommissioning financial assurance piece, as Wes was alluding to, is handled either privately or at a locality. Municipalities have requirements. Sometimes they're state forced requirements. Sometimes they're municipal generated requirements, or they they push it to the completely to the private contract negotiation. So if you're getting a leasehold from a landholder, that lease would hold a decommissioning requirement and obligation and some sort of financial assurance for the landowner, but it's not managed or regulated by the state or the municipality. So Apologies if
[Rep. Kathleen James (Chair)]: you explained this already. Would the funds also be available to the developer to recondition the site? That seems a much more likely scenario to me,
[Steph Hoffman (General Counsel, Public Utility Commission)]: that they would put on new panel, you know, put on the new generation of panels. So our goal would be that this system, you know, this model or the fund model would take into account different end of financial useful life scenarios. And it wouldn't just be geared toward taking the RAC and You did the GAML so. So, we hope to gather as much information about what those possibilities look like and whether perhaps an investment today in the fund won't be required in the same way in twenty years because what's happening on sites, we have that data now and we can tell the legislature and others what's happening. We will know what's happening and we can tailor this approach to better suit what's actually needed on the on the site. Yeah.
[Rep. Bram Kleppner]: Yes. Seems to me that the more we can eliminate externality is in our economy, the better the economy works, the more accurately it works. And we have a lot of experience, sad experience recently and over the last hundred years of companies going bankrupt and leaving a mess, which is a fine example of an externality. They've dumped all that cost onto the neighborhood, typically a physical geography, whether it's a mining company or the barge canal in Burlington or other infrastructure that's left drained. So conceptually, this feels very consistent with the notion of economic actors having responsibility for the costs of their actions over the lifetime of the effects of those actions.
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: I will say that we look to several of ANR. ANR does have several cleanup funds, we based the language we proposed off of those models. And so I think that's just sort of to your point about how to regulate risks like that.
[Rep. Bram Kleppner]: Which sadly means our generation has to pay for the last hundred years plus the next thirty years. Right? I mean, functionally, that's where we're at because we didn't do this a hundred years ago, which would have solved us a lot of problems. But that's where we're at. That's what we have to do, so let's do it. Good thing we're young and strong.
[Rep. Kathleen James (Chair)]: Other questions, comments. So, we have Brett Campbell put in a bill to, move forward the single the the plant language as defined. And you said you have suggested legislative language for the decommissioning? Yes.
[Steph Hoffman (General Counsel, Public Utility Commission)]: The letter that was submitted to the committee with the plant report. Has that The last
[Wes Goodmore (Staff Attorney, Public Utility Commission)]: Two pages.
[Steph Hoffman (General Counsel, Public Utility Commission)]: Two pages are this the proposed statutory changes and or
[Rep. R. Scott Campbell (Vice Chair)]: new language. Are really hard to find in this. And
[Steph Hoffman (General Counsel, Public Utility Commission)]: I apologize if we did not resubmit the report and the letter with our slides and the comments. That's okay.
[Rep. Kathleen James (Chair)]: We we have it and or can get it, and we'll make
[Steph Hoffman (General Counsel, Public Utility Commission)]: sure it's posted with your. Perfect.
[Rep. Richard Bailey]: Thanks.
[Rep. Kathleen James (Chair)]: Okay. Thank you very much for your work. Appreciate you coming in. We are adjourned for the week, and we can go offline.