Okay.

Oh, my mic is on.

All right.

Good evening and welcome to the July 8th meeting of the Sustainability Advisory Board.

Before we begin, I'd like to explain the various ways to participate in tonight's meeting.

First, you can join us here in person in the commission room, or you can join us remotely by going to Bozeman.net and clicking on the meetings tab where you'll find the agenda for this meeting.

Click the link on the agenda page to join.

You can provide public comment on an agenda item by using the raise your hand feature.

And we also take public comment in the room first and then move online.

Lastly, this board has decided to refer to one another on a first name basis for ease of communication.

With that, I call the July 8th meeting of the Sustainability Advisory Board to order.

Natalie, are there any changes to the agenda?

There are no changes to the agenda.

Okay.

Are there any disclosures board members would like to make on tonight's agenda?

Okay.

All right.

So we're moving on to approving the minutes from the previous meeting.

We need to amend the meeting minutes from the June meeting to reflect the attendance from four five is documented to four, which reflects the actual attendance.

So would anyone like to move that amendment to a vote?

I move to amend the minutes to accurately reflect the number of attendees at the meeting.

I'll second.

Awesome.

Thank you.

Kesley, would you please move that amendment to vote?

Nick?

Aye.

Kendra?

Aye.

Brooke.

Aye.

Eric.

Aye.

Chris.

Aye.

Great.

Okay.

Now would anyone like to approve the minutes from the June 10th meeting with uh including the amendment?

Please move it to a vote.

I move to approve the amended meeting minutes.

Second.

Kessley, could you please facilitate the vote?

Nick.

Aye.

Kendra.

Aye.

Brooke.

Aye.

Aaron.

Aye.

Kristen.

Aye.

Great.

Okay, thank you.

Are there any FYIs anyone on the board would like to share?

I have one.

Okay, so uh the next IWERP meeting, the integrated water resource update plan meeting will be in this room, the City Commission uh room at City Hall on Wednesday, July 29th from 11 30 a.m.

to 2 30 p.m.

They'll review conservation measures to complement um the previous discussion on water supply.

And you can join in person or online.

Um the information to join virtually um should be on engage Bozeman.

Yeah, I guess I also have an FYI.

Um following up, I believe I mentioned last meeting that the public service commission might have some meetings in different communities about the integrated resource plan of Northwestern Energy, not to be confused with what Brooke just mentioned.

They did schedule some meetings.

They're not going to be coming to Bozeman.

They're holding both in Helena on the 21st and the 23rd at 6 p.m.

But those are streamed and can be attended virtually if anyone is interested in attending, and so we'll make sure to check in with you.

Can you hear us all right?

Yes, I can.

Thank you all.

Um I caught a summer cold, so I'm um giving you the the gift of my absence.

But uh yeah, be be careful out there.

It's going around.

Um, and also I just wanted to also share that there will be a work session on July 21st with the city commission regarding the um review of the city commission um boards, and I believe everyone here has provided input into that process, so just want to give you the heads up that that's when the work session will take place.

Okay, thank you.

Um welcome, Jesse.

Um any FYIs, other FYIs.

Okay, now I'll ask if there's any public comment on any non-agenda items in person.

Any public comment online?

Okay, no public comment for now.

So um we'll move on to our special presentation for the evening.

Uh, we're gonna hear about the proposed wetland and water course code submittal requirements amendment um presented by Nick Ross.

I promise I checked my presentation and did this exact thing.

Hmm.

What do you think, Natalie?

Can you press into it?

Press escape.

Does it change anything?

We did something really special.

Ooh, smart.

Let's consider that.

Off to a great start.

Thank you all.

Uh for the record, my name is Nick Ross.

I serve as your director of transportation and engineering for the city of Bozeman.

Uh, I've had the privilege of leading all of the city's wetland water course code updates over the last three years, and we'll be tracking through the implementation of our wetland water course code as well as um serving as the review authority now for all uh development review applications that have impacts to our wetland and water course resources.

So, get underway for uh mostly familiar faces in the room, but a couple new ones.

Um, the city began um uh with a uh updating our wetland water course co-project uh with uh a city commission goal way back in 2022 that was originally focused on uh assisting with the creation of a local wetland mitigation bank.

We took the approach of using our code authority to help direct more of the mitigation of wetland impacts locally.

Uh we presented back in 2023 a pretty narrowly uh revised wetland and water course code that specifically talked about mitigation priority and through uh a lot of great engagement from this board and others.

Um, we're sort of sent back to the drawing board by our city commission to do a real overhaul of our uh total wetland and water course code code within the UDC.

Um we got that project completed uh and approved by ordinance last October, and now in the intervening months, have gotten a chance to actually use it.

Through that opportunity, um, we've become aware of a couple portions um that are within the submittal requirements uh related to outside regulatory agencies uh that have become conflicts, and that is specifically the relatively narrow scope of the current amendment that we're gonna be here talking about today.

So uh you as a state Sustainability board uh get to be subject matter experts in advising staff, the community development board, and our city commission on the appropriateness of these uh proposed changes.

Uh I'll explain at the last slide, but then we'll take your feedback, present that uh with this same presentation to our community development board, who has the uh more approximate authority over changes to the UDC, and then we right now have tentatively scheduled for the first hearing of the ordinance in front of City Commission on September 1st.

So what are those changes?

As I mentioned, we have a relatively narrow request in front of you to remove two of I believe the nine submittal requirements that we defined in our October 2025 update to the wetland and water course delineation report that we require with all development applications that have wetlands and water courses on site.

Those two requirements that we are proposing to be removed are A2 small A2 and A2 Small A 8, which are an approved jurisdictional determination provided by the Army Corps of Engineers and a determination of water course status issued by the Gallatin Conservation District.

So this is one of those exercises where the city has review authority over land use applications, but for certain things we require outside agencies to do their portion of review and an implementation of these two have found that there's been some conflicts.

And so we'll dive into a little bit of exactly what those are.

So with the Army Corps, first and foremost, why this middle requirement was included in the first place stems back from the Supreme Court ruling that more narrowly defined the types of wetlands that the Army Corps was responsible and able to regulate.

At that time, this was in the middle of our code project, and it caused a lot of consternation because it at least gave the potential that there would be a significant amount of wetlands that we value, but are no longer under the authority of the Army Corps of Engineers to regulate.

That was one of the main reasons that we kind of took a broader look and ensured first and foremost that whether it's the core or us as the local agency, there is some review authority over all wetland types within our planning area, and that remains true.

Um all wetlands within city limits are now protected by either federal or local authority.

Umly the Army Corps has the responsibility and ability to actually define which are core jurisdictional based on the definition of the clean in the Clean Water Act, and what are no longer jurisdictional under their authority.

That's done through a process called an approved jurisdictional determination.

So at the time we wrote the code, we thought it made sense to require the applicant to go up front and get their jurisdictional determination.

So we sort of understood which path they had to take towards regulatory compliance.

In practice, what we learned from the Corps is that the uh AJD, and I'm gonna use that for short from now on, approved jurisdictional determination is a fully separate action outside of their 404 permitting authority under the Clean Water Act.

And also, because of their staffing issues and the time it takes to do these, actually getting to an approved jurisdictional determination can often take anywhere from 12 to 18 months.

So we were left in a little bit of a pickle.

Um what they have guided us towards, though, uh, is that an applicant may assume core jurisdiction by entering the 404 permitting process and not be required to go and do the additional year to year and a half of getting the AJD, only then to realize that either it's the core or it's the city, they're still going to have to demonstrate avoidance minimization, and then for what is not determined, or for what are determined to be unavoidable impacts, still have to mitigate in the exact same way that our code, relatively exact same way that our code requires.

So, in an effort to try to streamline our code, uh streamline our permitting process, uh, which also happens to be one of uh the city commission's um uh priority goals for this year's cycle.

We are proposing to remove that AJD from the submittal requirements, and if an applicant chose to allow them to enter directly into that 404 permitting process.

So that means that the core authority authority would extend beyond what might be narrowly defined under the Clean Water Act, and the applicant has the choice then to assume court authority, avoid that 18-month AJD process, and again, only to end up in relatively the same place as they would if they went through that step to begin with.

There's a lot there, it is very technically nuanced, but that's gonna be the pitch.

We'll talk about the Gallic conservation district next, and then I'll come back for any questions you might have on that.

But that's that's the that's all we're asking for with this uh removal of the submittal requirements, no longer requiring the AJD right up front with their preliminary submission.

On the conservation district side, um we also uh in response to um a lot of issues that are uh coming up around the classification of a water course, whether it is a jurisdictional water course that requires a 310 permit or whether it is an irrigation facility.

We oftentimes were running into a situation where an application would get fairly far along in the process before even knowing whether that was an irrigation facility that then they had to go and coordinate with the water delivery company, or if it was uh true stream or water course that then would have to go through the 310 permitting process uh with the conservation district.

So, again, by way of trying to push as much of the information early into applications as possible, we felt it was prudent to ask the conservation district for a preliminary determination of water course status right at the beginning of the application.

Well, in the time that it took to actually pass our code, uh GCD changed their policy and they no longer allow or no longer will offer that preliminary jurisdictional determination before a 310 permit application is in front of them.

Um there's some legal nuance to that for their justifications, but it oftentimes it also comes down to staff and resource availability for them as well or our partners, unfortunately, just they oftentimes don't have uh, you know, very much staff resources to be able to handle an enormous amount of applications in a year.

Uh, and so having every one of our applications that comes in for development review go to them for the determination before even getting started, before they even realize if it's going to become a 310 permit that they do have to review, it was becoming a burden, and they were no longer going to uh give that preliminary determination.

So this is one where you know the city, first of all, first and foremost, completely understands their plight, and we cannot compel them uh to do otherwise.

And so that leaves us currently in a situation where we have a code that requires revision in order to provide a viable path towards approval for an application.

That's always the sort of baseline regulatory authority for an agency.

You ultimately have to provide some way for an application to become compliant.

Uh, and without removing this submittal requirement, uh technically, no application could move forward because they could not get that determination at the beginning stage without the 310 permit application as is currently written in our code.

So two fairly um different but similar issues about timing uh and ability for our agency regulatory partners to um uh comply with the code that we had written in the best of interest.

So we'll talk a little bit about engagement.

Throughout our wetland water course code development process, we had uh sort of the general public engagement and then brought those issues to our advisory boards as technical subject matter experts.

Um by the end of our code uh project, we kind of had a core group of folks uh that were coming to the public meetings, um, and so we took the approach here for this relatively narrow amendment of convening a uh more of a stakeholder level group.

And a huge shout out shout out to the Galton Watershed Collaborative for doing a great job of kind of pulling in both all three regulatory agencies as well as some of the um uh technical experts in our community to have a conversation uh last week, June 3rd, 30th, uh, that really dove into uh these specific issues as part of our compliance with the engagement plan to do this code amendment, uh and then also a really really compelling conversation about further discussion for the next steps of code implementation.

So those are things that aren't necessarily part of this code amendment process, but it's stuff that I very much expect to bring in front of this board, and so as a sort of primer for that, we're then going we're now going to be starting to discuss um uh city defined replacement ratios for mitigation of impacts, the potential development of on-site mitigation manuals to assist with one of those forms of mitigation that an applicant uh may choose.

And then also there was a pretty interesting conversation about the potential to either revive or start sort of a joint permitting process between the city and the Army Corps, respecting that if we're both essentially reviewing the same regulatory issue, it's possible to streamline these applications even further by having the city perform the review under the authority of the Corps, and then have the whole process hopefully work in a much more streamlined and direct manner from that way.

So that's just a little bit of a primer, but I did very much want to uh acknowledge the great stakeholder engagement we had, the great work that the watershed council was done to get us together, and then also note that uh we did reach consensus at that meeting that these two uh submittal requirement revisions uh were reasonable and appropriate.

So that's sort of the the open public engagement side that we did for this code amendment.

So pulling it back to conversation now.

Um we'll take feedback from this board, provide it to the community of development board on their uh August 17th meeting.

That's when they will hear uh sort of the whole um community development department um spiel about the formal code amendment.

Um, community development leads all code amendments when they are um uh technical in nature, they pull somebody like me in to do more of the background, and so that's why I'm here with you tonight.

Um we'll take the feedback from both boards and then present it to our city commission as well as the stakeholder feedback right now on uh tentatively scheduled for 9-1, September 1st, where uh we will formally present uh this code amendment.

Um so diving back into details.

Um, I would welcome any general questions and then uh hopefully engage in some feedback on the actual uh proposals.

Thank you very much.

Um we can start with Nick maybe and go down this way.

I don't have any questions right now.

Thank you, though, for the presentation.

Yeah, hi.

Um thank you very much for the presentation.

Um I guess I mostly have a few comments and some questions.

So um comments, I think I commend the city for taking an interest in protecting surface waters that are no longer protected under the newly narrowed definition of LOTUS.

That's really important.

Um, sort of a huge gap for a lot of wetland categories we probably see in the valley.

Um I also strongly agree with the proposal to remove the requirement for an AJD, as it sounds like you found out getting an AJD can be almost impossible.

Um, and if you're avoiding and minimizing impacts, there's really no reason to get a any sort of JD from the Army Corps.

Um so I think this makes a lot of sense, and I imagine um, you know, it wasn't just wasn't tenable for developers to try to get an AJD.

I'm curious to know more about the surface waters under the jurisdiction of the conservation district.

That's a gap in my own knowledge, so I don't have too much commentary on that.

I think it makes sense to not require a determination if the district won't give a determination until a permit application because that's you know, often when projects of any sort are really really early in development, there's not enough information to apply for permits.

So that's that is um likely often unnecessarily onerous.

Um very interested to hear about this idea of a joint permit process with the Army Corps.

Um I've worked with a lot of local jurisdictions.

I have never seen anything below the state level in terms of a joint permit process with the Army Corps.

I think it's an interesting idea.

Um knowing what it's like to work with the Army Corps, I would really caution against creating another process that is similarly unworkable and puts additional um work on city staff.

You know, you know what I'm saying.

The Army Corps can be uh challenging to work with, they're highly under-resourced, and and sometimes for projects that have pretty minimal impacts, they just don't have the bandwidth to work on those in my experience.

So um, but yeah, I would love to to learn more about that as you guys go down that road.

Great, thank you.

Thank you uh for the update.

I don't I don't have any questions or comments now.

Yeah, thank you for the update.

And um yeah, I don't have any questions, just appreciate the city considering wetlands and um making sure the requirements don't become more lenient um within recent policy changes.

Thanks, Erin.

Yeah, I also don't have any questions, just um appreciate the education about this, and it seems like a really um practical, pragmatic, necessary thing to do.

So thank you.

Thanks.

Thank you.

Um can you remind me who are the partners that were at the table at that meeting you had on June 30th?

Was it Army Corps and the um Gallatin Conservation District?

Sure.

So Army Corps uh did attend.

We were not able to have the Gallant Conservation District there.

They did submit the city, sort of what kicked this whole thing off, but uh a letter um that was um basically expressing their concerns.

Uh and then we were able to meet with them one-on-one a few months ago as well, but they were not able to attend the meeting last week.

Um the other partners in the room um are uh Bill Kleindel, so he's our uh primary wetland consultant um uh reviewer.

And uh then let's think um Catherine can remind me, and then I believe oh um uh sorry.

We actually did have somebody from the conservation district.

So that was um uh Brianna Schultz, uh, who's on the board there?

Uh and then we had one other member of the public who works in the wetland resources field.

Also Jared, sorry, Jared and Catherine and Lily from the watershed council.

Okay, great.

I was curious if they were also part of part of that.

Um, so I guess as it relates to the 310 permits, um, is anybody going to provide a determination of status prior?

Is there the opportunity for somebody else to do that?

Um that is one of those things that only the conservation district has the authority uh to um to issue.

Uh and so they would do that at the time that the permit is submitted.

So um the permit application they require a project to be developed enough that they can actually see what the impacts would be to the water uh water source in question.

And then that's when they do uh their determination of whether or not they have um authority over it.

Okay.

I used to serve on the Madison Conservation District Board, so I'm familiar with the process, but I wasn't aware that it's only conservation district boards that can make that determination.

That probably is something I knew at the time.

Um, but has gone in one year and the other.

Um, so are the I agree these are solutions to the language.

Are there holes that aren't being filled as part of this?

And can you help us understand what those look like?

Sure, that's a very good question.

Um so I'm gonna take you down a little bit of a rabbit hole for specifically what gave us some consternation about the AJD process.

So going back to uh the mitigation portion of our code update.

If you'll remember, uh we established for the four first time um what we, as the city determined to be uh mitigation priority of all the options uh that are uh potentially viable for um compensatory mitigation of wetland impacts.

Um we understand though that priority is different than what the Army Corps' priority of compensatory mitigation uh typically follows.

We were concerned about removing the AJD because we were concerned that that basically threw that whole mitigation priority out the window.

Uh we understand the Army Corps through their compensatory mitigation rules uh will require applicants to mitigate for impacts, wetland impacts at an approved wetland bank, a core-approved wetland bank.

Um we also understand that they don't have the authority to define which wetland bank an applicant has to choose.

And we as the city don't have the authority to tell them to tell the applicant which the wetland bank which wetland bank to choose.

So our my our our primary concern was okay, well, they're still gonna go then to the cheapest one, that's probably gonna be the regional one out of Twin Bridges, and then that's gonna leave our code sort of toothless that encourages local mitigation at the soon to be created wetland bank here in town.

Um, what we um what we learned through discussion with the court is that's all true, but the applicant still has the choice of deciding which approved wetland bank they will go and mitigate with our land use authority still requires the applicant to tell us in their application their method of mitigation.

So if the applicant chose to mitigate in a manner that wasn't compliant with one of the potential core options, or our own code, then they could get the 404 permit, but they're not going to receive adequacy under our own land use code because they did not follow the appropriate mitigation priority under our land use authority.

So basically, they could go get the 404 permit, but they couldn't get the actual site plan or subdivision approval to go build what they were getting permitted to do.

So by way of thinking through your question there about maybe unintended consequences or loopholes, we feel confident that that will still give us the teeth to require an applicant, effectively require an applicant to mitigate as locally possible through the core approved means, okay.

That's helpful.

Um basically the threat of going non-local for the mitigation bank is is okay.

You've made that you've made it work, you've done kind of an end-around on that.

Okay.

Um, what about for the 310?

What about not having that approval for the 310?

Does that leave any holes in the system?

Uh it won't because this basically kicks us back to the same process that we had in place before our last code update in October.

So, this was a new provision that was put into place.

Exactly.

We we've always required the 310 permit basically the applicant to get final site plan or subdivision approval.

They have to show us evidence that they've gotten their 310 permit.

Um we tried to basically front load that determination in the new code update.

Now that the GCD won't, you know, doesn't provide that, they're basically back to the same place of our code still requires them to get the 310 permit for a water course impact.

We just can't have them define in the initial application if that water course is a 310 is under 310 authority.

So basically they propose they do their design, it shows some impact to a water course.

We say you have to go now and submit that 310 permit application through that review process.

The conservation district now determines if it is in fact a 310 water course.

And if it is, they complete their review, issue the permit, and the applicant has to provide that permit to us before they booth ahead.

Okay.

Okay, let's see if I have any other questions.

I don't think so.

Interesting issues to come across um unexpectedly right at the time of trying to strengthen the code.

Thank you.

I echo the waters of the US issues.

That's sad.

Challenging.

Um what is a 310 water course?

Is that a state protected designation that's then delegated to conservation districts?

I apologize that I'm not I think.

So I will not um present myself as anywhere near the kind of regulatory expert that those folks uh that running that are running the program are.

Um the simplest way I can state it is they have the authority to to make that determination and issue the permit.

So whether that is passed down from the state um or county or otherwise, that is the uh agency within our planning area that has the authority to issue that permit.

And do water courses covered under the 310 permit, are they only those explicitly not protected as vote?

Uh my understanding is that there is uh uh uh almost a separate technical definition for how they determine um whether or not that meets those standards.

So I I can't tell you exactly if they ultimately refer back to the WOTUS ruling for that or otherwise.

Um but um primarily my understanding is they basically have to define whether it's an ephemeral stream or perennial stream, and also then if it is um a uh like an irrigation facility, purely irrigation facility, or if it's purely a water course, or there's actually a uh a combination that we kind of colloquially call a stream ditch.

And so it's primarily water conveyance structure, but also receives groundwater infiltration and runoff to the point where it also can be classified as a 310 water course.

Thank you.

Yeah, I was gonna say it's if a stream bed or stream bank is impacted, a 310 is needed.

On rivers or streams, yeah.

Yeah.

Okay.

I want to ask if Emma, uh Commissioner Bodie, do you have any questions or comments?

Um, yeah, I just I really appreciate that conversation and the expertise support.

It's it's providing a really good question.

Um, and it's clear that um some of you have have a lot of yeah background in this area.

Um I don't have immediate questions, but I'm looking forward to seeing this again at commission and um appreciate getting a sneak peek.

Okay, any other questions from questions or comments?

Um with that, thank you, Nick.

Thank you.

Um, we'll take public comment um on this agenda item in the room first.

Good evening.

My name is Catherine Barry.

I'm with the Gallatin Watershed Council, and I want to start off by thanking Nick and City staff for all of their work on the well-end and water course code update last year, and then also beginning to start implementing the code and continuing to try and support um a lot of the really cool new policies that they've adopted.

Um we submitted a public comment earlier today, so I won't dive into everything we put into there, but uh as Nick said, we had a meeting on June 30th with the city and some of the other stakeholders, and there was consensus around removing the approved jurisdictional determination from the Army Corps and the jurisdictional determination from the conservation district from the wetland and water course delineation report.

And with that, there was also a lot of excitement around an opportunity.

Because the delineation report would no longer be tied to the timeline of these jurisdictional determinations, which, as Nick said, usually take 12 months to 18 months.

The delineation report could be required at the earliest development phase.

So for subdivisions, that's the pre-application, and for just regular development applications, that's the concept plan review.

So I think yeah, there's a lot of great expertise in this room and in the city to want to protect our water resources like our wetlands, water courses, and ditches.

And the best way that we can protect them is avoiding them, and the only way we can avoid them is if we know exactly where we are.

So in the pre-application and concept plan review currently, there applicants are required to map out and identify where wetlands and water courses and ditches and a lot of other kind of water resources are on a site.

But you know, those are using aerial images and different mapping tools, and those are sometimes the best that they can be, or sometimes they're not as updated and current.

The best way to find out what is on a parcel is through the on-site wetland delineation by a wetland professional.

And that comes in later, and that's usually due at the preliminary application, preliminary plat, and also the wetland delay delineation.

Sorry, I feel like I'm saying delineation so much because of the delineation report and all those other things.

But a wetland delineation, when a wetland specialist goes out to a site and delineates a wetland, they are able to tell, okay, here is how big this, what is the acreage of this wetland?

Also, here are the water courses, here are the ditches on this site, and you can use a lot of that information in that one foul swoop for the wetland delineation report for all of the nine or I guess now seven requirements if this goes through.

So one of the things that we really think is the best thing to implement the intent of this code and take advantage of avoidance and protecting our water resources is now that the wetland delineation report is not tied to this timeline for the jurisdictional determinations, move that as early in the process as possible so that then we can design our parks and our roads and our utilities and our buildings around where we know those water resources are instead of having to go back because someone delineated it later in the process and found that actually it's bigger and it's more functional, and there's way cooler birds than we thought there were.

So thank you so much and hope that we can have this discussion now or going forward.

Thank you.

Thank you very much.

Um any public comment online.

Okay.

All right.

And with that, we'll move on to our action item for the evening.

Um, the recommendation to authorize the green power program lead community agreement with Northwestern Energy presented by Natalie.

All right, cleared the room.

Not here.

All right, good evening, members of the board.

Natalie Meyer, sustainability program manager, and um thank you for the second opportunity to um present on the lead community agreement for the green power program.

Uh, tonight we're going to um ask the board to make a recommendation to the city commission.

I'm going to review a lot of the same slides, but try to address some of your questions from the last work session in a little more detail as we move through the slides.

Um, in your agenda packet, you received um the actual programmatic documents, and um I would invite the board to ask any specific questions as we near the end of this presentation.

First off, really just want to reiterate the partnership with Missoula County and the city of Missoula.

That partnership has extended over many years now, and it is a solid partnership.

We are very grateful to the city staff and leaders over in Missoula, past and present, for their work on this effort.

In addition, I wanted to acknowledge that we do have two consultants on this project.

The first started at the onset of the project, it's energy strategies based in Salt Lake City.

They work specifically on helping commercial customers and other communities develop green tariffs and other procurement methods of acquiring green power.

They've been essential throughout the process and a good resource for us, especially as we move forward, hopefully to the public service commission.

In addition, about two years ago, we engaged with a Montana attorney UTA law firm to assist us in finalizing the documents and also representing us at the Public Service Commission.

And of course, Northwestern Energy is a key partner here.

So again, just to recap and for the benefit of everyone out there in the public, today's agenda, we're going to talk about why establish a green power program, the guiding principles behind our green power program, the timeline and process, and we'll discuss specifically the impact of approving the lead community agreement, as well as potential off-ramps moving forward, and then future city commission steps.

Just to reiterate, the green power program is considered to be one of our key strategies to reaching our 100% clean electricity goal for the city of Bozeman.

Within the context of Montana, we have limited opportunities to acquire green power, clean power.

Self-supply on-site generation is limited by that net energy metering cap of 50 kilowatts.

There's no enabling legislation for community solar yet.

And just in general, there's limited options in Montana.

So this program is a new opportunity that did not exist before.

It's an option specifically for customers of regulated utilities to buy power from newly developed renewable energy sources through a special rate or tariff on their utility bills.

Tariff is not a tax, it's a it's a rate.

Across the country, the concept of a green tariff is not new.

There's multiple programs throughout the country.

They have other opportunities through community choice aggregation.

Some of you may be familiar with that, but generally there's an absence of an opportunity in this specific northern section of Montana and North Dakota.

And we have to give credit to the Clean Energy Buyers Association for putting together this map and summary of green power programs across the country.

Also want to talk more broadly about the impact of voluntary clean energy deals.

I don't think this gets much attention.

One of the graphics that the Clean Energy Buyers Association put together recently is this deal tracker.

And so according to SIBA, the voluntary commercial institutional buyers have added 143.8 gigawatts of clean energy to the US grid since 2014.

That's through power purchase agreements, green tariffs, tax equity investments, and direct project ownership, and they track projects that are over 20 megawatts, so not really smaller scale renewables.

And for perspective, the American Clean Power Association estimates we have 370 gigawatts of installed clean energy in the US.

So that means that voluntary clean energy deals represent up to 40% of total installed clean energy capacity.

And that's an approximation.

And about 10% of those deals are specifically green tariffs.

So there's a lot of interest historically in voluntary clean energy buyer programs, and that demand is not diminishing despite what's happening at the federal level.

So the guiding principles of this program, the objective is to develop a new utility-scale renewable renewable energy project in Montana within Northwestern Service Territory.

The idea is to make program rates and contract terms and eligibility requirements as accessible and attractive to as many customers as possible, and we cannot impact non-participating customers.

And honestly, this is generally a feature of a lot of green power programs or green tariffs.

And I should say that it could be potentially another type of renewable energy, but we've just envisioned that these are probably the most economic opportunities available today, potentially paired with storage located in Montana.

The program will be capped at 50 megawatts for the initial phase of the program with an agreement to potentially have future programs or iterations of the program.

And the resource will be owned and operated by Northwestern Energy.

We talked a little bit about the scale of renewable energy resources, and I realize that this group would probably appreciate a little bit more of a breakdown of how we're assuming when we talk about this.

So 50 megawatts, just as a starting point, that's a thousand times greater than the 50 kilowatt net energy metering cap.

If we were talking about Bozeman and a wind project, hypothetically, our community-wide energy use is about 326,000 megawatt hours.

I believe that is data from 2024, our last inventory.

If we were to assume that we were trying to offer a 50% clean energy offset, divide that in half, and again, that number of the gap we're trying to fill is going to fluctuate from year to year, but it's it's going to be in that range, plus or minus.

That would require approximately a 39 megawatt wind project, and that's assuming a 48% wind capacity factor, which admittedly is high if you look at Northwestern's current IRP, but Montana's wind capacity factors are generally higher than the US average.

If we were to assume or target 35% of Bozeman's community commercial load to participate, we would need about a 7.7 megawatt subscription rate participating in that wind project, and that would move us 10% closer to our clean energy goal.

So again, could be wind, solar paired with battery storage.

Accessible and attractive.

All local governments, not just Bozeman and Missoula, can participate, as well as commercial and industrial customers throughout Northwestern Energy's service territory electric supply customers for the depreciable life of the project, which was generally assumed to be about 25 years.

Residents and participating jurisdictions will have the ability to opt in for short-term subscriptions, and the idea here is just to make it more available to residential customers that are not going to be able to participate in a long-term agreement.

And of course, importantly, as we go through this approval process, participation is completely voluntary.

Interconnection costs at the site, not upstream or downstream upgrades.

And so that is include all included in a revenue requirement, which would be calculated after the RFP process.

This is offset by a floating credit.

And that floating credit is based on the market value of the electricity produced currently within the Western EIM locational marginal price.

So each facility the facility will have specific pricing.

In addition to that, there will be a capacity credit for the resource.

I mentioned before our early modeling indicated a modest premium with the potential for a bill credit.

So participants could experience an upside to this program, unlike other, like just purchasing recs, for example.

However, with the expiration of the clean energy tax credits, it could have significant impacts on the program economics.

I'm not going to forecast today what that could look like in a few years when we're actually to the RFP process.

But just a flag that the circumstances have changed over the process of developing this program, and the renewable energy industry as a whole is really trying to adjust and adapt and catch up with changing market conditions.

So we really just can't predict pricing at this point.

Like I mentioned, the cost of the project will be incorporated into the into the subscription rate, and all program costs have to be fully recouped through program subscribers.

And that's the principle of no cost shifting.

Some other provisions to flag the lead community agreement identifies the process for PSC approval, commercial and industrial recruitment, and issuance of the RFP.

It includes an opportunity to participate through the depreciable life of the project with the option to extend.

So in other words, once the project is fully paid for, participants and Northwestern continues to operate the facility, participants should be able to continue to participate once that resource is paid for.

They would still be responsible for operation and maintenance costs.

That doesn't preclude Northwestern from participating in marketing if they wish.

Some of these conversations started back in 2019 with the provisional goal of 100% clean electricity when we were developing our climate plan.

Then in 2019, the public service commission directed Northwestern Energy to explore a green tariff.

The organization Walmart was involved with that request.

And then in June of 2020, Missoula assigned an MOU with Northwestern Energy that included a reference to developing a green tariff.

And in December of 2020, Bozeman adopted our 100% clean electricity goal under the climate plan.

Then in February of 2021, we entered into the interlocal agreement with Missoula City, County, and also Helena at the time to formalize the agreement and collaboration around developing this green power program.

In January of 2024, this board approved the green Power Program term sheet, and it was also adopted by the city commission, which was a non-binding agreement that really outlined some of these foundational principles.

So the benchmark here is that we have finalized those agreements with Northwestern, really worked through some of the more challenging details, and this is the first time the documents have been publicly available.

And so you're the first to see the documents.

So what is the LEED community agreement?

Again, it outlines those roles and responsibilities for the lead communities in Northwestern to bring the Green Power Program to the Public Service Commission, including RFP design and process specifications.

Each community is going to sign its own lead community agreement with Northwestern.

And it provides that the lead communities and Northwestern will jointly file and support the Green Power Program, and it identifies the rate structure.

So looking on a forward-looking basis just to anticipate what the timeline could look like.

And this we're never comfortable with the uncertain, but there are some real uncertainties, especially when it comes to filing with the Montana Public Service Commission, which would be the next step after adoption of the LEED community agreement.

That process we PSC does not have a statutory requirement on a filing of this nature, but once they do take it up, they would likely provide some sort of timeline for us to on the process.

And that would be used to inform the size of the project to design the RFP.

Once the RFP is issued and proposals are received back, Northwestern would, in collaboration with the communities, identify the top performing bids, provide a revenue requirement, and then the communities would, in other words, pricing for the pro to participate, and then the communities would go back to everyone who submitted notices of interest to say this is the final pricing.

Are you interested in moving forward?

And if so, you would submit a binding subscription agreement.

So that's the long-term commitment is the subscription agreement.

And then once the project is really take is substantially underway, there would be a compliance filing with the public service commission that would include the actual pricing and final pricing, and this would be probably a more simple process relative to the initial filing.

So just to reiterate, the Lee Community Agreement is the first step moving forward through an implementation process.

The subsequent step is the tariff with the Public Service Commission, the notice of interest, the RFP subscription agreements, and then a compliance filing with the Public Service Commission.

And to share that information in yet another way, this table attempts to outline the obligations to the city and the level of financial commitment for each of these documents.

The lead community agreement.

Again, it's a commitment to support the filing at the PSC.

It's a commitment to pay for the RFP if we don't move forward, if we issue the RFP and don't move forward with the project, and that would be shared among the participating lead communities.

However, if we do move forward with a project, that RFP cost would be spread out among all participating subscribers.

Other costs relate to legal representation, potentially a technical expert witness.

And then when it comes to the tariff, this is not a real commitment to the city other than legal representation at the PSC.

When we get to the notice of interest stage, we do see some costs associated with subscriber engagement.

And then finally, the subscription agreement is again where we make an agreement to purchase power through through this optional tariff.

So our recommended motion tonight, which is in the staff report, is paraphrased there.

So take a moment to review that language of what we are asking of you tonight.

But first, want to just offer an opportunity for questions now that you've had an opportunity to digest the documents, and admittedly it's it's a heavy read.

But I I'm certain that you'll probably have some questions.

Thank you, Natalie.

Very helpful to get that second presentation a month after the first, which is really nice.

Okay, we have a couple of people on the board very knowledgeable about this topic.

So if anybody wants to kick off, I'll just kind of open the floor.

Thanks, Natalie, for the presentation and for keeping with this for as long as you have.

I mean, I see as well, and I've had conversations with you in that capacity.

Um, I had a couple extra questions that came to mind.

I guess the first, it sounds like any RFP would be a ways down the road, and maybe a lot of the details of how that would look aren't determined yet.

But do you have an idea of what that RFP would be like targeting?

Like how you the selection would work.

Is it looking for a lowest cost, like energy, lowest cost capacity, any preference wind solar storage, or what is the selection criteria gonna be for that?

Um it is not entirely determined at this point, other than um we have an opportunity to participate in developing the scoring matrix.

I would assume that the price per megawatt hour is going to be high on the list of priorities for the communities.

Um that's not at the exclusion of of other um attributes and um certainly um, yes, we we will be thinking about how to score environmental impact um related to the facility.

Um as you observed, there is a capacity credit.

So when I say price per megawatt hour, that would include um a capacity credit.

So if there is storage that comes with a project, it would receive a better capacity credit, so it would be kind of inherently considered in the pricing.

Great.

Yeah, that's helpful.

I was just thinking, I mean, a solar project might have really low cost of energy when it's producing, but how does that compare to the cost or the availability of wind in Montana?

Sounds like those will be balanced and figured out when that comes.

Right, right.

And another side of the evaluation, I think for the communities will be examining relevant LMP market pricing to determine which project is perhaps best on the cost side and the credit side.

Definitely.

Thanks.

The reserve fund that is part of the total cost of the project.

And it says that at the end of the project, end of the program, if there's any money left in this reserve fund, this kind of insurance, that would be credited back to subscribers.

And I am curious if how that would work with any residential subscribers that are kind of under a city and not going to be as long-term committed.

If you have thoughts on that.

Right.

No, that's a great question.

And just to bring everyone up to speed on the purpose of the reserve fund.

The issue being that if Northwestern experienced a catastrophic loss or a partial loss or damage to the facility, they of course have insurance, but there is something similar to a deductible, which is quite high on and could potentially impact subscribers if just to pay that um deductible.

And that is not the precise word, but just trying to use language that makes sense to most people.

And so that reserve fund was designed to kind of save up some funding to help pay down that deductible to access the insurance.

And I think that's a good question.

But on the residential end, it's not going to be a lot of money.

I don't want to misspeak, but could I follow up on that one?

No worries.

And I don't think it's a huge it seems like that's not going to be the majority of the cost of the program and not the end of the world if those aren't recouped mainly, just was curious.

And I I think if you're asking the question, I'm certain that the members of the public service commission will also be interested.

So I'll I'll make sure to have that um answer ready to go.

Yeah.

Yeah, and I think I think it wouldn't be the only scenario where a refund wouldn't be perfectly matched with like who paid for it, because that if in rate proceedings, if there's a refund issued, it's not usually perfectly matched if you're not paying the same utility account that you were when those payments were made.

So it's just part of rate making, it seems like.

Correct.

Yeah.

Those are my main questions right now, but appreciate um all the details you've provided for this, and yeah, excited to see this move in moving along.

Okay.

Thank you.

Yeah, I've got a couple more questions, and I'm I hope they're not confusing in how I learned them.

Um it looks like the maximum nameplate is 50 megawatts.

How does the energy storage fit into that equation?

Because I mean, 50 megawatts nameplate is going to be different energy based on the capacity factor, right, or wind versus solar, whatever.

Is the is this would the storage just meant be meant to collect like capacity benefits, or would it be meant to be part of the nameplate capacity?

I hear two questions there.

Yeah, okay.

Um let's start with the nameplate capacity.

Um this has been a you know a point of discussion, and um the the nameplate capacity does reflect um the cumulative nameplate capacity of both the generation and the storage.

So would this the storage would the intent?

I'm just trying to think of you know, from someone bidding into the RFP what the advantage of of storage would be.

Is the storage meant to store energy produced from the renewable energy project?

I assume it's it's not meant to I mean, or could someone propose 50 megawatt storage project that's taking storing energy from another generation source?

Right, and I I wouldn't necessarily anticipate a storage only project.

Um that wouldn't quite align with the goals of the program.

Um certainly it could be a hybrid project, but it does raise an interesting question of what is that storage um offering to the system?

Is it actually providing capacity to the utility, or is it actually being used to um optimize our energy credit on the market?

That would need to be determined, and as referenced, Northwestern would own and operate this facility, so we would need um their full participation and buy-in and um how that that storage would be used.

Um most likely they would want to use it to the benefit of the system, and so therefore we would receive a capacity credit based on a hybrid project, but it it hasn't been fully developed.

Yeah, but that would be my assumption.

Okay, um and then will the RFP is it meant to be like you know, every project bid into it can be 50 megawatts max, or could uh a project presumably bid in a larger 200 megawatt project that is pursuing like a commercial PPA for 150 megawatts, just given that the larger the project, the you know, typically the lower the the cost per megawatt hour.

Um so it my understanding is if you had a 200 megawatt project that was being developed, um, and has a different offtake agreement.

The max that could bid into this project is 50 megawatts.

We we couldn't say it would it would have to be kind of bid in as a uh carve carve out from that project.

Um it couldn't be entertained as this is a 200 megawatt project, and but there's nothing that would limit, you know, a larger project for carving out part of that project to go towards this agreement?

I don't believe that there would be anything that specifically precludes it.

Um yeah, that's definitely something we've talked about and um would be interested in exploring further.

Yeah, and I don't know exactly what the structure of something like that would look like.

Um I guess just one more question.

I mean, this this seems like this all is looking really great to me, but have there been any major red flags raised by any sort of like ENGOs or or stakeholders that you know, you know, questions or issues that we haven't talked about yet, or that I haven't heard about given my newness.

Um I think um we have not received a great deal of comment on the program, just general um concerns that I I kind of shared in the last presentation around the CAP and I I think maybe some topics that we have not fully explored or specifically discussed and and presently is maybe just broader questions around um the the energy landscape in Montana and the potential impact of the merger and the potential impact of data centers.

These are um questions that I think all of us have and we want to um protect ourselves from from those impacts, which is why we feel it's really important to have these off-ramp opportunities, um, because I don't think anyone in this room truly knows um what exactly what the future holds for Montana.

Now that makes sense.

Thank you.

Thank you.

And I did watch the recording from last meeting and then this one, and I'm this is not my area of expertise.

So I do have a couple of questions.

I don't really know if they're directly related to our recommendation tonight, but I'll ask them anyway, just in case.

So I just wanted to clarify we're talking about a large scale renewable energy utility, like so would where would this be built?

Is it going to be built on like you said Northwest Energy is going to own the facility, which could be solar and or wind?

Is it gonna be on Northwest Energy owned land, agreements with private landowners, county land?

I'm just curious because sometimes where the best projects where they're suited for, I don't know where are we going to be limited in where?

That's a great question, and I'm appreciate the chance to kind of clarify that.

Um when we talk about an RFP process, we're um we're presuming that there will be developers that will bid into the RFP process, so it would be what's considered to be a build transfer, um, and so Northwestern um and as was discussed during the last meeting, Northwestern does reserve the um opportunity to potentially bid into the project, though we have no indication that that's um what will happen, um, but it is a possibility.

So we tried to build in some firewall safeguards there.

Um but we we don't know where it will be located.

It will be based on um, you know, driven by the developer and where they propose to locate a project.

It could be um private land.

I don't necessarily think it would be northwestern energy land, um, most likely there would be some sort of lease agreement with with a landholder.

Okay.

Thank you.

That helps.

And so part of the RFP process will be determining, you know, you're gonna build a bunch of wind power on an area that doesn't have any wind.

No thanks.

Like that, okay, right.

Right.

Um, and are there gonna be any modifications to the grid needed that like Northwest Energy would control?

And or is that part of the fee?

Like, is that part of what we're paying for through the tariff?

Um, a good good question.

So identifying the grid interconnection costs would be part of the RFP process.

Um the the language in the program talks about um costs to enter to connect to the grid, not necessarily system-wide upgrades.

Um there can be arguments for a project triggering the need, uh, one project specifically triggering the need for for some sort of upgrade that I think would have to be negotiated through the process, but generally participants should not be paying for system-wide upgrades.

And I suspect that there's people in this room that could help talk through what that process would look like.

But that is our expectation is that the interconnection costs will be identified through the RFP process.

And certainly those that have further along in the process and have identified those costs will have an advantage.

Okay.

So just a couple questions on the fees.

How much wiggle room do we have to negotiate how these costs are being passed on to the subscribers?

So, for instance, um, let's say one commercial building is much more energy efficient than their neighbor is.

Are they all paying a flat fee to participate in this project, or can we negotiate a percentage?

Are those pre-set?

Like, do we have a you know a sense to still encourage energy efficiency, in other words, um through the way we set up the fee structure, or is that kind of predetermined and we just negotiate the rate?

That's that's a that's helpful to um hear that question.

Really, the price will be the same for all subscribers, it's just based on the cost of developing that project and the share of electricity that a subscriber requests.

Um so if they're more energy efficient, then you know they will require less energy.

So that's that's their incentive.

Um, but but there's no inherent um distinction between the type of subscriber necessarily other than it has to be in a certain rate class, and um and we're not looking for we're not anticipating extremely large loads to participate in this program.

It's not really the correct scale.

Okay, cool.

Yeah, I know there's some research showing that the more um sometimes you people see renewable energy as free or not have any impact, or you could say the same for some research on water, and so they use they end up using more of it as a result.

So I just try to think through that, yeah.

Um and then the subscription fee will stand beyond the I mean, I guess my question is there's a project to be built, and that will be built, and then that will have a long payback time, I suppose.

So it's so the subscription fee will just stay the same even long after the project is built, and that's built into the tariff structure.

Um that's an important distinction too.

So the subscription price um will be relatively fixed, but it's going to be um updated on an annual basis based on the actual costs of um incurred by the utility for OM repairs.

So there will be annual compliance filings at the public service commission.

So we are in a sense um committing ourselves over the long run to monitor that process.

Um and the um subscription length, it it is long, but that was also our preference in order to make the the program more affordable.

It's like a 30-year mortgage versus a 15-year mortgage.

Yeah.

Okay, thanks for uh putting up with my questions.

Thanks, Natalie, for the presentation and sharing all this work you've been doing.

Um maybe I'll start with a question that that made me think of in terms of this subscription fee.

So, how are you gonna build in the long-term payoff of renewable energy?

Knowing that you know, the upfront costs and installing are going to be higher, but then over the life of a solar project, you expect that you'll end up you know paying off those costs, and then electricity is you know cheaper once you've paid off the initial costs.

So will that be part of the rate structure?

And how will you incentivize people to join early if like if are the fees going to be higher early to account for that?

And then will they be reduced in 25 years?

I would expect the fees just to be kind of maintenance versus the development of the project.

Um that's that's a great question.

And we have to we have to change the mindset around is renewable energy more affordable.

That's not really the question in this case.

What we're doing is trying to drive new renewable energy development, and there's a price to construct that process that that facility.

And what we're doing through this program is aggregating as customers to pay for a new renewable energy project and pay for it over an extended period of time.

There will be that cost will be offset by an energy credit that is variable that's going to have upsides and not necessarily really a downside.

Um we're not at risk of negative pricing, which is a possibility in energy markets.

But we have an agreement to curtail the facility during periods of negative pricing if it falls below what was the production tax credit.

So it's that there is we want to reinforce the message that generally renewable energy is more affordable, but this is a unique vehicle where we're really trying to drive that transition.

This facility is above and beyond what Northwestern has identified as their power supply needs.

So we are, as customers, asking to add renewable energy, help us reach our goals on an accelerated timetable.

And it's not necessarily about in the long run, is this cheaper?

That's kind of a separate question.

Okay.

Yeah, that makes sense.

Does that help?

Yeah, yeah.

No, I was thinking about it in the wrong way.

Um so what was my other question?

Um, I'm forgetting my other question.

Um, but yes, that does help clarify.

Um, blanking on my other question, so maybe we can come back to you.

Come back when I remember.

Thank you.

Well, actually, yeah, one other question is how is the 50 megawatt limit set?

And do you feel like that's adequate for what the proposed or like your you think what the demand will be?

Um, you know, it's a it's a mix.

I it certainly could be higher.

Um, but at the same time, having that cap does um sort of create some guardrails around risk for participating communities, and there may be some, like Kendra mentioned.

Okay, larger projects benefit from an economy of scale, but maybe a smaller project would have more simplified permitting and maybe an up better opportunity for interconnection.

So that I think there's trade-offs there, and at this point, um, and I can't speak for all of the communities, but I am quite comfortable with that 50 megawatt cap.

Cool.

Thank you.

I have no questions.

Thank you.

Thanks.

I don't either.

I think this has been a thorough discussion, and a lot of really good points have been brought up.

Um, and I think several were at our last meeting, too.

So yeah, I don't have any, I'm not a subject matter expert on this.

So thanks to everybody for your knowledge and thoughts.

Well, and I just appreciate the breadth of expertise in this group.

It's it's really kind of fun to have subject matter experts across the spectrum.

So I have a question if I can chime in from the ether from above.

Um yeah, thanks again for the presentation.

And Natalie, I know you and I have had a chance to talk about this as well.

And so most of my kind of miscellaneous questions are answered, but something just occurred to me during this conversation.

Um I know that when we started this whole process, we were thinking that there would be a green energy tax credit, and that it's no longer the case currently, and so that's kind of changing some of the math on what the rates might be.

I know we won't know exactly how things look until we get the RFP and have a little bit like clearer sense of things.

But um I guess I'm just recognizing that our current federal landscape is going to be kind of in place for the next two years, and then after that, um we're not sure how federal policy might change around green energy.

Is there any um any ability to sort of like I'm trying to figure out how I want to phrase this?

Let's let's say we run through the entire process and we get to a point where we've got the RFP, we've got things approved by the PSC, and it just doesn't pencil out.

Like it doesn't make sense financially to take this move.

Um if everything else is in place, is there a way for us to kind of um press pause on the terms and the things that we've approved and wait for better federal legislation or a better federal environment for a certain amount of time and um see if if things shift and that it suddenly does make sense like three years from now?

Um yes, thank you for that question, Commissioner Bodie.

I think it's a really good question and it's on the forefront of my mind.

Um first off, I'd say I hope we don't entirely have to wait till we go through the RFP process to find out that pricing is not favorable.

Um I think we anticipate that we'll have an opportunity to do some um price modeling uh before we get to that that point um just as to help keep us all in informed.

Um but through the process, there are some um timetables that we negotiated um early in the process with the intent of trying to keep the process moving.

So for example, after PSC approval, we'll have 180 days to collect notices of interest.

Um, then you know, after finalizing the RFP, um I think it's 30 days to issue the RFP.

So there are um opportunities in there where we could potentially delay, but I would also um hope that in good faith our utility partners would um allow us to press pause if that um seemed like it was in the best interest of all participants, and I I think that could be achieved by mutual agreement, but we we have not thoroughly discussed it with the utility at this point.

Okay, yeah, what would there be a way to kind of add some sort of writer, I don't know if that's the right terminology, but something in here to say like if um costs are seen to be unfavorable and the current we can keep all the same terms of this agreement in play for a two-year period or something.

Um just some some sort of thing that would make it so we don't have to go back to the drawing board if we get all the way to that cost analysis place and find that it doesn't make sense now.

Um given just how quickly things changed with a different presidency.

Um I think it is a very real reality that um if there were a different presidential landscape, like the landscape could shift pretty quickly again.

Agreed.

And um at the same time, I don't want to say that we absolutely need to have the tax credit in order for this to make sense.

So um I think a number of dynamics could change that would make things more favorable.

And there's members of this board who could probably speak to that that point.

That revisions to the agreement will result in a delay even if it's mutually agreed upon and um we have a window to move forward and a commitment to file with the the public service commission and we don't necessarily want to um pass on that opportunity without being pretty intentional.

Thank you.

Any comment last comments or questions?

Otherwise oh god I guess to Commissioner Bodhi's point um I think it's obviously a really important topic.

But for my experience in the renewable energy industry um pricing is complicated in changing free camp frequently with or without the tax credits so the tax credits of course are really important.

The cost of equipment it has also been um dropping very significantly year over year especially solar equipment.

So with or without tax credits there's likely going to be some level of uncertainty as to how these projects are going to price out okay it thank you.

If there's no further comment from the board um seeing that there's nobody in the room um I would ask for public comment um is there any public comment online no public comment online okay um any further discussion or are we ready to are we ready to make the recon recommended motion if anyone is ready they could make the recommended motion.

Having reviewed and considered staff report materials public comment and all information presented I move to recommend that the city commission authorize the city manager to sign the Green Power Program lead community agreement with Northwestern Energy.

Thank you Kesley can you facilitate a vote please make Kendra aye Brooke aye Aaron aye Kristen I Jesse I great okay passed okay and with that I believe our meeting is adjourned is that there's nothing else that I'm missing I I believe so um thank you all very much this feels like a big landmark to me and all the participants who've been involved so yeah thank you so much on for all the work and persistence thank you Commissioner Boney for joining online I hope you feel better thanks for by everybody.