We'll briefly talk about the process that goes into this type of an analysis and then we'll dive into this update, focusing on some of the key factors, assumptions, and then finally results of the key steps.

Just due to timing that we have allocated for the presentation, I might be moving pretty quickly, so if I am talking pretty fast, do let me know.

Now, as a quick background, uh, the last study completed was in 2023.

We did perform a five-year projection, and based on the discussions of that time, two years were adopted from that five-year plan, and then we wanted to revisit our rates uh before any additional rates are implemented just because some of the uncertainty that we were experiencing that time.

So the major drivers of that study were related to high inflation.

We're coming out of the pandemic.

We saw supply chain pressures as well as increased power costs from Bonneville, as well as some major capital projects that we had identified that we needed to construct at the time.

In addition to the overall rate strategy, we developed two new rate schedules, schedule four and schedule five, which are related to new large loads coming onto the system, kind of to safeguard the system, existing customers from the uh the additional pressures from power costs related to these type of customers.

Schedule 4 focused on smaller type of connections, any uh loads above one average megawatt or two megawatt peaks.

Schedule five focused on the bigger connections above uh one uh ten average megawatts, which is in line with bondable definitions of a new large load.

Those come with some substantial costs to the city.

So we definitely wanted to have a safeguard in place, a rate schedule in place within that situation.

Now, oh, if you can go back one second.

Now, some uh significant changes have occurred since that study.

The the major one is Bonneville just finished adopting rates as recently as last month of July.

The combined impact to the city is about 9.1%, which is made up of about 8.8 to the power portion of the cost and uh almost 15% of transmission.

The majority of the charges uh are related to power, about 88% of total expenses are power related, so that's why the average increase is 9.1.

We're also anticipating that two new loads will be joining the system in the next five years, and we'll have a good discussion about that.

I think uh because there is some uncertainty with those loads, but everything is pointing to these connections joining.

And if they do at the schedule that we have anticipated, they would more than double our electricity unit usage in the system.

Now, in terms of the overall rate study, we can quickly summarize it in two analytical steps.

First, we have to define our overall needs through what we call uh revenue requirement analysis.

And once we have established overall dollar target on the multi-year basis, we move on to rate design.

This is the actual development of the fixed and variable rates.

So let's start with the first step revenue requirement.

Now, the very basic level, all it is is a comparison of your rates to your ongoing obligations.

Here we want to make sure that any strategy we develop allows us to uh keep our electric trades self-sufficient.

We're not relying on external sources on other utilities because not every electric customer is a water customer or a sewer customer and so forth.

When developing the analysis, we're really making sure that we're can cover our direct costs, such as operating capital power debt service, but also our indirect costs, such as appropriate financial policies to make sure we're sustainable, not just today, but into the future.

When uh the revenue requirement is established, really break it down into five key elements or key components.

The first one is putting a monetary value to the policies that we have established, then forecasting revenues of current rates, just we never want to assume there's gonna be uh there's gonna be an increase.

Then we forecast costs, breaking them down to the more consistent operating and and and power cost and more kind of a peaky type cost related to capital and and uh debt service.

Now, a big uh significant component of any electric rate study is really the load forecast.

And as I mentioned in the introduction, we're gonna be looking at some alternatives for your consideration.

Uh we'll we're looking at growth uh for our current system in place today, so just national growth that we have experienced, which is fairly uh modest at half a percent, zero to half percent depending on the class of service, but on average, we're anticipating just our current system uh growing at less than half a percent per year.

At 31 average megawatts, not even getting up to 31 and a half in the next five years.

If the new large loads connect as we anticipated the them to connect, they'll add up to 52 average megawatts by the fifth year of the forecast, continuing beyond that.

And the total system will grow from 31 average megawatts all the way up to 84.

So, because of this uh significant impact of load, we're actually going to be discussing two options looking at uh the business as usual without new large loads as well as with the addition of the new large loads.

Now, starting with some of the initial elements with existing revenues, we are forecasting for the the next five years of 26 through fiscal year 2030.

We wanted to take a look and include all the revenue sources at our disposal, including non-rate revenues, which include connection charges, conservation revenues, clean fuel, rental income income, as well as other miscellaneous like interest income sources.

Overall, while these are great revenue sources, they're only make up about 2% depending on the year of our total revenue profile.

So the majority of funds are coming from our monthly utility fees.

Now, if we look into the new large lows, the way we structured our schedules for and schedule five rates during the last study is that we would be passing on the cost of power to them.

So if that does if the uh load does materialize, they can generate about 43 million dollars on their own into the future projection.

So if we look at current levels of revenues before any kind of rate strategy discussion, we're at 27 million dollars.

With that new large loads, we can get up as high as 70 million dollars in the next five years.

On the extensive side, we start started the forecast with your current budgets that you have discussed internally already.

Uh, these include budgets for fiscal year 25, 6, and 7 because we do have to forecast this fund balances and every expense line item.

We did review the expenses in detail with your staff to make sure there's no one-time costs that are being carried forward, and we are including costs related to equipment replacement reserve transfers, but all in all, our average inflation when we put everything together is about 3.5%, which doesn't include pilot because pilot grows uh which pilot stands for payment in lieu of taxes, uh grow grows proportionally based on revenues.

So if we have uh greater revenues coming in from uh new large loads, the pilot transfer will increase proportionally.

So uh overall inflation we're assuming is about three and a half percent average.

The expenses are anticipated to go up about 12.7 uh to 16.3.

That is inclusive of the pilot growth from new large load payments.

On the power front, as I mentioned in the introduction, we are including the latest billing determinants from Bonneville Power.

Now, historically, Bonneville Power Administration sets rates on a two-year cycle.

So they set a rate effective October, that's the beginning of a federal fiscal year, and then those rates are in effect for two years.

So they do two year rate increases.

This year is a little bit unique because this is the end of the wholesale contract for all their wholesale customers.

This is actually a three-year contract period, so they're setting rates for fiscal year 25 or 26, 27, and 28 with the effective months of October 1st, 25, and the last month of September 30th.