Good morning, everyone, and welcome to Portland General Electric Company's Third Quarter 2025 Earnings Results Conference Call. Today is Friday, October 31, 2025. This call is being recorded. [Operator Instructions] For opening remarks, I will turn the conference over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead, sir.

Thank you, Michelle. Good morning, everyone, and thank you for joining us today. Before we begin, I would like to remind you that we have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The slides are available on our website at investors.portlandgeneral.com. Referring to Slide 2. Some of our remarks this morning will constitute forward-looking statements. We caution you that such statements involve inherent risks and uncertainties, and actual results may differ materially from our expectations. For a description of some of the factors that could cause actual results to differ materially, please refer to our earnings press release and our most recent periodic reports on Forms 10-K and 10-Q, which are available on our website. Turning to Slide 3, leading our discussion today are Maria Pope, President and CEO; and Joe Trpik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it's my pleasure to turn the call over to Maria.

Good morning, and thank you all for joining us today. We delivered another strong quarter in Q3, and we maintain our laser focus on execution, driving value and advancing our five strategic priorities. Starting on Slide 4. First, investing in customer-driven clean energy goals. Second, working to keep customer prices as low as possible; third, supporting data center and high-tech growth in the region's economic development, fourth, reducing risk through operational execution, system hardening and wildfire policies; and fifth, promoting an investable energy future. Our industry and Portland General are seeing tremendous growth. Since 2019, high-tech manufacturing and infrastructure investments have resulted in over 8% industrial growth, which is expected to only increase, driving our overall load growth of 3% through the end of the decade. Portland General's customers and our region remain focused on clean energy. We are also focused on affordability as we work to keep our cost structure flat and customer prices as low as possible, in turn, providing stable competitive returns to shareholders. I will cover the progress we've made in each of these five priorities before highlighting this quarter's results. Clean Energy. Given the dynamic policy and market environment for clean energy, our state and company are accelerating to meet the moment. Earlier this month, Oregon Governor, Tina Kotek, issued an executive order aimed at accelerating renewable energy development before federal tax credits expire. An important step that supports continued progress for the state's goals. This dovetails with the multipronged procurement strategy PGE deployed in July to maximize the approximate 30% of federal tax credits that directly lowers cost for customers. As part of the 2023 RFP, we undertook a price refresh to capture the impacts of The One Big Beautiful Bill and trade tariffs, which culminate in an updated shortlist filed with the commission…

Thank you, Maria, and good morning, everyone. Q3 was another solid quarter and reflects the strength of our strategy. We are serving significant demand growth and executing our cost management program with discipline and focus. Turning to Slide 6. Total load increased 5.5% overall and 7.3% weather adjusted compared to Q3 2024. Residential load increased 2.2% quarter-over-quarter but increased 6.7% weather-adjusted. Residential customer count increased by 1.2%. Commercial load increased 1.3% overall or 1.9% weather adjusted. Industrial load again saw significant growth with Q3 demand increasing 13% or 13.2% weather-adjusted led again by our diverse group of data center and high-tech customers. Given our robust load growth, we've observed and our forecast for the Q4 demand, we are updating our weather-adjusted 2025 load growth guidance to 3.5% to 4.5%. Now I'll cover our quarter-over-quarter earnings drivers. We experienced a $0.44 increase in total revenues driven by a $0.16 increase from our 5.5% demand growth and a $0.28 increase due to our higher average price of deliveries from improved recovery. A decrease from power cost of $0.24 driven by a $0.38 from favorable power cost in 2024 that reversed for this comparison and a $0.14 benefit from the cost to serve load in Q3 2025 driven by stable market pricing and power cost recovery timing. A $0.06 EPS increase from lower operation and maintenance expenses driven by our continued benefits from our cost management work as our teams drive efficiencies and realize savings across our business. A $0.23 decrease from impacts in support of our ongoing rate base investments and execution of our financing plan made up of $0.14 of depreciation and amortization, $0.05 of dilution and $0.04 of interest expense. A $0.07 increase from other items, including an $0.11 increase from our prior year deferral reserve that did not recur…

[Operator Instructions] The first question will come from Julien Dumoulin-Smith with Jefferies.

Look, let me just start off on this energy deliveries trend here. I mean 3.5% to 4.5%, that's a solid trend. Full year, obviously, we've seen some gyrations over the years. But given what you're describing here, data center -- data center-centric driven, how does that impact or revise any kind of longer-term thoughts? What are you seeing on this front? Clearly, adjacent states also seeing kind of positive revisions as well?

Thank you. And Julien, yes, we've been very fortunate to have both a robust and diverse semiconductor manufacturing in this region and growing a number of data centers. Most of the data center forecasts that we have are folks that already have built out their facilities as well as those who are turning dirt and have existing sites. So we have a -- our pipeline is really solid and reaffirms that we're confident in our 3% long-term growth.

Got it. Okay. So no gyrations yet. Understood. Just maybe if I can come back to the holdco outcome. And how do you see that progressing here? I mean, any updated thoughts on this front in as much as that could impact, obviously, Joe, the financing strategy as you think about heading into '26 and being a month out. But separately, just any feedback in that process, et cetera. Obviously, it's a big deal as you think about '26 priorities.

Sure. Let me take the Holdco timing and what we're seeing from parties and then Joe can talk a little bit more about financing. We're getting lots of questions on the transmission company. In particular, discussions around what's jurisdictional to the OPUC versus what's jurisdictional to FERC. I think it will take us a while to work through all of these questions. But we are getting very few questions with regards to the holding company. This may give us a window of opportunity to separate the filings, probably maybe extending the transmission company filing a little bit and pulling in the holding company filing. I would note that our filing is very similar to others in the region. And Northwest Natural, a little while ago was able to conclude their holding company filing earlier than the statutory allotted time. Joe, do you want to talk a little bit about financing because this provides us with some opportunities.

Yes, Julien. As it relates to the holdco, we anticipate understanding the filings proceeding that we will operate the holdco and use it as financing very consistent how virtually all the other utilities in our sector have been operated that holdco. Under the right scenario, we agree we will have the ability to displace certain equity needs. Currently -- we have strong financing metrics. I mentioned that we're above CFO. Our metric on CFO to debt is above 20%. And we'll be thoughtful as we work towards the RFP outcome and the holdco project or process matures, as Maria mentioned, to really align that to our financing plans as we have more clarity.

Just quickly, lastly, on the refresh and the '25 RFP, obviously, ongoing in parallel here. What's the scale of scope? I mean the refresh seems to be fairly similar in opportunity set for you guys, but you've got these things in parallel. I mean, could we see an acceleration? Or how do you think about the timing, given the way that this is all kind of been backed up, if you will. As you think about forward-looking CapEx ultimately translating?

So first of all, I just want to remind us of why we're doing this. With the One Big Beautiful Bill, we continue to have investment tax credits and production tax credits that have been very important to reducing the overall cost of clean energy and battery storage on our system. And as I noted, between our projects as well as third-party contracts, it's about $2 billion of roughly what we can estimate of benefit that we've brought back to this region. So we're refreshing the 2023 RFP, as you noticed, there's a lot of tariff issues. And then also, we have a PPA focused RFP as well as the 2025 RFP. Joe, anything more you want to talk about in terms of timing of when we can see resolution?

Julien, I think really what you get to -- you sort of talk to size here of the two RFPs. Obviously, this RFP, the '23 we mentioned has just over 1 gigawatt of power between the solar and the batteries. We used as a foundation for this RFP and the '25 RFP that we're accelerating the IRP action plan that was filed that last updated at midpoint would say, overall, we need 4,000 megawatts before the end of the decade, understanding you have to back out this '23 RFP result and some PPAs, I mean you would expect that as you work to the next RFP, both in size and the timing, hopefully to accelerate, you could see something of the need of 2,000 megawatts, something maybe even a plus there. We'll have to see there's a lot of factors to that again, what other PPAs get entered into, how demand moves, how the clean energy policy plans evolve. But it would expect to be a more meaningful and robust RFP than the one that we have currently -- that we're working to contract.

And the next question will come from Sophie Karp with KBCM.

A couple of things. Is there a scenario where you get your holdco but not the Transco? Given that you're saying that questions seem to be concentrated on the Transco side?

As it relates to -- and I think it's more a matter of timing, is there a scenario where the holdco and the Transco approval process gets separated and the holdco occurs more promptly? I think the answer is, yes. In the right circumstances, we could see that occur. We would anticipate over time that ultimately both are approved but we could see a longer path on the Transco. Just as we relate to our finance, each is a very different financing functionality for us. The holdco, we think, drives more valuable for the customers and shareholders more currently and the Transco does have a little more time, and therefore, it's okay to have a little more time to evolve.

Got it. Super helpful. And then just a more strategic question on the transmission, right, and it kind of, I guess, dovetails into the Transco conversation. What would it take for you to direct CapEx and your efforts away from generation RFPs and more into transmission? Like is there a case to be made that this is a better approach for growth, right, just given recovery mechanisms or demand, a variety of factors that you may consider?

Currently, I mean, as you can see in our plan, right, we have $1.8 billion in transmission spend, including 2025. I do think -- so we do have a relatively balanced growth to your question if there would be a reason to shift more towards that transmission. If that really facilitated the needs of our customers and the clean energy plan and also drove to affordability, that could be a case where we will drive more to transmission. But right now, we are driving to serve the overall needs of our customer, which has really been a balanced transmission and generation approach.

And so the long term and as well as in the past, what we have found is that it's really important to have a robust competitive environment for generation build. And we need to continue to move forward to drive customer prices as absolutely low as possible. Sounds good?

And the next question will come from Gregg Orrill with UBS.

Congratulations on the year-to-date. On the financing plan, just what are your assumptions within the growth rate guidance as it relates to your commitments around RFPs? And assumptions around tax credit monetization versus equity. How do you think about that?

Sure. So as it relates to the financing plan, and again, this is -- we assume that a 50% -- 50-50 financing structure on the RFPs currently and that is net of tax credit monetization, which has historically been at this 30% credit. This year alone, we've monetized about $150 million of tax credits to offset our financing needs. And then to your comment, our historical -- I apologize for using another 50%, right, our outcome on RFPs has historically been at about 50% of the overall projects.

Okay. Maybe another question as well. Just what are your thoughts around the extension of the reliability contingency event framework and how is that proceeding?

So currently, within the PCAM filing, we are having discussions on the RCE. RCE are reliability contingency event, we feel has been a pretty consistent and effective tool to date. We are -- we continue to focus and dialogue with them. Would we like something like that to proceed to further align the energy cost? Yes. Because it helps support our just overall approach to a more efficient pricing of energy. That's an open dialogue right now. I don't know that I really want to handicapped it. I know that it's more of a broader discussion on how to address energy costs here. I will just say it is a -- it is a nice tool. It works effectively for us now, and we'll continue to work towards as modern and effective in energy recovery mechanism as we can with our regulator.

Gregg, let me add a little bit to that. The events that we saw in January of 2024, we're also impacting other utilities in the region, and we saw similar issues across the entire Pacific Northwest and West Coast in terms of energy markets. So we're pretty similar in terms of the impact of those storms to other utilities. Longer term, we are working towards joining the energy data head market with the California independent system operator. We're expected to go live with that in October of next year. That will very much change our overall energy procurement and I'm not so sure that the PCAM mechanism with the RCE will be the best going forward. We're going to need to align the state's policies to the broader market as we are doing more scheduling of energy and optimization versus energy management and purchases.

And the next question will come from Shar Pourreza with Wells Fargo.

It's actually [ Constantin ] here for Shar. Maybe just a little bit of cleanup just with the kind of quarter up 5% loan growth and the full year step up. Is that significant enough to incorporate financial plans? And kind of what's the threshold for some of this higher load growth to start kind of making more impact within the kind of base financial plan?

So as it relates to the load growth to your question of how does the -- how does it drive more to the plan. It will be as we clarify and get the tariff as it relates to margin, right now, the new data center tariff is with -- on the regulatory side to get drawn out. And so being able to take advantage of that growth at a more balanced margin, we'll do two things. One, it will balance out the cost to our residential and other customers, but then to also to the extent you see this growth will incrementally drive further value. So that for us, we're a bit in a wait and see. We expect that tariff -- we'll get that tariff when we get that tariff. But that will be a nice metric point to be able to capture some value, and I believe that's scheduled for March.

Okay. And that's kind of when you would start incorporating some of that into the forward-looking financial plans?

Well, I think that's the place where you'd start to be able to identify to the extent that you continue to see that growth, you would start pricing that growth a little bit differently and you'd be able to start to determine if there's incremental value there -- because you'll have a clear cost structure.

And then just one follow-up on the '25 RFP process. You kind of noted that there's some lessons learned kind of being incorporated there. Just maybe given the cyclical nature of the RFP process and generation needs, is there kind of any changes in the framework that we should be thinking in terms of long-term assumptions, like volumes, ownerships just in light of the '23 outcomes?

I don't think as it relates to the ownership and anything like that, no. I mean, we continue to work with the commission on a multipronged approach here. I mean I do think like the key message, if you ask me right now, what is it for '25, it is we've accelerated the process, right? The change this time is instead of having a consecutive RFP process, we have a concurrent process that is looking to optimize the credits that are out there, and that's part of this design. We will continually work to balance the procurement, both between ownership and PPAs. But for right now, the main changes to drive as much of the benefit as we can tax credit wise out of these projects. And that could either lead to the acceleration of projects from what is the requested date within the RFP. Other than that, I don't think we'll see any other changes. Other than to continue to just work with all the constituents to continue to align to the market.

And our next question will come from Paul Fremont with Ladenburg.

You gave sort of $150 million of tax credit for '25, and I think you've talked about sort of $2 billion. Can you give us sort of an annual estimate of what tax credits you expect to realize?

So what we're really looking at is anywhere from 30% upward of renewable energy projects battery storage. And so we will continue to focus on maximizing all available ITCs and PTCs and really, we make a determination on which one based on the net present value. Batteries and solar tends to lean a little bit more to our ITCs and wind tends to lead a little bit more towards PTCs. But this is an important way that we're bringing federal dollars back to reducing customer prices for renewable energy and creating investment opportunities with the state of Oregon and regionally.

And Paul, just to add the -- there is a bit of a cyclicality as we have these cash flows. So as we have these projects, the ITCs will come through for the RFP, obviously, what we are talking about here, and you're seeing the cash flows this year you're seeing are both the remaining ITCs that came from the Constable project last year and then the ITCs from the Seaside project this year. On an annualized basis, the foundation that we come from, is the PTCs as related to our wind projects, call that around $50-ish million a year, and then the cyclicality would be the ITCs that come from RFP projects at least, currently, the way cash flows.

Then with respect to the wildfire action by the legislature last year, I think there was a proposal that would have created a fund of I think it was $800 million. Are you -- number one, I mean, is that amount -- an amount that you would feel is adequate? And is that what you would like to see the legislature do to create sort of a wildfire fund of 800? And what other action would you hope for out of the legislature?

Sure. So we're still actively engaged with legislators and stakeholders across the state and the region. But this isn't just a legislative strategy. It's also a regulatory strategy as well. This next coming year, we have a short session. It's just about 5 weeks. And there are a number of state-wide priorities, meaning that we could see more results out of the legislature in '27 versus '26. On the regulatory side, we continue to work with regulators and staff on solutions. First of all, starting with all of the work we do operationally to reduce wildfire risk. And that's all detailed in our wildfire plan. And obviously, the recovery associated with that as well as standard of care and then also mechanisms for self-insurance and other sorts of things.

Great. And then last question for this year, can you give a sense of -- are you expecting to experience any regulatory lag in terms of earning your authorized ROE? Or what would -- if there is lag, how many basis points would you expect that to be this year?

Paul, using our sort of approach this year with the Seaside battery approach as well as the cost management, we've tried to put some downward pressure to squeeze that lag, and we believe we're down to something around 70 basis points or less that we expect to see here and into the future as we balance a selection of regulatory filings and cost management.

I'm sorry. You said 3 basis points?

I said 70.

70. I'm sorry. Okay.

Yes, that is -- and just as a reminder, that is a compression from what we had experienced historically.

Right. And then you would expect then to achieve on a go-forward basis, sort of a maintenance of that level, that 70 basis points go forward?

Yes. We expect to do that and we expect to continue to apply downward pressure on that as it relates to our cost management work as it continues to mature. And so we expect to see at least somewhat of a little bit more compression there as we execute and get fully into the cost management program in 2026.

So that could be -- in other words, that could be diminished, let's say, to what level?

We haven't disclosed to what that level is. I mean the way we look at it is a balance to where we think to next year using the DSP as our regulatory approach as well as the cost management and others. We sort of think of it as a basket of items to help us continue to drive within our earnings range. But it is a goal of ours to just be as tight as we can.

And the next question will come from George Sanoulis with Mizuho.

So I know the DSP was filed in July, but I'm just wondering if you had any preliminary discussions with parties ahead of that filing? And given the Seaside proceeding resulted in the balanced outcome, do you think we could see that in the DSP proceeding?

As it relates to the DSP consistent with the Seaside filing, we did have an MOU, we do have an MOU in place with them. So the MOU does govern the DSP as well. The -- just as a reminder, the reason we took the approach with the DSP here was really to drive clarity for parties, right? The DSP is a filed and accepted docket from -- that lays out our sort of our action plans for the distribution. And so we felt that you get to the clarity to say we'll have a case that focuses on projects that are agreed to have benefits for the customers. So that -- then using that and then looking to Seaside, right, the Seaside, we felt that the MOU really and having an MOU and spending the time before really allowed us to have a focused dialogue and have a constructive dialogue and outcome when we look to both the testimony and some of the intervenor work, and we would expect that to continue here with the DSP.

Great. And can you talk a little bit about how you plan to utilize GridCARE? And what initial tests you've done or you plan to do and when you expect to see measurable impacts to unlock additional system capacity?

Sure. So first of all, we're really excited about the opportunity that we've seen with our partnership with GridCARE. It comes out of the work that we've done with other start-ups and innovative companies at Silicon Valley and Stanford's school of engineering. The program is essentially takes a lot -- enormous amount of data, AI analytics. It actually takes compute that exceeds most capabilities and for which we actually went to Stanford to do the work. Right now, we have about 80 megawatts unlocked, but that's just in a pretty narrow portion of our system. So we would expect to advance. I would also say it's not just the AI analytics and also the dynamic line ratings, which gives us much more information on temperature and wind speeds that can unlock additional capacity and then having battery storage in different places across the service territory further enhances the work that we're able to do to get the maximum amount of capacity out of existing and new transmission infrastructure.

I show no further questions in the queue at this time. I would now like to turn the call back over to Maria for closing remarks.

Thank you. And thank you all for joining us today. We appreciate your interest in Portland General, and we hope to connect with you soon. In particular, I assume that we will see many of you at EEI shortly in Florida. So thank you very much. Have a great day and a nice weekend.

This does conclude today's conference call. Thank you for participating, and you may now disconnect.