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. 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 lower costs 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 earlier this month. The shortlist reflects a rigorous least cost, least risk approach designed to yield reliable, affordable outcomes on timelines responsive to evolving legislative requirements. In parallel, we saw community-based renewable energy and bilateral PPAs for energy and capacity which are yielding additional projects. Finally, we took a critical step forward in the 2025 RFP, which was also launched in July. All bids have been received, and we are now evaluating projects and building toward contract execution in 2026. Every element of our strategy prioritizes reliable delivery of energy to customers while maximizing the window of several clean energy tax credits. To date, we have secured over $1 billion of PTCs and ITCs for our clean energy portfolio, and we estimate as much as another $1 billion from long-term third-party energy contracts. This is just one part of our approach that enables clean energy affordability, allowing our customers to receive the full benefit of high-value clean energy resources at the lowest cost possible. Customer affordability. The customer affordability commitment, our multiyear management program continues to deliver great results. This work touches every corner of our company as we focus on safe, reliable service while keeping customer prices as low as possible. Joe will cover more about our progress in detail shortly. Customer growth. We continue to see significant load growth with total load up over 5% compared to the same quarter last year. Our industrial customers, led again by data centers and semiconductor manufacturers, grew their energy usage by over 13%. As these customers expand their existing facilities and develop new sites, this builds upon over a decade of high-tech manufacturing and infrastructure expansion in the region. We are continuing to plan and execute alongside our customers as they scale and ramp their operations. The passage of Oregon's data center legislation, which will be implemented through regulatory proceedings concluding next March, provides rate-making clarity, improved cost allocation, and importantly, margin expansion from PGE's fastest-growing industrial customers. Building on this supportive policy, we're investing in new transmission and utilizing a combination of system upgrades. These include dynamic line ratings, AI data analytics, and customer-sided solutions to maximize new investments and leverage existing infrastructure. PGE recently completed a project with AI start-up GridCARE that leverages flexibility in data center usage, applying generative AI forecasting to unlock additional system capacity. We also achieved a first-of-its-kind solution alongside distributed storage provider, Calibrant Energy, and digital infrastructure provider, aligns data centers. The agreement will deliver a battery system to the aligned campus, enabling the facility to come online and scale operations years earlier than previously expected. High-tech manufacturing and digital infrastructure are important contributors to the strength of Oregon's economy. I'd like to reiterate that for Portland General Electric, this load growth isn't theoretical. For years, we have been meeting this significant and growing customer energy usage quarter-over-quarter. Today, we're working with regulators and parties to ensure that costs are fairly allocated across customer groups. Industrial growth is helping us spread fixed costs of our system across a larger base, supporting affordability for all customers. Risk management. Wildfire season has officially ended in our service area. Our comprehensive year-end mitigation programs continue as we work to deliver results. Hardening the system, enhancing situation awareness, and deploying technology to protect our communities and improve liability. We recognize that more is needed to address the collective risk presented by wildfires and extreme weather. We remain committed to working with policymakers to find meaningful answers to these complex issues. Wildfire risk is a societal-wide problem, and we are working on operational, legislative, regulatory, and other outcomes to deliver societal-wide solutions. An investable energy future. Lastly, an update on our regulatory proceedings and proposed update to our corporate structure. Last week, we received the order on the Seaside Alternative Recovery Mechanism for the largest stand-alone battery on our system. The order represents a constructive outcome and was supported by the memorandum of understanding reached with parties back in the spring. This is an important step forward in our ongoing cooperation with the regulatory stakeholders. We appreciate the careful consideration of the commission and the collaboration with staff and intervenors. The distributed system plan remains on track, and we continue to expect a resolution in the first part of next year. The proceedings for PGE's proposed creation of a holding company and transmission company are also progressing as expected. The docket now includes a procedural schedule with a target date of June 2026. The proposed holding company update aligns PGE's corporate structure to industry standards. Both the holding company and the transmission company enable improved financing flexibility that will yield benefits for customers and shareholders. We look forward to continued engagement with stakeholders to reach outcomes that encourage investment in Oregon and advance our customers' and state's long-term goals. I'll now turn to Slide 5 for our financial results. For the third quarter, we reported GAAP net income of $103 million or $0.94 per diluted share. On a non-GAAP basis, net income was $110 million or $1 per share. This compares to third quarter 2024 GAAP net income of $94 million or $0.90 per diluted share. Similar to Q2, our non-GAAP results exclude business transformation and optimization expenses from the customer affordability commitment and updates to our corporate structure. Results this quarter underscore the mission of our company and my commitment to executing with discipline, advancing our strategy, and delivering value to customers, communities, and shareholders. Our team is laser-focused on execution and results, finishing 2025 strong and building off our momentum of our continued success in the years ahead. With that, I'll turn it over to Joe.

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. 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 by our diverse group of data center and high-tech customers. Given our robust load growth and our forecast for 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. There was a decrease from power costs of $0.24 driven by a $0.38 unfavorable power cost in 2024 that reversed for this comparison and a $0.14 benefit from the cost to serve load in Q3 2025 due to stable market pricing and power cost recovery timing. There was a $0.06 EPS increase from lower operation and maintenance expenses thanks to our continuous cost management efforts 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 consisted of $0.14 of depreciation and amortization, $0.05 of dilution, and $0.04 of interest expense. A $0.07 increase from other items included an $0.11 increase from our prior year deferral reserve that did not recur and $0.04 of miscellaneous items. Lastly, there was a $0.06 decrease from business transformation and optimization expenses, resulting in our GAAP EPS of $0.94 per diluted share. After adjustments, our Q3 2025 non-GAAP EPS was $1 per diluted share. Moving on to our capital forecast, our plan continues to focus on expanding our transmission capabilities, optimizing our distribution system, and maintaining a reliable generation fleet. We are pleased with the over 1 gigawatt of solar and battery projects on the updated final shortlist from the 2023 RFP. We have requested acknowledgment from OPUC in Q4 and expect the projects to be operational by the end of 2027. We will update our CapEx plan for the incoming RFP projects as negotiations finish and contracts are executed in the coming months. These projects will support our growth trajectory as we meet the significant demand and align with Oregon's clean energy goals. As for our liquidity and financing summary, total liquidity at the end of Q3 was just over $1 billion. Our investment-grade credit ratings and outlook have remained stable since the last quarter. We continue to see strength in our cash flow metrics, including a trailing 12-month CFO to debt metric of above 20%. For financing this quarter, we completed our ATM pricing activity for 2025 to support our base equity needs. In August, we drew $49 million, and earlier this month drew an additional $72 million, both for rate base investment and general corporate purposes. We currently have $137 million of equity priced but not drawn, which satisfies our needs through the end of the year. We will carefully assess our equity needs for the 2023 RFP projects as negotiations proceed, and we will provide financing clarity alongside our final CapEx expectations. We are also working closely with key stakeholders on the proposed holding company formation to create important flexibility in securing the most efficient financing options for our customers and shareholders. This structure could help reduce costs and provide options for funding critical grid investments, potentially displacing future equity needs for both base and RFP CapEx. As we reflect on our progress over the past three months and look ahead to Q4, we are proud of our disciplined execution. We are optimizing our business while advancing essential regulatory matters, all while staying focused on serving the growth in our area and delivering value. In Q4, we expect the continued impacts of load growth, moderately favorable power costs, CapEx supported financing, and benefits from our cost management work. Given our results through Q3 and expectations for Q4, we remain on track. We are reaffirming our 2025 adjusted earnings guidance of $3.13 to $3.33 per diluted share. Our progress in 2025, supported by our rate base investment pipeline, sustained confidence in our service territory, and improved operational performance, has solidified our long-term expectations. Therefore, we are reaffirming our long-term EPS and dividend growth guidance of 5% to 7% and our long-term growth guidance of 3% through 2029. Looking ahead, we are excited to continue executing our strategic plan, providing safe, reliable, and efficient service, while maximizing value for our customers, communities, and shareholders. Now, operator, we are ready for questions.

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-driven, how does that impact or revise any kind of longer-term thoughts? What are you seeing on this front? Clearly, adjacent states are 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 solid pipeline that reaffirms our confidence 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. 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 consistently how virtually all the other utilities in our sector have been operating 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%. 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 gain 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 has all 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 in reducing the overall cost of clean energy and battery storage on our system. 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 the timing of when we can see resolution?

Julien, as you mentioned, the size of the two RFPs is significant. The 2023 RFP has just over 1 gigawatt of power from solar and batteries. This serves as a foundation for both this RFP and the accelerated 2025 RFP based on the updated action plan, which indicates we need 4,000 megawatts by the end of the decade. When factoring in the 2023 RFP results and some power purchase agreements, for the next RFP, we anticipate a need of around 2,000 megawatts, possibly even more. However, several factors will influence this, including new PPAs, demand changes, and the evolution of clean energy policies. Overall, we expect the next RFP to be more substantial and comprehensive than the current one we are 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?

Is there a scenario where the Holdco approval process is separated from the Transco and the Holdco occurs more promptly? I believe the answer is yes. Under the right circumstances, we could see that happen. We expect that over time, both will ultimately be approved, but the Transco might take longer. Each serves a different financing function for us. We think the Holdco currently drives more value for customers and shareholders, while the Transco has a bit more time, so it's acceptable for it to take longer 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, as outlined in our plan, we have $1.8 billion allocated for transmission spending, including for 2025. I believe we have a balanced growth strategy in place. If there was a significant need to shift more resources towards transmission to better meet our customers' needs and support our clean energy goals while maintaining affordability, we would consider that. However, at this moment, our focus is on addressing the overall needs of our customers with a balanced approach to both transmission and generation.

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. 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. As it pertains to the financing plan, we are assuming a 50-50 financing structure for the current RFPs, which is after accounting for tax credit monetization that has typically been around 30%. This year, we have monetized approximately $150 million in tax credits to help meet our financing needs. Regarding your earlier comment, historically, our outcomes on RFPs have been about 50% of the total 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?

Currently, we are discussing the reliability contingency events within the PCAM filing. We believe these events have been a consistent and effective tool so far. We continue to engage in discussions regarding this. We would like to see something like this advance to better align energy costs, as it supports our overall strategy for more efficient energy pricing. The conversation is still ongoing, and I prefer not to speculate on the outcome. It is part of a larger discussion on addressing energy costs. I can say that it is a useful tool that works well for us at the moment, and we will keep working towards an effective energy recovery mechanism in collaboration 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 on 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% load 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?

In relation to the load growth and how it impacts our plans, we are currently working on clarifying the tariff concerning margins. At the moment, the new data center tariff is being processed on the regulatory side. Taking advantage of this growth with a more balanced margin will serve two purposes. Firstly, it will help distribute costs more evenly among our residential and other customers. Secondly, as we experience this growth, it will create additional value for us. Currently, we are in a wait-and-see mode regarding the tariff, which we expect to finalize in March. This will provide a good opportunity to capture some value.

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

I think that's where you would begin to identify how continued growth might affect pricing, allowing you to determine if there's additional value since you would 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, ownership 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 tend to lean a little bit more towards 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 there is a bit of a cyclicality with our cash flows. As we undertake these projects, the Investment Tax Credits will come through for the Request for Proposals we are discussing, and the cash flows this year include both the remaining Investment Tax Credits from the Constable project last year and those from the Seaside project this year. On an annualized basis, our base is the Production Tax Credits associated with our wind projects, which is approximately $50 million per year, and the cyclicality is driven by the Investment Tax Credits from Request for Proposals, at least in the current cash flow situation.

Regarding the wildfire legislation from last year, there was a proposal for an $800 million fund. Do you consider that amount sufficient, and is that what you would like the legislature to establish as a wildfire fund? What additional actions would you like to see from 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 statewide 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 provide an idea of whether you anticipate any delays in earning your authorized return on equity? If there are delays, how many basis points do 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 a reduction 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.

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?

In relation to the DSP consistent with the Seaside filing, we did have a memorandum of understanding with them, which governs the DSP as well. The reason we pursued this approach with the DSP was to enhance clarity for all parties involved. The DSP is a filed and accepted document that outlines our action plans for distribution. This clarity helps us focus on projects that are recognized as beneficial for the customers. We believe that having the MOU and dedicating time to it allowed us to engage in focused and constructive discussions regarding the testimony and the work of intervenors. We expect this positive interaction to continue 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 essentially takes an enormous amount of data, AI analytics. It 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 give 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.