Portland General Electric Company Aktie

Good morning, everyone, and welcome to today's conference call with Portland General Electric. Today is Friday, May 1, 2026. This call is being recorded. [Operator Instructions]. For opening remarks, I will turn the conference call over to Portland General Electric's Senior Manager of Investor Relations, Erin Schwartz. You may begin.

Thank you, Towanda. Good morning, everyone, and thank you for joining us today. Before we begin, I would like to remind you that we issued a press release this morning and have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The press release and 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 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 I will turn things over to Maria.

Good morning. Thank you, Erin. Thank you all for joining us today. The first quarter delivered another stretch of warm winter weather, 10% year-over-year Industrial customer demand growth and continued maturity of our cost management initiatives.

Beginning with Slide 4, I'll speak to our financial results and key drivers. For the first quarter, we reported GAAP net income of $45 million or $0.38 per diluted share and non-GAAP net income of $68 million or $0.58 per share. Our non-GAAP results exclude the previously disclosed deferral adjustments related to the January 2024 storm restoration and reliability contingency event and business transformation, optimization and acquisition expenses.

Our results reflect extremely mild weather, particularly in February and March and lower seasonal usage from Residential and small Commercial customers, which Joe will cover in more detail. We will be engaging with our regulator to explore frameworks to help mitigate weather and other volatility impacting both revenue and power costs. Greater predictability is good for both customers and shareholders, and we recognize that this will be multiyear work. Despite weather and usage impacts, our team delivered a quarter of strong operational execution, including overcoming inflationary pressure and advancing our cost management program, adopting to power market conditions, positioning our portfolio and generation suite to deliver optimal value and executing on our robust capital investment plan to support customer growth, clean energy and long-term reliability.

On recent calls, you have heard us highlight the company-wide work to optimize our cost structure. We are using our operational strength, which we've built over multiple years to mitigate the impact of recent weather challenges by accelerating our cost management work. Our teams are squarely undertaking the challenge, and we are committed to delivering strong results. As such, we are reiterating our full year earnings guidance of $3.33 to $3.53 per diluted share and our long-term earnings and dividend growth guidance of 5% to 7%.

Turning to Slide 5 for updates on our 5 key strategic priorities. First, our teams made progress on the Washington acquisition and other key regulatory filings. In late March and early April, we filed applications with the Washington Utilities and Transportation Commission and the Oregon Public Utility Commission for approval of the Washington transaction. We anticipate the regulatory approval process to take about a year and continue to target a mid-2027 close.

PGE's holding company proposal continues to advance. The docket procedural schedule has been modestly extended. To prioritize timely resolution of the holding company, we have paused the transmission company. That said, formation of a transmission company remains part of our long-term strategy. We appreciate the ongoing collaboration and expect to engage with parties in the near future. having just received reply testimony late yesterday. Many issues have been resolved with a few key items remaining. The process is on course, with a target final order date probably in August. Second, building upon our 2025 O&M cost management work. We continued driving efficiencies and improving productivity. We are accelerating this work given the very warm winter weather and first quarter results.

Importantly, our large low tariff proposal, UM-2377 is in the final stages of review with the OPUC and we expect an order in the next several weeks. A transparent, predictable tariff for new and existing data centers strengthens protections for existing customers while supporting economic development in our region. Our proposed rate structure under consideration enabled by Oregon's recent legislation includes a 26% increase in data center prices, which will help reduce the costs borne by residential and small business customers.

Third, as I noted, industrial demand growth is accelerating in our service area. We foresee robust energy usage from data centers and high-tech customers with large customer capacity growing by about 10% compounded annually through 2030. This growth forecast is driven by existing customers and contracts already executed with new customers, companies that own property and have civil work underway. Compared to Q1 last year, our data center customer load growth grew by 10%.

Fourth, progress towards additional clean energy resource procurement. We filed our 2025 RFP final short links with the OPUC in February as we aim to procure approximately 2,500 megawatts. The short list is composed of a diverse mix of projects and technologies to support our existing portfolio and growing customer demand. We look forward to working collaboratively with stakeholders to achieve commission acknowledgment in the coming months.

And fifth, our year-round risk-based wildfire mitigation work remains on track as we prepare for the summer months. In parallel, regulators and policymakers are engaged in this critical topic. The OPUC in coordination with the Oregon Department of Energy has hired experts on wildfire liability policy actions that balance customer needs for essential services, support for wildfire victims and financial health of utilities. We expect the study's findings of home inform policymakers in advance of the 2027 legislative session.

In December, we filed our 2026 through 2028 wildfire mitigation plan, which represents a significant evolution moving from an annual update to a forward-looking 3-year strategic framework.

As we progress through 2026, our focus continues to be on executing on our core priorities, solid operational performance, meeting growing energy demand, expanding into Washington State and advancing customer-driven clean energy investments. With the first quarter behind us, opportunities are significant. We are focused on achieving solid financial results and delivering value for customers, communities and shareholders. With that, I'll turn it over to Joe.

Thank you, Maria, and good morning, everyone. Turning to Slide 6. Our Q1 results reflect strong energy demand from our industrial customers and ongoing system investments. Total Q1 2026 loads were flat as compared to Q1 2025 and changes in demand between our customer classes were largely offsetting. Industrial demand increased 10% on a nominal and weather-adjusted basis. The industrial customer class is expected to continue growing at a strong pace, highlighting the strength of our large customer pipeline and the attractiveness of our service area to data centers and high-tech customers.

Commercial load decreased 2.9% or 2.3% weather-adjusted and residential load decreased 6.2% or 4.6% weather adjusted. PGE has seen seasonal shifts in residential and small commercial average uses in recent years with rooftop solar adoption and energy efficiency growth. While not considered in our 2026 plan, deviations of this magnitude are not unprecedented, and we are adapting to manage through this.

Historically, demand has been winter peaking, but our region has been transitioning to a dual peaking profile with customers increasing their cooling demand as air conditioning becomes more widespread in our region. After considering the recent trends in customer usage, we now anticipate weather-adjusted load growth of 1.5% to 2.5% this year.

In the last 12 months, our organization has evolved tremendously in the ability to adapt through cost management. We have a well-defined plan in place for the balance of the year to solve for the load impacts experienced this quarter, which I will discuss shortly.

Now I will cover our quarter-over-quarter earnings drivers. We experienced a $0.07 increase in retail revenues, including a $0.09 increase from additional cost recovery largely from the inclusion of our seaside battery asset in customer rates beginning in November 2025, a $0.09 increase driven by higher industrial demand, offset by $0.11 due to lower residential demand, a decrease from power costs of $0.15, driven by $0.09 from power cost performance in 2025 that reverses for this comparison and $0.06 from current year power cost performance driven by less favorable wholesale and environmental credit market conditions, a $0.16 decrease from other capital and financing costs in support of our ongoing rate base investments made up of $0.10 of higher depreciation and amortization, $0.05 of dilution and $0.01 of additional interest cost, a $0.09 decrease from other items, primarily the timing of tax credits and O&M costs.

$0.10 from deferral reductions related to the January 2024 storm and reliability contingency event, reflecting the outcome of the final OPUC order received in March. A $0.10 decrease from business transformation, optimization expenses and acquisition costs. This brings us to our GAAP EPS of $0.38 per diluted share.

After adjusting for the 2024 regulatory disallowance and our business transformation expense, we reach our Q1 2026 non-GAAP EPS of $0.58 per diluted share.

On to Slide 7 for our 5-year capital forecast, which includes 2026 and 2027 spend for the incoming 2023 RFP projects. I will note this view does not contemplate CapEx from the ongoing 2025 RFP for the Washington Utility business. Given our ongoing investment in critical systems and assets serving our customers, and other policy priorities, we remain engaged with stakeholders as we consider our next regulatory steps. We will keep you informed as this progresses in line with our usual practice.

On to Slide 8 for liquidity and financing summary. Total liquidity at the end of the quarter was $954 million. Our investment grade credit ratings remain unchanged and we will continue to maintain strong cash flow metrics with an estimated 2026 CFO to debt metric above 19%. In the first quarter, we executed a $550 million equity forward to address our 2026 base equity needs and fund the 2023 RFP project. This quarter, we also entered into 2 unsecured credit agreements, a $350 million term loan facility maturing in March 2028 to fund capital expenditures including those related to our 2023 RFP and general corporate needs and a $680 million delayed draw term loan intended to finance the washing acquisition-related costs. The loan is available until specific milestones tied to the acquisition are achieved and matures 364 days after funding.

Lastly, in April, the Board of Directors declared a quarterly common stock dividend of $0.525 per share, representing an increase of 5% on an annualized basis. We remain committed to paying a competitive dividend in line with our 60% to 70% payout target, while balancing overall financing needs. Our plan focuses on maintaining strong operating cash flows, while supporting continued investments in customer-focused capital projects, all while advancing us towards our authorized capital structure.

As Maria and I have mentioned, our teams remain focused on advancing key priorities for the balance of the year. Most notable is our deployment of incremental cost management measures to offset load impacts on 2026 earnings to date. Relative to our plan, Q1 was $0.25 below our expectations. While $0.09 is driven by timing, we will address the remainder through refining our capital and maintenance work streams, optimizing our team, equipment and facilities management and positioning our power portfolio and generation fleet to deliver optimal value. We are confident that these cost savings measures are achievable, especially considering the $25 million we saved last year, our existing momentum built into our 2026 plan and the opportunity to accelerate what was planned for 2027 into this year.

As such, we are reaffirming our long-term earnings and dividend growth guidance of 5% to 7% in our full year adjusted earnings guidance of $3.33 to $3.53 per diluted share. We remain focused on safe, reliable and efficient operations, advancing our strategic priorities and achieving our commitments to deliver value to our customers, communities and shareholders. And now, operator, we are ready for questions.

[Operator Instructions] Our first question comes from the line of Julien Dumoulin-Smith with Jefferies.

It's nice to chat. If we can start off here a little bit more on the negotiations and conversations on the holdco side. I mean what are the key areas of contention that prevented a settlement here, if you can kind of go back -- you said possible, obviously, I'm been asking how it's difficult, but the impossible to elucidate a little bit around that. And particularly now that you've removed the Transco from the filing, how do you think about prospects from here given how perhaps the 2 became at times a little overly intertwined?

Sure. Well, first of all, thanks, Julien. With regards to the holding company, we're really encouraged that parties have been meeting together to align thinking and to further the process. We just received a testimony yesterday. And we've agreed upon some [indiscernible] general provisions around ring fencing, including commissions oversight access to books and records and other things. Obviously, we still remain pretty far apart with regards to credit, the use of leverage and other such things. And we look forward to engaging with stakeholders as well as commission staff.

This is all part of the process. And as you can see, there are a lot of different concepts and history brought up in the filing that was just published yesterday.

Yes, absolutely. And then if I can follow up real quickly here. Just around the year itself, and I know you guys were just talking here. But obviously, there's been some gyrations here especially with the start of the year. Can you talk about the levers a little bit more? It's Joe question here in the context of the remainder of the year on the offsets, if you will, against the full year number here again. I know the load number was moving, started the year here with 1Q. Just -- and obviously, cognizant ultimately of the 26 being reaffirmed here, but can you speak a little bit to the levers going into that, if you will?

Sure. Well, as we mentioned, our cost management program that we had in place has always been designed as a multiyear plan. We achieved -- slightly exceeded our goals last year. So it really gave us a foundation to build off of to have levers, tools, items in place to react to situations like this. Part of the plan overall was to mature the organization to give us flexibility when situations like this occur. So one of the things we're doing is really taking advantage of this. It's a multiyear plan. This plan was intended to exceed beyond 2026. So we had already been working on identifying levers and benefits that were for this year, but also items for next year. So we've had the ability to just look into what is our toolkit here of items and actions.

In addition, we're realigning based on what we're now seeing as the pattern of performance to set the portfolio up to really optimize itself based on this design. So when I look at this as two-pronged, we have the ability of both being in our control, how we plan and adapt our energy portfolio and then how we -- how we plan and adapt to our cost, working throughout the whole management team and organization, right? This process has already been in place. We've already been working this because the goal of all of this has always been transformation. So we feel pretty confident that as we look to our toolkit as we identified this gap that we have the ability to execute and do things well within our control to react and because this work has already been underway, and it's really just steering it a little differently or giving it a little more momentum.

Excellent. And Maria, just to clarify the earlier comment you made, just at this point don't expect any kind of further settlement conversations on either the Holdco or Transco, right? Just I heard your comment about -- you remain pretty far apart on some of these key issues?

No, -- the process still allows for settlement conversations, and we're engaging with parties and working through the issues.

Okay. All right. Great. So I wanted to make sure it came across.

Our next question comes from the line of Shahriar Pourreza with Wells Fargo Securities.

This is Whitney Matalan on for Shar. So thinking broadly on recovery tools, with the RC mechanism no longer available, how are you thinking about the path to future reliability related costs in a way that remains timely and investable. Should we assume the fallback is simply broader GRC treatment? Or are there other tools you think Oregon could still support for event-driven cost recovery?

So first of all, an excellent question. And over time, you're absolutely right. We are engaging with regulators to work on removing the volatility and generating more predictability, both on the impact to energy usage from weather as well as other issues, obviously, RC was around significant events. And of course, we have more volatility to power costs and exposure. This is clearly something that's going to take some time, and it's really important.

Yes. And then just as a follow-up, as it relates to the multiyear rate planning, obviously, Portland is super supportive of Oregon's transition to that. But staff has been arguing with just the transition framework. And the company finds it super restrictive. So as Oregon moves into the multiyear rate plans, what do you think the main principal Portland is trying to protect? Is it the ability to retain the existing statutory tools during this transition or the ability to continue using narrower just mechanisms for high priority capital without needing a full rate case. And that's it.

So a good question, and there's no question that we need to work on. I think a common understanding of what's needed for all stakeholders, particularly investors and tools that will provide for adequate capital recovery and other interim items as we move to the multiyear framework. I think as we saw from the [indiscernible] testimony that was just issued yesterday, we have a lot of work to do around common understanding of how we'll attract and retain capital, and continue to grow the utility to invest for customers and clean energy, reliability and customer growth.

Whitney, just to add to the comment, you're right, there's a collection of new tools that are needed, both in the transition and also in the multiyear plan. And we've already been adapting to those. You saw those new tools and all honestly, the seaside tracker as well as the [indiscernible] that have taken some time to work through. So I mean, I think what you're seeing here is we're all working to evolve here from what was a very traditional process to both a multiyear process and how to find your way to that multiyear process. So I think the dialogue with the commission is really about what type of tools do we need and you understand they're new, and that honestly, why this takes a bit of time here to make sure they work well for all parties of all.

Our next question comes from the line of Chris Ellinghaus with Siebert Williams Shank.

Maria, can you just talk about what you're seeing in the Oregon economy. I know it's been struggling a little bit, but can you give us some color on are you seeing some recovery? Is it still sort of where it was? And as an adjunct to that, customer growth year-over-year was a little lighter than first quarter of last year. Is that part of that issue or there are some other factors at play?

Fair. First of all, we consider customer growth to actually continue to be quite strong, particularly in the non-downtown areas, so slightly under 1%. And we continue to also see good business formation and new entrants, particularly on the data center side, but also on the high-tech and semiconductor manufacturing side. We're very encouraged. Our customers are focused, and they continue to invest in many parts of Oregon.

Chris, if I can just add on the load, right, just for when you ask to the patterns, right? We saw this a combination of what was some warm months and just some unusual flows of weather even within the month that we obviously, to ourselves, peel back and ask ourselves very questions, very similar to you, are there economic conditions or other conditions and really seeing items that are really reacting to what is an unusual set of weather patterns. We've had one of the warmest winters here as well as it was a little sunnier. So you've got things like a little more solar penetration than you normally would have seen in the winter months and things like that, but we didn't, to Maria's comment, the broad economic factors at the guidance that gets us to what we believe are longer term as it relates to load continues to be hold and be consistent.

Sure. And there clearly are some unusual customer in migration patterns that seem to fluctuate. So I'm just kind of curious if there's any other factors there. Joe, in the reduction to the 2026 load expectations, is that merely a Q1 adjustment? Or is there other factors that incorporated there?

As it relates on an overall basis, we believe largely realized with this being the main -- the heating part of the load reduction. We have reshaped the remainder of the year, but in all honestly, the reshaping is some movements between the other quarters. But from a load experience, we think we've sort of work through the unusual part of the year on a cumulative basis and then just expect some slightly different flows here as we see different customer reactions to heat and cold weather, but overall net should be relatively close to [indiscernible].

So Maria, you were talking about wanting to pursue some mechanism for the volatility. The weather for you guys in the region is supposed to be on the warmer side for the spring and into the summer, that sort of effect on consumers? Do you think that will be sort of inspirational for your interveners for maybe pursuing that mechanism discussion a little more?

It's a good question. Certainly, last year, we began to see the impacts of significant higher AC penetration. And we saw quite a bit of higher load growth without as much high temperatures one would have historically needed to have seen. So definitely more correlation to high temperatures in terms of energy usage, which is a positive going forward for us, and we have not factored in that in our forecast. We're relying on those things right now that are actionable.

With regards to the commission and how they might think of this, affordability is a priority and predictability for customers is super important. We have -- I have had conversations with the Chair of the commission with regards to these unique patterns that we're seeing. And so those conversations with the commissioners and with staff will be ongoing.

Okay. A couple of related questions on the Holdco. One, can we infer from the Transco sort of retreat that while you didn't come up with an official settlement that you guys have resolved some issues unofficially through that process? And secondly, the sort of references to historical events are not terribly surprising. They were very sensitive about things like ring fencing and credit back in the day. But the Holdco is a pretty different animal than some of those events. So does the commission staff sort of appreciate the pretty significant differences despite them bringing them up again?

First of all, with regards to your question on the transmission company, our goal was to prioritize at the request of staff and commissioners we're trying to be cognizant of their workload, and make sure that we are talking about those things which are in the highest priority. But the transmission company remains a topic that we will continue to discuss in the future, but not at this time.

I think that the testimony shows that we have common ground on a number of items. I would agree with you in some of the written words in the [indiscernible] testimony, and it just shows that we have more work to do, and collaborate and establish common understanding and kind of the why and drivers as well as utility practices across the country that are pretty standard. The next step is to engage directly to continue the conversation.

Our next question comes from the line of Aidan Kelly with JPMorgan.

Just with the applications in Oregon and Washington now underway, could you speak to the initial feedback from stakeholders on the pending acquisition as well as the upcoming milestones we should watch for? And just any sense of kind of what the customer benefits you're highlighting for the commissions at this time?

Sure. So first of all, we've engaged with a wide variety of stakeholders. We've spoken with all of the commissioners and staff in Oregon, spoken multiple times with the commissioners in Washington as well as staff respective Governor's offices. And I think particularly important is we spent time actually in the service territory and are really encouraged by the receptivity we had, the focus on economic development, and the interest in our ability to serve current and new businesses in both the Walula, Wallula and [indiscernible] regions. So I'm really encouraged with the opportunities as we move forward.

In terms of discussions on benefits, we're just at the very early stages. But I would say, in particular, for Washington, it is very much of a constructive business-focused environment, and we look forward to engaging with all stakeholders as we move forward.

Great. Thanks for the insight there...

The conversations could not have gone down.

Okay. That's good to hear. And then yes, just wanted a separate question, just wanted to pick up on the regulatory front again. I know it's kind of been talked about earlier in the call, but maybe just clearly asking, like, could you just speak to the timing of your next CRC as we kind of get closer your stay out expiring this summer. What are the factors you would call you to file earlier later at this time?

So clearly, we're spending a lot of time talking about that issue. And we are focusing on sort of what's next, our timing. We know that energy bills are incredibly important to all businesses and families, and we are working to keep customer bills as low as possible by delivering reliable services that customers can count on. We also have not decided exactly on the next timing of our rate case, but there's no question that it will probably be sometime in the second half of the year. We're still evaluating the major components.

Your next question comes from the line of Gregg Orrill with UBS.

When would you be in a position to include the '25 RFP into the CapEx plan?

Right now, our anticipation, just as a reminder, right, we include the RFPs in the plan once we have them under contract. We think the earliest we'll start to see contracts is the beginning of 2027, things work to the normal course as we work through these projects. So we're hoping that it'd be nice to have it align relatively to our fourth quarter update. But as you know, we are -- since we are working with a collection of individuals and you have a series of negotiations, going on that can bear.

Our next question comes from the line of Paul Fremont with Ladenburg Thalmann & Company.

I guess my first question is, should we think about the prospects for settlement being the best between now and when hearings are scheduled in early June?

I hope so. The sooner we can settle the better, but I want to make sure that we give all parties an adequate time to establish good understanding and being able really to move forward constructively.

Right. But in most states, typically, if it's going to settle, it's going to -- it usually settles before hearing. Is that sort of the case in Oregon? Or would you expect the prospects for being just as good after hearings?

Well, I don't know if I would hedge either side. I think we're going to continue the process just as we have in the past. And hopefully, we can come to settlements. And if not, we'll go to the hearings and then work towards settlements afterwards. We've got plenty of runway to engage ahead of the hearings, and we're always hopeful of settling sooner rather than later.

Okay. And in the past, I guess, you've expressed a very high level of confidence in your ability to settle this particular case. Is that unchanged given your comments earlier that the parties still remain pretty far apart?

No. We still have good expectations of being able to settle. And I would reiterate as well that we have put a number of issues behind us as we work through the process.

And then have you received the counterproposal that was referenced in your regulatory filing from the intervener parties? And judging, I guess, by your comments earlier, it sounds like even in the counter -- even if you did receive one that there are still sort of major issues to be resolved?

No. We haven't -- the parties are working on that, and we are continuing the discussions.

Great. And then I guess it looks as if to us as if the Washington Utility subsidiary of Berkshire may not be earning at levels that are close to their authorized return levels. Is there something that you plan on doing to potentially narrow the gap between what they're earning and what their authorized are?

So our focus as we move into Washington and look at the opportunities in the state -- is -- first, it's a strong operational fit with the operations that we know well. We have noted that we expect it to be accretive in the first year and to enhance our long term and the overall businesse's EPS growth and dividend growth. And much of that is driven by the opportunity for new investments for clean energy investments in particular that are supporting the [indiscernible] compliance obligations that they have and the commissioners have continued to reiterate that for us. But we would be expecting to drive to a similar return profile in Washington as we have in Oregon or better.

Yes. I mean, Paul, the historical gap that we've seen has been mainly related to power costs. And one of the -- one of the attributes that when we do this transaction is a very -- it's a very much more specific and transparent direction of the costs for the Washington customers, and we believe having this clarity of the Washington Utility as well as having a much more specific instead of allocated set of assets and costs there will drive to a more effective recovery over time.

Okay. So it's not through merger synergies that you would expect to sort of improve.

No, Paul, to date, when we've talked to and we speak to the accretive nature of this transaction here on the front end and as it relates to getting a better recovery, this is about the execution of the plan, the execution of the cost and the operation of utility, we have not layered in any type of cost synergy or other work here. We've really just layered in an effective operation and getting the financing and other benefits of the company. Synergies, as I know we've talked to you and that we will work to, but we're not counting on those to make this accretive on that front.

And there are absolutely [indiscernible] synergies on the O&M side and on the power cost side.

Our next question comes from the line of Travis Miller with Morningstar.

Got 2 quick ones and then a follow-up. It's a higher level one, but 2 quick ones. The 26% increase in the data center prices you talked about through the tariff, are those for all existing PAUSE and prospective customers? Or would those be just for perspective?

Those are for existing and new customers, all data center customers. And we worked very collaboratively with each of those customers, and there's no surprises.

Okay. That was my 1 quick one. The other quick one, the generation mix Q1 last year to Q1 this year, some changes there in terms of your own generation versus purchased? Was there anything was weather driven? Is there something fundamental going on? Anything to read through some of those mixes, particularly in the owned versus purchased?

Yes. No, there's no real -- there's no strategic changes going on there. I mean what you will see it's really a combination of events. The weather, the energy pricing related to running assets as well as certain contracts that will roll on and off. I think you'll see a contract there rolled on under the not owned [indiscernible] contracted section. But no, overall, our strategy on how we manage the portfolio and the mix of owned versus contracted state on it. But these are just ebbs and flows in the normal course of a year.

Okay. Makes sense. And my higher-level question. I think there was a report that called the E3 report that came out in the last couple of days, talked about a 9 gigawatt shortfall by 2030 and a 14 to 18 gigawatt shortfall by 2035 and particularly along the western edge of the region where you serve and up and down there. I wonder if you could talk to whether you are involved in the report, if these are numbers that are consistent with what you're seeing with what you've reported the regulators, et cetera.

Sure. So the report was commissioned on behalf of industry groups that we participate and know well across the Pacific Northwest. And as you know and can see through our 2025 RFP as well as our IRP, we are working to procure more energy than we certainly have in the past and there would be others in the region that are doing the same. The report was really focused also on resource adequacy and how we better manage resource adequacy as a region. It includes additional focus on transmission. And clearly, our entering the energy and balance marks the day ahead market and building upon our energy and balance market, we'll improve that for Portland General as well as Pacific or who actually -- it just went live with the day ahead market today. So we appreciate the information that was put together has created a lot of regional discussions that are very constructive.

Our next question comes from the line of [indiscernible] with Mizuho.

This is [indiscernible] from Mizuho for Anthony Crowdell. You've talked about the Washington acquisition as this opportunity to bring a growth-oriented philosophy to a sort of territory that has historically say more maintenance-focused. Can you walk us through what that looks like in the first, say, 12 to 18 months after you take over. Perhaps you've already touched on this in previous questions, but just specifically, what are the areas that you bring this growth initiative to? And what would you point to as early signs that the shift is taking hold?

I'll start here and maybe hand it over to Maria. When you're talking in the shorter term here, this is really about supporting and giving them the right investment, mainly on the D side, a little bit of tea as it relates to putting -- continuing to build that infrastructure at the rate that it needs to support growth. The longer-term growth will really come from, as we've mentioned, our RFPs that we will be involved in and really helping support economic growth and development in a region that we believe is primed for economic growth and development. And that -- so that's why if you look to the charts that we show here on -- as it relates to the inclusion of the Washington utility, you'll see that the growth is a little more back-end focused as we give a little time here to support some industrial growth and then support some of the RFP needs that will go in the area.

Perfect. We're really encouraged with -- yes, we're really encouraged with the regional leaders interest in accelerating the growth in Eastern Washington and have had terrific conversations with our existing customers as well as with new potential customers.

Ladies and gentlemen, I am showing no further questions in the queue. I would now like to turn the call back over to Maria for closing remarks.

Thank you very much for joining us today. We appreciate your interest in Portland General, and we look forward to seeing you at upcoming conferences. Have a great day.

Ladies and gentlemen, that concludes today's conference call. Thank you for your participation. You may now disconnect.

Good morning, everyone, and welcome to today's conference call with Portland General Electric. Today is Tuesday, February 17, 2026. This call is being recorded. [Operator Instructions] For opening remarks, I will turn the conference call over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead, sir.

Thank you, Daniel, and good morning, everyone, and thank you for joining us today on short notice. Before we begin, I would like to remind you that we issued a press release this morning and have prepared a presentation to supplement our discussion, which we will be referencing throughout the call. The press release and 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 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 I'll turn things over to Maria.

Thank you, Nick. Good morning, and thank you all for joining us very early today to discuss our expansion into Washington State and the proposed acquisition of PacifiCorp's utility assets. We will begin by covering this exciting news as well as RFP results, guidance for 2026 and our 2025 financial results.

I'll start with Slide 4. Earlier today, we announced a definitive agreement to acquire the Washington electric utility business from PacifiCorp for $1.9 billion. This includes select generation, transmission, distribution and other utility assets in Washington State. We are partnering with Manulife Investment Management and its affiliate, John Hancock, an insurance and investment company who will be a 49% minority partner in the Washington business.

Manulife brings broad financial expertise and energy infrastructure and has owned and invested in agriculture, timberland and other businesses in both Oregon and Washington for over 2 decades. This transaction represents a key step in our strategy and complements the work that Portland General team does every day, prioritizing safe, reliable, increasingly clean electricity to serve customers at the lowest possible cost, enabling economic development and strengthening energy infrastructure across the Pacific Northwest and creating value for customers, communities and shareholders.

In this time of unprecedented electricity demand, PGE's commitment to the Pacific Northwest and our excellent service and energy infrastructure will benefit Central and Southeastern Washington. Our overall portfolio will grow by approximately 18%, and the acquired operations will continue to operate as a Washington-regulated utility, serving 140,000 Washington customers. These additions bring benefits of scale and operational expertise to both Oregon and Washington service areas. We look forward to working together with the 140 dedicated employees who will continue to serve Washington customers.

This transaction is forecast to be accretive in the first year, while diversifying and broadening our growth opportunities, underscoring long-term EPS and dividend growth of 5% to 7%. The acquisition will be subject to industry standard regulatory approvals, including from Washington, Oregon and other jurisdictions, which we will expect will take approximately 12 months after regulatory filings are submitted.

This is a unique opportunity during a pivotal moment for our region and industry. We are excited to bring PGE's operational expertise, customer focus and reliable energy delivery to Washington. Before Joe and I go further into the details of the transaction, we will cover our 2025 earnings results, 2026 guidance and highlights from the year.

Turning to Slide 6. For the full year, we reported GAAP net income of $306 million or $2.77 per diluted share and non-GAAP net income of $336 million or $3.05 per share. Our 2025 results were impacted by unprecedented warm weather in November and December as seen elsewhere across the West. We saw the warmest temperatures on record since we started recording 85 years ago. In total, this abnormal fourth quarter weather reduced earnings by $0.17.

Despite these conditions, our teams worked throughout the year to execute, advancing our cost management programs, achieving multiple constructive regulatory outcomes and accelerating clean energy procurement to maximize federal tax benefits for customers. Importantly, we continue to see strong growth in our service area. Total weather-adjusted load growth was about 5%.

Large customers, including high-tech manufacturers and especially data centers ramp their energy usage throughout the year, driving industrial growth of 14% compared to 2024. This combination of operating performance and strong fundamentals in our service area underpins our 2026 earnings guidance of $3.33 to $3.53 per share. We are also reaffirming our long-term earnings and dividend growth guidance of 5% to 7%.

Turning to Slide 7. Our 5 strategic priorities. First, our team advanced multiple key regulatory proceedings in 2025. We received approval of the Seaside battery project and reached constructive stipulation for the distributed system plan. We are making continued progress on data center tariff updates that support residential and small business customer affordability, which I'll cover shortly.

Discussions are ongoing regarding our holding company and transmission company proposals. We will be meeting with parties at settlement conferences later this week and in early March as we work towards resolution of the process around the end of June. Second, we're focused on O&M and capital cost management. In 2025, we work to realize efficiencies and improve productivity in delivering safe, reliable service at the lowest possible cost.

Net of transformation costs, our teams exceeded targets for the -- and reduced PGE's overall cost structure by about $25 million. Third, as I noted, customer growth continues to accelerate in our service area. In the fourth quarter and early 2026, we executed 5 additional contracts with data center customers totaling 430 megawatts. These contracts further strengthen our pipeline of large load customers who are invested in the region, constructing facilities and energizing their operations.

Our large customer group is forecast to grow energy usage by about 10% compounded annually through '23 (sic) [ '30 ] Enabling this growth is transmission capital investment and extensive work to unlock capacity through the use of AI analytics, data -- excuse me, dynamic line ratings and other grid-enhancing technologies.

Alongside this work and in conjunction with Oregon's recent data center legislation, the POWER Act, our proposed large load tariff, UM 2377 is tracking towards completion in the second quarter of this year. This includes the creation of separate data center customer class, sharpening the cost allocation framework and enabling contracting flexibility. Our tariff proposal includes a 25% price increase for data center customers, which in turn would reduce residential and small business customer prices.

Fourth, today, we are announcing 4 new energy projects and executed agreements. We have signed build transfer agreements to construct a combined 125-megawatt solar and 125-megawatt battery storage facility at Biglow. We also signed a build transfer agreement to construct a combined 240-megawatt solar and 125-megawatt battery facility as part of the Wheatridge Expansion project. PGE will own 175 megawatts and procure the remaining 190 megawatts via a PPA.

Both projects are slated to come online by the end of 2027 and are eligible for federal investment tax credit between 30% and 40%, enabling additional clean energy at significant lower cost to customers. In addition, we are procuring 400 megawatts of battery capacity through 2 capacity storage agreements. We are also taking steps forward in the 2025 RFP and hope to have announcements later this next year.

And fifth, we continue our year-round data center wildfire risk mitigation approach, hardening and modernizing the grid and reducing risk through strong operational performance. With that, I'll turn it over to Joe to cover 2025 results and 2026 guidance in more detail before we return to discuss our acquisition. Joe?

Thank you, Maria, and thank you, everyone, for joining us to hear about today's important developments. Turning to Slide 8. 2025 was another year of strong energy demand in our service area. This significant growth again was led by the diverse and growing data center and high-tech customers that Maria highlighted earlier. From 2020 to 2025, PGE's industrial customers have grown at 10% compounded annually. This same group is expected to continue at this pace through 2030, highlighting the strength of our large customer pipeline.

These trends speak to the attractiveness of our service area and our team's ability to serve growing customer needs, invest in critical assets and enable benefits for the entire system. In 2025, total load increased 3.8% overall and 4.7% weather-adjusted compared to 2024. Industrial load increased 14%, residential load decreased 1.8% year-over-year but increased 0.4% weather adjusted. Residential customer count increased by 1.3% and commercial load remained largely flat.

Turning to Slide 9, where I'll quickly cover year-over-year earnings drivers. Overall, our full year 2025 results reflect meaningful industrial demand growth, improved recovery of assets serving our customers, differing power cost conditions as compared to 2024, our team's strong execution of cost management programs, ongoing rate base investment and financing, other items and business transformation and optimization costs as we work towards reducing our cost structure. These drivers bring us to GAAP EPS of $2.77 per diluted share. After adjusting for business transformation and optimization expenses, we reached our 2025 non-GAAP EPS of $3.05 per diluted share.

As Maria mentioned, our full year results were impacted by the unprecedented warm weather conditions in the last quarter of the year. December alone accounted for $0.14 of the $0.17 EPS impact in Q4 as it was the warmest December on record for our region with 24% fewer heating degree days than average. Turning to Slide 10 for an overview of the executed 2023 RFP projects, the Biglow Optimization and Wheatridge Expansion, which will widen our generation capabilities to meet the needs of our customers.

Both projects will be in construction this year and are expected to be serving customers by the end of 2027. We are also advancing our 2025 RFP, and we'll be submitting the final shortlist to the OPUC this week. The shortlist includes a variety of renewable and non-emitting capacity projects totaling approximately 5 gigawatts. As we proceed to negotiations, we will prioritize projects that include renewable generation, close earlier in the eligibility period and maximize tax credits. We expect the final selection to be a blend of build transfer agreements and PPAs that total approximately 2,500 megawatts.

On to Slide 11 for our 5-year capital forecast, which now includes 2026 and 2027 spend for the incoming RFP projects. I will note that this view does not contemplate CapEx from the Washington utility business from the transaction we announced today. On to Slide 12 for our liquidity and financing summary. Total liquidity at the end of the year was $954 million. Our investment-grade credit ratings remain unchanged. Our outlook from Moody's has improved from negative to stable.

We continue to maintain strong cash flow metrics with estimated 2025 CFO to debt metrics above 19%. As we look ahead to 2026, we continue to expect a base equity need of $300 million as we work towards our authorized capital structure. Our plan considers the constructive regulatory outcomes in 2025 and continued robust operating cash flows in 2026. These factors will enable solid progress in our equity ratio and ultimately arrival at our target capital structure earlier than anticipated. As such, we expect base needs to taper to approximately $50 million in 2027.

We anticipate financing the 2023 RFP projects in line with our 50-50 cap structure, net of tax credit monetization, resulting in $350 million of total equity needs in 2026 and 2027. I will note these financing expectations do not contemplate the potential holding company for investment in the Washington utility.

In recent years, we've effectively utilized our at-the-market program to opportunistically fund accretive rate base investments. We continue to see value of this tool and the strategy, and we are refreshing our ATM, which we've upsized to $500 million in support of our diverse and robust CapEx plan. This facility enables issuances over multiple years and like our previous programs, will include a forward component. We also expect debt issuances throughout 2026 of up to $350 million, focused on funding our capital expenditures.

Turning to Slide 13 for an overview of our 2026 guidance. Overall, our focus on managing cost structure, robust load growth and rate base investment catalysts underpin our expectations for 2026 and the years ahead, including 2026 earnings guidance of $3.33 to $3.53 per share, 2026 weather-adjusted load growth guidance of 2.5% to 3.5%, long-term load growth guidance of 3% through 2030 and reaffirming our long-term EPS and dividend growth guidance of 5% to 7%. Now let me turn it back to Maria for continued discussion on this morning's announcement.

Thank you, Joe. Turning to Slide 15. We will be adding 140,000 customers across 2,700 square mile service area anchored around Yakima, Walla Walla, and other Washington communities. The portfolio of generation assets in this transaction is a valuable mix of natural gas and wind resources that provide safe, reliable and affordable power. These assets will complement PGE's 1.8 gigawatts of natural gas generation over 1 gigawatt of wind assets, including PGE's Tucannon River Wind project located midway between the Marengo and Goodnoe Hills wind farms.

On to Slide 16. This acquisition is a great fit. First, an excellent opportunity to expand our service to Washington State and acquire generation, transmission and distribution assets we know very well. The Washington Utility and Transportation Commission will continue regulatory oversight of the Washington utility operations. Washington's regulatory jurisdiction includes many positive components, including multiyear rate plans, competitive ROEs, constructive fuel mechanisms and frameworks for clean energy investment. We look forward to working with Washington regulators and stakeholders in enabling economic development and advancing clean energy policy goals.

Second, enhanced scale and reach, and operational capabilities will position us for rate base and customer growth. Central and Southeast Washington are home to dynamic communities and industry, including agriculture, manufacturing and technology businesses that serve regional and global markets. We will have the opportunity to support economic growth in these regions and bring further investment for grid modernization and renewable energy acquisition to serve growing customer demand.

Third, we anticipate meaningful customer upside. Portland General Electric brings a track record of effective operational performance, including strong plant availability, first quartile safety, commitment to wildfire and other risk mitigation, top 10 customer service and programs and first quartile reliability. The expertise of Washington employees who are deeply familiar with Washington customers and assets will be supported by PGE's administrative, finance, energy management and other system-level expertise.

We also expect that the increased scale will deliver benefits from shared corporate functions, enhanced purchasing power and efficient financing for system investments. And fourth, clear shareholder value that will sustain further customer-focused investment. PGE expects EPS accretion in the first full year, while enhancing PGE's long-term EPS and dividend growth of 5% to 7%, supporting strong investment-grade credit ratings. Manulife's partnership is a key element in the acquisition's strength. They bring significant expertise in this region and in our sector.

Turning to Slide 17. The broadening of our service area footprint represents an exciting moment for our company and shareholders. As I noted, our overall portfolio increases by 18%, a 22% increase in generation and transmission, a 14% increase in distribution and a 15% increase in the number of customers. This transaction fortifies our key strengths, broadens opportunities for growth and delivers benefits for all customers and communities we serve. With that, I'll turn it back to Joe. Thank you.

Thank you, Maria. As you can see from this view, PGE's acquisition of PacifiCorp's Washington operations presents a structured, executable transaction with clear advantages for our customers and stakeholders. The key upsides include additional scale, diversification into a constructive jurisdiction and enhanced capacity for system improvements to serve customers.

Overall, we expect both operational synergies and incremental rate base growth opportunities. Notably, we will now step into the Washington RFP process to pursue varied ownership structures that deliver least cost, least risk options, drive towards the state's goals and support customers' energy and capacity needs.

Moving to Slide 18 for a summary of the transaction structure. The acquisition is structured as a sale of certain assets serving customers in PacifiCorp's Washington service area. Due to PacifiCorp's existing structure, we expect customary regulatory approvals in each of their jurisdictions as well as from FERC. I will note that due to the asset purchase nature of the acquisition and PacifiCorp's multistate structure, we will be assuming relatively few liabilities as part of this transaction.

Upon closing, which is expected 12 months after regulatory filing submission, PGE and Manulife will form a joint venture to own the regulated utility in Washington, which PGE will operate. While our ongoing corporate structure update, including the creation of a holding company and a transmission company are not prerequisites for this transaction to close, we see the holding company structure as supported by this scenario.

In the coming months, we will submit regulatory filings in both Washington and Oregon for approval of the transaction. We look forward to engaging stakeholders during the approval process, and we'll provide status updates as part of our typical disclosure.

Turning now to Slide 19 for our planned financing approach for the transaction. First, concurrent with the agreement signing, PGE obtained commitments for the full $1.9 billion purchase price, including bridge financing from Barclays and JPMorgan and commitments from Manulife. For our permanent financing plan, we expect to utilize a combination of $600 million equity contribution from Manulife, $700 million secured debt at the Washington utility and $600 million raised at the proposed holdco. This approach strikes the right balance across financing channels. It strengthens accretion, manages risk and supports investment-grade credit ratings, which are expected across all entities.

On to Slide 20 for an overview of the Manulife Investment Management and the partnership agreement. Manulife IM and its affiliate, John Hancock, is a leading direct investor in U.S. infrastructure. Their presence in the Pacific Northwest is notable, having invested in infrastructure, agriculture and timberland in our region for over 2 decades.

Beyond these important local ties, this partnership structure brings value both during the transaction window and after closing, particularly reducing overall capital markets exposure and equity needs, introduction of another cost-efficient source of capital, preservation of PGE's strong balance sheet and strong support for further investment and growth opportunities at the Washington utility.

Overall, the partnership is structured as a traditional arrangement with familiar features for our sector. PGE will manage and operate the Washington business and will also be a 51% owner with Manulife owning the remaining 49%. PGE will also hold the majority of seats on the 5-person Board. Moving on to Slide 21 for our operational track record and approach to business integration that supports this acquisition.

PGE has captured significant organic growth within Oregon service area over the last 2 decades, adding over 180,000 customers and expanding the generation portfolio by 2.4 gigawatts of utility-owned generation. As Maria mentioned earlier, we are excited to welcome the highly skilled Washington employees who will be an important part of the integration and go-forward operation.

Our growth and ability to serve robust customer demand have been supported by the company's investment in integrated operations. These encompass several critical functions that enable low-cost access to market power, renewable energy integration and reliability. PGE has recently implemented and enhanced several technologies that enable the smooth addition of business units and are expected to help streamline the technical integration of the Washington service area.

I'll also highlight the experience of our leadership team. Many of our officers bring expertise from large organizations, including multi-jurisdictional utilities and have executed many transaction integrations. We will draw upon this experience to deliver a seamless transition for our customers. Now let me turn things over to Maria to close.

Thank you, Joe. We've covered a lot of ground today, both what we've accomplished and what lies ahead for Portland General Electric. Let me close today's discussion on Slide 22. The strength of our existing approach and the opportunities in Washington are all rooted in PGE's 5 strategic priorities. We are deeply committed to the Pacific Northwest region and continued investment, which will expand to include assets and operations in Washington State.

We remain focused on delivering safe, reliable power at the lowest possible cost, efficient and effective operations, realizing economies of scale and regulatory frameworks that support customer affordability. We are advancing critical infrastructure investments that support economic development and builds upon a base of growing data center and high-tech customers.

We are integrating clean energy resources to satisfy customer and policy-driven goals, executing RFPs and reducing customer price impacts by maximizing federal tax credits. And we are deploying our mature data-driven wildfire risk mitigation programs, modernizing the grid and reducing risk through strong operational execution. We are excited for the road ahead. We are affirming our trajectory of strong financial results and look forward to delivering for customers, communities in both Oregon and Washington for years to come. And now, operator, we're ready for questions.

[Operator Instructions] Our first question comes from Shar Pourreza with Wells Fargo Securities.

Congrats on the deal. It's definitely interesting, really good transaction here, so unexpected. So Maria, just let me ask you. So the deal is done at 1.4x, and you expect the deal to sort of be accretive in year 1. Can you just touch a bit on the accretion drivers and maybe frame the sensitivities to items like regulatory timing, financing, transaction, transition costs, et cetera, so we can kind of better understand upside, downsides around the numbers.

Sure. First of all, there are several key areas. The first is our permanent financing plans that we laid out today. We also are expecting our cost management plans to continue to be executed and integration of this new company will really help our cost structure. And then we will be bringing data center and other customers to the area and development. It's a great operational opportunity and fit for us as we expect first year accretion.

And then just on the language, Maria and Joe, around just the enhancements to the EPS growth rate. I guess, can you define maybe a little bit on what you mean by enhancement in this context? Is it sort of a step-up in the growth rate, a higher midpoint within the existing range, a lengthen and extend scenario? I guess, can you just be a little bit more specific on the accretion?

Sure. So we have a combination of factors that give us confidence to be squarely above the midpoint of our guidance range of 5% to 7%.

Big congrats...

Thank you.

On the deal.

Our next question comes from Julien Dumoulin-Smith with Jefferies.

Maybe just a few different questions here, more housekeeping than anything else. But just at the outset, how do you think about earned ROEs? What's the ability? What do you think the opportunities over time here as you think about extracting the full extent of the value from this transaction? What's the normalized ROE to think of over time? And then maybe a couple of credit ones just to chime in on here. How do you think about new metrics from the rating agencies given the diversification that this offers? How the agency is thinking about maybe some of the benefits from a wildfire diversification perspective? Yes, I'll leave it there.

Julien, as it relates to ROE, their -- from their last general rate case, they have an imputed allowed ROE of 9.5%. We do believe that over time, as we work into the organization as it relates to our cost management programs, our cost structure as well as the regulatory filings, we would expect it to perform in a -- work towards a gap similar to what we're seeing performance-wise over time here. I mean it will take a little bit of a time period as we integrate them in, but that is the expectation that we can we can work them into a relative level of efficiency to ours or a little better.

As it relates to the credit metrics, we have had preliminary conversations with the rating agencies. We've been very clear with the rating agencies about our desire to have investment-grade credit ratings and quality credit metrics across the organization. We'll continue to have discussions with them as this matures, but it is fully our intent to have a structure of these organizations to have relatively high credit metrics.

Got it. And just to come back to you real quickly here. Earned -- where have earned returns been of late? And how do you think about what that -- how long it would take to get to that 50 plus, call it, 50-ish basis points lag or wherever you're exactly pinning that down? And then if I can just quickly also clarify on the -- are there break fees in the event that you don't get approval here? I mean -- and how does this fit into the process you have underway already regarding the HoldCo Transco? Just if you can elaborate a little bit around that.

Sure. So I'll start with your earned returns. This company has a portion of the subsidiary, obviously, not a bunch out there to show in detail, but they have had -- their earned returns have been a little off mainly due to the cost recovery on the power cost side of the equation, understanding that, that power cost recovery was part of the allocated structure that they had as opposed to what we'll see as a very specific plant and contract-based cost recovery method.

As it relates to break fees, yes, there are break fees that go on both sides of this transaction that we've included in some of the disclosures. There are break fees for certain reasons that the transaction does not close as if there is not FERC or regulatory approval, there are break fees that are out there as well as if the rate base that is approved by the regulator is not equal to what is -- which is agreed to within the contract. And there's a few other nuanced break fees out there, relatively symmetrical and again, all generally valued at $35 million to the extent there's a break fee.

Our next question comes from Chris Ellinghaus with Siebert Williams Shank.

What do you expect the filing cadence to look like?

We expect the filings to take place in the next 30 to 60 days. The regulatory process should take about 11 months to 12 months.

With the new proposed data center tariff, can you give us any kind of metric on how that helps on the residential side as an offset?

Sure. Chris, the data center tariff, which you mentioned is UM 2377, and it follows the POWER Act that we put in place with parties through the legislature in 2025. We've had several passes at it. And overall, the increase in data centers, which today is about 6% of our customer load and about 4% of our peak directly benefits residential and small business customers.

Initially, it's about a 2% reduction, and that should grow over time as the data centers continue to grow in the area. It also allows for direct contracting and something that we call in the filings, the Peak Growth Modifier. So we are fortunate to be able to work with parties as well as with all of our data center customers to ensure this works with everyone across the state of Oregon. And we hope to take some of our -- this kind of work around customer relationships, regulatory and economic development to the new Washington area.

The $25 million cost reduction that I think Joe quoted, can you give us any kind of sense of how that sort of prorated over time to get a sense of when that's effective essentially?

Sure. So the $25 million cost savings in 2025, it was a program that started in 2025. So we expect that to grow. So when you do the run rate on that as a general rule, probably more of like use a half year convention since a lot of these cost programs were put in sort of the second to the third quarter. The key to our cost management program here is a cumulative approach. So the savings that we had in '25 that we will do two things. They will become full year savings as they come into '26 and they are permanent. And then we will be building upon those savings as we've been doing a rollout plan here as we plan to manage our costs for the next several years.

So we will be introducing a new set of cost management for different portions of the organization that will do that same thing again. We'll have programs that are implemented in '26 that will have benefits in '26 that then grow to full year in '27 as we have this thoughtful rollout to drive this efficiency and be able to manage inflation over a multiyear period. To date, the program has been very successful. As we noted, we exceeded our targets.

And if you normalize our O&M for 2026, we even did a little better just on not spending money in places, maybe not per se aligned to the efficiency program. But pretty excited about the execution and would say that the program for '26 is more mature than '25 because in '25, we were developing as we were going in '26 has an established plan in place already for the year.

Great. That helps, Joe. Maria, lastly, can you just sort of talk about how you see the Washington acquisition aiding or providing an opportunity for additional large load growth?

Yes. So Eastern Washington is focused on economic development. We also hope to leverage our existing relationships. As you can see, we have quite a broad and diverse set of high-tech and data center customers, and we'll work closely with them in the area of Washington as we have throughout our service area in Oregon.

Our next question comes from Anthony Crowdell with Mizuho.

Congrats on the transaction. If I could just squeeze hopefully, 3 quick questions. If you could help us out, when I look at Slide 19, the $600 million raised at the HoldCo, is that all debt, all equity structure, like 50-50 of a utility? How should we think of that $600 million financing?

Sure. So as it relates to that $600 million, think of it as a balanced mix of the investment, be it at the HoldCo or other structure, but it will be a balanced mix of debt, equity, potentially hybrid or other securities that align to the capital structure that we'll be focused towards.

Got it. And then you've given out an EPS CAGR of 5% to 7% for a number of years. The thought was the holding company that you're going to create was going to provide efficient financing for the Oregon utility. Now you're potentially adding in already taken some of the debt capacity based on the $600 million. Could you tell us maybe in '27 and '28, how much debt do you forecast being held at the holding company now?

So for right now, I don't want to front run the holding company regulatory approval process, which will itself potentially have stipulations. But I'll take the -- to the comment in tying this to the earnings growth trajectory that we have, be it the Washington transaction that we're talking about right now or the holding company, either both taken in a vacuum together, each one is an enhancement to that earnings growth rate.

And as each of them mature here, we will continue to -- we will reevaluate how that -- do they just enhance the growth rate or do they put upward pressure on that. But we want to give them both a little time to settle. There is -- obviously, within the regulatory approval process, there could be items which impact one way or the other. And so as these items come more into clarity, we will reevaluate. But I do acknowledge that each one individually does have a level of enhancement to the earnings growth.

And just lastly, I thought my view was like 2026 talking with investors, you guys had the holding company structure going. You had such great tailwinds with -- coming from the RFPs. It was like a transformative year for Portland now to jump into a transaction. Just the timing of why now, I guess, because I was looking at 2026 as a very transformative year for Portland on that holding company structure, more financing, you had these RFP wins. And now it's like a 12-month freeze.

Actually, I -- the transformational 2026 is exactly correct. I wouldn't call it a freeze at all. Joe talked about the operational work we're doing across the company. We have tremendous opportunities with regards to customer growth, and we have some RFP wins. We also continue to work with regulators on a number of topics that are constructive. And we look forward to being able to close on this transaction in mid-2027, and it gives us a unique opportunity to continue our growth trajectory.

Our next question comes from Andrew Levi with Hite Hedge.

Can you hear me?

We can.

So a couple of questions. So just on the holding company, so you have settlement talks next week. Is that correct?

We do. We have them this week.

This week...

As well as in March. These discussions will probably go on through to the summer.

Okay. So I guess my question was this transaction, does this enhance the possibility of getting the holding company approved?

Yes, I mean, we believe that this transaction both supports the logic that was laid out in the holding company, but it also is the cleanest vehicle here to allow for the benefits of this transaction, which to the Oregon or to the Washington customers to be clearly identified and work through the process. I mean we just see the holding company as just a natural way to clearly make this work. It is not required. It is not a prerequisite for this transaction, but we do think that it is very clean. It makes for a very different way...

That wasn't my question. My question was, does this enhance the possibility of settling your HoldCo case by having this acquisition?

Obviously, the regulators will work through the process. Do we think that this provides further validation and clarity to this? Yes. Do we believe it enhances the view of why a holding company makes sense for Portland? Yes. And we look forward to discussing these in detail at these settlement conferences.

Okay. And then why -- just based on Maria's comment, why are we -- why does it bleed into the summer? Why wouldn't you be able to potentially settle next week? What's kind of the sticking points? And then I have a few other questions.

Sure. I mean, Andy, I'll just do it. As it relates to timing, there are 2 scheduled settlement conferences that are out there. And in all honesty, to Maria's comment that there are scheduled settlement conferences to the extent that we're having constructive dialogue and those settlement conferences do not yield a result, we -- there can be discussions that will continue up until once we get into the procedural part of a case and filing with an ultimate resolution required here at the end of June.

I mean there's nothing to say, I mean what the sticking points in all honesty, as we've gone through on the holding company, which got a little clear in this last round of testimony are about what are the benefits for the customers. And I think this, again, back to what I said before, is just another validating point that we had a compelling case before. This does nothing more that we believe and puts more weight on the scale because this transaction is about -- also about benefits to Oregon.

Okay. And then on the Hancock partnership, so how should we think about that longer term? So obviously, I understand the partnership within Washington. But you get this holding company approved. Do you envision Hancock possibly doing a similar type of investment in Oregon? And is that kind of the longer-term goal in part of this transaction and having Hancock involved?

Having a partner involved, this partner is focused on Washington. But having a partner involved to support growth while continuing to manage our balance sheet strength, our credit quality, that's really what the focus is. So the idea of the partner here is to give us an efficient form of capital, allows us to support this growth. So we will continue to evaluate our financing options and flexibility going forward. But the key to the partner here was about continuing to have the right balance sheet strength.

And then just a couple of questions on the Oregon business. So on the '23 RFP, I guess, the primary -- the bigger investment is solar/batteries. Is that correct?

Yes.

That's the $400 million and whatever million, right? So once that goes COD, right, that goes right into rates because since it's a combined asset, right? Is that right?

Correct, Andy. Both had...

So, that's...

There's 2 projects. One is Wheatridge and one at Biglow, and both will use the renewable adjustment mechanism.

So does that -- obviously, you got this distribution rate increase. Does this help continue to postpone a base rate increase or base -- not base rate increase, but a general rate case, I should say?

Speaker.

So we will be evaluating where we are with the general rate case. As you may remember, we have a stay out until about mid-summer. But the last time we brought in energy, we actually had customer prices go down. And so that was the Clearwater project in Montana. On the regulatory side, we're also working through a multiyear framework, and we'll evaluate that also in conjunction with whether we do a rate case this summer.

And one -- my last question is just around hyperscalers. So I guess in the handout, you talked about 430 megawatts, I think it was with incremental load, something like that, right? Is that the number?

Yes.

There you inked in the -- was that in the quarter you inked or was that for the year?

So those are 5 contracts. The names of the different companies are highlighted in the deck of the materials. This is in the fourth quarter and then in the very first part of 2026.

And then you have -- there's up to another 1,200 megawatts of talks going on, I guess, is that my understanding not correct or...

Yes. And we have people in our queue, and it's actually 1.7 gigawatts, Andy, and we have comps...

1.7 gigawatts, I'm sorry...

Yes, some of those are with existing customers and some of those are with new customers.

So how should we think about that incremental load? Obviously, it's under the new tariff rules. How should we think about that as far as your 5% to 7% forecast and whether that's actually included or whether that gets you to the high end of your forecast or above your long-term growth rate?

So as I mentioned before, this supports continued growth within that 5% to 7%. And it also -- the data centers create additional margin that supports the capital investment needed to support them as well as ensures affordability for residential and small commercial businesses.

Does the Washington acquisition get you -- maybe not in the first year, but as you get out to '28 and '29, also see a big step-up in CapEx in Washington, especially in the outer years, does that get you to the high end of your forecast?

Yes, that keeps on moving us through our forecast range, supporting accretion in the first year and underlying our growth trajectory long-term of 5% to 7%.

Andy, I'll just add to you, as I mentioned before, right, take this individually, each one of these items has enhancements within the growth trajectory. And as the dust settles a little bit here and as the HoldCo works, how Washington matures itself to approval, we will reassess what these individual enhancements mean to the long-term trajectory as there are several items that we've spoken here today that all have individually positive pressure on the upward side of our earnings guidance.

And then I'm sorry, I just have one last question, and I'll let somebody else go. But if for some reason, the HoldCo doesn't get approved, should we just assume hybrids at that point? Or how should we think about it?

I do think if the HoldCo is not approved...

That $600 million -- you know, the $600 million you talked about.

That's right. I mean I think we will do a -- what makes sense is a combined set of financing. We will look at -- if we don't have the HoldCo, based on what structure we have and where we finance, we will look to what are the right instruments and the right mix at that time that still allows us to realize the value that we see in this transaction.

Our next question comes from Steve Fleishman with Wolfe Research.

What are the -- remind me what the approval requirements are in Oregon and Washington. Are they no harm to customers? Are they net benefits? About standards...

So in -- in Oregon is a no harm standard and think of that as both a qualitative and quantitative no harm standard with about an 11-month approval process for Oregon. In Washington, it is a net benefit standard, that same approach of qualitative and quantitative net benefits with an 11-month approval process with the ability under circumstances to get a 4-month extension.

Okay. And then just -- how did you get kind of comfortable on wildfire risk in the Washington territory? Just any color on kind of the nature of that territory and the like?

Sure. So as you know, we spend a lot of time on managing wildfire risk from prevention and mitigation to early detection and working closely with first responders and have as mature a process and program as any utility. PacifiCorp also has done quite a bit of work. We calibrate with them, both in Oregon as well as work with Washington regulators. They have a wildfire approved plan for years 2024 through 2027. We will pick up that plan, but also bring our expertise as well as collaboration with Washington regulators and stakeholders as we work in both states to improve the risk framework and investability of utility businesses in both states.

Our next question comes from Matt Davis with North Rock.

Sorry, my questions have been asked and answered.

Our next question is a follow-up from Julien Dumoulin-Smith with Jefferies.

Sorry, coming right back here real quickly. Just want to make sure I heard you right. How are you thinking about that $600 million in equity financing at HoldCo? What are the gating factors here? How do you think about like FFO to debt from the rating agencies? What do they want to see thus far in terms of limiting parameters here? Any comments or statements, any pro forma targets that they're at least initially giving you? Any reason that you couldn't imagine doing a fully debt financed HoldCo transaction, for instance?

Julien. So a couple of things. So our discussions with the rating agencies have been preliminary, right? Our -- and our focus with them has been about investment grade across each of the utilities and the proposed holding company. To the specific financing plan at what would be the proposed holding company, there is -- we will evaluate what is the right mix.

To your question of how you finance at the holding company, we don't want to front run the regulatory process, which may have certain requirements for reporting. But what we're committed to do is to effectively use the holding company to allow for what is a good financing structure for the company consistent with other utilities, but we would like to make sure we're aligned with our regulators and their approach. But the holding company, if you take it to its fundamental, just like you laid out, it should give us the flexibility for the choices for what are the right instruments for us where right now without a holding company, we do have somewhat of a limited choices as we try to manage our balance sheet, manage our credit metrics.

And our final question comes from Paul Fremont with Ladenburg Thalmann & Co.

Does the diversification of state regulatory risk play a role in your decision to acquire the Berkshire properties in Washington?

Yes. Not only are we gaining important economies of scale, but having 2 different jurisdictions to operate in is very beneficial.

And then sort of following up on Andy Levi's question. Obviously, you haven't determined the mix of debt and equity. But should we look at the establishment of the holding company as potentially driving the mix? In other words, might there be less equity issued if you were granted approval to establish a holding company?

Paul, so I agree, right? The holding company itself is this variable to flexibility. So yes, there are opportunities at the holding company, if approved in the structure that you could get a differing cap structure. And all honestly, if even not for the holding company, considering what structure we'll choose, we'll have a varying amount of instruments.

But we do find the holding company to be really attractive because it comes back to -- it supports the deal. It supports driving the benefits clearly to the customers, and it gives us the flexibility to have these choices like we're talking about here of choosing what are the right instruments for the situation. I mean obviously, because the holding company is a proposed item right now and not approved, we don't want to front run the process, and we just -- we will evaluate and appreciate the flexibility that we expect that it will afford us.

And then after the Washington utility is acquired, would you expect to use consolidated accounting or equity accounting?

Our current expectation, obviously, we will finalize and haven't done the reporting is that based on the partnership structure and our operations that we would be consolidating the utility.

Got it. And then can you tell us what was the most recent PacifiCorp Washington rate base?

It's $1.4 billion.

And that would be as of -- is that at the end of '25, the end of '24?

End of 2025.

I believe you'll find that -- that rate base was included in a fuel type filing, an energy filing is where it was last presented. And I believe it's called their -- and do not ask me for to spell that, it's called their [indiscernible] They have been -- as they've disclosed, which they've talked in their release, they have been attempting to sort of restructure their multistate setup here. And this was a movement in the multistate to start to realign what assets they are serving, what parts of the -- of their set of companies, not completely, at least partially address that.

And then...

Last question from -- sorry.

I was just going to say we look forward to in Washington, we believe they've been pretty constructive on the regulatory front, have the opportunity for a multiyear plan and think that their mechanisms are somewhat helpful to the fuel recovery. So I just want to finish that thought.

Great. And then I think in the past, you've given us sort of a sense of what percent of properties in Oregon are high risk relative to wildfire. Is there a similar percent that you can share with us in the Washington properties?

You know, as we move forward, we will do the same sort of disclosure that we have. Overall, it's pretty similar to Oregon, where it's actually quite low, maybe about 2% or so. It's about 20 distribution miles. Much of the area that you can see on higher fire risk maps is actually non -- not in hazard by individuals that's forest service or tribal land.

This concludes the question-and-answer session. I would now like to turn it back to Maria Pope for closing remarks.

Thank you very much for joining us today. We remain focused on delivering efficient, effective operations, realizing economies of scale and regulatory frameworks that support customer affordability as we move forward with this exciting opportunity. We're advancing critical infrastructure investments that will support economic development, both in Oregon and in Washington and builds on a base of growing data center and high-tech customers.

The Washington opportunity and acquisition of PacifiCorp's assets represent a strong operational fit. They're accretive in the first year and enhances our long-term EPS and dividend growth guidance of 5% to 7% as well as credit supportive. We look forward to moving through the process with stakeholders and regulators on a number of fronts and speaking with you next quarter and probably meeting with many of you at investor conferences in the months and weeks to come. Thank you very much for joining us.

Thank you. This concludes today's conference call. Thanks for participating. You may now disconnect.

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 5 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 5 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 earlier this month. The short list reflects a rigorous least cost, least risk approach designed to yield reliable, affordable outcomes on time lines, 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, was also launched in July. All bids have been received, and we are now evaluating projects and building towards 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 own 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 grid care 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, [ caliber ] at [ Angen ] and digital infrastructure provider of line [ DataCash ]. The agreement will deliver a battery system to align 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, support affordability for all customers.

Risk management. Wildfire season has officially ended in our service area. Our comprehensive year-end mitigation programs continues as we work to deliver results. Hardening the system, enhancing situation awareness and deploying technology to protect our communities and improve the liability. We recognize that more is needed to address the collective risk presented by wildfires and extreme weather. We remain committed to working with policy [ makes ] 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 arm 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 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 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. 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.

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 and $0.04 of various miscellaneous items.

And lastly, a $0.06 decrease from business transformation and optimization expenses, bringing our GAAP EPS of $0.94 per diluted share. After adjusting for this impact, we reach our Q3 2025 non-GAAP EPS of $1 per diluted share.

Turning to Slide 7 for our capital forecast. Our plan continues to focus on expanding our transmission capabilities, optimizing our distribution system and maintaining a reliable generation fleet. As Maria highlighted, the 2023 RFP continues to advance towards resolution, and we are pleased with the over 1 gigawatt of solar and battery projects on the updated final shortlist. We have requested OPUC acknowledgment in the fourth quarter, and we continue to expect the projects will be in service by the end of 2027. We will update our CapEx plan for the incoming 2023 RFP projects as those negotiations finalize and contracts are executed in the coming months.

Overall, these projects bolster our rate base growth trajectory as we serve the significant demand we're experiencing and support Oregon's clean energy goals.

On to Slide 8 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 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 during the quarter, we completed our ATM pricing activity for 2025 in support of our base equity need for the year. 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 now have $137 million of equity price but not drawn under our ATM, 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 will provide financing clarity in tandem with our final CapEx expectations.

We are also continuing to work closely with key stakeholders on the proposed holding company formation aimed at creating important flexibility as we seek the most efficient financing options for our customers and shareholders. This structure can help reduce costs and create optionality in how we fund critical grid investments with the potential to displace future equity needs for both base and [indiscernible] CapEx.

As we look back at our progress over the last 3 months -- or 3 quarters and turn to Q4, we are proud of our results and disciplined execution. We are optimizing our business while advancing important regulatory items all while remaining laser-focused on serving the growth in our area and delivering value to our customers and shareholders. In Q4, we expect the continued impact of load growth, moderately favorable power cost, supported financing and benefits from our cost management work. Given our results through Q3, in line of sight to Q4, our plan remains on course. We are reaffirming our 2025 adjusted earnings guidance of $3.13 to $3.33 per diluted share. Our progress in 2025 underpinned by our rate base investment pipeline, sustained confidence in our service territory and sharpened operational performance has also 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.

As we look to the balance of the year and beyond, we are excited to continue delivering on our strategic plan: Safe, reliable and efficient service, advancing the priorities of our company, communities and region and maximizing value for our customers, communities and shareholders.

Now operator, we are ready for questions.

[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 [ generations ] 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 [indiscernible] is 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.

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, [indiscernible] 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 2 RFPs. Obviously, this RFP, the '23 we mentioned has just over a 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 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 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 transport 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 rate and kind of get those tails into the Transco conversation. What would it take for you to direct CapEx in 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.

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 ] 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 [ PCA ] 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 [ Konstantin ] 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 2 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?

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 [ Console ] 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?

[indiscernible], using our sort of approach this year with the Seaside, with battery approach as well as the cost management. We 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 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 item 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 Sales ] 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 a 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 an 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 -- and then -- so then using that and then looking to Seaside side, 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 in some of the [indiscernible], we would expect that to continue here with the DSP.

Great. And can you talk a little bit about how you plan to utilize [ Great Care ]? 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 [ Red Care ]. 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.

Good morning, everyone, and welcome to Portland General Electric Company's Second Quarter 2025 Earnings Conference Call. Today is Friday, July 25, 2025. This call is being recorded. [Operator Instructions] For opening remarks, I will turn the conference call over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead.

Thank you, Victor. Good morning, everyone. I'm pleased you can join us today. Before we begin this morning, I would like to remind you that we have prepared a presentation to supplement our discussion, which we'll 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 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. Starting on Slide 4. Our second quarter has been marked by strong execution across the business and significant advances in each of our 5 strategic priorities, which we've outlined in previous calls. 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 and the region's economic development; fourth, reducing risk through operational execution, system hardening and wildfire policies. And fifth, promoting an investable energy future for Oregon, updating our corporate structure and aligning legislative and regulatory policies. .

Today, we stand at the intersection of high growth and in Oregon, a continued focus on clean energy, all while driving to meet customer needs reliably and affordably. Let me describe the progress we have made in each area.

Clean Energy. To align with the one big beautiful bill and take advantage of the changes to investment tax credits and production tax credits, we're undertaking a price refresh in our 2023 RFP and accelerating our 2025 RFP procurement. Our company, region and customers remain firmly committed to a decarbonized future, and we're adopting to build on our recent progress, while also delivering maximum value. We're focused on securing projects that meet the latest timing and domestic content requirements, allowing us to maximize the impact of important federal tax credits. These credits are a significant tool in lowering the cost of clean energy and keeping customer prices as low as possible. Joe will cover this in more detail shortly.

Customer affordability. Our customer affordability commitment, multiyear cost management work is underway and delivering results. This quarter, we made the difficult decision to reduce 330 employed and contracted positions and now have process improvement work ongoing across our company. Every aspect of Portland General will be touched and everyone is involved.

Customer-driven growth. Our strong growth continues. Importantly, we're seeing sustained growth from data center and high-tech customers, over 16% compared to the same quarter last year. This comes from over a dozen text manufacturing and infrastructure companies, including the upcoming return of a significant semiconductor company to PGE's cost of service. This robust demand builds on the significant high-tech and data center growth trajectory that we have seen for over 7-plus years and benefits all customers, enabling grid-wide improvements and infrastructure upgrades while spreading the company's fixed costs across a broader base.

We're also pleased with the Oregon legislature passed the Power Act which furthers growth and brings greater clarity to the ratemaking framework, enabling regulatory flexibility to the allocation of costs and direct long-term contracting with data center customers.

Risk management. We still have work to do on wildfire policy and are focused on supporting policies that clarify standards for wildfire mitigation, established financial backstops and provide timely recovery for victims. Operationally, we're deepening our focus on wildfire mitigation and prevention with system hardening and monitoring, quick response and collaboration with first responders, including the U.S. Forest Service and the Oregon Department of Forestry and targeted use of public safety power shutoff in response to high-risk conditions, an investable energy future for Oregon.

And finally, on our last call, we discussed our intent to file for a holding company. That notification was made on May 23. And today, we completed the filings with the Oregon Public Utility Commission for the approval of a holding company, under which the existing utility company and a separate transmission company will sit. This proposed corporate structure update is designed to help reduce the cost of investments and infrastructure as we work to achieve clean energy goals and serve society's rising needs for electricity, while working to keep customer prices as low as possible.

We also worked in close collaboration with the customers and the Citizens Utility Board on the passage of the Fair Energy Act, which brings important clarity to future regulatory proceedings. This moves Oregon to a more predictable multiyear ratemaking and offers additional flexibility and opportunities for securitization as well as adjusting the timing of when new customer prices take effect.

In state regulatory proceedings, we've strengthened collaboration with all parties and recent MOU with interveners and staff in both the seaside battery filing made in May and the distributed system plan alternative recovery mechanism, the DSP arm, which we're filing later today. We're very pleased with these outcomes, which incorporate the Fair Energy Act requirements and provide well-defined path forward. This combination of multiyear rate making, the MOU and other regulatory improvements drive towards regulatory predictability in Oregon, while supporting greater precision in our planning and execution capabilities.

I want to recognize PGE's legislative and regulatory teams for the exceptional work in outcomes achieved this quarter. This includes important progress made on numerous complex topics, outcomes that move PGE forward in serving our customers.

Now let's turn to Slide 5 for financial results, and then I'll turn it over to Joe. For the second quarter, we reported GAAP net income of $62 million or $0.56 per diluted share. On a non-GAAP basis, net income was $73 million or [ $0.66 ] per share. This compares to second quarter GAAP net income of $72 million or $0.69 per diluted share. Q2 2025 non-GAAP results exclude business transformation and optimization expenses as part of our customer affordability commitment and the updates to our corporate structure.

This has been a busy quarter for Portland General Electric. We continue building on the momentum of the first half of 2025 executing on expectations and delivering results. We remain laser-focused on our strategic priorities and continued execution. Thank you to the entire PGE team for your work this quarter, bringing safe, reliable energy to our customers. and building upon our strong operational capabilities to deliver value for our stakeholders and the communities we serve. With that, I'll turn it over to Joe.

Thank you, Maria, and good morning, everyone. Q2 has indeed been a busy period for PGE, and we climbed a bunch of Hills across the organization. Turning to Slide 6. Our results reflect significant demand growth from industrial customers mild spring temperatures and the maturing of our cost management and optimization program. Total load increased 4.9% overall and 6.1% weather adjusted as compared to Q2 2024. Residential load decreased 2.3% quarter-over-quarter, but increased 1% weather-adjusted, highlighting the warmer-than-average temperatures in April and May.

Residential customer count increased by 1.4%, offset by continued energy efficiency. Commercial load increased slightly at 0.3% overall or 0.7% weather adjusted. Industrial load, particularly from data centers, continued its rapid acceleration with Q2 demand increasing 16.5% on a nominal and weather-adjusted basis.

We expect continued demand growth from our industrial customer class underpinning our reaffirmed weather-adjusted 2025 load guidance of 2.5% to 3.5%. In the long run, with the 2023 CEP IRP update published in June, captured fresh load inputs further solidifying our long-term growth expectations of 3% through 2029.

Now I'll cover our quarter earnings driver. We experienced a $0.32 increase in total revenue, driven by a $0.12 increase from the 4.9% demand growth and a $0.20 increase from the average price of deliveries from improved recovery, partially offset by delivery composition changes, a decrease from power costs of $0.20, driven by a $0.12 EPS decrease from power cost performance in 2024 that reverses for this comparison and an $0.08 decrease from current year power cost performance driven by less favorable wholesale and environmental credit market conditions.

A $0.06 EPS increase from lower operations and maintenance expenses as we begin to realize the benefits and savings from our cost management and optimization work. a $0.13 EPS decrease from other operating expenses in support of the ongoing rate base investments made up of $0.10 from higher depreciation and amortization and $0.03 from higher interest expense. An $0.08 decrease from other items, including $0.04 from dilution and $0.04 from other miscellaneous items. And lastly, a $0.10 decrease from business transformation and optimization expenses as we update our practices and corporate structure to achieve improved financing flexibility and lower long-term -- lower our long-term cost.

This brings us to our GAAP EPS of $0.56 per diluted share after adjusting for the $0.10 impact we reach our Q2 2025 non-GAAP EPS of $0.66 per diluted share.

Turning to Slide 7 for our 5-year capital forecast. We've made a modest reduction in 2025 -- to our 2025 forecast due to efficiencies from our capital execution this year. Overall, we plan -- our plan continues to support the trajectory of our growth and the escalating needs of our customers and region. On to Slide 8, I'll detail meaningful regulatory and stakeholder progress Maria highlighted earlier. After thorough engagement with regulatory stakeholders, PGE signed an MOU in June with the OPUC staff, the Oregon CUB and AEC, which will govern 2 important cost recovery proceedings.

First, the expedited recovery of the seaside battery project, which began serving customers in early July. This filing has a proposed conclusion of October 2025. Second, an alternative recovery mechanism for distribution system assets, the DSP arm, which has a proposed conclusion of April 2026. As a result of the MOU, the earliest filing for our next general rate review would occur after Q2 2026 with the earliest rate effective date being May 1, 2027. Combined, these 2 proceedings covered nearly $600 million of critical rate base investments serving customers while also clarifying our regulatory path and go-forward strategy.

Moving to Slide 9 for an update on resource planning and procurement. With the passage of the federal legislative package, PGE is planning a price refresh for conforming bidders in the 2023 RFP. We undertook a very similar process in our 2021 RFP, which also navigated tariff and tax policy changes. This refresh is a strong net positive, allowing bidders to price in what was once uncertain, lowering risk and improving consideration of key macro factors. In collaboration with the RFP independent evaluator, we will work to update bid scoring and ranking to reflect pricing changes in the coming months. We still expect contract execution by year-end and remain firmly committed to a 2027 COD target for these projects.

Overall, we expect a similar opportunity set for the 2023 RFP CapEx investments, which supports our long-term growth expectations. As we noted in the recent CEP IRP update, we have large procurement needs ahead, driving the 2025 RFP, which we plan to issue to the market in the coming weeks. The current time line anticipates a final short list in the first half of 2026 and with contract execution later next year as we track to complete the projects by the end of the decade.

We'll continue to utilize a lease cost and lease risk selection approach, which will evolve to capture the changing tax policy environment and impacts to customer prices for RFP projects. At this time, we see limited tax credit exposure for the 2023 RFP projects, especially given the firm end of 2027 COD requirement. For the 2025 RFP projects, tax credit eligibility will be key as we evaluate acceleration to keep customer prices -- price impacts as low as possible.

In both the 2023 and 2025 RFP, we are focused on maximizing tax credits to dampen customer price impacts.

On to Slide 10 for our liquidity and financing summary. Total liquidity at the end of Q2 was $980 million, and our credit ratings and outlook remained static since the last quarter. As of June 30, we have $104 million of equity priced but not drawn under our ATM. Our total equity target in 2025 remains at about $300 million in support of our capital program. As our holding company application proceeds, we'll continue evaluating our financing needs as we seek the most efficient options for our customers and shareholders. This approach helps reduce costs, better serve customers and creates optionality in how we fund critical grid investments in support of the growing demand for clean, reliable energy.

This also dovetails with our broader cost management work, which is scaling as designed to reduce costs across the organization. We're leaving no stone unturned, and we have -- as we enhance our practices and optimize our structure to safely operate, meet our financial commitments and keep customer prices as low as possible.

We are pleased with our year-to-date execution and remain committed to achieving our full year plan. Our progress in Q2 has kept us on course for a solid performance. We are reaffirming our 2025 adjusted earnings guidance of $3.13 to $3.33 per diluted share and our long-term earnings and dividend growth guidance of 5% to 7%. We remain focused on safe, reliable and efficient operations, advancing our strategic priorities and achieving our commitments to deliver value to our customers, communities and shareholders. And now operator, we are ready for questions.

[Operator Instructions]

Our first question will come from line of Richard Sunderland from JPMorgan. .

A lot of things in motion here. Appreciate all the color. Maybe starting with this MOU and the side and distribution recovery proceedings, how do you think that MOU informs the path to actually progress through those 2 proceedings in a fashion versus a general rate case more broadly. I guess I'm curious how you think these proceedings will be different. Is this just a focus on the prudency of capital? Maybe to frame it more broadly, how do you think about the $600 million of rate base you highlighted is in these 2 proceedings and how intervenors are going to evaluate that under the terms of the MOU?

Great. Great question. And so first of all, I think we have really front-loaded a lot of the discussion -- with regards to the seaside battery projects, which, by the way, is fully operational and delivering tremendous value to customers, keeping energy prices lower as we're into these hot summer months. But as we also include the distributed system plan, and much of our capital that is in the distribution system for customer growth as well as reliability. We're able to have a lot of these conversations before we actually get into a rate review proceeding.

That allows for really good understanding and shared outcomes as we file the filings under those MOUs. The first, we hope to finish up in October. That would be the Seaside Battery Project in the DSP arm in April. But again, I think we're aligning interest, having shared understanding of the work that we're doing, which should lead to certainty, predictability and driving value.

Understood. That was very helpful there. Switching to the RFP topics. You mentioned tax credit eligibility is key for the '25 RFP. I guess, turning back to 2023, how do you think about the price refresh and then opportunities to execute those projects in the back half of the year? Is there a potential to accelerate some of the procurement from the '23 RFP where you seem less concerned with the tax credit eligibility. I guess just '23 versus '25 RFPs, any other dynamics you'd highlight there?

Richard, so as it relates to 2023 RFP. So yes, there is the opportunity to accelerate. The reprice will open up to all of the bidders that were in the original short list. And so that selection will be expanded. I mean we do think it's a -- I think it's a good opportunity to drive certainty here. We expect similar performance that we saw in the last case. But the whole point of this reprice RFP is that to really be able to get clarity for these bidders. And then also, I know we were talking '23, but in '25, to start moving quickly on '25 to hopefully find -- to be able to have time to identify bidders who have the tax credit ability for those projects as well. .

Got it. That's helpful. And then sorry, just one final cleanup for me. The business transformation efforts and the cost there, are those going to continue over the balance of the year into next? Or is that kind of a one and done on this quarter?

Yes. As it relates to the business transformation, we're just getting rolling. I mean we're pretty excited about the momentum that we created we would expect that we'll incur cost or investments as it relates to the business transformation into next year, a collection of costs related to change management as well as other items. But clearly, having the benefits will start to really yield themselves later this year and then create a pretty significant momentum into next year. But on the cost exclusion side, that is something that will work into '26.

Our next question will come from the line of Chris Ellinghaus from Siebert Williams Shank.

Can you talk, Maria, a little bit about 3179 and some of the limitations that are within that legislation in terms of like rate timing and things like that. Will that make you make adjustments for when you try to time investment? Or is that just something you think you can just work around?

Sure. So first of all, the bill that you're referring to is the Fair Act and something that we worked collaboratively with the Citizens Utility Board, with customers. And we're really pleased that it creates the opportunity to really look at multiyear rate making. And we are also focused on ensuring that all of our systems and our processes are aligned with customer prices going into effect in April to November time period and not during the most difficult months of winter. So much of that is internal work that we need to do and isn't a problem, but just as work to get done.

Overall, we're very pleased with the ability to have increased securitization. And we've had a lot of good discussions on what is good long-term rate making look like in the current environment and as we go forward. I think our MOUs that we've just talked about in answer to Richard's questions, right along those same lines of how do we work better together for outcomes that ensure adequate investment for our economic growth in the state of Oregon, for customers and for reliability and affordability while delivering value to all stakeholders and good returns on equity.

Okay. And with SB-688, can you just sort of talk about how you envision utilizing [ TDRs ]?

So when we look at what your -- the bill that you're referring to is what we call the Power Act, and as we look to that, we're looking at performance metrics that are connected to our core work. I don't -- in terms of performance rate making, I don't think we've been long talking about this with our regulators, and we're not -- I'm not overly concerned about working through these issues. .

Obviously, we need clean energy, energy efficiency, and these aren't new concepts. In fact, you probably know that we have some of the most productive energy efficiency programs in the entire country. And Portland General Electric customers, we have the #1 clean energy program. But as we also look to serving a diversified and growing customer base, particularly data centers and semiconductors. All of these things work together.

Okay. In the MOU, and it's probably fairly irrelevant given the timing of the next GRC filing. But going forward into the future, does that MOU have any bearing on utilization of ARMs in the future?

No, I think we'll continue the conversations and keep looking at what's going to work best given the different work we have in front of us and how we can best serve customers. Joe, do you want to add something? .

Yes. The MOU is a onetime item specific to these. And then the same thing with the arm. The ARM is a specific item, and the way we think of the ARM side, they're a nice bridge between now, the next rate review and then ultimately, a multiyear plan. We think this ties nicely with the the legislation that's come out there and the timing of rate cases, it continues to tie to our overall growth plan of just how these rate reviews can be laid out in a way where we can keep the cost as low as possible for the customer, we can manage our costs and do some internal items that really just bridge us across what is a longer period of time and create some clarity and certainty as we work through the regulatory framework over the next few years.

Okay. That helps, Joe. And lastly, you gave us a bunch of dockets to Peru for the weekend. Are you still expecting the Seaside intervener testimony today to be filed?

Hopefully, I would also say that there's more still to come. So Chris, you should be expecting the DSP later this afternoon. And clearly, you've got all of the WholesoTransco filings this morning.

Yes. So you gave us a lot of homework. I appreciate that.

Our next question will come from the line of Julien Dumoulin-Smith from Jefferies. .

It's Brian Russo, on for Julian. Just with the House Bill 3179 and the DSP filing in the ARM, how would you see your ROEs trending until you get new base rates? I think 2025 guidance assumes an 8.8% to 9.1% versus your allowed ROE. Do you think you can maintain that type of return level? Or should we expect any sort of degradation given the timing of the next base rate case.

So our intention here is that the combination of our cost management actions, the timing of these cases is to really continue in that same type of earnings and we don't -- we don't expect to see any additional lag. I think the range that you derived of the earned ROE side continues to be where our expectation lies with even considering this legislation.

In all honesty, our regulatory plan our growth plan contemplate something very similar to this. So we'd expect our performance that relative earned to allow to be consisting over this period.

Okay. Great. And then the 23 CEP IRP update actually calls for 800 megawatts more of renewables and storage. And I'm just curious, with the OBBB -- and does that increase Portland General's competitiveness to essentially improve the win rate, which I think historically has been about 25%?

So we talk about 25% as sort of a baseline that's in our financial forecast. But our actual performance has actually exceeded that. As when we work with parties on projects that end up as ownership, we're only focused on Portland General Electric customers. We're not looking at other customers to serve. So we're more focused on what would meet the needs of this specific region and also making sure that very cost conscious and cost competitive as these are all lease cost, lease risk competitive projects.

We've done well in the past. And we also have a number of PBAs that come into our service territory as well. And actually, you can see those in the financial statements because we pull them out somewhat separately on the energy procurement line. So balanced with all parties to make sure that we're achieving lease costs, lease risk, clean energy options for customers.

All right. And then lastly, assuming a 12-month review and approval process for the holdco, how should we think about kind of the August 2026 kind of new structure and capital markets initiatives. It's a $300 million a year, still applicable with 50-50 financing for RFP related investments? Or is there something about this holdco structure that can alter that and I guess, just make it more efficient.

So as it relates to the holdco, we look forward to working through the proceeding here through to next year. The goal of the holdco is to drive flexibility. So as the holdco gets ultimately defined and put in place. And as a reminder, right, in addition, there would be a Transco we will evaluate what flexibility it provides, how it allows us to yield greater benefits for our customers as well as us.

And in that time, we will also rethink what that means to our financing plan. We really just -- we want to wait and see how this lays itself out and then how do we most efficiently over time, drive what benefits will come from having the holdco.

Our next question will come from the line of Nicholas Campanella from Barclays.

Yes, a lot of good questions. Just a quick follow-up on the RFP repricing. It sounds like you still see a good opportunity for ownership in any outcome, but just -- with prices potentially being higher, is that additive to the current 9% rate base CAGR that you show in slides -- are there offsets elsewhere in the plan? Can you just kind of talk about like competition for capital in the plan at this point? And then how you think about financing that?

Sure. So as it relates to our base plan that we know as a specific capital, right, obviously, doesn't include the results of the RFP and then we have the illustrative growth. I mean this this really just underpins that illustrative growth that we showed a 25% rate, right? We yielded about a 60% win rate in 2021. But we really just think that the reprice here gives an opportunity to drive this certainty. We think it yields a very similar opportunity set for both the overall megawatts as well as our performance in the overall portfolio. I mean we just think of it as the reprice here is driving certainty into what has been a bit of an uncertain time.

Okay. Okay. And then just the distribution filing that you're going to be putting out there today if that gets approved, and then you're then going in to file the next case after that, just what do rate cases look like if you have this type of structure in place going forward? I would imagine that they're less onerous from an ask level, but maybe you can kind of talk through some of the puts and takes around the benefits of that?

I think we look at the overall puts and takes sort of in the totality of the whole and it's really based on good conversations with all stakeholders, ensuring that we have alignment on the work that we're doing, keeping customer prices as low as possible, but ensuring that we are supporting and enabling the growth across the region that is making a difference in our economy.

Nick, if I could add, right? So we're -- when we think to the cases, right, I mean we've been pretty clear on -- you have the Seaside tracker and then you have the DSP and then some kind of a rate review within the committed period, right? And the goal here is to have predictability, both on our side as well as the stakeholder side. It allows us to have time to continue to drive the cost benefits that we're driving into the organization to yield here.

But Ultimately, I think of these all as steps along the path to get towards the multiyear a multiyear plan, which gets to a place, I think, for both parties where we can get clarity and have clarity over longer periods of time here instead of some of these small steps, although I think right now, I think there's some pretty clear thoughtful aligned steps that we have? All right. We're looking forward to seeing you.

Our next question will come from the line of Gregg Orrill from UBS.

I was just wondering if you could sort of talk about the balance of your sort of earnings bridge versus last year, sort of the the variable power margin drivers to kind of bridge the gap there, which I think is around [indiscernible]? .

2024 and 2025 are a little bit of a challenge to compare. As you recall, in '24, very front-end loaded. Now we came in above the midpoint of our guidance there on the actual results, but it was -- a lot of that earnings was in the first half of the year, and it was weighted to what were some pretty favorable market conditions that occurred both on a load consumption side but also on a favorable pricing side at the same time.

And if you recall, in Q3 and Q4 of last year, we tailed off pretty significantly to where Q4 was quite a low performer. This year, based on the way the energy markets have set themselves up based on the way that the cost management and the cases have set themselves up, we see this as a much more evenly distributed plan. And we just need to continue to -- from where we sit right now, continuing on our path is staying on our net variable power cost plan in year to hit our results.

So we think this year is a lot cleaner and not as not as unusual flow, right? The last year is the one that's causing more of the uncertainty. And we're pretty confident. I mean based on where we sit cost management-wise, understanding we had a warmer April and May. We feel we're pretty -- we're set up pretty well to have a solid performance considering normal bands of market price and load consumption.

Our next question will come from the line of Sophie Karp from KBCM.

And I appreciate the comprehensive update this morning. So I just kind of wanted to dig a little bit more on what Nick was asking. So with the Seaside tracker in place, I guess, on the distribution recovery separate, how much capital would you save and would be subject to general rate reviews and kind of rate cases going forward? Is there like a percentage you can think of to help us think about how the importance of rate cases might be diminished in the future?

Sure. I think the best way of taking a look at that, Sophie, is looking at our capital plan as we go forward. And you'll see that the bulk of our capital spend, and it's on Page 7 of the slides, is in the distribution area. Much of that is reliability related work that we do. Much of this area that we serve grew about -- quite dramatically, about 60 to 40 years ago, and that equipment is getting older and it's quite a bit of replacement. .

We also have the renewable adjustment cost, the rack for all wind and solar projects. And so that's another way that we can have customer prices tracked. And then we also have for wildfire, the AAC as well. So there's a lot of good work to create more predictability which also enhances our ability from an operational planning standpoint along executing on 5-year disciplined plans.

Right, right, right. So yes, that sounds like a lot of the capital will be recovered more contemporaneously to these mechanisms. Can you remind us what would govern I guess, the allowed ROEs over this entire kind of portfolio of capital spend? Is that an area that's going to be set in this rate review? Or is that for proceeding, like, how do they work?

So taking a look at the ROE would require a general rate case. And we're planning on that in the future. But right now, we have a really good bridge through great recovery of recovery opportunities of the capital we've just discussed as well as a number of other improvements from our cost structure as well as financing alternatives.

Great. Great. And lastly from me, I guess. I'm assuming your next rate case would be a multiyear rate case already?

That is -- we're going to start having that discussion with parties, and I wouldn't want to front run the conversations. There's benefits to that, that allow for greater certainty of sort of the blocking and tackling kind of capital that we do, which we've long benefited from in terms of clean energy.

I think, Sophie, right. We think we have a clear path to ultimately get to it. I mean it will be up to just working collaboratively with the groups to determine if that cases it, but we think we are well on the path here. And it's just a matter of -- a matter of which case it will fall in.

Our next question will come from the line of Anthony Crowdell from Mizuho.

I wanted to jump on Nick's question, and I think Nick was jumping on Richard's question. But I said you may want to answer it. On one of the other earnings calls we had earlier this week, one of the companies was talking about when you look at renewable projects and there's changes in tax law or I'm were like just some turbulence in the whole business model, it's benefited certain developers and hurt other developers. And when I -- you guys had mentioned, I think your forecast was based on a 25% win rate from the RFPs, but you've achieved kind of, I think, you said a 60% number. Do you see those numbers changing in the repricing of the RFPs?

No. I think as we look, as we go forward, we're going to see what kind of projects come forth. We do have a number of very beneficial partnerships with developers, but we also have a number of completely third-party developers that bid in. The 25% that you're referring to is illustrative in our forecast and sort of a baseline. As Joe mentioned, our most recent build percentages were about 60%.

To add on with where -- the IRP update set, we believe that in this reprice, there is plenty of room for all parties here. We expect to have pretty solid performance and back to Maria, we use the 25% here is solely a guide.

I think we need to remember that we have a great window while we have investment tax credits and production tax credits that can significantly reduce the cost of clean energy in customer prices.

Got it. And then I want to jump on Richard's question. I think that was on the business transformation and optimization. And you talked that you would see that through 2025, those charges and we'd start to see them benefiting in '26? And my question is did I hear that right? And do we see the same magnitude or the actual amount of the charges? Or does that improve as we move closer to the beneficial part of it?

So the charges will taper into '26, but the charges are more front-end loaded here, right? We're making some pretty significant investments here that the biggest investments on the spend side are going to be here in '25, they'll trickle into '26 here. And really just -- and the true then benefits will really start to materialize. Obviously, there are already benefits this year. will materialize next year. We view the benefits that we'll see next year, combined with the regulatory items, as we talk to is really part of our nice clear path to continue to perform in our earnings expand. .

And overall, if you think to the cost, pretty solid performance. But because we're trying to drive transformational change, we're going to thoughtfully step into these changes over time. But even with that, the payback period of time on -- from investment to true net return is really a year -- right around a year or less.

In our forecast, and I think this is to Brian Russo's question, should we be updating our assumption for earned return once this program starts yielding fruit or that's not what you're trying to tell us? .

So what we're saying is we believe, to our earned return guidance, I believe, we've given you had somewhere around 70 basis points or so at the midpoint. We believe that right, our plan that we have now, we will hold that type of item right. That's a compressed number from what you've seen before. But we believe that the cost management plan will continue to allow us to earn to get that earned ROE in that higher range that we've talked about in our guidance.

Our next question will come from the line of Travis Miller from Morningstar.

I think you've answered the multiple derivatives of all my questions, but have a higher level, maybe a different subject here. As you get more of this industrial demand growth and that becomes a larger share of your total demand -- how do you see that now? Or how do you anticipate that changing purchase power costs, that variable costs, anything involved in the wholesale market. Just wondering if an industrial demand comes with a different type of pricing environment, if that's the right word to use?

So first of all, that's a great question and a complex question. The first is that under some of the legislation that just recently passed, is the Power Act. And in the spirit of [indiscernible] give you the number, it's UM2377. We are able to do long-term contracting with key customers, in particular, with data centers, 10-year-plus contracts, which will make a big difference in how we're able to secure ties that investment into infrastructure and enable better financing long term.

From a power cost standpoint, that will go all the way into generation projects, which should overall reduce power costs pressures on all customers. From the power cost side, many of the things that we have been doing have made a tremendous difference already. I would note that we have just under 500 megawatts of battery storage which is really smooth customer prices, particularly during these critical periods of the summertime and cold winter days, but also are advancing across Western wide energy markets. We've announced our intention to join the energy day-ahead market. led by the California Independent System Operator, and that will also make a big difference in terms of procurement west-wide and taking advantage of excess renewable energy generated and Desert Southwest and in California.

We've seen remarkable change in power flows already, and we expect to see more, which will only benefit customers in our region as we work to lower costs.

Okay. That's great. Appreciate that. All of that, that you talked about and especially with the contracting opportunity, will that reduce some of the earnings exposure to net variable power costs or no change in that earnings [indiscernible] .

So we need to go to -- on the net variable power cost side is really looking at the underlying rate design, some improvements that we can make in our PCAM mechanism, as well as the volatility that we just see as an evolution of the growth of the region and the tighter markets overall, as well as balancing that with the energy day-ahead market. We're going to have to rationalize how these work because there are some conflicts that we will experience in the late fall of 2026 after we go live with EDAM.

Okay. Perfect. I appreciate it. One quick clarification. The timing of that base rate case, is that part of the DSP or the MOUs? Or is that just your anticipation of when you might need it [indiscernible] ?

In the MOU, we haven't agreed upon a not before a filing or not before that Q2 -- the beginning of Q3 in 2026. So that isn't agreed upon.

Okay. But you don't have to, just...

I'm not showing any further questions in the queue. I would now like to turn the call back over to Mario Pope for closing remarks. .

Great. Thank you for joining us all today. We appreciate your interest in Portland General Electric, and we hope to connect with you soon. Thank you very much. Have a great day.

Thank you for your participation in today's conference. This does conclude the program. You may now disconnect. Everyone, have a great day.