POR - NYSE

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 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 that 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 DSPARM, 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 -- 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 AWEC, 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 DSPARM, 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 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. I appreciate all the color. Maybe starting with this MOU and the Seaside 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 those 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 DSPARM 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 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 has some 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 SB688, can you just sort of talk about how you envision utilizing PBRs?

So when we look at what you -- 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's 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 Seaside, they're a nice bridge between now, the next rate review and then ultimately, a multiyear plan. We think this ties nicely with the legislation that's come out there on 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 approve 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 Holdco, Transco 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 Julien. 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 9.34% 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 stand. 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 contemplates something very similar to this. So we'd expect our performance that relative earn 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 we have a balance with all parties to make sure that we're achieving least cost, 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, obviously doesn't include the results of the RFP and then we have the illustrative growth. I mean 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 are some pretty clear, thoughtful aligned steps that we have?

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 year sort of earnings bridge versus last year, sort of the variable power margin drivers to kind of bridge the gap there, which I think is around $0.40 at the midpoint?

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, 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, continue on our path to staying on our net variable power cost plan in the year to hit our results. So we think this year is a lot cleaner and 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 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.

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 RAC, for all wind and solar projects. And so that's another way that we can have customer prices tracked in. 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 there an ROE that's going to be set in this rate review or separate proceedings? Like, how does that 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 to 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 case is 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 just think you may not 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 if I'm just using a word 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 sat, 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's, 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. 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 spend. 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 so we -- 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, the POWER Act. And in the spirit of [ Chris ], I'll 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 securitize 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 cost 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 in 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 exposure in general?

I think where 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 a base rate case or a [ DRC ]?

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

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

You don't have to file. That is the earliest that we could...

After that, you don't have to file. Okay.

That's correct.

I'm not showing any further questions in the queue. I would now like to turn the call back over to Maria 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.