Earnings Call Transcript - POR Q2 2025

Operator, Operator

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. For opening remarks, I will turn the conference call over to Portland General Electric's Manager of Investor Relations, Nick White. Please go ahead.

Nick White, Investor Relations Executive

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.

Maria MacGregor Pope, President and CEO

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 tech 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 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 a well-defined path forward. This combination of multiyear ratemaking, the MOU and other regulatory improvements drives 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.

Joseph R. Trpik, Senior Vice President of Finance and CFO

Thank you, Maria, and good morning, everyone. Q2 has indeed been a busy period for PGE, and we have made significant progress across the organization. Our results reflect considerable demand growth from industrial customers, mild spring temperatures, and the advancement of our cost management and optimization program. Total load increased by 4.9% overall and 6.1% when adjusted for weather, compared to Q2 2024. Residential load decreased by 2.3% quarter-over-quarter but increased by 1% when weather-adjusted, which highlights the warmer-than-average temperatures in April and May. The residential customer count rose by 1.4%, though this was offset by continued energy efficiency efforts. Commercial load saw a slight increase of 0.3% overall or 0.7% when adjusted for weather. Industrial load, especially from data centers, continued to grow rapidly, with Q2 demand rising by 16.5% on both a nominal and weather-adjusted basis. We anticipate ongoing demand growth from our industrial customers, supporting our reaffirmed weather-adjusted 2025 load guidance of 2.5% to 3.5%. In the long term, the 2023 CEP/IRP update published in June provides fresh load inputs that further strengthen our long-term growth expectations of 3% through 2029. Now let me discuss our Q2 earnings drivers. We experienced a $0.32 increase in total revenue, attributed to a $0.12 increase from the 4.9% demand growth and a $0.20 increase from average delivery prices due to improved recovery. This was partially offset by changes in delivery composition; we saw a decrease from power costs of $0.20, resulting from a $0.12 EPS decline due to power cost performance in 2024 that reverses for this comparison, and an $0.08 decline from current year power cost performance amid less favorable wholesale and environmental credit market conditions. We achieved a $0.06 EPS increase from lower operations and maintenance expenses as we begin to realize benefits from our cost management and optimization efforts. There was a $0.13 EPS decrease from other operating expenses associated with ongoing rate base investments, comprising a $0.10 increase from higher depreciation and amortization and a $0.03 increase from higher interest expenses. Other items contributed an $0.08 decrease, including $0.04 from dilution and $0.04 from miscellaneous items. Finally, we saw a $0.10 decrease due to business transformation and optimization expenses as we refine our practices and corporate structure to improve financing flexibility and reduce long-term costs. This brings us to our GAAP EPS of $0.56 per diluted share. After adjustment for the $0.10 impact, our Q2 2025 non-GAAP EPS stands at $0.66 per diluted share. Turning to our 5-year capital forecast, we have made a modest reduction in our 2025 forecast due to efficiencies in our capital execution this year. Overall, our plan continues to support our growth trajectory and the increasing needs of our customers and region. Now, let’s discuss the meaningful regulatory and stakeholder progress. Following extensive engagement with regulatory stakeholders, PGE signed an MOU in June with OPUC staff, the Oregon CUB, and AWEC, which will govern two significant cost recovery proceedings. The first is the expedited recovery of the Seaside Battery Project, which started serving customers in early July, with a proposed conclusion in October 2025. The second involves an alternative recovery mechanism for distribution system assets, known as DSPARM, with a proposed conclusion of April 2026. Because of the MOU, the earliest filing for our next general rate review would occur after Q2 2026, with the earliest effective date for new rates being May 1, 2027. Together, these two proceedings comprise nearly $600 million in critical rate base investments, benefitting customers and clarifying our regulatory path and future strategy. Regarding 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. This is similar to the process we undertook in our 2021 RFP, which also addressed tariff and tax policy changes. The refresh is a net positive, allowing bidders to incorporate previously uncertain factors, thus lowering risk and enhancing considerations of key macro factors. In collaboration with the RFP independent evaluator, we will work to update bid scoring and ranking to account for these pricing changes in the coming months. We still expect contract execution by year-end and remain committed to a 2027 COD target for these projects. Overall, we foresee similar opportunities in the 2023 RFP CapEx investments that align with our long-term growth expectations. As noted in the recent CEP/IRP update, we have significant procurement needs ahead, prompting the upcoming 2025 RFP that we plan to issue to the market in the coming weeks. The current timeline aims for a final shortlist in the first half of 2026, with contract execution set for later next year, aiming to complete projects by the end of the decade. We will continue to apply a low-cost and low-risk selection approach, adapting to the evolving tax policy landscape and its impact on customer prices for RFP projects. Currently, 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 crucial as we evaluate opportunities to accelerate and maintain low customer price impacts. In both the 2023 and 2025 RFPs, our focus is on maximizing tax credits to mitigate customer price impacts. On to our liquidity and financing summary, total liquidity at the end of Q2 was $980 million, and our credit ratings and outlook have remained unchanged 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 for 2025 is approximately $300 million to support our capital program. As we progress with our holding company application, we will continue to assess our financing needs, aiming for the most efficient solutions for our customers and shareholders. This strategy helps minimize costs, enhances service to customers, and provides options for funding essential grid investments aligned with growing demand for clean, reliable energy. This complements our broader cost management efforts, which are scaling as planned to reduce costs across the organization. We are dedicated to thoroughly optimizing our practices and structure to operate safely, meet our financial commitments, and keep customer prices low. We are satisfied with our year-to-date progress and remain committed to fulfilling our annual plan. Our achievements in Q2 keep us on track for strong 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 stay focused on safe, reliable, and efficient operations while advancing our strategic priorities and delivering value to our customers, communities, and shareholders. Now, we are ready for questions.

Operator, Operator

Our first question will come from Richard Sunderland from JPMorgan.

Richard Wallace Sunderland, Analyst

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?

Maria MacGregor Pope, President and CEO

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.

Richard Wallace Sunderland, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

Regarding the 2023 RFP, there is indeed a chance to speed things up. The reprice will include all the bidders from the original shortlist, expanding the selection. We see this as a good opportunity to establish certainty. We expect to achieve similar performance to what we observed in the previous situation. The main goal of this reprice RFP is to provide clarity for these bidders. Additionally, while we are focused on 2023, it's important to start planning for 2025 to ensure we have sufficient time to identify bidders eligible for tax credits related to those projects.

Richard Wallace Sunderland, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

Yes. As it relates to the business transformation, we're just getting rolling. I mean we're pretty excited about the momentum that we've created. We would expect that we'll incur costs 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.

Operator, Operator

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

Christopher Ronald Ellinghaus, Analyst

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?

Maria MacGregor Pope, President and CEO

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.

Christopher Ronald Ellinghaus, Analyst

Okay. And with SB688, can you just sort of talk about how you envision utilizing PBRs?

Maria MacGregor Pope, President and CEO

The bill you mentioned is known as the POWER Act. We are examining performance metrics linked to our core operations. We haven't discussed performance rate setting extensively with our regulators, and I don't have significant concerns about addressing these matters. Clearly, we require clean energy and energy efficiency, which are not new ideas. In fact, we have some of the leading energy efficiency programs in the country, and Portland General Electric boasts the top clean energy program. Additionally, as we cater to a diverse and expanding customer base, especially data centers and semiconductors, all of these elements work in harmony.

Christopher Ronald Ellinghaus, Analyst

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?

Maria MacGregor Pope, President and CEO

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

Yes. The MOU is a one-time 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.

Christopher Ronald Ellinghaus, Analyst

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?

Maria MacGregor Pope, President and CEO

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.

Operator, Operator

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

Brian J. Russo, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

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 strand. 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 consistent over this period.

Brian J. Russo, Analyst

Okay. Great. The 2023 CEP/IRP update calls for 800 megawatts more of renewables and storage. I'm curious if this change increases Portland General's competitiveness and improves the win rate, which has historically been about 25%.

Maria MacGregor Pope, President and CEO

So we talk about 25% as sort of a baseline that's in our financial forecast. But our actual performance has 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 least cost, least 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, least risk, clean energy options for customers.

Brian J. Russo, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

Regarding the Holdco, we are looking forward to progressing through the process into next year. The Holdco's aim is to enhance flexibility. As the Holdco is further defined and established, we will also be assessing its associated Transco to determine what flexibility it offers and how it can provide greater advantages for both our customers and ourselves. In the meantime, we will reconsider how this impacts our financing strategy. We prefer to observe how things develop before deciding the most efficient way to leverage the benefits of having the Holdco.

Operator, Operator

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

Nicholas Joseph Campanella, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

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.

Nicholas Joseph Campanella, Analyst

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?

Maria MacGregor Pope, President and CEO

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.

Joseph R. Trpik, Senior Vice President of Finance and CFO

Nick, if I could add, when we think of the cases, we've been quite clear about the Seaside tracker, the DSP, and some kind of rate review within the committed period. The goal here is to establish predictability for both us and our stakeholders. This gives us time to continue driving the cost benefits we are implementing in the organization. Ultimately, I see these as steps toward a multiyear plan that provides clarity for both parties over longer periods, rather than focusing on smaller incremental steps. However, I believe there are currently some clear, aligned steps that we have in place.

Operator, Operator

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

Gregg Gillander Orrill, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

Comparing 2024 and 2025 is somewhat challenging. In 2024, our results were heavily front-loaded, leading us to exceed the midpoint of our guidance. However, much of our earnings came in the first half of the year, benefiting from favorable market conditions in both load consumption and pricing. In contrast, we experienced a significant decline in Q3 and Q4 last year, particularly low performance in Q4. This year, the energy markets and our cost management strategies suggest a more evenly distributed performance. We need to stay focused on our net variable power cost plan to achieve our targets. We believe this year presents a clearer outlook, and last year introduced more uncertainty. We're confident in our cost management, especially considering the warmer weather in April and May, which positions us well for solid performance within typical market price and load consumption ranges.

Operator, Operator

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

Sophie Ksenia Karp, Analyst

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?

Maria MacGregor Pope, President and CEO

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 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.

Sophie Ksenia Karp, Analyst

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?

Maria MacGregor Pope, President and CEO

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 capital we've just discussed as well as a number of other improvements from our cost structure as well as financing alternatives.

Sophie Ksenia Karp, Analyst

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

Maria MacGregor Pope, President and CEO

We are going to begin discussions with various parties, and I prefer not to preempt those talks. There are advantages to this approach as it provides more certainty regarding the fundamental capital activities we engage in, which have consistently supported our clean energy initiatives.

Joseph R. Trpik, Senior Vice President of Finance and CFO

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 which case it will fall in.

Operator, Operator

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

Anthony Christopher Crowdell, Analyst

I wanted to address Nick's question, which I believe was a follow-up to Richard's query. However, it seems you may be hesitant to respond. Earlier this week, in another earnings call, a company mentioned that changes in tax laws or fluctuations in the business model can impact renewable projects in different ways, benefiting some developers while disadvantaging others. You noted that your forecast was based on a 25% win rate from the RFPs, but you’ve actually achieved around 60%. Do you anticipate any changes to these figures with the repricing of the RFPs?

Maria MacGregor Pope, President and CEO

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%.

Joseph R. Trpik, Senior Vice President of Finance and CFO

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 as solely a guide.

Maria MacGregor Pope, President and CEO

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.

Anthony Christopher Crowdell, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

The charges will decrease into 2026, but they are more concentrated in the earlier part of the period. We're making substantial investments, with the largest expenses occurring in 2025, and they will gradually extend into 2026. The real benefits will begin to emerge, although some advantages will already be realized this year and more will materialize next year. We believe that the benefits we anticipate next year, along with the regulatory considerations, are key to maintaining our strong performance in earnings. Overall, our cost management has shown solid results. However, as we seek to implement significant changes, we will carefully navigate these adjustments over time. Nevertheless, the payback period from investment to actual net return is around a year or less.

Operator, Operator

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

Travis Miller, Analyst

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?

Maria MacGregor Pope, President and CEO

Thank you for your question, which is both important and multifaceted. Recently, legislation like the POWER Act has allowed us to engage in long-term contracts with key customers, especially data centers, for over ten years. This is crucial as it helps us secure investments in infrastructure and improve our long-term financing capabilities. In terms of power costs, these measures will extend to generation projects, ultimately alleviating cost pressures for all customers. We've already implemented several initiatives that have significantly impacted costs. For instance, we have nearly 500 megawatts of battery storage that help stabilize customer prices during critical summer and winter periods. Furthermore, we plan to participate in the energy day-ahead market run by the California Independent System Operator, which will enhance procurement efforts across the West and utilize the excess renewable energy produced in the Desert Southwest and California. We've observed substantial changes in power flows already and anticipate further improvements, which will benefit our customers as we strive to reduce expenses.

Travis Miller, Analyst

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?

Maria MacGregor Pope, President and CEO

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.

Travis Miller, Analyst

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?

Joseph R. Trpik, Senior Vice President of Finance and CFO

In the MOU, we haven't agreed on a specific date for filing, whether it will be before the second quarter or at the beginning of the third quarter in 2026. So that remains unresolved.

Travis Miller, Analyst

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

Joseph R. Trpik, Senior Vice President of Finance and CFO

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

Operator, Operator

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.

Maria MacGregor Pope, President and CEO

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.

Operator, Operator

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