Portland Gen Electric reports Q3 GAAP net income of $103 million, driven by 5% load growth and strategic investments in clean energy and infrastructure.

Good morning everyone and welcome to Portland General Electric Company's third quarter 2025 earnings results. ence today is Friday, October 31, 2025. This call is being recorded and as such all lines have been placed on mute to prevent any background noise. After the speaker's remarks, there will be a question and answer period. If you would like to ask a question during this time, simply press star then the numbers 11 on your telephone keypad. If you would like to withdraw your question, please press star 11 again. If you do intend to ask a question, please avoid the use of speakerphones 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 websiteat 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 10K and 10Q which are available on our website. Turning to Slide 3 leading our discussion today are Maria Pope, President and CEO, and Joe Terpik, Senior Vice President of Finance and CFO. Following their prepared remarks, we will open the line for your questions. Now it's my pleasure to turn the call over to Maria.

Good morning and thank you all for joining us today. We delivered another strong quarter in Q3 and we maintain our laser focus on execution, driving value and advancing our five strategic priorities. Starting on slide 4. First, investing in customer driven clean energy goals. Second, working to keep customer prices as low as possible third, supporting data center and high tech growth and the region's economic development. Fourth, reducing risk through operational execution, system hardening and wildfire policies and fifth, promoting an investable energy future. Our industry and Portland General are seeing tremendous growth since 2019. High tech, manufacturing and infrastructure investments have resulted in over 8% industrial growth which is expected to only increase driving our overall load growth of 3% through the end of the decade. Portland General's customers and our region remain focused on clean energy. We are also focused on affordability as we work to keep our cost structure flat and customer prices as low as possible, in turn providing stable competitive returns to shareholders. I will cover the progress we've made in each of these five priorities before highlighting this quarter's results. Clean Energy Given the dynamic policy and market environment for clean energy, our state and company are accelerating to meet the moment. Earlier this month, Oregon Governor Tina Kotek issued an executive order aimed at accelerating renewable energy development before federal tax credits expire, an important step that supports continued progress for the state's goals. This dovetails with the multi pronged procurement strategy Portland Gen Electric deployed in July to maximize the approximate 30% federal tax credits that directly lowers costs for customers. As part of the 2023 RFP, we undertook a price refresh to capture the impacts of the one big beautiful bill and trade tariffs, which culminated in an updated shortlist filed with the Commission earlier this month. The shortlist reflects a rigorous least cost lease risk approach designed to yield reliable, affordable outcomes on timelines responses to evolving legislative requirements. In parallel, we sought community based renewable energy and bilateral PPAs for energy and capacity which are yielding additional projects. Finally, we took a critical step forward in the 2025 RFP which also launched in July. All bids have been received and we are now evaluating projects and building towards contract execution in 20 every element of our strategy prioritizes reliable delivery of energy to customers while maximizing the window of federal 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 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 multi year 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're 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 PG'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 cited solutions to maximize new investments and leverage existing infrastructure. Portland Gen Electric recently completed a project with AI startup 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 Calibrant Energy and digital infrastructure provider Align Data Centers. The agreement will deliver a battery system to Align's 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 situational awareness and deploying technology to protect our communities and improve reliability. We recognize that more is needed to address the collective risk presented by wildfires and extreme weather. We remain committed to working with policymakers to find meaningful answers to these complex issues. Wildfire risk is a societal wide problem and we are working on operational, legislative, regulatory and other outcomes to deliver societal wide solutions an investable energy future lastly, an update on our regulatory proceedings and proposed update to our corporate structure Last week we received the order on the Seaside Alternative Recovery Mechanism for the largest standalone 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 resolution in the first part of next year. The proceedings for Portland Gen Electric'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 Portland Gen Electric's corporate structure to industry standards. Both the holding company and the transmission company enable improved financing flexibility that will yield benefits 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 94 cents per duluthed share. On non GAAP basis net income was 110 million or a dollar per share. This compares to third quarter 2024 GAAP net income of 94 million or 90 cents per diluted share. Similar to Q2, our non GAAP results exclude business transformation and optimization expenses from the customer affordability commitment and updates to our corporate structure. Results this quarter underscore the mission of our company and my commitment to executing with discipline, advancing our strategy and delivering value to customers, communities and shareholders. Our team is laser focused on execution and results, finishing 2025 strong and building off our momentum of our continued success in the years ahead. With that, I'll turn it over to.

Joe 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 we've observed in 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 44 cent increase in total revenues driven by a 16 cent increase from our 5.5% demand growth and a 28 cent increase due to our higher average price of deliveries from improved recovery A decrease from power costs of $0.24 driven by a $0.38 from favorable power costs 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 6 cent 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 23 cent decrease from impacts in support of our ongoing rate based investments and execution of our financing plan made up of 14 cents of depreciation and amortization, 5 cents of dilution and 4 cents of interest expense, a 7 cent increase from other items including an 11 cent increase from our prior year deferral reserve that did not recur and 4 cents of various miscellaneous items and lastly a 6 cent 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 or 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 based 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 twelve 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 based investment in 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 rfp. Capex as we look back at our progress over the last three months or three 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 impacts of load growth, moderately favorable power costs, capex supported financing and benefits from our cost management work. Given our results through Q3 and 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 based 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.

Thank you. As a reminder to ask a question, please press Star one one on your telephone and wait for your name to be announced. And to withdraw your question, please press star 11 again. The first question will come from Julian Dumoulin Smith with Jeffries. Your line is open.

Morning Julian. Hey, good morning team. Hey, good morning Maria. Thank you guys for the time. I appreciate it. Look, let me just start off on this energy deliveries trend here. I mean three and a half to four and a half, that's a solid trend full year. Obviously we've seen some gyrations over the years, but given what you're describing here, data center centric driven, how does that impact or revise any kind of longer term thoughts? What are you seeing on this front? Clearly adjacent state is also seeing kind of positive revisions as well. Thank you.

And Julian, yes, we've been very fortunate to have both 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 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, how do you see that progressing here? 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, etc. 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 partners 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 Oregon Public Utility Commission (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.

Yeah. Julian, good morning. You know, as it relates to the Holdco, you know, we anticipate understanding the filings proceedings that we will operate the Holdco and use it as financing. Very consistent how, you know, virtually all the other utilities in our sector have and operate that Holdco under the right scenarios. We agree we will have the ability to displace certain equity needs. You know, currently we have, you know, strong financing metrics. You know, I mentioned that we're above CFO. Our metric on a CFO to debt is above 20% and we'll be thoughtful as we work towards the RFP outcomes and the Holdco project. Our process matures as BRIA mentioned to really align that to our financing plans as we have more clarity. Excellent. Thank you guys very much, appreciate it. Just quickly lastly on the refresh and the 25 RFP obviously ongoing in parallel here. What's the scale and scope? The refresh seems to be fairly similar in opportunity set for you guys, but you've got these things in parallel. Could we see an acceleration or how do you think about the timing given the way that this has 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, and as I noted, between our projects as well as third party contracts, it's about $2 billion of roughly what we can estimate, a benefit that we've brought back to this region. So we're refreshing the 2023 RFP. As you notice, there's a lot of tariff issues. And then also we have a PPA focused RFP as well as the 2025 RFP. So any more you want to talk about in terms of timing of when we can see resolution?

Oh, yeah, Julian, I think really what you get to. You sort of talk to size here of the two RFPs, obviously this RFP, the 23 we mentioned, has just over a gigawatt of power between the solar and the batteries we use as a foundation for this rfp and the 25 RFP that we're accelerating. The IRFP action plan that was filed that last, updated at midpoint, would say overall we 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 a need of 2,000 megawatts, something maybe even a plus there. We'll have to see. There's a lot of factors to that. Again, what other PPAs get entered into how demand moves, how the clean energy policy and plans. 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. All right, guys, I'll leave it there. Thank you so much. Have a nice weekend.

Thank you, Julian.

And the next question will come from Sophie Karp with kbcm. Your line is open.

Hi, good morning, guys. Thank you for taking my question. A couple of things. Is there a scenario where you get your hold call but not the Transco? Just given that, you know, you're saying that questions seem to be concentrated on the Transco side. Yeah. So.

Good morning, Sophie. You know, as it relates to that, and I think it's more a matter of timing, is there a scenario where the Holdco and the Transco approval process get separated and the Holdco occurs more promptly? I think the answer is yes. You know, under the right circumstances, we could see that. See that occur. We would anticipate over time that Ultimately both are approved but you know, could see a longer path on the trans code each again, you know, just as we relate to our finance, you know, each is a very different financing functionality. And for us, you know, the Holdco is we think drives more value both for the customers and shareholders more currently. And the Transco does have a little more time and therefore it's okay to have a little more time to evolve.

It's super helpful. And then just the most strategic question on the transmission, right. And it kind of gets dovetails 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.

You know, currently, I mean as you can see in our plan, right, we have 1.8 billion in transmission spend including 2020, 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 would 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.

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

And the next question will come from Greg Orl with ubs. Your line is open.

Yeah, thank you. 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%, a 5050 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 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's that proceeding? So currently within the PCAM filing, we are, you know, we are having discussions on the rce. The rce, the reliability contingency event, we feel has been a pretty, you know, consistent and effective tool to date. You know, we are, we continue to focus and dialogue with them. Would we like something like that to proceed to further align the energy costs? Yes, because it helps support our just overall approach to more efficient pricing of energy. That's an open dialogue right now. I don't know that I really want to handicap 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 nice tool. It works effectively for us now and we'll continue to work towards as modern and effective an energy recovery mechanism as we can with our regulator.

Craig, let me add a little bit to that. The events that we saw in January of 2024 were 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 datahead 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 Power Cost Adjustment Mechanism (PCAM) mechanism with the RCE will be.

The best going forward. We're going to need to align the state's policies to the broader market as we are doing more scheduling of energy and optimization versus energy management and purchases.

Thank you. Thank you for the color.

And the next question will come from Shar Pereza with Wells Fargo. Your line is open.

Morning, Char.

Hi. Good morning. Good morning, team. It's actually Constantine here for Char. Thanks for taking the question. Maybe just a little bit of cleanup. Just with the kind of quarter up, 5% load growth and the full year step up, is that significant enough to incorporate in 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? Good morning, Constantine. Yeah, so as it relates to the load growth, to your question of how does it drive more to the plan, It'll be as we clarify and get the tariff as it relates to margin. Right now the new data center tariff is on the regulatory side to get drawn out. And so being able to take advantage of that growth at a more balanced margin, we'll do two things. One, it will balance out the cost to our residential and other customers. But then two, 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. You know, we'll get that tariff when we get that tariff. But that will be a nice measure point to be able to, you know, you know, capture some value. I believe that's scheduled for March. Okay. And that's kind of when you would start incorporating some of that into the forward looking financial plans. Well, I think that's the place where you'd start to be able to identify to the extent that you continue to see that growth, you would start pricing that growth a little bit differently and you'd be able to start to determine if there's incremental value there. Okay, perfect. Because you'll have a clear cost structure. Structure. And then just one follow up on the 25 RFP process. You kind of noted that. And there's some lessons learned kind of being incorporated there. And 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? You know, I don't think as, as it relates to the ownership or anything like that. No. I mean, we continue to work with the, with the commission on a multi pronged approach here. I mean, I do think like the key message, if you ask me right now, what is it for? 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 change is to drive as much of the benefit as we can tax credit wise out of these projects. And you know, 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, just work with all the constituents to continue to align to the market. Excellent. Perfect. Thank you.

And our next question will come from Paul Fremont with Ladenburg. Your line is open.

Thank you very much. You gave sort of 150 million of tax credit for 25 and I think you talked about sort of 2 billion. Can you give us sort of an annual estimate of what tax credits you expect to realize. 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 towards ITCs and wind tends to lead a little bit more towards PTCs. But this is an important way that we're bringing federal dollars back to reducing customer prices for renewable energy and creating investment opportunities with the state of Oregon and regionally.

And Paul, just to add, there is a bit of a cyclicality 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 are seeing the cash flows this year, you are seeing are Both the remaining ITCs that came from the Constable project last year and then the ITCs from the seaside project this year on an annualized basis. The foundation that we come from is the PTCs as related to our wind projects, call that around 50 ish million dollars a year. And then the cyclicality would be the ITCs that come from RFP projects. At least that's currently the way cash flows.

Then with respect to 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 five weeks and there are a number of statewide priorities, meaning that we could see more results out of the legislature in 27 versus 26. On the regulatory side, we continue to work with regulators and staff on solutions. First of all, starting with all of the work we do operationally to reduce wildfire risk. And that's all detailed in our wildfire plan and obviously the recovery associated with that as well as standard of care and then also mechanisms for self insurance and other sorts of things.

Great. And then last question for this year, can you give a sense of are you expecting to experience any regulatory lag in terms of earning your authorized ROE or. What would.

If there is lag, how many basis points would you expect that to be.

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

I'm sorry, you said three basis points.

I said 70. 70. 70. I'm sorry. Okay. Yeah, that's. And that is, and just as a reminder, that is, that is a compression from what we had experienced, you know, 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?

Yeah, we expect to do that and we expect to continue to apply downward pressure on that as it relates to our, our cost management work as it continues to mature. And so we expect to, or 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, you know, when we think to next year, using the DSP as our regulatory approach as well as the cost management and others, we sort think of it as a basket of items to help us continue to drive within our earnings range. But it is a goal of ours to just be as tight as we can. Thank you very much. That's it for me.

Thank you.

And the next question will come from George Sonales with Mizuho. Your line is open.

Thanks for taking my question. Morning. So I know the DSPR was filed in July, but I'm 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? So. Good morning, George. 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. You know, the. Just as a reminder that the reason we took the approach with the DSP here was really to drive clarity for parties. Right. The DSP is a filed and an accepted docket from that lays out our sort of our Action plans for the distribution. And so we felt that, you know, 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, you know, and then, so that then using that and then looking to seaside. Right, the seaside. We felt that the MOU really, and having an MOU and spending the time before really allowed us to have a focused dialogue and have a constructive dialogue and outcome. You know, when we look to both the, you know, the testimony and some of the intervener interorg and we would expect that to continue here with the dsp. Great, thank you for the clarity. And can you talk a little bit about how you plan to utilize GridCare and what initial tests you've done or you plan to do and when you expect to see measurable impacts to unlock additional system capacity? Sure.

So first of all, we're really excited about the opportunity that we've seen with our partnership with Grid Care. It comes out of the work that we've done with other startups and innovative companies that will Silicon Valley and Stanford's School of Engineering. The program is essentially takes an enormous amount of data AI analytics. It actually takes compute that exceeds most capabilities 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. I would also say it's not just the AI analytics, it's 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 our 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.

Great, I'll leave it there. Thank you. Thank you.

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 and at Edison Electric Institute (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.